[Federal Register Volume 63, Number 203 (Wednesday, October 21, 1998)]
[Proposed Rules]
[Pages 56292-56391]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 98-26292]
[[Page 56291]]
_______________________________________________________________________
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; Proposed
Rule
Federal Register / Vol. 63, No. 203 / Wednesday, October 21, 1998 /
Proposed Rules
[[Page 56292]]
ENVIRONMENTAL PROTECTION AGENCY
40 CFR Parts 52 and 97
[FRL-6170-6]
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: Notice of proposed rulemaking (NPR).
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SUMMARY: In accordance with section 126 of the Clean Air Act (CAA), EPA
is proposing action on petitions filed by eight Northeastern States
seeking to mitigate what they describe as significant transport of one
of the main precursors of ground-level ozone, nitrogen oxides
(NOX), across State boundaries. Each petition specifically
requests that EPA make a finding that NOX emissions from
certain stationary sources emit in violation of the CAA's prohibition
on emissions that significantly contribute to ozone nonattainment
problems in the petitioning State. If EPA makes such a finding of
significant contribution, EPA is authorized to establish Federal
emissions limits for the sources. The eight Northeastern States that
filed petitions are Connecticut, Maine, Massachusetts, New Hampshire,
New York, Pennsylvania, Rhode Island, and Vermont.
This notice proposes to find that portions of certain petitions are
technically meritorious under the test applicable under section 126.
The EPA is proposing that the technically meritorious portions of the
petitions be deemed granted or denied at certain later dates pending
certain actions by the States and EPA regarding State submittals in
response to the final NOX State implementation plan call
(NOX SIP call). This notice describes the schedule and
conditions under which applicable final findings on the petitions would
be automatically triggered. Further, this notice proposes the control
requirements that would apply to sources in the source categories for
which a final finding is ultimately granted. This notice also proposes
to deny certain petitions, in whole or in part. The EPA published a
shorter proposal on the section 126 petitions on September 30, 1998
that announced the availability of this longer proposal in the docket
and on EPA's Website, announced the public hearing, and requested
comment on the proposal.
The transport of ozone and its precursors is important because
ozone, which is a primary harmful component of urban smog, has long
been recognized, in both clinical and epidemiological research, to
affect public health. There is a wide range of ozone-induced health
effects, including decreased lung function (primarily in children
active outdoors), increased respiratory symptoms (particularly in
highly sensitive individuals), increased hospital admissions and
emergency room visits for respiratory causes (among children and adults
with pre-existing respiratory disease such as asthma), increased
inflammation of the lung, and possible long-term damage to the lungs.
DATES: Comments may be submitted until November 30, 1998, as previously
announced in a shorter notice of proposed rulemaking published in the
Federal Register on September 30, 1998.
Comments must be postmarked by the last day of the comment period
and sent directly to the Docket Office listed in ADDRESSES (in
duplicate form if possible). The public hearings for the section 126
and FIP proposals will be held on October 28 and 29, 1998, as
previously announced in a shorter notice of proposed rulemaking
published in the Federal Register on September 30, 1998.
ADDRESSES: Comments may be submitted to 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. Comments and data may
also be submitted electronically by following the instructions under
SUPPLEMENTARY INFORMATION of this document. No confidential business
information (CBI) should be submitted through e-mail. For comments that
include color graphics, a courtesy copy of comments to Carla Oldham
would be appreciated at Office of Air Quality Planning and Standards,
Air Quality Strategies and Standards Division, MD-15, Research Triangle
Park, NC 27711, telephone (919) 541-3347, fax (919) 541-0824, e-mail
address oldham.carla@epa.gov. The address for sending overnight
packages is U.S. EPA, Air Quality Strategies and Standards Division,
411 W Chapel Hill St., Durham, NC 27701.
The public hearing will be held at the EPA Auditorium, 401 St.,
SW., Washington, DC.
Documents relevant to this action are available for inspection at
the Docket Office, at the above address, between 8 a.m. and 4 p.m.,
Monday though Friday, excluding legal holidays. A reasonable copying
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.
Please refer to SUPPLEMENTARY INFORMATION below for a list of contacts
for specific subjects described 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
CBI, is available for inspection from 8 a.m. to 4 p.m., Monday through
Friday, excluding legal holidays. The official rulemaking record is
located at the address in ADDRESSES at the beginning of this document.
Electronic comments can be sent directly to EPA at: A-and-R-
Docket@epamail.epa.gov. Electronic comments must be submitted as an
ASCII file avoiding the use of special characters and any form of
encryption. Comments and data will also be accepted on disks in
WordPerfect in 5.1 file format or ASCII file format. All comments and
data in electronic form must be identified by the docket number A-97-
43. Electronic comments on this NPR rule may be filed online at many
Federal Depository Libraries.
The EPA has issued a separate rule on NOX transport
entitled, ``Finding of Significant Contribution and Rulemaking for
Certain States in the Ozone Transport Assessment Group Region for
Purposes of Reducing Regional Transport of Ozone'' (see notices
included in the docket for this rulemaking). The rulemaking docket for
that rule, hereafter referred to as the NOX State
implementation plan (SIP) call (NOX SIP call), contains
information and analyses that are relied upon in today's proposal on
the section 126 petitions. Therefore, EPA is incorporating by reference
the entire NOX SIP call record for purposes of the section
126 rulemaking. Documents related to the NOX SIP call
rulemaking are available for inspection in Docket No. A-96-56 at the
address and times
[[Page 56293]]
given above. In addition, the proposed NOX SIP call and
associated documents are located at http://www.epa.gov/ttn/oarpg/
otagsip.html. The EPA is finalizing action on the NOX SIP
call concurrently with today's proposal on the section 126 petitions.
Additional information relevant to this NPR concerning the Ozone
Transport Assessment Group (OTAG) is available on the Agency's Office
of Air Quality Planning and Standards' (OAQPS) Technology Transfer
Network (TTN) via the web at http://www.epa.gov/ttn/. If assistance is
needed in accessing the system, call the help desk at (919) 541-5384 in
Research Triangle Park, NC. Documents related to OTAG can be downloaded
directly from OTAG's webpage at http://www.epa.gov/ttn/otag. The OTAG's
technical data are located at http://www.iceis.mcnc.org/OTAGDC.
For Additional Information
For additional information related to air quality analysis, please
contact Carey Jang, Office of Air Quality Planning and Standards;
Emissions, Monitoring, and Analysis Division, MD-14, Research Triangle
Park, NC 27711, telephone (919) 541-5638. For legal questions, please
contact Howard Hoffman, Office of General Counsel, 401 M Street SW, Mc-
2344, Washington, DC, 20460, telephone (202) 260-5892. For questions
regarding the NOX cap-and-trade program, please contact
Melanie Dean, Office of Atmospheric Programs, Acid Rain Division, MC-
6204J, 401 M Street SW, Washington, DC 20460, telephone (202) 564-9189.
For questions regarding regulatory cost analyses for electricity
generating sources, please contact Ravi Srivastava, Office of
Atmospheric Programs, Acid Rain Division, MC-6204J, 401 M Street SW,
Washington, DC 20460, telephone (202) 564-9093. For questions regarding
regulatory cost analyses for other stationary sources, please contact
Scott Mathias, Office of Air Quality Planning and Standards, Air
Quality Strategies and Standards Division, MD-15, Research Triangle
Park, NC 27711, telephone (919) 541-5310.
Outline
I. Background
A. Summary of Rulemaking
B. Ozone Transport, Ozone Transport Commission NOX
Memorandum of Understanding (OTC NOX MOU), OTAG, the
NOX SIP Call, the Revised Ozone National Ambient Air
Quality Standard, and Ozone Effects
C. Section 126
D. Summary of Section 126 Petitions
1. Control Remedies Recommended By Petitions
2. Sources Covered By Petitions
E. Litigation on Rulemaking Schedule
F. Advance Notice of Proposed Rulemaking on Petitions
II. EPA's Analytical Approach and Proposed Action on Petitions
A. EPA's Proposed Interpretation of Section 126 and Analytical
Approach for Determining Whether to Grant or Deny the Petitions
1. The Appropriate Test under Section 126
2. EPA's Analytical Approach for Determining Whether to Grant or
Deny the Petitions
a. EPA's Interpretation of Significant Contribution under
Section 110
b. Applying EPA's Section 110 Interpretation of ``Significant
Contribution'' and ``Interference'' under Section 126
c. Emitting ``In Violation of the Prohibition'' in Section 110--
the Decision Whether to Grant or Deny Each Petition
B. Weight of Evidence Determination of Named Upwind States
C. Cost-Effectiveness of Emissions Reductions
1. What NOX Controls Are Highly Cost Effective
2. Determining the Cost Effectiveness of NOX Controls
i. Large EGUs
ii. Large Non-EGUs
iii. Legal Process Heaters
iv. Small Sources
v. Summary of Control Measures
3. Other Cost-Related Considerations
D. Identifying Sources
E. Air Quality Assessment
F. Conclusions on Granting or Denying Petitions
1. Technical Determinations
2. Action on Whether to Grant or Deny Each Petition
a. Portions of Petitions For Which EPA is Proposing an
Affirmative Technical Determination
b. Portions of Petitions For Which EPA is Proposing An Negative
Technical Determination
3. Requirements for Sources for Which EPA Makes a Section 126(b)
Finding
III. Federal NOX Budget Trading Program
A. Program Summary
1. Purpose of the Federal NOX Budget Trading Program
2. Relationship of Section 126 Remedy to the NOX SIP
Call and the FIP
B. Federal NOX Budget Trading Program
1. Program Overview
2. Elements of the Federal NOX Budget Trading Program
That Are the Same as the State NOX Budget Trading Program
a. General Provisions
b. Authorized Account Representative
c. Permits
d. Compliance Certification
e. NOX Allowance Tracking System
f. Banking
g. NOX Allowance Transfers
h. Audits
3. Elements of the Federal NOX Budget Trading Program
That Differ from the State NOX Budget Trading Program
a. General Provisions
i. Purpose
ii. Definitions
iii. Applicability
iv. Standard Requirements
b. Compliance Certification
c. Aggregate NOX Emissions Levels and Allowance
Allocations
i. Data Sources
(1) EGUs
(2) Non-EGUs
ii. Methodology Used to Determine Controlled Emission Levels
(1) Large EGUs
(2) Large Non-EGUs
iii. Development of Section 126 Trading Program Budget
iv. Timing Provisions
v. NOX Allowance Allocation Methodology
(1) EGUs
(2) Non-EGUs
(3) Treatment of New Sources
d. Compliance Supplement Pool
i. Size of Compliance Supplement Pool
ii. Distribution of Compliance Supplement Pool to Sources
e. Emissions Monitoring and Reporting
f. Opt-ins
g. Program Administration
C. New Source Review
IV. Non-ozone Benefits to NOX Reductions
V. Administrative Requirements
A. Executive Order 12866: Regulatory Impact Analysis
B. Impact on Small Entities
1. Regulatory Flexibility
2. Outreach to Small Entity Representatives
3. Potentially Affected Small Entities
4. Panel Findings and EPA Actions
a. Exemptions
b. Continuous Emissions Monitoring Systems (CEMS)
c. Electricity Generating Units
d. Industrial Boilers
e. EPA Guidance to States on Small Entities
C. Unfunded Mandates Reform Act
D. Paperwork Reduction Act
E. Executive Order 13045: Protection of Children from
Environmental Health Risks and Safety Risks
1. Applicability of Executive Order 13045
2. Childrens' Health Protection
F. Executive Order 12898: Environmental Justice
G. Executive Order 12875: Enhancing the Intergovernmental
Partnership
H. Executive Order 13084: Consultation and Coordination with
Indian Tribal Governments
I. National Technology Transfer and Advancement Act
I. Background
A. Summary of Rulemaking
In today's action, EPA is proposing to make a technical
determination that certain major stationary sources and source
categories identified in the section 126 petitions are significantly
contributing to nonattainment in, or interfering with maintenance by,
one or more petitioning State with respect to one or more of the
national ambient air quality standards for ozone (hereafter
[[Page 56294]]
referred to as a positive or affirmative technical determination). On
the basis of that proposed affirmative technical determination, EPA is
proposing that the petitions naming these sources and source categories
be granted or denied at certain later dates pending certain actions by
the States and EPA regarding State submittals in response to the final
NOX SIP call. The schedule and conditions under which the
applicable final findings on the petitions would be triggered are
discussed below in Section II.F. The EPA's analysis of significant
contribution is discussed in Section II below.
Under the 1-hour ozone standard, EPA is proposing to make
affirmative technical determinations as to a subset of sources and
source categories named in the petitions from Connecticut, Maine,
Massachusetts, New Hampshire, New York, Pennsylvania, and Rhode Island.
The source categories for which EPA is proposing this affirmative
technical determination of significant contribution are discussed in
Section II. The existing sources that are affected by this technical
determination are listed in appendix A to proposed part 97.
The EPA is also proposing to partially deny the petitions from
Connecticut, Maine, Massachusetts, New Hampshire, New York,
Pennsylvania, and Rhode Island because EPA believes some of the sources
or source categories named in the petitions are not significantly
contributing to nonattainment in the relevant petitioning State with
respect to the 1-hour ozone standard. The EPA is proposing to deny the
Vermont petition in full with respect to the 1-hour ozone standard
because the 1-hour standard no longer applies in that State (See 63 FR
31014).
Three of the petitioners, Massachusetts, Pennsylvania, and Vermont,
also directed their petitions at the new 8-hour ozone standard. Under
the 8-hour ozone standard, EPA is proposing to make a positive
technical determination as to a subset of sources named in the
petitions from Massachusetts and Pennsylvania. The source categories
for which EPA is proposing this affirmative technical determination of
significant contribution are discussed in Section II. The existing
sources that are affected by this technical determination are listed in
appendix A to proposed part 97. The EPA is proposing to deny the
Vermont petition in full with respect to the 8-hour ozone standard
because Vermont has no current 8-hour ozone nonattainment problems and
no future projected nonattainment problems based on available analyses.
In aggregate for all petitions and both ozone standards, the
sources and source categories that EPA is proposing to find
significantly contribute to nonattainment in, or interfere with
maintenance by, (hereafter simply contribute significantly to) one or
more of the petitioning States are located in the following States:
Alabama, Connecticut, Delaware, District of Columbia, Illinois,
Indiana, Kentucky, Maryland, Massachusetts, Michigan, Missouri, New
Jersey, New York, North Carolina, Ohio, Pennsylvania, Rhode Island,
Tennessee, Virginia, and West Virginia. The combined list of existing
sources affected by a positive technical determination with respect to
at least one petition, along with proposed emissions limitations in the
form of tradable allowance allocations, is located in Appendix A to
proposed part 97. The EPA intends to update the list of affected
sources on a periodic basis to include new sources in the source
categories that are significantly contributing.
Some of the sources that EPA is proposing do not significantly
contribute to the petitioning States may be located in States that are
affected by a separate rulemaking on NOX transport, the
NOX SIP call. While emissions from sources in certain States
may not be significantly contributing to nonattainment or maintenance
problems in any of the eight petitioning States, the sources may be
significantly contributing to nonattainment problems in other downwind
States. In acting on these section 126 petitions, EPA can only consider
the impacts on downwind nonattainment problems in the petitioning
States, which are all located in the Northeast. In the NOX
SIP call, EPA considered impacts on nonattainment problems throughout
the eastern half of the United States. Therefore, a determination that
sources in certain States are not significantly contributing for
purposes of this action on the section 126 petitions should not be
assumed to reflect EPA's conclusions on significant contribution with
regard to the NOX SIP call or other transport-related
rulemakings.
The section 126 petitions varied with regard to the control
requirements they recommend for mitigating the interstate transport.
While EPA considered the recommendations, section 126 does not limit
EPA to the recommended controls in determining an appropriate remedy.
In Section III, EPA proposes the emissions limitations that would be
necessary to ensure that the affected sources do not or would not emit
in violation of the applicable statutory prohibition on significant
contribution by upwind States to downwind air quality problems. The
control remedy is based on the uniform application of highly cost-
effective controls (as determined based on cost per ton of
NOX reduced for each type of source). In selecting the
control measures, EPA considered the recommendations made by OTAG on
July 8, 1997 and the analyses for the NOX SIP call. The EPA
considered controls that would effectively minimize emissions while not
exceeding a source-categorywide $2000 per ton for reductions of ozone
season NOX (in 1990 dollars), on average, for each source
category. For electricity generating units larger than 25 MWe, EPA is
proposing a control level corresponding to 0.15 lb/mmBtu. For
industrial boilers and turbines greater that 250 mmBtu/hr, EPA is
proposing a control level corresponding to a 60 percent reduction from
an uncontrolled baseline. For small sources and process heaters, EPA is
proposing no additional controls. For purposes of this rulemaking, EPA
is defining small sources as: (1) Electricity generating boilers and
turbines serving a generator 25 MWe or less, and (2) other indirect
heat exchangers with a heat input of 250 mmBtu/hr or less. The control
requirements are consistent with the assumptions used in developing the
final budgets for the NOX SIP call. Further discussion
concerning small point sources can be found in Section II of this
preamble.
The EPA intends to implement the control requirements through a
Federal NOX cap-and-trade program, which is described in
Section III. The EPA believes a trading program is the most cost-
effective approach for achieving emissions reductions from large
stationary sources. The proposed trading program is consistent with the
model trading rule that EPA is finalizing for purposes of the
NOX SIP call, except for changes necessary to account for
Federal implementation instead of State implementation. The EPA
envisions that there would be a common trading program among section
126 sources and NOX SIP call sources in States that choose
to participate in the State trading program, and sources subject to a
Federal implementation plan under the NOX SIP call.
In accordance with section 126, sources must comply with the
control requirements no later than 3 years from a final positive
finding on the petitions, on a schedule to be determined by the EPA
Administrator. The EPA is proposing that the full 3 years is necessary
for compliance. As discussed below, EPA is proposing that the
technically meritorious portions of the
[[Page 56295]]
petitions be deemed granted or denied at certain later dates, pending
certain actions by States and EPA regarding implementation plans
required in response to the NOX SIP call. The EPA intends to
take final action by April 30, 1999 on the technical determination
described above, the decision as to when each portion of the petitions
would be deemed granted or denied, and the emissions limitations that
would apply to any sources for which a petition is ultimately deemed
granted.
B. Ozone Transport, Ozone Transport Commission NOX
Memorandum of Understanding (OTC NOX MOU), OTAG, the
NOX SIP Call, the Revised Ozone National Ambient Air Quality
Standard (NAAQS), and Ozone Effects
Today's action occurs against a background of a major national
effort, spanning at least the last 10 years, to analyze and take steps
to mitigate the problem of the transport of ozone and its precursors
across State boundaries. This effort has grown more intensive in the
past several years with the approval of the OTC NOX MOU by
11 of the Northeastern States and the District of Columbia included in
the Northeast Ozone Transport Region (OTR), the completion of the OTAG
process (described below), and the publication of EPA's proposed
NOX SIP call. In addition, on July 18, 1997, EPA issued a
revised NAAQS for ozone, for which is determined over an 8-hour period
(the 8-hour standard) (62 FR 38856). In establishing the 8-hour
standard, EPA is setting the standard at 0.08 parts per million and
defines the new standard as a ``concentration-based'' form,
specifically the 3-year average of the annual 4th-highest daily maximum
8-hour ozone concentrations. This has resulted in more areas and larger
areas with monitoring data indicating nonattainment. Thus, it is even
more important to implement regional control strategies to mitigate
interstate pollution in order to assist downwind areas in achieving
attainment. This new 8-hour standard must now be taken into account,
along with the pre-existing 1-hour standard, in resolving transport
issues. These issues and events are detailed in the proposed
NOX SIP call (62 FR 60318) and familiarity with that notice
is assumed for purposes of today's notice. In addition, in many areas
of the country, the 1-hour standard has been revoked because the areas
are attaining that standard (63 FR 31013; June 5, 1998 and 63 FR 39432,
July 22, 1998). A State may petition under section 126 for the both the
1-hour standard, to the extent that it still applies in the petitioning
State, and the 8-hour standard.
The 1990 CAA set forth many requirements to address nonattainment
of the 1-hour ozone NAAQS. Many States have found it difficult to
demonstrate attainment of the NAAQS due to the widespread transport of
ozone and its precursors. The Environmental Council of the States
(ECOS) recommended formation of a national work group to allow for a
thoughtful assessment and development of consensus solutions to the
problem. This work group, OTAG, was established 3 years ago to
undertake an assessment of the regional transport problem in the
eastern half of the United States. The OTAG was a collaborative process
conducted by representatives from the affected States, EPA, and
interested members of the public, including environmental groups and
industry, to evaluate the ozone transport problem and develop
solutions. The OTAG region included the 37 eastern-most States and the
District of Columbia. Through the OTAG process, the States concluded
that widespread NOX reductions are needed in order to enable
areas to attain and maintain the ozone NAAQS. Based on information
generated by OTAG and other available data, EPA determined that certain
States in the OTAG region were significantly contributing to
nonattainment problems in downwind States. Therefore, EPA issued a
proposed NOX SIP call requiring the States to revise their
SIPs to include NOX control measures to mitigate the ozone
transport. The EPA is finalizing the NOX SIP call in the
same timeframe as this proposal on the section 126 petitions.
The EPA's response to the section 126 petitions differs from EPA's
action in the NOX SIP call rulemaking in several ways. In
the NOX SIP call, where EPA concludes that NOX
emissions from a State are significantly contributing to nonattainment
problems in downwind States, EPA will require the State to submit SIP
provisions to prohibit an amount of NOX emissions which
represents the significant contribution. The State will have the
discretion to select the mix of controls measures for their sources to
meet the required statewide NOX reduction reductions. If the
State does not make the required SIP submission, EPA is required to
promulgate a Federal implementation plan (FIP) within 2 years of the
State failure. In the November 7, 1997 NOX SIP call
proposal, EPA announced that it intended to expedite the FIP
promulgation in order to assure that the downwind States receive the
air quality benefits of regional NOX reductions as soon as
practicable. Therefore, the EPA is proposing FIPs for all the States
affected by the NOX SIP call in conjunction with EPA's
issuance of the final NOX SIP call.
By comparison, section 126 petitions are limited to addressing
emissions from upwind stationary sources and not other sectors of the
inventory. If EPA grants the petitions, it is EPA, not the States, that
promulgates control requirements for the sources. The control remedy
for sources in the section 126 petitions that EPA is proposing in this
action is consistent with the control assumptions EPA used for these
sources in determining reductions projected to meet the final statewide
NOX budgets for States subject to the NOX SIP
call.
Because the NOX SIP call process overlaps considerably
with the section 126 petition process, in that they both address
NOX transport in the eastern United States, EPA believes it
is important to coordinate the two actions as much as possible. As
discussed below, EPA and the petitioning States developed a proposed
consent decree on the rulemaking schedule for the petitions that takes
into consideration the NOX SIP call rulemaking.
All of the States that submitted section 126 petitions are included
in the OTR and participated in the OTAG process. In addition, all of
the upwind sources identified in the petitions are located in the OTAG
region. All eight petitions rely, in part, on the OTAG analyses for
technical justification. The OTAG process concluded in June 1997 prior
to the promulgation of the new 8-hour ozone standard and, therefore,
the OTAG analyses focused on the 1-hour standard. All the petitions
request relief under the 1-hour standard. Three of the petitions also
request relief under the new 8-hour standard. In acting on the section
126 petitions, EPA believes that it can only consider 8-hour
nonattainment problems for the petitioning States that expressly
requested relief under that standard. Under the NOX SIP
call, EPA considered both 1-hour and 8-hour nonattainment problems
throughout the OTAG region.
Ground-level ozone, the main harmful ingredient in smog, is
produced in complex chemical reactions when its precursors, volatile
organic compounds (VOCs) and NOX, react in the presence of
sunlight. The chemical reactions that create ozone take place while the
pollutants are being blown through the air by the wind, which means
that ozone can be more severe many miles away from the source of
emissions than it is at the source.
[[Page 56296]]
At ground level, ozone can cause a variety of ill effects to human
health, crops and trees. Specifically, ground-level ozone induces the
following health effects:
Decreased lung function, primarily in children active
outdoors,
Increased respiratory symptoms, particularly in highly
sensitive individuals,
Hospital admissions and emergency room visits for
respiratory causes, among children and adults with pre-existing
respiratory disease such as asthma,
Inflammation of the lung,
Possible long-term damage to the lungs.
The new 8-hour primary ambient air quality standard will provide
increased protection to the public from these health effects.
Each year, ground-level ozone above background is also responsible
for several hundred million dollars worth of agricultural crop yield
loss. It is estimated that full compliance of the newly promulgated
ozone NAAQS will result in about $500 million of prevented crop yield
loss. Ozone also causes noticeable foliar damage in many crops, trees,
and ornamental plants (i.e., grass, flowers, shrubs, and trees) and
causes reduced growth in plants. Studies indicate that current ambient
levels of ozone are responsible for damage to forests and ecosystems
(including habitat for native animal species).
C. Section 126
Subsection (a) of section 126 requires, among other things, that
SIPs require major proposed new (or modified) stationary sources to
notify nearby States for which the air pollution levels may be affected
by the fact that such sources have been permitted to commence
construction. Subsection (b) provides:
Any State or political subdivision may petition the
Administrator for a finding that any major source or group of
stationary sources emits or would emit any air pollutant in
violation of the prohibition of section 110(a)(2)(D)(ii) * * * or
this section.
Subsection (c) of section 126 states that--
[I]t shall be a violation of this section and the applicable
implementation plan in such State [in which the source is located or
intends to locate]--
(1) For any major proposed new (or modified) source with respect
to which a finding has been made under subsection (b) of this
section to be constructed or to operate in violation of the
prohibition of section 110(a)(2)(D)(ii) * * * or this section, or
(2) For any major existing source to operate more than three
months after such finding has been made with respect to it.
However, subsection (c) further provides that EPA may permit the
continued operation of such major existing sources beyond the 3-month
period, if such sources comply with EPA-promulgated emissions limits
within 3 years of the date of the finding.
Section 110(a)(2)(D) provides the requirement that a SIP contain
adequate provisions--
(i) Prohibiting, consistent with the provisions of this title,
any source or other type of emissions activity within the State from
emitting any air pollutant in amounts which will--
(I) Contribute significantly to nonattainment in, or interfere
with maintenance by, any other State with respect to [any] national
* * * ambient air quality standard, or
(II) interfere with measures required to be included in the
applicable implementation plan for any other State under part C to
prevent significant deterioration of air quality or to protect
visibility.
(ii) Insuring compliance with the applicable requirements of
sections 126 and 115 (relating to interstate and international
pollution abatement) * * *
As explained in detail in Section II.A., below, it is EPA's view that,
with respect to existing stationary sources, sections 126(b)-(c) and
110(a)(2)(D), read together, authorize a downwind State to petition EPA
for a finding that major stationary sources or groups of sources upwind
of the State emit in violation of the prohibition of section
110(a)(2)(D)(i) because, among other reasons, their emissions
contribute significantly to nonattainment, or interfere with
maintenance, of a NAAQS in the State. If EPA grants the requested
finding, the existing sources must shut down in 3 months unless EPA
directly regulates the sources by establishing emissions limitations
and a compliance period extending beyond 3 months but no later than 3
years from the finding. In accordance with section 302(j) of the CAA,
the term major stationary source means ``any stationary facility or
source which directly emits, or has the potential to emit, one hundred
tons per year or more of any air pollutant. * * *'' For the purpose of
this rulemaking the relevant pollutant is NOX emissions.
The EPA acknowledges that others have urged different readings of
sections 126(b)-(c) and 110(a)(2)(D) and EPA solicits comments thereon
in this rulemaking, as described in Section II.A.1., below.
D. Summary of Section 126 Petitions
The petitions vary as to the type and geographic location of the
source categories identified as significant contributors. All the
petitions identified source categories; some petitions also provided
lists of sources within the specified categories. The source categories
include electric generating plants, fossil fuel-fired boilers and other
indirect heat exchangers, and certain other related stationary sources
that emit NOX. All the petitions target sources in the
Midwest; some also target sources in the South and Northeast. The
geographic area covered by each petition is shown in Figure 2. The EPA
requests comment from the petitioning States as to whether EPA has
correctly interpreted the geographic scope of their petitions.
The petitions also vary as to the level of controls they recommend
be applied to the sources to mitigate the transport problem. Several
recommend EPA establish a 0.15 lb/mmBtu NOX emission
limitation and several recommend that controls be implemented through a
cap-and-trade program. The petitions are described in greater detail
below.
All of the petitions rely, in part, on OTAG analyses for technical
support. In addition, the States submitted a variety of other technical
analyses which include computerized urban airshed modeling, wind
trajectory analyses, results of a transport study by the Northeast
States for Coordinated Air Use Management, and culpability analyses.
Table I-1 shows, by petitioner, the named source categories, the
named geographic areas, and the requested remedy sought by the
petitioning States. The named source categories are worded as they
appear in the petitions. A map of the OTAG Subregions is provided in
part 52, appendix F,
Figure 1.
[[Page 56297]]
Table I-1.--EPA's Summary of Section 126 Petitions
----------------------------------------------------------------------------------------------------------------
State Named source categories Named States Requested remedy
----------------------------------------------------------------------------------------------------------------
CT................... Fossil fuel-fired boilers or Sources in OTAG Subregions Establish, at a minimum,
other indirect heat 2, 6, and 7 and portion of emission limitations and a
exchangers with a maximum OTR extending west and schedule of compliance
gross heat input rate of 250 south of CT. Includes all consistent with the OTC NOX
mmBtu/hr or greater and or parts of IN, KY, MI, NC, MOU, and a cap-and-trade
electric utility generating OH, TN, VA, WV. And OTR program. Does not request
facilities with a rated States DC, DE, MD, NJ, NY, remedy for OTR States
output of 15 MW or greater. PA. because of OTC NOX MOU.
ME................... Electric utilities and steam- Sources within 600 miles of Establish compliance
generating units with a heat Maine's ozone nonattainmen schedule and emissions
input capacity of 250 mmBtu/ t areas. Includes all or limitation of 0.15 lb/mmBtu
hr or greater. parts of NC, OH, VA, WV, for electric utilities and
and OTR States CT, DE, DC, the OTC NOX MOU level of
MD, MA, NJ, NY, NH, PA, RI, control for steam
VT. generating units, in a
multi-state cap-and-trade
NOX market system.
MA................... Electricity generating Sources in region within 3 Establish emissions
plants.. counties on either side of limitation of 0.15 lb/mmBtu
the Ohio River in IN, KY, or 1.5 lb/MWh and a
OH, WV. compliance schedule.
NH................... Fossil fuel-fired indirect Sources in OTR States and Establish compliance
heat exchange combustion OTAG Subregions 1 through schedule and emission
units and fossil fuel-fired 7. Includes all or parts of limitations no less
electric generating IL, IN, IA, KY, MI, MO, NC, stringent than: (a) Phase
facilities which emit ten OH, TN, VA, WV, WI. Also III OTC NOX MOU reductions;
tons of NOX or more per day. OTR States CT, DE, DC, MD, and/or (b) 85% reductions
MA, ME, NJ, NY, PA, RI, VT. from projected 2007
baseline; and/or (c) An
emission rate of 0.15 lb/
mmBtu.
NY................... Fossil fuel-fired boilers or Sources in OTAG Subregions 2 Establish, at a minimum,
indirect heat exchangers 6, and 7 and portion of OTR emission limitations and a
with a maximum heat input extending west and south of schedule of compliance
rate of 250 mmBtu/hr or NY. Includes all or parts consistent with the OTC NOX
greater and electric utility of IN, KY, MI, NC, OH, TN, MOU, and a cap-and-trade
generating facilities with a VA, WV. And OTR States DC, program. Does not request
rated output of 15 MW or DE, MD, NJ, PA. remedy for OTR States
greater. because of OTC NOX MOU.
PA................... Fossil fuel-fired indirect AL, AR, GA, IL, IN, IA, KY, Establish emission
heat exchange combustion LA, MI, MN, MS, MO, NC, OH, limitations and a
units with a maximum rated SC, TN, VA, WV, WI. compliance schedule for a
heat input capacity of 250 cap-and-trade program
mmBtu/hr or greater, and requiring: (a) seasonal
fossil fuel-fired electric reductions of the less
generating facilities rated stringent of 55% from 1990
at 15 MW or greater. baseline levels, or 0.20 lb/
mmBtu, beginning by May
1999; (b) if necessary,
seasonal reductions of the
less stringent of 75% from
1990 baseline levels, or
0.15 lb/mmBtu, beginning by
May 2003; (c) such
additional reductions as
necessary beginning in
2005.
RI................... Electricity generating plants Sources in region within 3 Establish emissions
counties on either side of limitation of 0.15 lb/mmBtu
Ohio River in IN, KY, OH, or 1.5 lb/MWh and a
WV. compliance schedule.
VT................... Fossil fuel-fired electric Sources located within a Establish emissions
utility generating geographic area extending limitation of 0.15 lb/mmBtu
facilities with a maximum 1000 miles southwest from or 1.5 lb/MWh and a
gross heat input rate of 250 Bennington, VT. Includes compliance schedule. Does
mmBtu/hr or greater and all or parts of IL, IN, KY, not request remedy for OTR
potentially other MI, NC, OH, TN, VA, WV. States because of OTC NOX
unidentified major sources. Also AL GA, IA, MO, SC, WI. MOU.
Also OTR States CT, DE, DC,
MD, MA, NJ, NY, PA.
----------------------------------------------------------------------------------------------------------------
1. Control Remedies Recommended by Petitions
The petitions vary regarding the remedy requested. Several of these
petitions reference the OTC NOX MOU, with regard to control
levels, affected sources, or compliance deadlines. All of the
petitioning States were signatories on the OTC NOX MOU. The
OTC NOX MOU commits these States (and the 4 other signatory
parties--New Jersey, Maryland, Delaware, and the District of Columbia)
to reductions in ozone season NOX emissions from large
utility and industrial combustion sources through implementation of a
phased-in regionwide cap-and-trade program. Specifically, affected
sources in the OTR are fossil fuel-fired boilers and other indirect
heat exchangers with a maximum rated heat input capacity of 250 mmBtu/
hr or greater, and electric generating facilities with a rated output
of 15 megawatts (MW) or greater.
The OTC NOX MOU established emissions reduction
requirements for these sources in the OTR, creating emissions budgets
for 1999 (Phase II) and 2003 (Phase III). (Phase I required the
installation of reasonably available control technology (RACT) by May
1995.) The requirements vary across three control zones in the region:
an inner zone ranging from the District of Columbia metropolitan area
northeast to southeastern New Hampshire (covering all contiguous
moderate and above nonattainment areas), an outer zone ranging out from
the inner zone to western Pennsylvania, and a northern zone which
includes much of northern New York and northern New England (including
most of New Hampshire).
For Phase II of the OTC NOX MOU, which begins in 1999,
sources in the inner zone are subject to emissions reduction
requirements based on the less stringent of an emission rate of 0.20
pounds NOX per million British thermal units of heat input
(lb/mmBtu), or a 65 percent reduction from 1990 NOX levels;
sources in the outer zone are subject to emissions reduction
requirements based on the less stringent of a 0.20 lb/mmBtu rate, or a
55 percent reduction from 1990 NOX levels; and
[[Page 56298]]
sources in the northern zone must adopt RACT. The Phase III
requirements, which may be altered by a ``mid-course correction'' based
on new information such as refined air quality modeling, establish
emissions reduction requirements based on the lesser of a 0.15 lb/mmBtu
rate, or a 75 percent reduction from 1990 levels for sources in both
the inner and outer zones. Northern zone sources would face emissions
reduction requirements based on the lesser of a 0.20 lb/mmBtu rate, or
a 55 percent reduction from 1990 levels. In both Phase II and III in
all three zones, electric generating facilities less than 250 mmBtu/hr
but above 15 MW are subject only to a capping of emissions at 1990
levels for purposes of budget calculation. However, individual States
determine specific allocations for each source from their overall
budget based on independent allocation formulas, and thus the
allocation for these sources will not necessarily reflect this level.
Though all of the petitions request that EPA impose controls in
terms of various emissions limitations, four of the eight petitions--
New York, Connecticut, Pennsylvania, and Maine--also request that a
trading program with a cap, or emissions budget, be established to
implement these controls. Massachusetts, Rhode Island, and Vermont
request that limitations be established for all named sources at 0.15
lb/mmBtu, which is the level of control for electric generating
facilities used to calculate the budget in the proposed NOX
SIP call. Maine requests an emission limitation of 0.15 lb/mmBtu for
named electric utilities, but the OTC NOX MOU level of
control for named steam generating units. New Hampshire requests
emission limitations no less stringent than the Phase III OTC
NOX MOU reductions, and/or 85 percent reductions from the
projected 2007 baseline, and/or an emission rate of 0.15 lb/mmBtu. New
York, Connecticut and Pennsylvania all request that emissions
limitations consistent with the OTC NOX MOU be imposed on
named sources, but Pennsylvania and Connecticut specify the outer zone
requirements; New York does not specify a zone. The level of reduction
requested for 2003 in these three petitions specifying basic OTC
NOX MOU requirements appears to be less stringent than that
in the petitions requesting 0.15 lb/mmBtu, since the remedy requested
would allow sources the option to implement the less stringent of a
percentage reduction or an emission rate. In terms of smaller sources
named by these three States, Pennsylvania's petition appears to seek
somewhat more reductions than the OTC NOX MOU by requiring
the same emission level for electric generating facilities less than
250 mmBtu/hr and greater than 15MW as for larger units. Both
Connecticut and New York appear to be aligned with the OTC
NOX MOU in seeking only a capping of emissions at 1990
levels for these smaller sources.
New York, Connecticut and Pennsylvania recommend a date for the
implementation by sources of control requirements: the OTC
NOX MOU schedule of compliance, including its phased-in
controls and implementation dates of 1999 and 2003. The remaining
States request that EPA establish a schedule of compliance requiring
sources to comply with emission limitations as expeditiously as
practicable.
2. Sources Covered by Petitions
The petitions vary somewhat regarding the universe of sources they
name as significant contributors to their ozone problem. Three of the
petitioning States--New York, Connecticut, and Pennsylvania--name the
same universe of sources covered by the OTC NOX MOU. New
Hampshire names fossil fuel-fired indirect heat exchangers and electric
generating facilities as well, but uses a tonnage applicability cut-off
to include only sources that emit ten tons or more of NOX
per day. Massachusetts and Rhode Island name ``electricity generating
plants'' as the universe requiring controls, without naming a specific
size cutoff. Finally, Vermont names fossil fuel-fired electric
generating facilities of 250 mmBtu or greater.
All of the section 126 petitions, except Pennsylvania's,
Massachusetts' and Rhode Island's, named some States in the OTR as
significant contributors. However, only New Hampshire and Maine
requested relief beyond OTC NOX MOU requirements from
sources in the OTR. The geographic scope of each petition is discussed
in Section II.
Section 126 allows States to petition EPA for a finding against
sources and groups of sources that ``emit'' or ``would emit'' pollution
that significantly contributes to nonattainment problems in the
petitioning State. Thus, a finding could potentially apply not only to
existing sources within a particular source category, but also to
sources that would be built in the future. The EPA believes the current
section 126 petitions are ambiguous as to whether the requested
findings are intended to encompass new sources.
All of the petitions describe the requested finding as against
source categories that ``are emitting'' significantly contributing
levels of NOX. This suggests that perhaps the petitions are
only intended to address existing sources. In addition, four petitions
(Massachusetts, New Hampshire, New York, and Rhode Island) provide
lists of sources in the targeted source categories and do not indicate
that future sources should be added. However, it is notable that, in
defining the universe of covered sources, all of the petitions
identified specific source categories rather than just identifying
specific sources. If emissions from the existing sources in the named
source categories are of concern to the petitioning States, then it
follows that emissions from new sources of the same type would also be
of concern because they would increase the amount of emissions emitted
by the category as a whole.
The recommended control remedies in the petitions may provide the
best insight into whether the petitions are to cover new sources. As
discussed above, all of the petitioning States are signatories on the
OTC NOX MOU. The OTC NOX MOU outlines a cap-and-
trade control program designed to reduce NOX transport from
certain groups of stationary sources in the OTR that are generally the
same types of sources as covered by the petitions. The OTC
NOX MOU program does include controls on both existing and
new sources. The Connecticut, New Hampshire, New York, and Pennsylvania
petitions all request the section 126 control remedy to be consistent
with the OTC NOX MOU. Maine also requests that a control
remedy be implemented through a cap-and-trade program. Further, five of
the eight petitions request that EPA make a section 126 finding against
sources in other OTR States, in addition to sources outside the OTR. It
does not seem reasonable that any of the petitioning States would
determine that both existing and new sources should be controlled for
transport purposes within the OTR through the OTC NOX MOU,
while recommending that outside the OTR only existing sources of the
same type would need to be controlled for transport.
Based on the above information, EPA is proposing to interpret all
eight section 126 petitions to cover both existing and new sources.
Therefore, if any final findings are triggered for source categories in
a particular geographic area, new sources in those source categories
locating in that area would also be subject to the section 126 control
remedy. If any of the petitioning States disagrees with this
interpretation as to its petition, EPA requests that the State
[[Page 56299]]
submit clarifying comments on this issue.
E. Litigation on Rulemaking Schedule
Section 126(b) requires EPA to make the requested finding, or deny
the petition, within 60 days of receipt. It also requires EPA to
provide a public hearing for the petition. In addition, EPA's action
under section 126 is subject to the procedural requirements of section
307(d) of the CAA. One of these requirements is notice-and-comment
rulemaking. Section 307(d) provides for a time extension, under certain
circumstances, for rulemakings subject to that provision. Specifically,
it allows statutory deadlines that require promulgation in less than 6
months from proposal to be extended to not more than 6 months from
proposal to afford the public and the Agency adequate opportunity to
carry out the purposes of section 307(d). In three notices dated
October 22, 1997 (62 FR 55769), November 20, 1997 (62 FR 6194), and
January 2, 1998 (63 FR 26), EPA ultimately extended the deadline for
its requirement to take action on the eight petitions to December 18,
1997.
On February 25, 1998, the eight petitioning States filed a
complaint in the U.S. District Court for the Southern District of New
York to compel EPA to take action on the States' section 126 petitions.
State of Connecticut v. Browner, No. 98-1376. The EPA and the eight
States filed a proposed consent decree that would establish a schedule
for EPA to act on the petitions. Pursuant to CAA section 113(g), the
EPA solicited comments on the proposed consent decree, by notice dated
March 5, 1998 (63 FR 10874). The comment period closed April 6, 1998.
On August 21, 1998, after considering the comments received in the
section 113(g) process, EPA requested the Court to enter a slightly
modified version of the consent decree. Pending the Court's action on
that request, EPA is continuing to follow the schedule in the proposed
consent decree.
The schedule recommended in the proposed consent decree would
require EPA to take final action on at least the technical merits of
the petitions by April 30, 1999. The recommendation would further
permit EPA to structure the final action it would take by April 30,
1999 so as to defer the granting or denial of the petitions to certain
later dates extending to as late as May 1, 2000. The section 126
rulemaking schedule is described in more detail in Section II.A.2. of
this notice.
F. Advance Notice of Proposed Rulemaking on Petitions
In accordance with the schedule in the proposed consent decree, on
April 30, 1998, EPA published in the Federal Register (63 FR 24058) an
advance notice of proposed rulemaking (ANPR) on the section 126
petitions. The ANPR provided EPA's preliminary identification of source
categories named in the petitions that significantly contribute to
nonattainment problems in the petitioning States, provided EPA's
preliminary assessment of the types of recommended emissions
limitations and compliance schedules, provided EPA's preliminary
assessment of the remedy the Agency would propose for approvable
petitions, discussed legal and policy issues raised under section 126,
and outlined the rulemaking schedule for the petitions. The ANPR
solicited comment on all of the issues and preliminary assessments. The
EPA received approximately 50 comments on the ANPR from industry,
States, and environmental groups. These comments covered the full
spectrum of issues discussed in the ANPR and were carefully considered
in the development of today's proposal. The EPA appreciates the efforts
by the commenters to provide early, thoughtful input on this
rulemaking. The EPA will respond to the ANPR comments, if any response
is appropriate, when EPA responds to comments on this proposal. After
reading this proposal, if any commenters on the ANPR believe their
comments are still relevant, there is no need to resubmit the comments
in full. Instead, commenters may simply submit a letter requesting that
EPA consider their ANPR comments for purposes of today's proposal
action. This proposal supersedes any preliminary positions taken in the
ANPR.
II. EPA's Analytical Approach and Proposed Action on Petitions
A. EPA's Proposed Interpretation of Section 126 and Analytical Approach
for Determining Whether to Grant or Deny the Petitions
1. The Appropriate Test Under Section 126
Section 126(b) provides that a State may petition EPA for a finding
that specified sources or groups of sources in other States emit or
would emit air pollutants ``in violation of the prohibition of section
110(a)(2)(D)(ii) of this title or this section.'' \1\ Section 110
(a)(2)(D) provides the requirement that a SIP:
\1\ The cross-reference to section 110(a)(2)(D)(ii) is repeated
3 times in section 126(b). The EPA will refer to these cross-
references in the singular.
---------------------------------------------------------------------------
Contain adequate provisions:
(i) prohibiting, consistent with the provisions of this title,
any source or other type of emissions activity within the State from
emitting any air pollutant in amounts which will--
(I) contribute significantly to nonattainment in, or interfere
with maintenance by, any other State with respect to (any) national
ambient air quality standard, or
(II) interfere with measures required to be included in the
applicable implementation plan for any other State under part C to
prevent significant deterioration of air quality or to protect
visibility,
(ii) insuring compliance with the applicable requirements of
sections 126 and 115 (relating to interstate and international
pollution abatement).
* * * * *
One issue is whether the cross-reference in section 126(b) to
section 110(a)(2)(D)(ii) is valid, or instead should be considered to
be a scrivener's error and be read to refer to section 110(a)(2)(D)(i).
The EPA has offered the latter view in general and preliminary
guidance. See, e.g., 62 FR 55769 (Oct. 22, 1997) and 63 FR 24058 (Apr.
30, 1998).
Some have argued that section 126(b) should be read literally and
that this reading would require EPA to deny the 8 petitions on grounds
that section 126 allows a State to file a petition with EPA only to
force other States to meet the requirements of section 126 itself
(i.e., the requirement in section 126(a) that SIPs include provisions
to require new and modified major stationary sources to give
preconstruction notification to nearby States under certain
circumstances). \2\
---------------------------------------------------------------------------
\2\ See Letter from Henry V. Nickel, et al., Counsel for the
Utility Air Regulatory Group, to Carol M. Browner, Administrator,
U.S. EPA, November 21, 1997 (UARG Letter); Letter from Betty D.
Montgomery, Attorney General of Ohio et. al., to Richard Wilson,
Acting Assistant Administrator for Air & Radiation, U.S. EPA,
November 5, 1997 (letters included in the docket to this
rulemaking).
---------------------------------------------------------------------------
In the alternative, some have argued that, if in fact there is a
scrivener's error, the proper cross-reference should be to section
110(a)(2)(D)(i)(II), and not section 110(a)(2)(d)(i)(I). UARG letter.
The effect of this reading would be to limit section 126 petitions to
cases in which the upwind sources are adversely affecting clean areas
under the prevention of significant deterioration requirements of part
C of title I of the CAA, or visibility.
The EPA believes that there is a scrivener's error in section 126.
Furthermore, EPA disagrees that the scrivener's error is a misreference
to section 110(a)(2)(D)(i)(II). In this
[[Page 56300]]
proposed action, EPA takes the position that the reference in section
126(b) to section 110(a)(2)(D)(ii) is a drafting error and that
Congress intended to reference section 110(a)(2)(D)(i). The merit of
this statutory interpretation is apparent on several levels. First, the
reference to ``the prohibition of section 110(a)(2)(D)(ii)'' is
ambiguous at best, and arguably nonsensical, since section
110(a)(2)(D)(ii) contains no prohibition, yet 110(a)(2)(D)(i) does.
Second, the statutory cross reference contained in section 126(b), if
taken on its face, would render section 126(b) largely meaningless.
Finally, the legislative history of the CAA Amendments supports this
interpretation. The EPA's interpretation is consistent with the reading
of the CAA prior to the 1990 Amendments and Congress expressed no
indication that it meant to substantively revise this provision of the
statute at the time it administratively renumbered the provision.
The EPA also does not believe that the reference to section
110(a)(2)(D)(ii) is a mistaken cross-reference to section
110(a)(2)(D)(i)(II). Such a cross-reference would limit the
availability of section 126 to the prevention of significant
deterioration and visibility provisions of section 110(a)(2)(D)(i), a
severe limitation for which there is no indication in the legislative
history.
Section 126(b) authorizes the EPA to find that any major source or
group of stationary sources emits or would emit any air pollutant ``in
violation of the prohibition of section (a)(2)(D)(ii) of this title or
this section'' (emphasis added). However, section 110(a)(2)(D)(ii)
contains no prohibition. Rather, it provides that SIPs must ``contain
adequate provisions insuring compliance with'' statutory sections
relating to interstate and international pollution abatement.
By contrast, section 110(a)(2)(D)(i)--the provision that EPA
believes Congress intended to cross-reference in section 126(b)--does
contain a prohibition. It requires that SIPs contain adequate
provisions ``prohibiting'' any source or other type of emissions
activity within the State from emitting any air pollutant in amounts
that, among other things, will contribute significantly to
nonattainment in, or interfere with maintenance by, another State with
respect to the NAAQS. Thus, the textual interplay between sections
126(b) and 110(a)(2)(D) provides strong evidence that the CAA contains
``a simple scrivener's error, a mistake made by someone unfamiliar with
the law's object and design.'' In re Chateaugay Corp., 89 F.3d 942, 954
(2d Cir. 1996) (holding that courts are empowered to correct an
erroneous statutory cross-reference that inadvertently results from
legislative changes (quoting United States Nat'l Bank v. Independent
Ins. Agents, 508 U.S. 439, 462 (1993)); see also, United States v.
Gibson, 770 F.2d 306, 308 (2d Cir. 1985) (per curiam) (correcting
ambiguity in criminal fraud statute that resulted from the error of a
scrivener in using the word `and' rather than `or' when codifying the
statute).
As further support, reading section 126(b) as cross-referencing
section 110(a)(2)(D)(ii) essentially renders that provision redundant
and meaningless. Section 126 allows a party to petition EPA with
respect to a ``violation of the prohibition in section 110(a)(2)(D)(ii)
or this section.'' Section 110(a)(2)(D)(ii) cross-references back to
section 126, as well as to section 115. To the extent section
110(a)(2)(D)(ii) cross-references back to section 126, the statute is
redundant. Reading the two provisions together, section 126 would
provide an opportunity for parties to file a petition claiming that a
SIP violates the prohibition of section 110(a)(2)(D)(ii) (i.e., section
126) or this section (i.e., section 126).
Moreover, to the extent section 110(a)(2)(D)(ii) references section
115, the provision is meaningless. There is no relief that can be
provided under section 126. Sections 126 and 115 create separate
processes for different parties to petition the Agency for a finding
that SIP is inadequate. Under section 115, the Administrator may issue
a SIP Call to a State based on a request by an international agency or
the Secretary of State that an air pollutant or pollutants emitted in
the United States ``cause or contribute to air pollution which may
reasonably be anticipated to endanger public health or welfare in a
foreign country.'' In contrast, only ``States'' or ``political
subdivisions''--entities under the jurisdiction of the United States--
may request relief under section 126. If Congress intended States or
political subdivisions in the United States with the opportunity to
seek relief for pollution transported to foreign countries, Congress
could have provided so in a much clearer fashion in section 115. It is
highly doubtful that Congress would have used such a cryptic reference
to grant political entities within the United States the power to
address pollution being transported out of the country from other
States.
Finally, EPA's interpretation that there is a scrivener's error and
that the reference should be to section 110(a)(2)(D)(i), fits with the
legislative history on this provision. Courts ``recognize that during
the drafting process an error may creep in,'' and that ``statutes are
not drafted with mathematical precision, and should be construed with
some insight into Congress' purpose at the time of the enactment.'' In
re Chateaugay Corp., 89 F.3d at 953. Here, the legislative history, as
set forth in the Senate Report and the House Conference Report
regarding the 1990 CAA Amendments, provides additional, persuasive
evidence that section 126(b)'s cross-reference to section
110(a)(2)(D)(ii) is erroneous. See Pierpont v. Barnes, 94 F.3d 813, 817
(2d Cir. 1996) (committee reports are ``particularly good indicator(s)
of congressional intent,'') cert. denied, 117 S. Ct. 1691 (1997).
To start, the Senate Report observes that the CAA, prior to the
1990 amendments, allowed section 126 to be used only for violations of
section 110(a)(2)(E)(i), which ``relate(d) to the preparation of
SIP(s).'' S. Rep. No. 101-228, 101st Cong., 2d Sess. 75 (1989),
reprinted in 1990 U.S.C.C.A.N. 3385, 3461. Thus, under section 126(b)'s
pre-1990 version, ``a State being injured by another State's pollution
(could) file a complaint about the offending State's SIP, but not the
pollution itself.'' Id. at 76, 1990 U.S.C.C.A.N. 3385, 3462. Notably,
the Senate Report makes no mention of changing section 126(b)'s cross-
reference to section 110(a)(2)(E)(i)-- nor would it, since section
110(a)(2)(E)(i) had defined the SIP violation historically redressable
under section 126(b). Because the amendments simply revised the text of
former section 110(a)(2)(E)(i) and then renumbered it as section
110(a)(2)(D)(i), compare 42 U.S.C.A. 7410(a)(2)(E)(i) (1990) with 42
U.S.C.A. 7410(a)(2)(D)(i) (1995), \3\ there is substantial reason to
believe that section 126(b)'s current cross-reference to section
110(a)(2)(D)(ii) is mistaken.
---------------------------------------------------------------------------
\3\ The 1990 CAA Amendments revised section 110(a)(2)(D) by
dropping certain provisions not relevant here, and incorporating
other provisions previously contained in section 110(a)(2)(E). See
CAA Amendments of 1990, Pub. L. 101-549, 101(b), 104 Stat.
2404(1990); S. Rep. No. 101-228, 101st Cong., 2d Sess. 20 (1989),
reprinted in 1990 U.S.C.C.A.N. 3385, 3406.
---------------------------------------------------------------------------
Indeed, ``[w]hen Congress revises and renumbers existing laws, a
court should not infer any legislative aim to change the law's effect
unless such intention is clearly expressed.'' In re Chateaugay Corp.,
89 F.3d at 953 (citing Finley v. United States, 490 U.S. 545, 554
(1989)). Far from expressing a clear intent to effectuate the
fundamental change in law that would result from section 126(b)'s new
cross-reference to section 110(a)(2)(D)(ii), the legislative history
for the 1990 CAA Amendments actually
[[Page 56301]]
demonstrates a contrary purpose. According to the House Conference
Report, these amendments sought to ``enhance the enforcement authority
of the Federal government under the CAA, ``including ``EPA enforcement
authority regarding violations of State Implementation Plans.'' H. Rep.
No. 101-952, 101st Cong. 2d Sess. 347 (1990), reprinted in, 1990
U.S.C.C.A.N. 3385, 3879. As noted above, however, the ambiguous change
in section 126(b)'s cross-reference would apparently divest the EPA of
its former jurisdiction to redress--via the section 126 petition
process--SIP violations regarding interstate pollution. See 42 U.S.C.A.
7426(b) (1990) (authorizing EPA to adjudicate petitions alleging
violations of SIP requirements that are now substantially incorporated
into section 110(a)(2)(D)(i)). Given the lack of any legislative
history that would support such a significant shift in policy, and
considering Congress' stated desire to enhance the EPA's SIP
enforcement authority, this contradictory result is highly suspect. See
In re Chateaugay Corp., 89 F.3d at 953 (``where it appears plain that
an error in drafting has occurred, so that a literal construction would
make a dramatic change in long-standing law, it is both sensible and
permissible for judges to consider, in conjunction with other factors,
Congress' complete silence on the literal effect of the change.'') \4\
---------------------------------------------------------------------------
\4\ The Senate Report also expresses a congressional desire to
promote the EPA's enforcement activity, not to constrain it. As the
Senate committee observed, prior to 1990, the CAA ``allow(ed) a
State to file a petition with the Administrator complaining of
interstate air pollution (in violation of section 110(a)(2)(E)(i)),
but not to file a lawsuit for violation of section 126. The
amendment to section 304, (however,) allow(ed) a State, and
citizens, to sue in Federal district court for violation of section
126.'' S. Rep. No. 101-228, 101st Cong., 2d Sess. 76 (1989),
reprinted in 1990 U.S.C.C.A.N. 3385,3462. That Congress created a
judicial mechanism by which to compel the EPA to respond to section
126 petitions is instructive. Because this legislative action is
clearly inconsistent with any construction of the CAA that divests
the EPA of its authority to enforce the very SIP requirements
formerly contained in section 110(a)(2)(E)(i), it casts serious
doubt upon the validity of section 126(b)'s amended cross-reference
to section 110(a)(2)(D)(ii).
---------------------------------------------------------------------------
The EPA believes that its proposed interpretation is permissible
because it resolves the ambiguity in the interplay between sections 126
and 110(a)(2)(D) in a manner that harmonizes and gives meaning to all
of their provisions and reasonably accommodates the purposes of the
provisions. See Chevron, U.S.A., Inc. v. Natural Resources Defense
Council, 467 U.S. 837, 844 (1984).
2. EPA's Analytical Approach for Determining Whether To Grant or Deny
the Petitions
a. EPA's Interpretation of Significant Contribution under Section
110. The EPA's final NOX SIP call rule sets forth EPA's
interpretations of section 110(a)(2)(D)(i)(I) in the context of
regional transport of ozone. The EPA proposes and is seeking comment on
retaining and employing those interpretations for purposes of
determining, under section 126(b), whether any of the sources and
source categories named in the petitions ``emits or would emit any air
pollutant in violation of the prohibition'' of section
110(a)(2)(D)(i)(I). For purposes of this proposal, EPA incorporates
into the proposal, by reference, the explanation of those
interpretations, as well as all of the supporting rationale and
technical support for them. See, especially, Section II of the preamble
to the final NOX SIP call rule. Each of these steps is
discussed in the remainder of Section II of this notice.
b. Applying EPA's Section 110 Interpretation of ``Significant
Contribution'' and ``Interference'' under Section 126. The EPA proposes
to apply its interpretation of section 110(a)(2)(D)(i)(I) to determine
which if any NOX sources or source categories named in the
section 126 petitions ``emits or would emit any air pollutant in
violation of the prohibition'' in section 110(a)(2)(D)(i)(I). The EPA
believes that its interpretations in the context of section 110 apply
with relative ease to its decision under section 126, with one
additional step noted below.
First, in acting on the section 126 petitions, EPA proposes to use
the linkages it drew in the NOX SIP call rulemaking between
specific upwind States and nonattainment and maintenance problems in
specific downwind States. The EPA is seeking comment on and will
carefully evaluate these linkages, and in particular, the linkages EPA
has made between some of the more distant States, such as the linkages
made between Alabama and Pennsylvania and Missouri and Pennsylvania.
In the next step, EPA determines which of that ``covered'' upwind
State's major stationary NOX sources that are named in the
downwind State's petition may emit in violation of the prohibition in
section 110(a)(2)(D)(i) because they emit in amounts that contribute
significantly to nonattainment in, or interfere with maintenance by,
the petitioning State. For this, EPA proposes to use its analysis of
highly cost-effective measures in the NOX SIP call rule to
determine which of the covered upwind States' major stationary
NOX sources named in the petitions emit NOX in
amounts that contribute significantly. Thus, if EPA identified highly
cost-effective measures for a particular source category in the
NOX SIP call, then EPA proposes in this notice to make an
affirmative ``technical determination''--i.e., a finding that any
source in that category located in a covered upwind State emits in
amounts that will contribute significantly to nonattainment in, or
interfere with maintenance by, the petitioning State(s) linked to that
upwind State.
This methodology applies both to a petition that names sources in
the entire contributing upwind State and to a petition that names
sources in only a small portion of an upwind contributing State. As
described more fully in the NOX SIP call rulemaking, the
only viable solution to ozone nonattainment is to apply pollution-
reduction measures to a large collection of sources in many States,
each one of which by itself may produce a small or perhaps immeasurable
impact on the nonattainment problem for a particular area. Under this
collective contribution approach, if EPA determines that the full set
of NOX sources in an upwind State significantly contributes
to nonattainment in, or interferes with maintenance by, a particular
downwind State, then any NOX sources in the upwind State
that can apply highly cost-effective control measures must be
considered part of the solution to those downwind problems and
therefore contributes to downwind nonattainment.
c. Emitting ``In Violation of the Prohibition'' in Section 110--the
Decision Whether to Grant or Deny Each Petition. As noted above, the
test under EPA's interpretation of section 126 is whether the sources
named in the petitions emit in violation of the section 110(a)(2)(D)(i)
prohibition. That prohibition, however, by the terms of section
110(a)(2)(D)(i), should be included in SIP provisions. The EPA has now
issued its NOX SIP call rule under that section, and has set
forth a track that upwind States must follow to satisfy its terms.
Under the NOX SIP call, EPA has given the covered States
until September 1999 to submit SIPs satisfying the rule, and has
specified that those SIPs must prohibit the NOX emissions
that contribute significantly by a date no later than May 1, 2003. By
that rule, EPA has established emissions budgets for each State, which
reflect elimination of the significant contribution of NOX
emissions within
[[Page 56302]]
the State. The EPA has further established by rule May 1, 2003 as the
final date by which all measures to meet that budget must be
implemented. In addition, EPA has proposed a FIP that could be
promulgated if a State fails to respond adequately to the
NOX SIP call.
Section 126 calls for relief where EPA finds that sources are
emitting ``in violation of the prohibition'' of section
110(a)(2)(D)(i). The EPA believes that it is sensible to interpret this
language in light of the ongoing action of both States and EPA. Thus,
so long as EPA and States (and ultimately the sources the State
determines to regulate) are on track to meet the goals of the
NOX SIP call, EPA believes it is appropriate to determine
that sources are not emitting in violation of the prohibition in
section 110(a)(2)(D)(i) for purposes of section 126(b). States and EPA
will be on track if States timely submit a complete and approvable SIP
and EPA acts promptly to approve the plan. In the alternative, if a
State fails to submit in a timely manner a complete or approvable plan,
efforts will be on track so long as EPA promulgates a FIP. The EPA
further believes this approach is sensible because an alternative
interpretation, which would result in a section 126 remedy going into
effect despite timely action by States and EPA in response to the
NOX SIP call, would lead to unnecessary and duplicative
efforts. Such an approach would not only waste Agency resources, but
could ultimately undermine efforts to reduce interstate transport by
adding confusion to the process.
Based on this interpretation of the language in section 126, EPA
has considered an alternative form of final action on the section 126
petitions that takes into account whether the State and/or EPA is on
track to institute a satisfactory plan in response to the
NOX SIP call rule.
As described in Section I above, the proposed consent decree would
require EPA to take a final action on the section 126 petitions by
April 30, 1999. In formulating the proposed consent decree, EPA
developed an alternative approach that it believes would harmonize the
section 126 and 110 actions. Specifically, paragraph 5.b. and c. state
that:
b. Unless EPA takes the final action described in paragraph 6,
as to each individual petition, EPA's final action will be to--
(i) Grant the requested finding, in whole or part; and/or
(ii) Deny the petition, in whole or part.
c. Unless EPA denies a petition in whole, its final action will
include promulgation of a remedy under CAA section 126(c) for
sources to the extent that a requested finding is granted with
respect to those sources.
Then paragraph 6 states:
6. EPA shall be deemed to have complied with the requirements of
Paragraph 5(a) if it instead takes a final action by April 30, 1999,
that--
a. makes an affirmative determination concerning the technical
components of the ``contribute significantly to nonattainment'' or
``interfere with maintenance'' tests under CAA section
110(a)(2)(D)(i), 42 U.S.C. section 7410(a)(2)(D)(i);
b. further provides that:
(i) If EPA does not issue a proposed approval of the relevant
Upwind State's SIP revision (submitted in response to the
NOX SIP call) by November 30, 1999, then the finding will
be deemed to be granted as of November 30, 1999, without any further
action by EPA;
(ii) If EPA issues a proposed approval of said SIP revision by
November 30, 1999, but does not issue a final approval of said SIP
revision by May 1, 2000, then the finding will be deemed to be
granted as of May 1, 2000, without any further action by EPA;
(iii) If EPA issues a final approval of said SIP revision by May
1, 2000, EPA must take any and all further actions, if necessary to
complete its action under section 126, no later than May 1, 2000;
and
c. Promulgates a remedy under CAA section 126(c) for sources to
the extent that an affirmative determination is made with respect to
those sources.
The EPA believes that the alternative form of final action set
forth in Paragraph 6 of the proposed decree best harmonizes sections
110(a)(2)(D)(i)(I) and 126. The EPA believes that sources in an upwind
State should not be considered to be emitting an air pollutant in
violation of the section 110 prohibition, and hence EPA should not
grant a petition naming such sources, if the State is adhering to the
NOX SIP call rule's schedule for submission of an approvable
SIP revision, and EPA is acting speedily to approve the SIP--or,
failing that, if EPA has promulgated a FIP for the State. After all, if
EPA's rule provides a particular path for the development of a plan
calling on sources to reduce interstate pollution by May 1, 2003, and
under that rule either the upwind State or EPA is moving forward to
develop, take action on or promulgate a satisfactory plan meeting that
rule and achieving attainment as expeditiously as practicable, it would
be difficult to conclude that an affected source in the upwind State
``emits or would emit in violation'' of the prohibition that the plan
is not yet required to contain.5
---------------------------------------------------------------------------
\5\ Moreover there does appear to be tension between section
110(a)(2)(D), which does not establish the timing as to when the SIP
prohibition needs to be effective against sources (i.e., when
sources need to implement controls to reduce emissions) and the
timing in section 126, which requires implementation no later than 3
years following a section 126(b) determination. The EPA does not
believe that Congress intended section 126 to be used to shorten
timeframes for action that EPA has previously determined are
approvable for purposes of eliminating significant contribution to
nonattainment areas in other States.
---------------------------------------------------------------------------
For these reasons, EPA proposes to follow the alternative described
in Paragraph 6 of the proposed decree. Thus, EPA proposes to structure
its final action to contain: (1) A series of ``technical
determinations'' as to which sources in which States named in the
petitions would emit in violation of the section 110 prohibition if the
State or EPA were to fall off track in putting a timely and
satisfactory plan in place;
(2) determinations that the petitions will automatically be deemed
granted or denied on the basis of the events set forth in Paragraph 6;
and (3) the remedial requirements that will apply to the sources
receiving affirmative technical determinations if a petition naming
those sources is ultimately deemed granted.
The EPA believes that the timeframes and triggers in Paragraph 6
are reasonable and feasible, and the Agency intends to execute them
timely. For States that make a timely SIP submission, EPA believes it
is feasible for the Agency to issue a proposed rule within 60 days of
the submission deadline. Under the CAA, EPA is provided 60 days--but no
more than 6 months--in which to affirmatively determine whether a
submission is complete.
If EPA does not make an affirmative completeness determination, the
submission is deemed complete. Once a submission is affirmatively found
to be or is deemed complete, the CAA then provides EPA with 12 months
to approve or disapprove the submission. Thus, at maximum, the CAA
provides EPA with 18 months to approve or disapprove a SIP submission.
The EPA is proposing a 7-month period to act on submissions in response
to the NOX SIP call. While this period is shorter than the
maximum period contemplated under the CAA, EPA believes that it is
feasible and appropriate in the present circumstances. The EPA
anticipates that the EPA Regional Offices will be working with States
as States draft rules in response to the NOX SIP call and
will be well prepared to issue a proposed determination within 60 days
of the required submission date. Further, in light of EPA's work with
the States in development of their plans, the 5-month period between
proposal and final action should allow the Agency ample time to review
any comments and to
[[Page 56303]]
prepare a final action. An additional benefit of this schedule for EPA
action is that it will provide sources with certainty about the
applicable requirements well before the latest implementation date that
is permitted by the NOX SIP call. Moreover, if the State
fails to submit an approvable plan, EPA will be well positioned to
promulgate a FIP for the State, based on the FIP proposal that the
Agency is issuing separately. It is important to achieve the
NOX reductions necessary to protect public health and to
attain the NAAQS as expeditiously as practicable. Therefore, where a
State or EPA has failed to meet a deadline it will be critical to have
the section 126 remedy go into effect as soon as possible thereafter in
order to ensure that the NOX emission reductions are
achieved as soon as practicable, which in the NOX SIP call
EPA has determined to be May 1, 2003. The schedule EPA has proposed to
enter into is intended to ensure that either the FIP or the 126 remedy
goes into effect in order to achieve the NOX emission
reductions by May 1, 2003.
B. Weight of Evidence Determination of Named Upwind States
As discussed above, in acting on the section 126 petitions EPA
proposes to rely on the conclusions it drew in the final NOX
SIP call rulemaking to determine whether the emissions in named upwind
States contribute significantly to the 1-hour and 8-hour nonattainment
and maintenance problems in the petitioning States. To evaluate the air
quality impacts in the final NOX SIP call rulemaking, EPA
used a weight-of-evidence approach involving three sets of modeling
information: The State-by-State UAM-V zero-out modeling, the CAMx
source apportionment modeling, and the OTAG subregional modeling and
other information such as emission density and transport
distance.6 A number of ``metrics'' (i.e., measures of ozone
contributions) were used to assess the air quality effects from several
perspectives of contribution from sources in various upwind States. The
technical details of the modeling information and metrics are described
in the final NOX SIP call rulemaking.
The named upwind States which are linked as containing sources that
are significant contributors to each petitioning State in the final
NOX SIP call rulemaking are listed in Tables II-1 for the 1-
hour NAAQS and Table II-2 for the 8-hour NAAQS. The information that
EPA relied on in making these significance linkages is provided in the
final NOX SIP call rulemaking. All of the information that
is contained in the docket of the NOX SIP call rulemaking is
incorporated by reference into this proposal. The EPA concluded from
all of this information that the following 20 jurisdictions contain
sources that make a significant contribution to nonattainment in, or
interfere with maintenance by, one or more petitioning States under the
1-hour and/or the 8-hour NAAQS:
Alabama
Connecticut
Delaware
District of Columbia
Illinois
Indiana
Kentucky
Maryland
Massachusetts
Michigan
Missouri
New Jersey
New York
North Carolina
Ohio
Pennsylvania
Rhode Island
Tennessee
Virginia
West Virginia
Table II-1.--Named Upwind States which Contain Sources that Contribute
Significantly to 1-Hr Nonattainment in Petitioning States
------------------------------------------------------------------------
Petitioning State
(nonattainment area) Named upwind States
------------------------------------------------------------------------
New York..................... DE, DC, IN, KY, MD, MI, NC, NJ, OH, PA,
VA, WV.
Connecticut.................. DE, DC, IN,* KY,* MD, MI,, NC,, NJ, NY,
OH, PA, VA, WV.
Pennsylvania................. NC, OH, VA, WV.
Massachusetts................ OH, WV.
Rhode Island................. OH, WV.
Maine........................ CT, DE, DC, MD, MA, NJ, NY, PA, RI.
New Hampshire................ CT, DE,* DC,* MA, MD,* NJ, NY, PA, RI,
VA.*
Vermont...................... None.
------------------------------------------
Total.................... CT, DE, DC, IN, KY, MA, MD, MI, NC, NJ,
NY, OH, PA, RI, VA, WV.
------------------------------------------------------------------------
*Upwind States marked with an asterisk are included in the table because
they contribute to an interstate nonattainment area that includes part
of the petitioning State. Part of New Hampshire is included in the
Boston/Portsmouth nonattainment area; part of Connecticut is included
in the New York City nonattainment area.
Table II-2. Named Upwind States which Contain Sources that Contribute
Significantly to 8-Hr Nonattainment in Petitioning States
------------------------------------------------------------------------
Petitioning State Named upwind States
------------------------------------------------------------------------
Pennsylvania................. AL, IL, IN, KY, MI, MO, NC, OH, TN, VA,
WV.
Massachusetts................ OH, WV.
Vermont...................... None.
------------------------------------------
Total.................... AL, IL, IN, KY, MI, MO, NC, OH, TN, VA,
WV.
------------------------------------------------------------------------
The EPA also concluded that sources in the following 11 States do
not make a significant contribution to nonattainment in, or interfere
with maintenance by, any of the petitioning States under the 1-hour
and/or the 8-hour NAAQS:
---------------------------------------------------------------------------
\6\ The UAM-V is the Variable-grid Urban Airshed Model. The CAMx
is the Comprehensive Air Quality Model With Extensions.
---------------------------------------------------------------------------
[[Page 56304]]
Arkansas
Georgia
Iowa
Louisiana
Maine
Minnesota
Mississippi
New Hampshire
South Carolina
Wisconsin
Vermont
As discussed below, in Section II.F., EPA does not have the same
level of information available regarding the named States of Maine, New
Hampshire, and Vermont as it has for the other States named in
petitions. Therefore, EPA intends to conduct further analyses on these
three States. If the additional analyses show that sources in any of
these States significantly contribute to a relevant petitioning State,
EPA will issue a supplemental notice of proposed rulemaking based on
the new information.
C. Cost Effectiveness of Emissions Reductions
As described in Section II.A, above, the second prong of the
significant-contribution interpretation that EPA applied in the
NOX SIP call rule, and that EPA proposes to apply for
purposes of this proposal, is the extent to which ``highly cost-
effective'' NOX control measures are available for the types
of stationary sources named in the petitions.7.
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\7\ As discussed in this section, the highly cost-effective
NOX controls happen to apply only to major stationary
sources. Under section 126, EPA can make a finding for ``any major
source or group of stationary sources.'' In other words, even if not
all sources subject to this action were major, they would be part of
a group of stationary sources that contribute significantly to
nonattainment and hence could potentially be subject to finding.
---------------------------------------------------------------------------
As in the NOX SIP call rule, the EPA proposes to select
these highly cost-effective measures by examining the technological
feasibility, administrative feasibility and cost-per-ton-reduced of
various multistate ozone season NOX control measures and
determining what measures feasibly achieve the greatest NOX
reductions and are among the most reasonable in light of other actions
taken by EPA and States to control NOX.\7\
---------------------------------------------------------------------------
\7\ As discussed in this section, the highly cost-effective
NOX controls happen to apply only to major stationary
sources. Under section 126, EPA can make a finding for ``any major
source or group of stationary sources.'' In other words, even if not
all sources subject to this action were major, they would be part of
a group of stationary sources that contribute significantly to
nonattainment and hence could potentially be subject to a finding.
---------------------------------------------------------------------------
1. What NOX Controls Are Highly Cost Effective
The first step in the cost-effectiveness process was to identify
the types of sources named in the various petitions. The petitioning
States have identified the source categories that they believe
significantly impact their ability to achieve attainment of the ozone
standard. These categories are listed in Table I-1 earlier in this
notice. The EPA has determined that the named source categories can be
combined into one general category--fossil fuel-fired indirect heat
exchangers. This term applies to boilers and turbines used for the
production of steam, electricity, and in some cases mechanical work,
and to process heaters. To assure equity among the various
subcategories of such sources and the industries they represent, EPA
considered the cost effectiveness of controls for each subcategory
separately throughout the affected 20-jurisdiction region described in
Section II.B above. Sources are combined into a common subcategory if
they serve the same general industry (e.g., boilers and turbines that
are used by the electricity generation industry are combined in the
same subcategory). The EPA believes that this categorization better
reflects the industrial sectors served. Thereby, the EPA split the
population of indirect heat exchanges into four subcategories,
consistent with the approach EPA took in the final NOX SIP
call: (1) A subcategory of boilers and turbines serving generators
greater than 25 MWe that produce electricity for sale to the grid
(``large EGUs''); (2) a subcategory of boilers and turbines with a heat
input greater than 250 mmBtu/hr that exclusively generate steam and/or
mechanical work (e.g., provide energy to an industrial pump), or
produce electricity for internal use only and not for sale (``large
non-EGUs''); (3) a subcategory of process heaters with a heat input
greater than 250 mmBtu/hr (``large process heaters''); and (4) a
subcategory of smaller indirect heat exchangers, i.e., all such sources
not included in the first three subcategories (``small sources'').
As mentioned above, in evaluating the cost effectiveness of
NOX controls for indirect heat exchangers, the EPA has taken
the same approach as that taken in the final NOX SIP call.
See generally, Section II.D of the preamble to the final NOX
SIP call rule. In short, for each subcategory, the amounts of emissions
that cause subcategories in the covered upwind States to contribute
significantly to a petitioning State's nonattainment were determined
based on the application of NOX controls that achieve the
greatest feasible emissions reduction while still falling within a
cost-per-ton-reduced range that EPA considers to be highly cost
effective. The NOX controls for this rulemaking were
considered highly cost effective for the purposes of reducing ozone
transport to the extent they achieve the greatest feasible emissions
reduction but still cost no more than $2,000 per ton of ozone season
NOX emissions removed (in 1990 dollars), on average, for
each subcategory. The discussion below further describes the basis for
this cost amount and the techniques used for each subcategory. The EPA
believes that certain controls that cost more than $2,000 per ton of
NOX reduced are reasonably cost effective in reducing ozone
transport or in achieving attainment with the ozone NAAQS in specific
nonattainment areas; however, EPA proposes to base the significant-
contribution determination on only highly cost-effective reductions. In
addition, as discussed further below, in determining whether to assume
reductions from the small source subcategory, EPA considered
administrative efficiency in evaluating this subcategory.
More specifically, to determine what level of control can be
considered highly cost effective, EPA considered other recently
undertaken or planned NOX control measures. Table II-3
provides a reference list of measures that EPA and States have
undertaken to reduce NOX and their average annual costs per
ton of NOX reduced. These measures cost up to $2,000 per
ton. With few exceptions, the average cost effectiveness of these
measures is representative of the average cost effectiveness of the
types of controls EPA and States have needed to adopt most recently,
since their previous planning efforts have already taken advantage of
opportunities for even cheaper controls. The measures listed in Table
II-3 generally represent the average costs (i.e., middle of the range
of costs) that the nation has been willing to bear recently to reduce
NOX. The EPA believes that the cost effectiveness of
measures that it or States have adopted, or proposed to adopt, forms a
good reference point for determining which of the available additional
NOX control measures are among the most cost-effective
measures that can be implemented by the sources considered in today's
action.
[[Page 56305]]
Table II-3.--Average Cost Effectiveness of NOX Control Measures Recently
Undertaken For Stationary Sources
[1990 $]
------------------------------------------------------------------------
Control measure Cost per ton of NOX removed
------------------------------------------------------------------------
NOX RACT.................................. 150-1,300.
Final NOX SIP call........................ Up to 2,000.
State Implementation of the Ozone 950-1,600.
Transport Commission Memorandum of
Understanding.
New Source Performance Standards for 1,290.
Fossil Steam Electric Generation Units.
New Source Performance Standards for 1,790.
Industrial Boilers.
------------------------------------------------------------------------
The EPA notes that there are also a number of less expensive
measures recently undertaken by the Agency to reduce NOX
emission levels that do not appear in Table II-3. These actions include
the title IV NOX reduction program. Though these actions are
very cost effective, the Agency is focusing on what other measures
exist, at a potentially higher (though still not the highest
reasonable) cost-effectiveness value, that can further reduce
NOX emissions. Table II-3 is thereby useful as a reference
of the next higher level of NOX reduction cost effectiveness
that the Agency considers among the most reasonable to undertake. As a
result, the Agency proposes that NOX controls that can
feasibly be achieved and have an average subcategory-specific cost
effectiveness less than $2,000 per ton of NOX removed be
considered highly cost effective. The subcategories that EPA proposes
to control are those major stationary sources in the named categories
for which EPA finds that these highly cost-effective controls are
available.
2. Determining the Cost Effectiveness of NOX Controls
In an effort to determine what, if any, highly cost-effective mix
of controls is available for each subcategory (i.e., large EGUs, large
non-EGUs, large process heaters, and small sources) the Agency
considered the average cost effectiveness of alternative levels of
controls for each subcategory as described in the final NOX
SIP call. That analysis is summarized here. The average cost
effectiveness of the controls was calculated from a baseline level that
included all currently applicable Federal or State NOX
control measures for each subcategory. The baseline did not include
Phase II and Phase III of the OTC NOX MOU since those
measures are not federally required and they have not yet been adopted
by all the involved States; 8 if the MOU were included in
the baseline, the overall costs would be lower. In determining the cost
of NOX reductions from large EGUs, EPA assumed an emissions
trading system. As discussed in the final NOX SIP call, EPA
evaluated and compared the likely air quality impacts both with and
without a multistate NOX emissions trading system for
electricity generating sources. This analysis shows that a multistate
trading program causes no significant adverse air quality impacts.
Because such a program would result in significant cost savings, EPA's
cost-effectiveness determination for large electricity generating
boilers and turbines (i.e., the majority of the core group of sources
in the trading program) assumes sources will participate in a
multistate trading program.9 For non-EGU sources, EPA used a
least cost method which is equivalent to an assumption of an intrastate
trading program. Inclusion of these sources in a multistate trading
program would provide further cost savings.
---------------------------------------------------------------------------
\8\ However, in the Regulatory Analysis of the final
NOX SIP call, EPA evaluates the economic impact of
including the MOU in the baseline for the electric power industry.
\9\ The EPA envisions sources in States that are covered by (1)
the section 110 NOX SIP call, (2) the section 110 FIP, or
(3) section 126, to be able to trade among each other.
---------------------------------------------------------------------------
Table II-4 summarizes the control options investigated for each
subcategory covered by the petitions and the resulting average,
multistate cost effectiveness as presented in EPA's final
NOX SIP call. Note that these cost figures are obtained by
performing the analysis over the 23-jurisdiction NOX SIP
call area. The values will be only slightly different for the States
covered by this action; those differences are insignificant for
purposes of identifying highly cost-effective controls. Additionally,
the cost effectiveness analysis included a consideration of each
subcategory's growth, including new sources. Thus, the control levels
arrived at are cost-effective for new sources also.
Table II-4.--Average Cost Effectiveness of Options Analyzed \10\
[1990 dollars in 2007]
----------------------------------------------------------------------------------------------------------------
Average cost- Average cost-
effectiveness ($/ effectiveness ($/
Subcategory ozone season ton) ozone season ton) Average cost-effectiveness ($/ozone season
for each control for each control ton) for each control option
option option
----------------------------------------------------------------------------------------------------------------
Large EGUs.................... 0.20 lb/mmBtu.... 0.15 lb/mmBtu.... 0.12 lb/mmBtu.
$1,263........... $1,468........... $1,760.
Large Non-EGUs................ 50% reduction.... 60% reduction.... 70% reduction.
$1,235........... $1,477........... $2,155.
Process Heaters............... $3,000/ton $4,000/ton $5,000/ton maximum per source.
maximum per maximum per $2,891.
source. source.
$2,859........... $2,891...........
----------------------------------------------------------------------------------------------------------------
\10\ The cost-effectiveness values in Table II-4 are multistate averages. In the case of large EGUs the cost-
effectiveness values represent reductions beyond those required by title IV or title I RACT, where applicable.
For large non-EGUs and process heaters, the cost-effectiveness values represent reductions from uncontrolled
levels.
[[Page 56306]]
The following discussion explains the controls determined by EPA to
be highly cost-effective for each subcategory.
i. Large EGUs. For large EGUs, the control level was determined by
applying a uniform NOX emissions rate across the 20
jurisdictions potentially subject to section 126 findings. The cost-
effectiveness for each control level was determined using the
Integrated Planning Model (IPM). Details regarding the methodologies
used can be found in the Regulatory Impact Analysis of the
NOX SIP call rulemaking. Table II-4 summarizes the control
levels and resulting cost effectiveness of three levels analyzed.
A regionwide level of 0.20 lb/mmBtu was rejected because though it
resulted in an average cost effectiveness of less than $2,000 per ton,
the air quality benefits were less than those for the 0.15 lb/mmBtu
level which was also less than $2,000 per ton. The results suggest that
a multistate level of 0.15 lb/mmBtu should be assumed when determining
the emission levels for this subcategory. This control level has an
average cost-effectiveness of $1,468 per ozone season ton
removed.11 This amount is consistent with the range for
cost-effectiveness that EPA has derived from recently adopted (or
proposed to be adopted) control measures.
---------------------------------------------------------------------------
\11\ It should be noted that in the final NOX SIP
call EPA also investigated the regionwide cost-effectiveness of
NOX reductions if each State individually met the budget
component for large electricity generating boilers and turbines
(i.e., through intra-state trading). In the case of the 0.15 lb/
mmBtu strategy intra-State trading resulted in a regionwide cost-
effectiveness of $1,499/ton compared to $1,468/ton for regionwide
trading.
---------------------------------------------------------------------------
The EPA acknowledges that a control level of 0.12 lb/mmBtu, which
carries a cost effectiveness of $1,760 per ozone season ton removed,
appears to be within the upper range of cost effectiveness. However,
for reasons explained in Section II.D. of the final NOX SIP
call, the EPA is proposing in the section 126 action not to base the
EGU control level on 0.12 lb/mmBtu. Therefore, EPA proposes to retain
and apply here its determination from the NOX SIP call
rulemaking that it is highly cost effective to control emissions from
large EGUs to a control level corresponding to 0.15 lb/mmBtu.
ii. Large Non-EGUs. The EPA determined a highly cost-effective
control level for large non-EGUs by applying a uniform percent
reduction multistate in increments of 10 percent. Details regarding the
methodologies used are in the Regulatory Impact Analysis. Table II-4
summarizes the control levels and resulting cost effectiveness for non-
EGUs.
For large non-EGUs, the cost-effectiveness determination includes
estimates of the additional emissions monitoring costs that sources
would incur in order to participate in a trading program. Some non-EGUs
already monitor their emissions. In the proposed NOX SIP
call, EPA had not included monitoring costs in the cost-effectiveness
determination because such costs could not be estimated at that time.
Since then, EPA has evaluated monitoring system costs. These costs are
defined in terms of dollars per ton of NOX removed so that
they can be combined with the cost-effectiveness figures related to
control costs. Monitoring costs varied from about $150 to $400 per ton
of NOX removed, depending on the type of subcategory.
The EPA, therefore, proposes to retain and apply here its
determination from the NOX SIP call rulemaking that for
large non-EGUs a control level corresponding to 60 percent reduction
from baseline levels is highly cost effective (this percent reduction
corresponds to a multistate control level of about 0.17 lb/mmBtu).
iii. Large Process Heaters. For large process heaters, the control
level was determined by applying various cost-effectiveness thresholds,
because trading was not assumed to be readily available for this
subcategory. Details regarding the methodologies used are in the
Regulatory Impact Analysis. Table II-4 summarizes the control levels
and resulting cost effectiveness for each option under this
subcategory.
The EPA determined that controlling process heaters, though
reasonably cost effective, is not highly cost effective. Thus EPA
proposes that these sources do not emit in amounts that significantly
contribute to petitioning States' nonattainment or maintenance
problems.
iv. Small Sources. For the subcategory of small sources, EPA is
proposing to determine that no additional control measures or levels of
control are highly cost effective and feasible to mandate. For the
purposes of this rulemaking, EPA considers the following sizes of point
sources to be small: (1) Electricity generating boilers and turbines
serving a generator 25 MWe or less, and (2) other indirect heat
exchangers with a heat input of 250 mmBtu/hr or less. In the
NOX SIP call, EPA found that the collective emissions from
small sources were relatively small (in the context of that rulemaking)
and the administrative burden, to the permitting authority and to
regulated entities, of controlling such sources was likely to be
considerable.
In today's action, for the same reasons as described in the final
NOX SIP call, EPA proposes that these sources do not emit in
amounts that significantly contribute to petitioning States'
nonattainment or maintenance problems. Further discussion concerning
small point sources may be found in the final NOX SIP call
preamble.
v. Summary of Control Measures. Table II-5 summarizes the controls
that are assumed for each subcategory. More detailed discussions of the
controls assumed are contained in the sections that describe each
sector.
Table II-5.--Summary of Feasible, Highly Cost-Effective NOX Control
Measures
------------------------------------------------------------------------
Subcategory Control measures
------------------------------------------------------------------------
Large EGUs........................ State-by-State ozone season
emissions level (in tons) based on
applying a NOX emission rate of
0.15 lb/mmBtu on all applicable
sources.
Large Non-EGUs.................... State-by-State ozone season
emissions level (in tons) based on
applying a 60 percent reduction
from uncontrolled emissions on all
applicable sources.
Large Process Heaters............. No additional controls highly cost
effective.
Small Sources..................... No additional controls highly cost
effective.
------------------------------------------------------------------------
3. Other Cost-Related Considerations
The EPA has addressed other cost-related considerations as
described in Section II.D of the final NOX SIP call notice.
The EPA proposes to rely on that analysis in this rulemaking.
D. Identifying Sources
As discussed previously, all of the petitions named specific upwind
source categories as significantly contributing
[[Page 56307]]
to nonattainment in, or interfering with maintenance by, the
petitioning State. Four petitioning States (Massachusetts, New
Hampshire, New York, and Rhode Island) also attempted to identify the
existing sources in the targeted source categories. However, the
petitioners cautioned EPA that the lists might not be complete and that
any omissions were unintentional. In addition, the EPA has received
several comments from sources on the State lists saying that they do
not meet the source category definitions provided in the petitions. In
order to identify and verify the sources in the named source categories
for the geographic areas covered by each petition, EPA used the most
up-to-date emission inventory available. These data sources are
described in Section III of this notice. The existing sources in the
source categories for which EPA is making an affirmative technical
determination are listed in Appendix A to proposed part 97. The EPA
seeks comment on whether it has identified correctly the sources
covered by the petitions.
E. Air Quality Assessment
In the final NOX SIP Call rulemaking, EPA evaluated the
ozone benefits in the petitioning States of NOX controls
proposed in today's action. The EPA believes that the results of that
modeling analysis are valid for the purpose of this proposed
rulemaking, as well. The EPA performed the modeling for the 23
jurisdictions covered in the NOX SIP Call to confirm that
those States collectively contribute significantly to downwind
nonattainment. The collective contribution of all the upwind States is
one factor that went into EPA's decision that each individual upwind
State contributes significantly to downwind nonattainment.
The ozone benefits determined in the final NOX SIP Call
were based on air quality modeling of the emissions scenarios described
below. Each emissions scenario was modeled by EPA using UAM-V run for
all four of the OTAG episodes (i.e., July 1-11, 1988; July 13-21, 1991;
July 20-30, 1993; and July 7-18, 1995). In brief, the emissions
scenarios include a 2007 Base Case and a control scenario designed to
evaluate the effects of NOX controls on nonattainment in
downwind States, including each of the petitioning States. The Base
Case scenario accounts for growth in emissions and reductions
associated with Clean Air Act mandated controls and additional Federal
measures. In the control strategy scenario, NOX emissions
from utility and non-utility sources were reduced by applying controls,
very similar to those in today's proposal, to all such sources in the
23 jurisdictions which EPA has found, in the NOX SIP Call,
contain emissions which make a significant contribution to
nonattainment in downwind areas. The details on the development of
these two emissions scenarios are described in the final NOX
SIP Call rulemaking.
The EPA recognizes that the amount of emissions reduction in the
modeled strategy is not identical to the amount of emissions reduction
in today's proposal. This is because of differences in (a) the
underlying emissions inventories and (b) the level of emissions
controls applied to individual sources. However, the overall effect of
these differences on the percent emissions reductions is small.
Specifically, the difference in the total NOX emission
reductions for the 20 jurisdictions covered by today's proposal between
what was assumed in the modeling compared to what is being proposed
today is only 3 percent. The EPA also recognizes that there are three
additional upwind States (i.e., Georgia, South Carolina, and Wisconsin)
which are controlled in the modeled strategy that are not covered by
today's proposal. These three States were covered in the NOX
SIP Call because of their contributions to States other than the
petitioning States. Since EPA believes that emissions from sources in
these States do not contribute significantly to nonattainment in any of
the petitioning States, it is reasonable to assume that emissions
reductions in these States will not have any appreciable impact on
nonattainment in any of the petitioning States. The EPA believes that
the differences between today's proposal and what was modeled, as
described above, are relatively small, and thus, the overall
conclusions on air quality benefits from the modeled strategy are
applicable to the controls in today's proposal.
The EPA used a number of ``metrics'' (i.e., measures of ozone
contribution or impact) to evaluate the air quality benefits in the
petitioning States of the proposed NOX controls. The
technical details of the air quality modeling information and metrics
are described in the final NOX SIP call rulemaking. The
results of this modeling indicate that the proposed NOX
controls applied to the sources in the upwind States proposed as making
a significant contribution to nonattainment in one or more of the
petitioning States will provide substantial ozone benefits in each of
the petitioning States.
F. Conclusions on Granting or Denying the Petitions
The EPA is proposing action on the petitions based on the outcome
of the multi-step process described in the preceding sections. The
EPA's proposed action consists of three components: (1) Technical
determinations of which upwind sources or source categories named in
each petition significantly contribute to nonattainment or interfere
with maintenance of the relevant ozone standard in each petitioning
State; (2) action specifying when a finding that such sources emit or
would emit in violation of the section 110(a)(2)(D)(i)(I) prohibition
will be deemed made or not made (or made but subsequently withdrawn)
and, thus, when a petition for such a finding will be deemed granted or
denied (or granted but subsequently denied) for purposes of section
126(b); and (3) the specific emissions-reduction requirements that will
apply when such a finding is deemed made. Each of these proposed
actions is described in more detail below. Under EPA's proposed action,
certain types of new and existing sources in 20 upwind States are
potentially subject to a section 126(b) finding and therefore to the
requirements set forth in this proposal.
1. Technical Determinations
First, EPA proposes to make affirmative and negative technical
determinations as to which of the new (or modified 12) or
existing major sources or groups of stationary sources named in each
petition emit or would emit NOX in amounts that will
contribute significantly to nonattainment of the 1-hour or 8-hour
standard in (or interfere with maintenance of the 8-hour standard by)
each respective petitioning State. The regulatory text accompanying
today's proposal sets forth each of those proposed technical
determinations for sources named in each petition.
---------------------------------------------------------------------------
\12\ Whenever the word ``new'' is used in relation to sources
affected by this proposed rule, it includes both new and modified
sources.
---------------------------------------------------------------------------
In short, for each petition, with respect to each ozone standard,
EPA proposes to make affirmative technical determinations of
significant contribution (or interference) for those large EGU and non-
EGU sources for which highly cost-effective controls are available (as
described in Section II.C.), to the extent those sources are located in
one of the ``Named Upwind States'' corresponding to that petition in
Tables II-1 and II-2. Thus, to illustrate, for the petition from New
York, EPA proposes to find that large EGUs and non-EGUs
[[Page 56308]]
of the types described in Section II.C. that are located in the named
portions of Delaware, the District of Columbia, Indiana, Kentucky,
Maryland, Michigan, New Jersey, North Carolina, Ohio, Pennsylvania,
Virginia, and West Virginia emit NOX in amounts that
contribute significantly to nonattainment of the 1-hour standard in New
York. By contrast, EPA proposes to find that such sources located in
Tennessee, which New York also named in its petition, do not emit
NOX in amounts that have that effect on New York. The result
is that EPA proposes to find that the large EGUs and non-EGUs in at
least some upwind States named in every petition except Vermont's
contribute significantly to nonattainment of at least one of the
standards (or interfere with maintenance of the 8-hour standard) in the
petitioning State. The EPA refers the reader to the regulatory text for
a full description of each of the proposed technical determinations for
each petition.
The EPA notes that the Agency is not proposing to make affirmative
technical determinations as to any sources located in Vermont, New
Hampshire, or Maine. That is because, based on the more limited
modeling and other assessments that EPA has done thus far with respect
to those States, EPA is not yet prepared to conclude that sources in
any of those States do contribute significantly to nonattainment (or
interfere with maintenance) of an ozone standard in any downwind State
named in one of those three States in its petition.13
However, EPA is continuing to study the impacts of sources in those
States on downwind States, so that it can make final decisions based on
the fuller set of information available today for other States. If EPA
believes, after completing its assessments, that large EGU or non-EGU
sources in any of those three States do contribute significantly to
downwind air quality problems in any of the States that name them in
their petitions, EPA will issue a supplemental notice of proposed
rulemaking based on those results.
---------------------------------------------------------------------------
\13\ Maine's petition named sources in Vermont and New Hampshire
and New Hampshire's petition named sources in Maine and Vermont.
---------------------------------------------------------------------------
Appendix A to proposed part 97 lists all existing sources for which
EPA proposes to make an affirmative technical determination linking
those sources to at least one petitioning State. These are the existing
sources that could receive a positive section 126(b) finding, depending
on the circumstances described in the next section.
2. Action on Whether To Grant or Deny Each Petition
a. Portions of Petitions for Which EPA Is Proposing an Affirmative
Technical Determination. For the reasons described in Section
II.A.2.c., EPA proposes to issue the type of final action on the
petitions described in that section. Under that approach, EPA's final
action for sources that EPA is proposing an affirmative technical
determination would provide that a finding that certain sources emit or
would emit in violation of the prohibition in section
110(a)(2)(D)(i)(I) would be deemed made as of certain specified dates
if certain events do not occur by those dates. More specifically, a
finding that new or existing sources, for which EPA has made an
affirmative technical determination, do emit in violation of section
110(a)(2)(D)(i)(I) would be deemed made:
As of November 30, 1999, if by such date EPA does not
issue either a proposed approval, under section 110(k) of the CAA, of a
State implementation plan revision submitted by such State to comply
with the requirements of section 110(a)(2)(D)(i)(I) of the CAA; or
final Federal implementation plan meeting such requirements for such
State in which the affected sources are or will be located,
As of May 1, 2000, if by November 30, 1999, EPA takes the
action described above for such State, but, by May 1, 2000, EPA does
not approve or promulgate implementation plan provisions meeting such
requirements for such State.
The EPA also proposes to find, as described earlier, that any such
finding as to any such major source or group of stationary sources
would be considered a finding under section 126(b) and, therefore,
would trigger the remedial requirements of the final rule. At such time
as a finding is deemed made, EPA intends to publish a notice in the
Federal Register announcing the source categories and locations
affected by the finding.
Furthermore, EPA proposes that as to any portion of a petition for
which EPA has made an affirmative technical determination (as described
above) that portion of the petition shall be deemed denied as of May 1,
2000, if a section 126(b) finding has not been deemed to have been made
by that date. In other words, if EPA has taken final action putting
into place an implementation plan meeting the requirements of section
110(a)(2)(D)(i)(I) by May 1, 2000, any outstanding portions of
petitions will be deemed denied by that date. In addition, after a
section 126(b) finding has been deemed made as to sources or groups of
stationary sources in an upwind State, that finding will be deemed
withdrawn, and the corresponding part of the relevant petition(s)
denied, if the Administrator either approves a SIP or promulgates a FIP
which complies with the requirements of section 110(a)(2)(D)(i)(I) for
such upwind State. This would minimize any overlap between an effective
section 126(b) finding, on one hand, and the application of
satisfactory SIP or FIP provisions, on the other.
b. Portions of Petitions for Which EPA Is Proposing a Negative
Technical Determination. Consistent with this overall approach, EPA
proposes that the sources for which EPA would make a negative technical
determination (as described above) do not or would not emit in
violation of the section 110(a)(2)(D)(i)(I) prohibition. As a result,
EPA proposes to deny each aspect of each petition relating to such
sources. For example, EPA proposes to deny New York's petition as to
sources in any State (or portion of a State) named in New York's
petition that is outside the large EGU and non-EGU categories described
in Section II.C., as well as any named sources of any type in
Tennessee. Another example is that EPA proposes today to deny Vermont's
section 126 petition in its entirety, because EPA proposes to find that
no sources named in Vermont's petition, in any of the upwind States
that the petition names, contribute significantly to nonattainment of
either the 1-hour or the 8-hour standard, nor interfere with
maintenance of the 8-hour standard, in Vermont.
3. Requirements for Sources for Which EPA Makes a Section 126(b)
Finding
The EPA proposes in Section III, below, the requirements that would
apply to any new or existing major source or group of stationary
sources for which a section 126(b) finding is ultimately made under the
approach just described. Section 126(c) states, in relevant part, that:
it shall be a violation of this section and the applicable
implementation plan in such State
(1) for any major proposed new (or modified) source with respect
to which a finding has been made under subsection (b) to be
constructed or to operate in violation of this section and the
prohibition of section 110(a)(2)(D)([i]) or this section or
(2) for any major existing source to operate more than three
months after such finding has been made with respect to it.
The Administrator may permit the continued operation of a source
referred to in paragraph (2) beyond the expiration of such three-month
period if
[[Page 56309]]
such source complies with such emission limitations and compliance
schedules (containing increments of progress) as may be provided by the
Administrator to bring about compliance with the requirements contained
in section 110(a)(2)(D)([i]) as expeditiously as practicable, but in no
case later than three years after the date of such finding.
The remedial requirements that EPA proposes to apply to sources for
which a section 126(b) finding is ultimately made would satisfy the
requirements just quoted. First, EPA proposes to find that new sources
for which a section 126(b) finding is ultimately made must comply with
the requirements described in Section III to ensure that they do not
emit in violation of the section 110(a)(2)(D)(i) prohibition. Second,
the program EPA is proposing serves as the alternative set of
requirements that the Administrator may apply for the purpose of
allowing existing sources subject to a section 126(b) finding to
operate for more than three months after the finding is made.
Consistent with section 126(c), the compliance period in EPA's proposed
program extends no further than three years from the making of the
finding. To the extent a finding is deemed made as of November 30,
1999, compliance will be required by November 30, 2002. But since the
program EPA is proposing would require actual emissions reductions only
in the ozone season, actual reductions will not need to occur until May
1, 2003, the start of the first ozone season after the November 30,
2002, compliance date. Thus, compliance by November 30, 2002 would not
require actual reductions until May 1, 2003. As described in Section
V.A.1 of the final NOX SIP call, EPA believes that
compliance by the ozone season beginning May 1, 2003 is feasible.
Section III of this notice describes the proposed section 126 control
requirements in greater detail.
III. Federal NOX Budget Trading Program
A. Program Summary
1. Purpose of the Federal NOX Budget Trading Program
Under section 126(c), EPA proposes to implement the Federal
NOX Budget Trading Program, a capped market-based system for
certain combustion sources in covered upwind States to bring sources
covered by any final section 126 finding into compliance. This type of
program is a proven method for achieving the highly cost-effective
emissions reductions described above while providing sources compliance
flexibility. (See SNPR for NOX SIP call at 63 FR 25918-19,
discussing OTAG's conclusions concerning advantages of market-based
systems).
The Federal NOX Budget Trading Program would be
triggered automatically if EPA makes a final finding as to any sources
under section 126, as described in Section II.F. Participation in the
Federal program would be mandatory for all sources affected by a
triggering of this section 126 remedy. It would also be mandatory for
all sources required to reduce emissions by the promulgated FIP, with
the exception of cement kilns and internal combustion engines.
The EPA would like to clarify that the use of the term ``budget''
in the context of the Federal NOX Budget Trading Program
does not mean that there is an aggregate emissions level that is
enforceable for the purposes of the section 126 remedy. Rather, the
term refers to the aggregate emission levels in each State for units
required to participate in the Federal NOX Budget Trading
Program as a section 126 remedy or as part of a FIP. The aggregation of
sources allocations is initially only for purposes of determining the
total amount available for allocation and and should not be construed
to represent a separate requirement for sources in the program for
purposes of any section 126 remedy.
The Federal NOX Budget Trading Rule is proposed in a new
Part 97 in Title 40 of the Code of Federal Regulations. Because EPA is
proposing to implement the Federal NOX Budget Trading
Program both in response to the section 126 petitions and as part of a
FIP if necessary; EPA intends to finalize part 97 in whichever of these
actions is finalized first. (The EPA expects part 97 will be finalized
in the section 126 rulemaking because final action on the remedy
portion of section 126 is required by April 30, 1999 under the proposed
consent decree discussed above.) In finalizing part 97, EPA intends to
respond to the comments it receives regarding part 97 through both the
proposed section 126 remedy and the proposed FIP. Therefore, commenters
who have identical comments in both rulemakings may submit their
comments to one docket and merely reference such comments in their
submission to the other docket. However, to the extent comments on part
97 are solely related to how it would be applied through a triggering
of the section 126 remedy, commenters should submit such comments to
the docket for this proposed section 126 remedy.
2. Relationship of the Section 126 Remedy to the NOX SIP
Call and the FIP.
The sources or groups of sources identified in the section 126
petitions are also sources for which EPA recommends States adopt
emission limitations and control strategies in response to the
NOX SIP call. The NOX SIP call establishes an
emissions budget for all sources of NOX emissions in all
States determined by EPA to significantly contribute to nonattainment
or interfere with maintenance of the ozone NAAQS in any other
jurisdiction. The FIP sets specific stationary source rules to decrease
NOX emissions and meet the NOX SIP call budget.
The section 126 proposed action, on the other hand, is limited to major
stationary sources or groups of stationary sources that are named in
the section 126 petitions and that EPA finds emit or would emit in
violation of the prohibition in section 110(a)(2)(D)(i) relative to a
petitioning State. Despite this difference in the scope of the proposed
section 126 action and the proposed FIP or final NOX SIP
call, all three actions are aimed at reducing the transport of ozone by
controlling emissions from sources in a given State that are found to
be contributing significantly to nonattainment or maintenance problems
in another State.
The EPA has promulgated the State NOX Budget Trading
Program, a cap-and-trade program for large combustion sources, to
assist States in meeting their obligations under the final
NOX SIP call. The EPA believes that this State
NOX Budget Trading Program--if selected by States to meet
their SIP call obligations--could be coordinated and integrated with
the Federal NOX Budget Trading Program promulgated in a
section 126 rule or a FIP, in order to address the transport problem on
a regional scale.
Integration is possible because, as noted above, both the
NOX SIP call, the corresponding FIP, and the section 126
petitions seek to mitigate the ozone transport problem by reducing
emissions from upwind sources that hinder attainment or maintenance of
the ozone NAAQS downwind. Further, the sources covered in the State
NOX Budget Trading Program under the NOX SIP call
include a majority of the sources named by petitioning States, and are
identical in size and categorization to sources for which EPA proposes
issue rules in the section 126 and FIP proposed actions.
In order to be eligible to participate in a cap-and-trade program,
the EPA
[[Page 56310]]
believes that there are two principal criteria that sources must meet,
as stated in the supplemental notice for the proposed NOX
SIP call (62 FR 25923). The first criterion requires that sources be
able to account accurately and consistently for all of their emissions
in order to maintain emissions within a cap. The second criterion is
the ability to identify a responsible party for each regulated source
who would be accountable for demonstrating and ensuring compliance with
the program's provisions. Assuming that these criteria are met, and
consistent control levels are used in setting emission requirements for
the covered sources, EPA supports the establishment of a common trading
program among sources subject to a trading program under the
NOX SIP call, a section 126 remedy, or a FIP among sources
subject to a trading program under the NOX SIP call, a
section 126 remedy or a FIP.
The resulting multi-state trading program could include all sources
in States found to be significantly contributing to nonattainment or
interfering with maintenance of the ozone standard in another State.
Under this common trading program, sources subject to the Federal
NOX Budget Trading Program under the section 126 rulemaking
or the FIP, and sources in States choosing to participate in the State
NOX Budget Trading Program in response to the NOX
SIP call, could trade with one another under a NOX cap
across participating States. The EPA's analyses in conjunction with the
NOX SIP call exhibit that implementation of a single trading
program with a uniform control level results in no significant changes
in location of emissions reductions as compared to a non-trading
scenario. Therefore, the common trading program will achieve the
intended emissions reductions while providing flexibility and cost
savings to the covered sources.
Integration of the trading programs reduces the possibility of
inconsistent or conflicting deadlines or requirements, increases the
potential cost savings for sources, and streamlines program
administration. Inconsistency could hamper the sources' ability to plan
and achieve the needed reductions as cost-effectively as possible. In
addition, if a State subsequently elects to submit a SIP including a
trading program after EPA has already established a Federal
NOX Budget Trading Program under a FIP or section 126
remedy, disruptions to sources that would shift from regulation under a
FIP or section 126 remedy to regulation under a SIP would be minimized.
Because sources may be included in the common trading program
through one of three possible mechanisms, the sources included in the
trading program for purposes of the NOX SIP call may vary
from sources included for purposes of the section 126 remedy. The EPA
does not foresee this to be problematic since sources would face
consistent control requirements regardless of which rulemaking includes
the sources in the common trading program. That the requirements would
be consistent follows from the similar nature of the rulemakings and
the comparable level of control which EPA has determined to be cost-
effective for each source category across all three actions.
The EPA proposes in part 97 to establish the geographic boundaries
of the common trading program as those States submitting SIPs in
response to the final NOX SIP call or subject to FIPs and/or
the sources in States for which EPA makes a finding for the section 126
petitions. The EPA would administer this common trading program in
collaboration with affected States.
The EPA is proposing a Federal NOX Budget Trading
Program as part of the FIP or section 126 remedy which mirrors, to the
extent feasible, the State NOX Budget Trading Program (set
forth in part 96) which is the model trading program that is available
for States to adopt in response to the NOX SIP call. While
EPA is proposing to keep the programs as similar as possible, there are
several differences which are more fully described below. These
differences arise primarily from the need for Federal implementation of
the program rather than State implementation. For example, EPA must
determine the NOX allowance allocations for each unit in the
Federal NOX Budget Trading Program, rather than simply
provide an example that States may use to determine allocations, as is
the case in the State NOX Budget Trading Program.
B. Federal NOX Budget Trading Program
1. Program Overview
In part 97, the EPA proposes a cap-and-trade program as an
aggregate remedy for the section 126 petitions which it today proposes
to determine are technically valid. Four of the eight petitioning
States (New York, Connecticut, Pennsylvania, and Maine) requested that
EPA establish such a trading program to implement the required
reductions.
The EPA has authority under section 126 to require sources or
groups of sources for which a finding of significant contribution is
made to comply with a cap-and-trade program. Section 126(c) provides
that such sources or groups of sources may continue to operate if they
comply ``with such emission limitations and compliance schedules
(containing increments of progress) as may be provided by the
Administrator to bring about compliance'' with section 110(a)(2)(D).
Under section 302, an ``emission limitation'' is ``a requirement * * *
which limits the quantity, rate, or concentration of emission of air
pollutants on a continuous basis.'' In fact, title IV of the CAA refers
to the allowance requirements of the Acid Rain SO2 cap-and-
trade program as ``emission limitations.'' 42 U.S.C. 7651c(a).
Under a cap-and-trade program, the Administrator sets an emission
limitation and compliance schedule for each unit subject to the
program. The emission limitation for each unit is the requirement that
the quantity of the unit's emissions during a specified period (here,
the tonnage of NOX emissions during the ozone season) cannot
exceed the amount authorized by the allowances (here, NOX
allowances, each authorizing one ton of emissions) that the unit holds.
Allowances are allocated to units subject to the program, and the total
number of allowances allocated to all such units for each control
period is fixed or capped at a specified level. The compliance schedule
is set by establishing a deadline by which units must begin to comply
with the requirement to hold allowances sufficient to cover emissions.
In essence, for purposes of complying with section 126, EPA would be
translating emission limits into allowance requirements. Since under
section 126 EPA has the authority to establish emission limits, and
allowance requirements are equivalent to emission limits, EPA has the
authority to promulgate allowance requirements and allocate allowances
for purposes of section 126. Since a cap-and-trade program is a
compliance mechanism which enables sources to make cost-effective
decisions to meet their allowance requirements, which are equivalent to
emission limits, EPA believes it has the authority under section 126(c)
to adopt a cap-and-trade program as a cost effective means of
implementing the requirements of sections 126 and 110(a)(2)(D).
Sources potentially subject to the emission limitations and
compliance schedule in the Federal NOX Budget Trading
Program for the purposes of the section 126 petitions are those sources
named by petitioning States and found by EPA to be emitting in
violation of the prohibition in a petitioning State. The
[[Page 56311]]
section 126 remedy will apply to these sources in States for which a
finding is triggered by the terms of today's proposed rule. For the
reasons discussed in Section II, these sources include any fossil fuel-
fired unit (boiler, turbine, or combined cycle) that serves a generator
with a nameplate capacity greater than 25 MWe, and any fossil fuel-
fired unit (boiler, turbine, or combined cycle) that has a maximum
design heat input of greater than 250 mmBtu/hr, located in any of the
following twenty States: Alabama, Connecticut, Delaware, District of
Columbia, Illinois, Indiana, Kentucky, Maryland, Massachusetts,
Michigan, Missouri, New Jersey, New York, North Carolina, Ohio,
Pennsylvania, Rhode Island, Tennessee, Virginia, and West Virginia.
The EPA requests comment as to whether additional stationary
sources that emit to a stack, can monitor NOX mass
emissions, and are located in a State where a finding is made under
section 126, but are not named in a petition, should be able to
voluntarily participate in the trading program. In today's notice, EPA
proposes providing these individual stationary sources the opportunity
to opt in to enable further cost savings from the Federal
NOX Budget Trading Program. These opt-in provisions would be
very similar to the opt-in provisions allowed under the State
NOX Budget Trading Program in part 96 (see Section III.B.3.e
for explanation).
The NOX allowances--each allowance representing a
limited authorization to emit one ton of NOX--would be the
currency used in the trading program. A fixed number of NOX
allowances would be allocated to sources for each ozone season equal to
the total amount of the aggregate emissions permitted among the sources
in each State included in the Federal NOX Budget Trading
Program for purposes of the section 126 remedy. The EPA has included in
today's proposal several alternative methodologies that EPA could use
to allocate NOX allowances to units. Appendix A proposed
part 97 sets forth the allocation for each unit based on the proposed
methodologies.
The control period for the trading program (i.e., the period during
which a source must hold sufficient NOX allowances to cover
emissions) would extend from May 1 through September 30, which is the
same as the control period under the NOX SIP call and the
FIP proposal. The EPA's proposed trading program remedy is based on the
application of a uniform control level to the covered universe of
sources. Based on analyses done in connection with the proposed
NOX SIP call (63 FR 25921) and the final NOX SIP
call, EPA maintains that trading could occur across States included in
a NOX Budget Trading Program without restrictions, other
than the requirement to comply with existing emission limits under
title I and title IV of the CAA, as well as any other State
limitations.
Under today's proposed rule, sources in the Federal NOX
Budget Trading Program would be required to monitor and report their
emissions in accordance with relevant portions of 40 CFR part 75. The
EPA has promulgated revisions to part 75 that establish NOX
mass monitoring requirements and provide greater flexibility to
regulated sources. Consistent and accurate monitoring of emissions is
necessary for accountability regarding compliance with the requirement
to hold NOX allowances and to ensure that a ton of emissions
attributed to one source in one State is equivalent to a ton attributed
to another source in the same or another State.
Under today's proposed rule, EPA would be responsible for all
aspects of program implementation, with the exception of permitting.
Permitting would be handled by States in accordance with the
requirements of the proposed rule. As further explained in Section
III.B.2.c., the Federal NOX Budget Trading Program does not
require a new or separate permit. If a source already has in place a
federally enforceable permit, either title V or non-title V, the
source's trading program obligations must be incorporated into this
permit; if a source does not have a federally enforceable permit, the
federally-enforceable NOX Budget Trading Rule applies to the
source on its own accord.
As discussed herein, EPA proposes to make the Federal and State
NOX Budget Trading Programs as similar as possible and has
modeled proposed part 97 after part 96 just finalized. The EPA notes
that discussion of the evolution of the NOX Budget Trading
Program is set forth in the supplemental notice of the proposed
NOX SIP call rule at 63 FR 25921-23 and in the final
NOX SIP call rule.
2. Elements of the Federal NOX Budget Trading Program That
Are the Same as the State NOX Budget Trading Program
Under part 97, as proposed, the following sections would be
virtually identical to the corresponding sections in part 96, which
sets forth the State NOX Budget Trading Program. The EPA
proposes to retain and rely on the analyses and considerations
undertaken in the NOX SIP call process to determine these
program elements. Moreover, the provisions in part 97 would be numbered
in the same sequence as the corresponding provisions in part 96, so
that, for example, Sec. 97.2 and Sec. 96.2 or Sec. 97.81 and Sec. 96.81
would address the same subject matter. The major differences between
the part 97 sections listed below and their corresponding part 96
sections would be the renumbering of cross references to other
regulatory provisions so that a section in part 97 would reference the
appropriate section in that part, as opposed to the section in part 96.
More detailed information on the rationale for the part 96 provisions
themselves can be found in the preamble accompanying the proposed part
96 (63 FR 25917-43) and the final part 96.
Subpart A--Federal NOX Budget Trading Program General
Provisions
Sec.
97.3 Measurements, abbreviations, and acronyms.
97.5 Retired unit exemption.
97.7 Computation of time.
Subpart B--Authorized Account Representative for NOX Budget
Sources
97.10 Authorization and responsibilities of the NOX
authorized account representative.
97.11 Alternate NOX authorized account representative.
97.12 Changing the NOX authorized account representative
and alternate NOX authorized account representative;
changes in the owners and operators.
97.13 Account certificate of representation.
97.14 Objections concerning the NOX authorized account
representative.
Subpart C--Permits
97.20 General NOX Budget permit requirements.
97.21 Submission of NOX Budget permit applications.
97.22 Information requirements for NOX Budget permit
applications.
97.23 NOX Budget permit contents.
97.24 Effective date of initial NOX Budget permit.
97.25 NOX Budget permit revisions.
Subpart D--Compliance Certification
97.30 Compliance certification report.
Subpart F--NOX Allowance Tracking System
97.50 NOX Allowance Tracking System accounts.
97.51 Establishment of accounts.
97.52 NOX Allowance Tracking System responsibilities of
NOX authorized account representative.
97.53 Recordation of NOX allowance allocations.
97.54 Compliance.
97.55 Banking.
97.56 Account error.
97.57 Closing of general accounts.
[[Page 56312]]
Subpart G--NOX Allowance Transfers
97.60 Scope and submission of NOX allowance transfers.
97.61 EPA recordation.
97.62 Notification.
The EPA requests comment on whether any of the part 97 provisions
listed above should differ substantively from the corresponding
provisions in part 96. If a commenter believes substantive differences
in the rules are appropriate, the commenter should describe the favored
changes and explain why these changes are appropriate.
a. General Provisions. For part 97, EPA is proposing to use the
same measurements, abbreviations, and acronyms, the same retired unit
exemption, and the same provisions for computation of time as those
that apply in part 96, with cross references to the appropriate
sections in part 97, rather than to sections in part 96. The EPA is
proposing these part 97 provisions for the reasons set forth both in
the proposed NOX SIP call (63 FR 25923-27) and final
NOX SIP call, and in order to minimize differences between
the Federal and State NOX Budget Trading Programs.
b. Authorized Account Representative. The NOX Authorized
Account Representative (NOX AAR) is the individual who is
authorized to represent the owners and operators of each NOX
Budget unit at a NOX Budget source in matters pertaining to
the NOX Budget Trading Program. Subpart B of part 97
addresses, among other things, the process for designating and changing
the NOX AAR and the responsibilities of the NOX
AAR and alternate NOX AAR. These provisions are the same as
those in part 96, with cross references to the appropriate sections of
part 97. The EPA is proposing these part 97 provisions for the reasons
set forth both in the proposed NOX SIP call (63 FR 25927)
and the final NOX SIP call, and in order to minimize
differences between the Federal and State NOX Budget Trading
Programs.
c. Permits. The regulations governing State permitting under title
V define an ``applicable requirement,'' which must be reflected in a
title V operating permit, as including ``[a]ny standard or other
requirement provided for in the applicable implementation plan approved
or promulgated by EPA through rulemaking under title I of the CAA that
implements the relevant requirements of the CAA, including any
revisions to that plan promulgated in part 52 of this chapter.'' 40 CFR
70.2. Since today's proposed rule is being promulgated under title I
(i.e., under section 126), the requirements of this rule are applicable
requirements under Sec. 70.2 and must be reflected in the title V
operating permit of NOX Budget sources required to have such
a permit. The EPA believes that the majority of NOX Budget
sources will be required to have a title V permit. Further, all State
and local air permitting authorities currently have EPA-approved title
V operating permits programs. These State and local agencies would be
the permitting authorities for the majority of NOX Budget
sources with title V permits, for which the trading program
requirements would be applicable requirements. For any sources that do
not have a title V permit, such a permit is not required. If a source
has a federally enforceable non-title V permit, the trading program
requirements must also be incorporated into this permit. If a source
does not have a federally enforceable permit, the requirements of the
Federal NOX Budget Trading Rule would be federally
enforceable without the federally enforceable permit.
Subpart C of part 97 addresses, among other things, the
administration of a permit, permit applications, permit contents,
effective date, and permit revisions. These provisions are the same as
those in part 96, with cross references to the appropriate sections in
part 97. The EPA is proposing these part 97 provisions for the reasons
set forth both in the proposed NOX SIP call (63 FR 25927-29)
and the final NOX SIP call, and in order to minimize
differences between the Federal and State NOX Budget Trading
Programs.
d. Compliance Certification. The NOX AAR must certify at
the end of each control period that the unit was in compliance with the
emissions limitation and other requirements of the Federal
NOX Budget Trading Program. Proposed Sec. 97.30 sets forth
the same provisions for compliance certification reports as those in
part 96, with cross references to the appropriate sections in part 97.
The EPA is proposing these part 97 provisions for the reasons set forth
both in the proposed NOX SIP call (63 FR 25929) and the
final NOX SIP call, and in order to minimize differences
between the Federal and State NOX Budget Trading Programs.
e. NOX Allowance Tracking System. The NOX
Allowance Tracking System is an automated system used to track
NOX allowances held by NOX Budget units under the
NOX Budget Trading Program, as well as those allowances held
by other organizations and individuals. Subpart F of part 97 addresses,
among other things, NOX allowance tracking system accounts,
the account responsibilities of the NOX AAR, the recordation
of NOX allowance allocations, the compliance process,
account error, and account closing. These provisions are the same as
those in part 96, with cross references to the appropriate sections in
part 97. The EPA is proposing these part 97 provisions for the reasons
set forth both in the proposed NOX SIP call (63 FR 25933-37)
and the final NOX SIP call, and in order to minimize
differences between the Federal and State NOX Budget Trading
Programs.
f. Banking. The EPA proposes to include banking as a feature in the
Federal NOX Budget Trading Program for the reasons set forth
in the final NOX SIP call. Proposed Sec. 97.55 sets forth
the same provisions for banking and the management of banked allowances
as specified in part 96. In accordance with these provisions,
NOX allowances held by units subject to the Federal
NOX Budget Trading Program may be banked for future use
starting in 2003 (except as noted in Section III.B.3.e.ii. of this
preamble). However, as in the State NOX Budget Trading
Program, the Federal NOX Budget Trading Program contains a
flow control mechanism to limit the variability associated with
banking. This mechanism allows unlimited banking by units subject to
the Federal NOX Budget Trading Program, but discourages the
``excessive'' use of banked allowances by establishing a discount rate
on the use of banked allowances over a certain level. Proposed part
Sec. 97.55 establishes a flow control mechanism which applies a 2-for-1
discount ratio to the use of banked allowances above a certain level
when the total number of banked allowances in the program exceeds 10
percent of the allowable NOX emissions for all sources
covered by the Federal trading program. This flow control mechanism,
along with the overall banking provisions, is proposed for the reasons
set forth in both the proposed NOX SIP call (63 FR 25934-37)
and the final NOX SIP call, and in order to minimize
differences between the Federal and State NOX Budget Trading
Programs.
g. NOX Allowance Transfers. Subpart G of part 97
addresses, among other things, submission, recordation, and
notification of transfers of NOX allowances under the
NOX Budget Trading Program. These provisions are the same as
those in part 96, with cross references to the appropriate sections in
part 97. The EPA is proposing these part 97 provisions for the reasons
set forth both in the proposed NOX SIP call (63 FR 25937-38)
and the final NOX SIP call, and in order to minimize
[[Page 56313]]
differences between the Federal and State NOX Budget Trading
Programs.
h. Audits. While program audits are not explicitly required by
today's rule, EPA intends to perform the same types of audits discussed
concerning the proposed NOX SIP call (63 FR 25942) and the
final NOX SIP call.
3. Elements of the Federal NOX Budget Trading Program That
Differ From the State NOX Budget Trading Program
The EPA proposes that the following sections in part 97 incorporate
certain differences from the corresponding sections in part 96 to
provide for Federal implementation of the NOX Budget Trading
Program.
Subpart A--Federal NOX Budget Trading Program General
Provisions
Sec. 97.1 Purpose.
Sec. 97.2 Definitions.
Sec. 97.4 Applicability.
Sec. 97.6 Standard Requirements.
Subpart D--Compliance Certification
Sec. 97.31 Administrator's action on compliance certifications.
Subpart E--NOX Allowance Allocations
Sec. 97.40 Trading program budget.
Sec. 97.41 Timing requirements for NOX allowance
allocations.
Sec. 97.42 NOX allowance allocations.
Subpart H--Monitoring and Reporting
Sec. 97.70 General requirements.
Sec. 97.71 Initial certification and recertification procedures.
Sec. 97.72 Out of control periods.
Sec. 97.73 Notifications.
Sec. 97.74 Recordkeeping and reporting.
Sec. 97.75 Petitions.
Sec. 97.76 Additional requirements to provide data for allocations
purposes.
Subpart I--Individual Unit Opt-Ins
Sec. 97.80 Applicability.
Sec. 97.81 General.
Sec. 97.82 NOX authorized account representative.
Sec. 97.83 Applying for NOX Budget opt-in permit.
Sec. 97.84 Opt-in process.
Sec. 97.85 NOX Budget opt-in permit contents.
Sec. 97.86 Withdrawal from NOX Budget Trading Program.
Sec. 97.87 Change in regulatory status.
Sec. 97.88 NOX allowance allocations to opt-in units.
a. General Provisions. i. Purpose. Proposed Sec. 97.1 explains that
proposed part 97 sets forth the provisions for the Federal
NOX Budget Trading Program addressing interstate transport
of ozone and NOX. As discussed above, this program would be
activated either under section 126 or under a FIP.
ii. Definitions. For part 97, EPA is proposing to use the same
definitions as those that apply in part 96, with cross references to
the appropriate sections in part 97, with three exceptions. First, the
definition of the term ``NOX Budget Trading Program'' would
be altered to reflect the fact that the Federal trading program is
established pursuant to part 52, as opposed to part 51.121, as is the
case with the State NOX Budget Trading Program under part
96. Secondly, the definition for the term ``State'' would be altered to
reference only those States that would be covered by any final section
126 or FIP action, and to reflect the fact that the Federal trading
program would be promulgated for a State, as opposed to adopted by the
State as is the case with the State NOX Budget Trading
Program. Last, the term ``State trading program budget'' would be
replaced with the term ``trading program budget''. For purposes of the
FIP, the trading program budget would be the aggregated budget for all
sources affected by the requirements to participate in the trading
program in a given State under the FIP. For purposes of the section 126
action, the trading program budget would be referred to as the
``section 126 trading program budget for the State''. The term
``section 126 trading program budget for the State'' is used to clarify
the fact that the budget for the Federal NOX Budget Trading
Program is not aggregated to a State level for the purposes of the
section 126 action except for the allocation calculation, since the
focus in the remedy is sources rather than States.
The following example illustrates the approach taken concerning the
unchanged definitions: the term ``NOX Budget Unit'' is
defined under part 97 as ``a unit that is subject to the NOX
Budget Trading Program emissions limitation under Sec. 97.4 and Sec.
97.80'', while that term has the same definition under part 96 except
that appropriate sections in part 96 are referenced (63 FR 25923).
iii. Applicability. For the reasons discussed above, EPA proposes
in part 97 that the Federal NOX Budget Trading Program for
purposes of the section 126 remedy would apply to any fossil fuel-fired
unit (boiler, combustion turbine, or combined cycle) that serves a
generator with a nameplate capacity greater than 25 MWe, and any fossil
fuel-fired unit (boiler, combustion turbine, or combined cycle) that
has a maximum design heat input of greater than 250 mmBtu/hr, located
in any of the following twenty States: Alabama, Connecticut, Delaware,
District of Columbia, Illinois, Indiana, Kentucky, Maryland,
Massachusetts, Michigan, Missouri, New Jersey, New York, North
Carolina, Ohio, Pennsylvania, Rhode Island, Tennessee, Virginia, and
West Virginia. The remedy will apply to these sources in those States
for which EPA makes a final finding granting a section 126 petition
under the triggers included in the proposed rule. These are the same
source categories included in the core group applicability for the
voluntary State NOX Budget Trading Program, only in a more
narrow range of States.
In the NOX SIP call, EPA offered States the option of
allowing units with a very low federally enforceable permit limitation
(i.e., 25 tons per season) to be exempt from the trading program, even
though they were above the applicability threshold (63 FR 25926). The
EPA proposes to include this provision in the Federal NOX
Budget Trading Program and solicits comment on the appropriateness of
such inclusion.
iv. Standard Requirements. Under the Federal NOX Budget
Trading Program, the NOX Budget units and their owners,
operators, and NOX AARs must meet certain standard
requirements that incorporate the full range of program requirements by
referencing other sections of the NOX Budget Trading Rule.
These provisions are the same as the related provisions in part 96,
with cross references to the appropriate sections of part 97, except
that the Administrator, rather than the permitting authority, would
allocate NOX allowances under the Federal NOX
Budget Trading Program. This reflects the fact that the NOX
Budget Trading Program would be Federally run, rather than run by the
State as under the NOX SIP call.
b. Compliance Certification. Proposed Sec. 97.31 is the same as
Sec. 96.31 except that the Administrator has the sole responsibility
for reviewing and auditing compliance certifications and other
submissions under the Federal NOX Budget Trading Program.
This reflects the fact that the part 97 NOX Budget Trading
Program would be federally run rather than run by the State as under
the NOX SIP call. The EPA is proposing these part 97
provisions for the reasons set forth both in the proposed
NOX SIP call (63 FR 25929) and the final NOX SIP
call, and in order to minimize differences between the Federal and
State NOX Budget Trading Programs.
c. Aggregate NOX Emissions Levels and Allowance
Allocations. This section discusses the calculation of State specific
aggregate emission levels and the methodology and timing for issuance
of NOX Budget unit allocations. The EPA calculated the State
specific aggregate emission levels that would remain after the
application of reasonable and highly cost-effective
[[Page 56314]]
NOX controls to upwind sources which contribute
significantly to nonattainment or maintenance problems in downwind
States. These aggregate emission levels for each State for which a
finding under section 126 may be triggered are listed in appendix C of
today's notice for both EGUs and non-EGUs. Section II.C of this
preamble describes the controls that were assumed for each subcategory
of sources. In determining what controls to assume in calculation of
the proposed emissions level for each subcategory, EPA used the cost-
effectiveness rationale also described in Section II.C.
The EPA also calculated individual unit allocations based on the
State specific aggregate emission levels described in this section.
Subpart E of today's proposed Federal NOX Budget Trading
Rule addresses the allocation of NOX allowances to
NOX budget units for purposes of the section 126 remedy. As
in the allocation-related provisions in part 96, part 97 includes
provisions for the timing of allocation issuance, the methodology for
issuing allocations, and the allocations for new sources. However, in
part 97, the Administrator, rather than the State, will determine the
allocations.
i. Data Sources. (1) EGUs. The EGU data base developed for this
analysis consists of both utility EGUs and non-utility EGUs. The non-
utility EGUs include independent power producers (IPPs) and non-utility
generators (NUGs). Eight data sources were used to develop the base
year EGU data: (1) EPA's Acid Rain Data Base (ARDB) (Pechan, 1997c);
(2) EPA's 2007 Integrated Planning Model (IPM) Year 2007; (3) EPA's
Emission Tracking System/Continuous Emissions Monitoring System (ETS/
CEM) (EPA, 1997b); (4) DOE's Form EIA-860 (DOE, 1995a); (5) DOE's Form
EIA-767 (DOE, 1995b); (6) EPA's National Emissions Trends Data Base
(NET) (EPA, 1997c); (7) DOE's Form EIA-867 (DOE, 1995c); (8) the OTAG
Emission Inventory (Pechan, 1997a); and (9) incorporation of comments
to the proposed NOX SIP call NPR dated November 7, 1997.
More details regarding these data sources can be found in the technical
support document (TSD) of EPA's NOX SIP call.
(2) Non-EGUs. The starting point for the non-EGU data base was the
1990 OTAG Inventory. This inventory was prepared with 1990 State ozone
SIP emission inventories supplemented with either State inventory data,
if available, or EPA's National Emission Trends (NET) data if State
data were not available. This inventory was further refined by the
incorporation of comments to the proposed NOX SIP call NPR
dated November 7, 1997. All records with utility SCCs (first 3 digits
101 or 201) were removed from the 1990 OTAG Inventory because it was
assumed that emissions from these sources would be accounted for in the
EGU component of the inventory. More details regarding these data
sources can be found in the TSD of EPA's NOX SIP call.
ii. Methodology Used To Determine Controlled Emission Levels.
Section II of this preamble identifies the two subcategories that EPA
proposes to control (i.e., large EGUs and large non-EGUs) and the
emission levels that are highly cost-effective to achieve (i.e., 0.15
lb/mmBtu for EGUs and 60 percent reduction from uncontrolled levels for
non-EGUs) in response to the section 126 petitions. This section
describes the methodology used in determining each of these
subcategory's emissions level on a State-by-State basis.
(1) Large EGUs. For reasons explained in the final NOX
SIP call, EPA is proposing to calculate each State's summer season
large EGU emissions level using a specific NOX emission rate
and the projected summer season utilization of the year 2007.
Specifically, EPA proposes calculating each State's large EGU
NOX emissions level by multiplying: (1) Each State's summer
activity level in mmBtu (EPA selected the higher of each State's
overall 1995 or 1996 summer utilization), by (2) each State's projected
growth between 1996 and 2007 (using the IPM model), by (3) a
NOX rate of 0.15 lb/mmBtu. The resulting figure, in lbs, was
divided by 2000 (lbs per ton) to determine tons.
In general, new units built to meet economic growth are lower
emitting than the older units they augment or replace. Thus, though the
industry's fuel utilization may increase over time, the industry's
average NOX rate may decrease as newer, cleaner units are
built and operated, and total emissions may or may not increase.
The EPA proposes to incorporate growth in industrial activity when
determining the large EGU emissions level, and thus accommodate new
sources into the section 126 remedy. Specifically, EPA projects each
State's projected change in utilization from current levels to the year
2007 and sets an emissions level based on that future year's
utilization. This approach directly accommodates industrial growth.
Additionally, this was the type of approach taken in the final
NOX SIP call in determining various State emissions levels.
Thus, EPA is proposing to use this type of approach for addressing
activity growth and, as described below, using the IPM growth
projections. Appendix C of proposed part 97 of this notice presents the
resulting proposed large EGU emissions level per State along with each
State's projected growth from 1996 to 2007.
(2) Large Non-EGUs. For reasons explained in the final
NOX SIP call, EPA is proposing to calculate each State's
summer season large non-EGU emissions level by reducing each State's
uncontrolled non-EGU NOX emissions levels (in tons) by 60
percent and assuming growth through the year 2007. Appendix C of
proposed part 97 presents the resulting large non-EGU emissions level
and projected growth rate for each State.
iii. Development of Section 126 Trading Program Budget. Proposed
Sec. 97.40 provides that the section 126 trading program budget for
each State would equal the sum of the aggregate emission levels for
large electric generating units and large non-electric generating units
in each State calculated as discussed in Section III.B.3.c.ii of this
preamble. Under section 126, the Administrator determines the
``emission limitations and compliance schedules'' with which
NOX Budget units under Sec. 97.4 must comply. In the Federal
NOX Budget Trading Program being proposed for the section
126 remedy, these NOX ``emission limitations'' take the form
of NOX ``allowance allocations'' and are assigned based on
the aggregate emission levels for the subcategories in the trading
program. The approach to issuing allocations under a section 126 action
is similar to that under the NOX SIP call, with the
exception that under Sec. 96.40, the State permitting authority, rather
than the Administrator, determines, through the SIP, the total amount
of allowable NOX emissions apportioned to NOX
Budget units.
iv. Timing Provisions. Proposed Sec. 97.41 sets forth the
provisions for when the Administrator will issue allocations of
NOX allowances to NOX Budget units. Under the
Federal NOX Budget Trading Program, the Administrator
(rather than the State permitting authority) determines the
NOX allowance allocations, as well as records them in the
NOX Allowance Tracking System. Thus, proposed Sec. 97.41
does not provide, or set deadlines, for the permitting authority's
submission of allocations to EPA. However, as discussed in the final
NOX SIP call, EPA believes it is important to issue the
allocations at least a couple years into the future to provide some
predictability for sources in their control planning and build
confidence in the market. Therefore, under part 97, the Administrator
will issue NOX allowances in EPA's NOX Allowance
[[Page 56315]]
Tracking System (NATS) by April 1 of every year for the control period
that is three years later. For example, EPA would issue the allocations
for the 2003 control period by April 1, 2000, for those sources for
which a finding has been triggered under section 126 at this time. For
those sources for which a finding is not triggered by April 1, 2000,
but for which a final finding is automatically triggered on May 1,
2000, EPA would issue the allocations for the 2003 control period to
NATS as soon as practicable in the year 2000, consistent with the
allocations finalized with this rulemaking. In both cases, EPA would
issue the allocations for the 2004 control period by April 1, 2001,
etc. so that the allocations are always known three years in advance.
These provisions are consistent with the minimum timing requirements
specified in the final NOX SIP call rulemaking.
As stated in the previous paragraph, EPA will issue allocations in
the NATS on an annual basis three years prior to the relevant control
period. However, EPA proposes to use the same allocations for the first
three years of the program (based upon one of the proposed
methodologies described below), unless a State replaces the section 126
action with its own allocations in an approved SIP. The EPA proposes
constant allocations for the first three control periods to provide
more consistency and certainty and to build market confidence during
the start-up phase of the program. Therefore, while the Agency will not
record the allocations in unit accounts until April 1 of the year three
years preceding each relevant control period, the allocations for 2004
and 2005 will be the same as the allocations for the 2003 control
period. However, if a State, as part of an approved SIP, submits
allocations for the 2004 control period to EPA prior to April 1, 2001,
or for the 2005 control period prior to April 1, 2002, the State's
allocations will replace the allocations EPA planned to issue for the
relevant control season. By issuing allocations into accounts one year
at a time, EPA is providing States the ability to replace a section 126
action with an approved SIP while still ensuring that sources receive
allocations at least three years prior to the relevant control season.
After the initial three year period, EPA may update its allocations
on an annual basis three years prior to the relevant control season. As
discussed in the final NOX SIP call, updating allocations on
an annual basis (three years ahead) is intended to allow the allocation
system to accommodate changes in market conditions.
The EPA is proposing these part 97 provisions for the reasons set
forth in the final NOX SIP call concerning part 96 and in
order to minimize differences between the Federal and State
NOX Budget Trading Programs.
v. NOX Allowance Allocation Methodology. The EPA
proposes that part 97 include the methodology that the Administrator
will use for allocating NOX allowances to NOX
Budget units. While in part 96 the Agency lays out an optional
allocation methodology that may be used by a State permitting authority
for issuing allocations, part 97 will prescribe the methodology that
the Administrator would use.
(1) EGUs. The EPA requests comment on three separate methodologies
that the Administrator could use for the initial allocation period (the
control periods in 2003 through 2005) for electricity generating units.
In whichever of these methodologies the Agency finalizes, the total
number of allowances issued would equal the portion of the section 126
trading program budget in each State attributed to large electricity
generating units (calculated as described in Section III.B.3.c.ii of
this preamble by multiplying a specified emission rate by a State's
summer activity level projected to 2007). The first option is to
allocate allowances based on the product of an emission rate in pounds
of NOX/mmBtu and the mmBtus of energy utilized for all units
in the Federal NOX Budget Trading Program; the proposed part
97 describes this approach. The second option is to allocate allowances
to fossil-fuel-fired electric generating units in the Federal
NOX Budget Trading Program based on the product of an
emission rate in pounds of NOX/kWh and the kWh of
electricity generated. A third option considered by EPA would allocate
allowances to all large electric generating units, regardless of fuel
type, in the States affected by the section 126 rulemaking based on
their electricity generated. For the second and third options, EPA
would use a surrogate for electricity generation data where electricity
generation data is not available. The EPA solicits comment on these
three methodologies.
With regard to the allocation methodology to be used by the
Administrator for the control periods starting in 2006, EPA requests
comment on the same three general methodologies mentioned in the
previous paragraph. To facilitate the use of the second and third
approaches for the control periods in 2006 and thereafter, EPA proposes
to work with stakeholders to design a system based on electricity
generation that could be used after the initial allocation period. The
EPA plans to propose an allocation system based on electricity
generation in 1999 and finalize the approach in 2000. Appropriate data
could then be measured and collected at NOX Budget units
during the control periods in the years 2001 and 2002. When it becomes
available, this approach could be incorporated into part 97 if the
Agency decides to allocate allowances based on electricity generation.
For whichever of these three allocation methods the Agency selects,
EPA proposes to use the average of the data for the two highest control
periods for the years 1995, 1996, and 1997 in determining an electric
generating unit's allocation for the control periods in 2003, 2004, and
2005. This approach using data from 1995, 1996, and 1997 differs
slightly from the way the aggregate emission level was calculated for
the EGU subcategory. As explained in Section III.B.3.c.ii of this
preamble, EPA calculated the aggregate emission level based upon the
greater of the State heat input data from 1995 or 1996. However, the
Agency believes it is useful to base the first three years of
allocations to individual units on operating data reflecting the
average of the highest of two out of the three most recent years. In
this way, the initial allocations better represent the operation of
particular units.
Once several years of allocations have been built into the system,
the Agency believes it is possible to move to an annually updating
allocation system that calculates allocations based on operating data
from a single year. Using data from a single year as a basis for
allocations enables the Agency to develop an updating allocation system
that can reflect changes in utilization or electricity generation. By
this time, the trading market should be more established and companies
will have several years of experience with the program. Therefore,
companies will better be able to accommodate variations in single year
allocations through the trading market and company-wide compliance
strategies. Therefore, after the initial period of allocations, EPA
would use data measured during the control period of the year that is
four years before the year for which allocations are being calculated.
Furthermore, for reasons discussed in the final NOX SIP
call, EPA proposes the establishment of an allocation set-aside account
for new units (units that commence operation during or after the period
on which general NOX allowance allocations are based) to be
used in whichever allocation methodology EPA adopts equaling 5 percent
of the section
[[Page 56316]]
126 trading program budget in each State in 2003, 2004, and 2005 and 2
percent of the section 126 trading program budget in each State in the
subsequent years. The Agency believes that if a new source set-aside is
employed, it should be large enough to provide allocations to all new
units entering the Federal trading program. Based on analyses EPA
conducted using the Integrated Planning Model (IPM) and on the Agency's
proposal to reallocate by April 1, 2003 for the control period in 2006,
5 percent appears to be a reasonable portion of NOX
allowances to set-aside for new units in the initial three years of the
program and 2 percent for the subsequent years.
However, while 5 percent (and 2 percent) may be an appropriate
region-wide average, an individual State may experience either more or
less growth in new sources during the relevant time period. The EPA
calculated the State-specific aggregate emission levels for each
subcategory using State-specific growth rates (see the rulemaking
docket). Therefore, EPA solicits comment on using State-specific growth
rates to determine the appropriate size of a State new source set-
aside. Additionally, the 5 percent (and 2 percent) numbers were
calculated based upon estimated growth in utilization by new sources
and therefore may be more appropriate when the first proposed
allocation methodology is employed. The EPA solicits comment on the use
of a different percentage for the set-aside if the Agency adopts an
electricity generation-based allocation system.
Using each of the three allocation methodologies on which EPA
solicits comment, the Agency has calculated unit specific allocations.
Two of the three sets of unit-specific allocations are in appendix A of
proposed part 97, the third set is included in the rulemaking docket.
The EPA is providing these unit specific allocations to solicit comment
on the underlying data used in these allocations and the methodologies
employed in determining the allocations. The Agency will select and
describe a set of allocations for all sources potentially subject to
the section 126 rulemaking in the final notice. The EPA would issue the
finalized set of the 2003 control period allocations in the NATS by
April 1, 2000 for those sources for which a finding has been triggered
under section 126 at this time. For those sources for which a finding
is not triggered by April 1, 2000, but for which a final finding is
automatically triggered on May 1, 2000, EPA would issue the allocations
for the 2003 control period to NATS as soon as practicable in the year
2000, consistent with the allocations finalized with this rulemaking.
For the first allocation approach in part 97, EPA determined
initial unadjusted allocations to existing electric generating
NOX Budget units by multiplying a NOX emission
rate of 0.15 lb/mmBtu by the units' historical heat input calculated by
taking the average of the heat input for the two highest control
periods for the years 1995, 1996, and 1997. The Agency used the heat
input data reported to EPA in quarterly reports during ozone season for
utilities affected under the Acid Rain Program. For non-utility
electricity generators, EPA used heat input information reported to EIA
on EIA Form 867.
After determining the initial unadjusted unit allocations, EPA
adjusted the allocation for each unit upward or downward to match the
portion of the section 126 trading program budget in the State
attributed to large electricity generating units. Then, the Agency
adjusted the allocation for each unit in the State proportionately so
that the total allocations equaled 95 percent of the portion of the
section 126 trading program budget in the State attributed to large
electricity generating units. This created a new source set-aside of 5
percent.
For the second allocation approach, EPA multiplied the unit heat
input in mmBtu and the generator heat rate 14 associated
with the generation for that unit, in Btu/kWh, to determine each unit's
associated historical electrical generation in kWh.15 For
non-utility electricity generators, EPA used heat input from OTAG's
database (1995 data) and the average heat rate values found below in
Table III-1. The Agency used this indirect approach to calculate
electrical output because EPA did not have access to unit-specific
generation data for non-utility electricity generators. The EPA used
average heat rate values for generators for which heat rates were not
publicly available, as shown in the table below.
---------------------------------------------------------------------------
\14\ Utilities report their generator-specific heat rates to EIA
on EIA Form 860.
\15\ The EPA used the average generation for the ozone season
during the highest two of the years from 1995 through 1997, similar
to the approach with heat input.
Table III-1.--Average Utility Generator Heat Rates
------------------------------------------------------------------------
Average
Unit and fuel type Generator size (MW) heat rate
(Btu/kWh)
------------------------------------------------------------------------
Combustion Turbine (gas or No. 2 fuel 50 14250
oil/diesel). >50 13200
Combined Cycle Turbine (gas or No. 2 100 11100
fuel oil/diesel). >100 8500
Oil-or Gas-fired Steam Boiler......... 400 10600
>400 10000
Coal-fired Boiler..................... 500 10400
>500 9800
------------------------------------------------------------------------
Some units are cogenerators, which are electrical generators that
divert part of their steam to provide steam output, rather than to
generate electricity. The Agency calculated output from cogenerating
units as described in the previous paragraph. That approach assumes
that heat input is converted into electricity at a particular
efficiency. The EPA's proposed approach does not account for the fact
that steam generation is generally more efficient than electricity
generation. The EPA encourages commenters to provide the Agency
electrical output data and steam output data to determine the
efficiency of cogenerating units.
To determine the individual unit allocations, EPA determined the
total electricity generation from all affected electricity generating
units within each State as estimated in the previous paragraphs and
calculated each unit's share of the total State electricity generation.
Each unit was then assigned an allocation based upon its share of
electricity generation. For example, if the Agency calculated that a
unit contributed 0.4 percent of a State's total electricity generation,
then it would receive 0.4 percent of the section 126 trading program
budget in the State attributed to large fossil-fuel-fired electricity
generating units. After determining the initial unadjusted allocation,
the Agency adjusted the allocation for each unit proportionately so
that the total allocation equaled 95% of the portion of the section 126
trading program budget for the State attributed to large fossil-fuel-
fired electricity generating units (to create the new source set-
aside).
The EPA is also proposing a third allocation approach which would
provide allowances to all electricity generators in the applicable
region regardless of the energy source. For fossil fuel-fired power
plants, EPA used the approach described above in determining the
electrical generation
[[Page 56317]]
from individual combustion units. For nuclear power plants and
hydroelectric plants, EPA used electrical generation reported by
utilities to EIA on EIA Form 759. The Agency was unable to find data
for all plants. The Agency solicits comment on these methods for
determining electricity generation data. The EPA also requests comment
on the data itself and solicits any additional information for the
plants for which EPA has not found data.
The Agency determined the initial unadjusted allocations in the
same manner as described for the electricity generation-based
allocations to fossil-fuel-fired units only. That is, the Agency
determined the total electricity generation within each State,
calculated each unit's share of the total electricity generation, and
calculated an allocation based upon that share of the section 126
trading program budget for the State attributed to large electricity
generating units. The Agency then adjusted the allocation for each unit
proportionately so that the total allocation equaled 95 percent of the
portion of the section 126 trading program budget for the State
attributed to large electricity generating units.
For each of these three allocation methodologies, the Agency
solicits comment on the data used to determine the allocations.
Electricity generators, and utilities in particular, already report
many of these data to Federal or State government agencies. The
necessary data and their sources include:
1. For each plant:
a. Plant name--as reported to U.S. EPA and EIA; if not currently
reporting to Federal government, then as reported to the state
environmental agency
b. ORISPL number, if available (or other unique identification
number for the plant, if no ORISPL number exists)--as reported to U.S.
EPA and EIA; if not currently reporting to Federal government, then as
reported to the state environmental agency
iii. State postal abbreviation and county FIPS code as reported to
U.S. EPA and EIA; if not currently reporting to Federal government,
then as reported to the state environmental agency
iv. Monitoring locations at the plant (e.g., stacks or fuel pipes
where monitoring equipment would be located) for existing monitoring
equipment, as reported to U.S. EPA, or to the state environmental
agency
2. For each unit (boiler or combustion turbine) at the plant:
a. An identification designation (e.g., 1, CT2) as reported to U.S.
EPA and EIA; if not currently reporting to Federal government, then as
reported to the state environmental agency
b. A description of each unit (e.g. combustion turbine, coal-fired
wet-bottom boiler) as reported to U.S. EPA and EIA; if not currently
reporting to Federal government, then as reported to the State
environmental agency or state utility commission
c. Fuel or energy source used--as reported to the U.S. Energy
Information Administration (EIA) or to the state utility commission
d. Heat input (mmBtu) in May 1 through September 30 of 1995, 1996
and 1997 as reported to U.S. EPA and EIA;
e. Estimated historical NOX mass emissions in May 1
through September 30 of 1995, 1996 and 1997 (as reported to the U.S.
EPA or the state environmental agency).
3. For each electrical generator at the plant:
a. Generation identification designation--as reported to U.S. EPA
and EIA; if not currently reporting to Federal government, then as
reported to the state utility commission
b. Nameplate capacity in MWe-as reported to U.S. EPA and EIA; if
not currently reporting to Federal government, then as reported to the
state utility commission.
c. Electrical generation (MWh)in May 1 through September 30 of
1995, 1996 and 1997--as reported to EIA;
4. For each steam turbines at the plant that is used to generate
steam output instead or in addition to electricity:
a. An identification designation
b. Capacity, in mmBtu/hr output rate
c. Steam output (mmBtu) (not used for electrical generation) in May
1 through September 30 of 1995, 1996 and 1997
The Agency believes these data are needed both to determine the
output of each source and to establish a unique identity for each
source and its units. The EPA requests comment on the specific data as
well as the type of data supporting the proposed allocations under part
97.
(2) Non-EGUs. For any allocation methodology adopted, the total
number of allocations issued to non-electric generating units would
equal the portion (less the 5 percent set-aside discussed below) of the
section 126 trading program budget for each State attributed to large
non-electricity generating units (calculated as described in Section
III.B.3.c.ii of this preamble by reducing each State's uncontrolled
non-EGU NOX emissions level by 60 percent and assuming
activity growth through 2007). At this time, the Agency proposes to use
heat input as the basis for determining allocations for large non-
electricity generating units in the Federal NOX Budget
Trading Program. The EPA proposes this basis for both the initial
allocation period of 2003 through 2005 and for subsequent years of the
program. This differs from the method used to determine the aggregate
emission level for non-electric generating units (a percentage
reduction from historical emissions) because at the time the aggregate
level was determined (during the SIP call proposal process), heat input
data for individual units was not available. Distributing allocations
on a heat-input basis provides a fuel-neutral method of allocating to
the units in the trading program similar to the allocation approaches
proposed for the electric generating units. Heat-input-based
allocations also allow for reallocating in the future (to accommodate
new units) whereas allocations based upon a specific percentage
reduction do not. Heat input data is now available for use in
developing allocations, and the Agency solicits comment on the data as
well as the use of heat input in developing allocations.
At this time, the Agency is not aware of any databases on steam
output information for industrial boilers. Therefore, for combustion
sources other than electrical generators, EPA finds that it is most
appropriate to base allocations upon heat input. However, EPA requests
comment on any methods for distributing allowances on an output basis
to non-electricity generating units. Comments should address the
availability, quality, and appropriateness of the data for regulatory
purposes and/or methods to obtain such data.
For the non-electricity generating units subject to the Federal
trading program, EPA proposes to use 1995 heat input data in the
allocation calculation for the control periods in 2003, 2004, and 2005.
The 1995 data are the most recent data the Agency knows are currently
available for non-electricity generating units. After this initial
period of allocations, as with the electric generating units, the
Agency will use data measured during the control period of the year
that is four years before the year for which allocations are being
calculated.
As was done for electricity generating units, the Agency has
calculated unit specific allocations for large non-electricity
generating units. These unit specific allocations are provided in
Appendix A of proposed part 97. The EPA solicits comment on the
underlying data used in these allocations and the methodology employed
in determining the allocations. The Agency plans to describe a set of
allocations in the final notice. The EPA would issue the final
allocations for the control period in
[[Page 56318]]
2003 by placing them in the NATS by April 1, 2000 for those sources for
which a finding has been triggered under section 126 at this time. For
those sources for which a finding is not triggered by April 1, 2000,
but for which a final finding is automatically trigger on May 1, 2000,
EPA would issue the allocations for the 2000 control period to NATS as
soon as practicable in the year 2000, consistent with the allocations
finalized with this rulemaking.
For the non-electricity generating unit allocations proposed in
today's notice, EPA determined initial unadjusted allocations to
existing non-electric generating NOX Budget units by
multiplying a NOX emission rate of 0.17 lb/mmBtu (the
average emission rate for existing non-electricity generating budget
units after controls are in place) by the units' historical heat input
(described above as 1995 control season data).
After determining the initial unadjusted unit allocations, EPA
adjusted the allocation for each unit upward or downward to match the
portion of the section 126 trading program budget for the State
attributed to large non-electricity generating units. Then, the Agency
adjusted the allocation for each unit in the State proportionately so
that the total allocations equaled 95 percent of the portion of the
section 126 trading program budget for the State attributed to large
non-electricity generating units.
The Agency proposes to set-aside 5 percent of the non-electricity
generating unit allocations to be consistent with the allocation for
electricity generating units. The EPA solicits comment on this approach
and the proposed size of the set-aside.
(3) Treatment of New Sources. As discussed in previous sections,
the Agency has proposed in part 97 a set-aside for new sources
consistent with the provisions of part 96. New electricity generating
units and non-electricity generating units required to participate in
the Federal NOX Budget Trading Program will have access to
this set-aside. In 2003, 2004, and 2005, each State set-aside would
initially hold NOX allowances equal to 5 percent of the
NOX allowances in the section 126 trading program budget in
the State. Starting in 2006, each State set-aside would originally hold
2 percent of the NOX allowances in the section 126 trading
program budget in the State. At the end of each relevant control
period, EPA will return any allowances remaining in the account on a
pro-rata basis to the units that had received an original allocation
that had been adjusted to create the new source set-aside in the State.
The NOX allowances in the allocation set-aside would be
available to any unit that would otherwise be eligible for an
allocation in a control period but did not receive one because the unit
commenced operation during or after the period on which the
NOX allowance allocations for existing units were based. To
receive NOX allowances from the allocation set-aside, the
NOX Authorized Account Representative for a unit would
submit a NOX allowance request to the Administrator. The
request could be for no more than 5 consecutive control periods,
starting with the control period during which the unit is projected to
commence operation and ending with the control period preceding the
control period for which it has sufficient data to receive an
allocation with existing budget units. For the sixth year or later (and
possibly earlier), there would be sufficient operating data for the
unit to be incorporated into the NOX allowance allocations
with existing NOX Budget units. The NOX allowance
request would need to be submitted prior to May 1 of the first control
period for which NOX allowances are requested and after the
date on which the State issues a permit to construct the new unit.
Consistent with part 96, the allowances would be issued to new
units on a first-come first-served basis. For the first allocation
approach proposed for electric generating units, allowances to new
electric generation units would be issued at a rate of 0.15 lb/mmBtu
multiplied by the unit's maximum design heat input. Following each
control period, the unit would be subject to a reduced utilization
calculation. EPA would deduct NOX allowances following each
control period based on the unit's actual utilization. Because the
allocation for a new unit from the set-aside is based on maximum design
heat input, this procedure adjusts the allocation by actual heat input
for the control period of the allocation. This adjustment is a
surrogate for the use of actual utilization in a prior baseline period
which is the approach used for allocating NOX allowances to
existing units.
For new non-electric generating units, allowances would be issued
at the average emission rate (e.g., .17 lbs/mmBtu) for existing budget
units (after controls are in place) multiplied by the budget unit's
maximum design heat input. Following each control period, the source
would be subject to a reduced utilization calculation similar to that
described above for electric generating units.
For the second and third allocation approaches proposed for
electric generating units, allowances to new electric generating units
would be issued at the average emission rate (in lbs/kWh) for existing
budget units (after controls are put in place) multiplied by the
maximum design electrical generation derived from operation of the new
budget unit. Following each control period, the budget unit would be
subject to a reduced utilization calculation similar to that described
above under the first approach.
d. Compliance Supplement Pool. This notice proposes to establish
Federal emissions limits for sources found to significantly contribute
to ozone nonattainment problems in a petitioning State. These sources
would be required to comply with the emissions limits by May 1, 2003.
As discussed in the final NOX SIP call and the technical
support document ``Feasibility of Installing NOX Control
Technologies By May 2003,'' EPA believes that this compliance date is a
feasible and reasonable deadline. However, EPA received comments for
the NOX SIP call expressing concern that some sources may
encounter unexpected problems installing controls by this deadline
that, in turn, could cause unacceptable risk for a source and its
associated industry. Commenters explicitly expressed concern related to
the electricity industry, stating that the deadline could adversely
impact the reliability of the electricity supply.
In the NOX SIP call, EPA addressed these compliance
concerns by providing additional flexibility for sources to comply with
the requirements. The EPA is proposing that similar flexibility
mechanisms be provided in part 97. First, EPA is proposing that part 97
include banking provisions as discussed in Section III.B.2.h. Second,
EPA is proposing that part 97 include a compliance supplement pool that
may be used by sources to cover excess emissions during the 2003 and
2004 ozone seasons that are unable to meet the compliance deadline. The
proposed part 97 includes a separate compliance supplement pool that
would be available to the sources in each State identified in this
proposal.
i. Size of the Compliance Supplement Pool. The EPA proposes to use
the same compliance supplement pools on a State-by-State basis as were
included in the final NOX SIP call. The justification for
the size of the State pools is included in the final NOX SIP
call. Table III-2 shows the compliance supplement pool that would be
[[Page 56319]]
available to sources in each State identified in this proposal.
Table III-2. Compliance Supplement Pools (Tons of NOX)
------------------------------------------------------------------------
Compliance
State supplement
pool
------------------------------------------------------------------------
Alabama.................................................... 10,361
Connecticut................................................ 559
Delaware................................................... 417
District of Columbia....................................... 0
Illinois................................................... 17,455
Indiana.................................................... 19,738
Kentucky................................................... 13,018
Maryland................................................... 3,662
Massachusetts.............................................. 285
Michigan................................................... 15,359
Missouri................................................... 10,469
New Jersey................................................. 1,722
New York................................................... 1,831
North Carolina............................................. 10,624
Ohio....................................................... 22,947
Pennsylvania............................................... 13,716
Rhode Island............................................... 0
Tennessee.................................................. 12,093
Virginia................................................... 6,108
West Virginia.............................................. 16,937
------------------------------------------------------------------------
ii. Distribution of the Compliance Supplement Pool to Sources. In
the final NOX SIP call, EPA provides States with two options
for distributing the pool to sources. One option is for a State to
distribute some or all of the pool to sources that generate early
reductions during ozone seasons prior to May 1, 2003. The second option
is for a State to run a public process to provide tons to sources that
demonstrate a need for a compliance extension. Tons that are not
distributed by a State prior to May 1, 2003 will be retired by EPA. A
State wishing to use the compliance supplement pool under the
NOX SIP call may divide the pool and make some of it
available to sources through both options, or may use only one of the
options for distributing the pool to sources prior to May 1, 2003.
Based on these options, EPA is soliciting comment on a number of
approaches for distributing the pool to sources under part 97.
First, EPA solicits comment as to whether the compliance supplement
pool should be distributed by EPA to sources or distributed by EPA to
the States that have sources included in this proposal. If the pools
were distributed to States, the States would then be able to distribute
the pool to sources. Part 97 is primarily designed to be implemented
and administered directly by EPA. For this reason, it may be most
efficient for EPA to retain the responsibility of distributing the pool
to sources. However, it may be possible to provide more flexibility in
the use of the pool for different sources if States were provided the
distribution responsibility.
Second, provided that EPA decides to retain the responsibility of
distributing the pool to sources, EPA solicits comment on two options
for distribution. First, EPA solicits comment on distributing the
compliance supplement pool only for early reductions. Under this
option, the Agency would distribute allowances from the compliance
supplement pool based upon the optional methodology the Agency laid out
in the final NOX SIP call. Using that methodology, the
Agency could issue early reduction credits for the 2001 and 2002 ozone
season to units that have installed part 75 monitoring by the 2000
control season, have reduced their emission rate in 2001 or 2002
relative to their rate in 2000 by at least 20 percent, and are
operating in the year(s) in which they are applying for early reduction
credits at an emission rate below 0.25 lb/mmBtu. Provided it meets all
of these criteria, a unit could request early reduction credits equal
to the difference between 0.25 lb/mmBtu and the unit's actual emissions
rate multiplied by the unit's actual heat input for the applicable
control period. The Agency laid out the reasons for adopting each of
these criteria for early reduction credits in the final NOX
SIP call. Part 97 currently describes this option.
Under this option, if the tons of NOX in the State's
compliance supplement pool exceeds the number of valid early reduction
credit requests in that State, the Agency would issue one allowance for
each ton of early reduction credit requested. Any allowances remaining
in the compliance supplement pool after all valid requests have been
granted would be retired by the Agency. If, however, the amount of
valid requests are more than the size of the State's pool, the Agency
would reduce the amount in the credit requests on a pro-rata basis so
that the requests equal the size of the State's pool. After the
requests have been reduced, the Agency would then issue allowances
based on the remaining size of each credit request.
With this option, sources in States in the Ozone Transport
Commission (OTC) that are subject to this section 126 action would be
allowed to bring their banked allowances into the Federal
NOX Budget Trading Program as early reduction credits
provided the sum of the banked allowances in any State does not exceed
the size of the State's compliance supplement pool. As is the case
under this option for States outside of the OTC, any remaining credits
in the compliance supplement pool would be retired. If the
NOX Budget units in an OTC State hold banked allowances from
the OTC program in excess of the amount of credits in the State's pool,
the Agency would reduce the amount of allowances eligible for early
reduction credit on a pro rata basis.
The Agency solicits comment on the methodology for issuing early
reduction credits in this option as well as the approach that limits
the use of the compliance supplement pool to early reduction credits.
Specifically, the Agency solicits comment on alternative methods for
calculating early reduction credits. In addition, EPA solicits comment
on the approach specified for integration with the OTC Program.
The Agency also solicits comment on a second option for
distribution of the compliance supplement pool. Under this second
option, the Agency proposes that a portion of the compliance supplement
pool be given out as early reduction credits and the remaining portion
be reserved for sources that demonstrate a need for the compliance
supplement. As described in the preamble to the final NOX
SIP call, sources would be responsible for demonstrating to the Agency
and the public achieving compliance by May 1, 2003 would create undue
risk either to its own operation or associated industry. The
administrator of the compliance supplement pool would provide the
public an opportunity to comment on the validity of the need for this
``direct distribution'' of the compliance supplement.
Under this option, the Agency would grant early reduction credits
using the method described in the first option (or some variation of
that approach) before allowing sources access to the direct
distribution credits from the compliance supplement pool. The Agency
proposes to address OTC banked allowances held by sources subject to a
section 126 action as suggested in the first option. To ensure that the
compliance supplement is only provided to sources that truly need a
compliance extension, the remaining credits in the compliance
supplement pool would be given out to an owner or operator of a source
that demonstrates the following:
The process of achieving compliance by May 1, 2003 would
create undue risk for the source or its associated industry. For
electric generating units, the demonstration should show that
installing controls would create unacceptable risks for the reliability
of the electricity supply during the time of installation. This
demonstration would include a showing that it was not feasible to
import electricity from other systems during the
[[Page 56320]]
time of installation. Non-electricity generating sources may also be
eligible for the compliance supplement based on a demonstration of risk
comparable to that described for the electricity industry.
It was not possible to compensate for delayed compliance
by generating early reduction credits at the source or by acquiring
credits generated by other sources.
It was not possible to acquire allowances or credits for
the 2003 ozone season from sources that will make reductions beyond
required levels during the 2003 ozone season.
The Agency solicits comment on this option that distributes the
compliance supplement pool both through early reduction credits as well
as direct distribution. Specifically, the Agency requests comment on
the number of credits to reserve for direct distribution, the
methodology used for direct distribution, and options for public review
of the direct distribution. The Agency also solicits comment on the
appropriate administrator of the direct distribution.
Under any of the options described above, the Agency proposes that
NOX allowances issued from the compliance supplement pool
would only be available for sources to use for compliance in the 2003
or 2004 control periods. Any NOX allowance issued from the
compliance supplement pool that is not used for compliance in 2003,
would be considered to be ``banked'' for the 2004 control period. The
Agency proposes to retire any NOX allowance issued from the
compliance supplement pool that is not used in either the 2003 or 2004
control period at the end of the 2004 true-up period for the reasons
cited in the preamble to the final NOX SIP call.
e. Emissions Monitoring and Reporting. Subpart H of today's
proposed rule addresses monitoring and reporting requirements
including, among other things, general requirements, initial
certification and recertification procedures, out of control periods,
notifications, recordkeeping and reporting, and petitions. These
provisions are essentially the same as the monitoring-related
provisions of part 96, with cross references to the appropriate
sections of part 97. The differences between the provisions reflect the
fact that administration of the monitoring requirements is overseen by
EPA, rather than by EPA and the permitting authority as is the case in
the State NOX Budget Trading Program. As a result, for
example, monitoring certification applications are submitted to the
Administrator and the appropriate EPA Regional Office in addition to
the permitting authority, and the Administrator, not the permitting
authority, will act on the applications. Further, the Administrator
handles all audit decertifications and all petitions for alternatives
to the monitoring requirements. Another difference is that in the State
NOX Budget Trading Program, EPA included heat input
monitoring requirements that States might choose to adopt if they were
basing their allocation methodologies on heat input. The proposed
Federal NOX Budget Trading Program bases its allocation
approach on heat input. Therefore, EPA has included the heat input
monitoring and reporting requirements in proposed part 97. Note that as
explained in Section III.3.c.5 of the preamble, EPA is taking comment
on three different allocation methodologies. Depending on the
methodology chosen, monitoring and reporting requirements would vary.
The EPA is proposing these part 97 provisions for the reasons set
forth both in the proposed NOX SIP call (63 FR 25938-40) and
the final NOX SIP call, and in order to minimize differences
between the Federal and State NOX Budget Trading Programs.
In particular, for the reasons set forth in the NOX SIP
call, EPA proposes that NOX Budget units be required to meet
the monitoring and reporting requirements in a new subpart H of 40 CFR
part 75, the Acid Rain Program regulations (63 FR 25938-40). The EPA
has promulgated these revisions part 75 to establish NOX
mass monitoring requirements and provide greater flexibility to
regulated sources in conjunction with the final NOX SIP call
rule.
f. Opt-ins. Subpart I of today's proposed rule addresses the opt-in
process and procedures applicable to operating units that are not
NOX Budget units under Sec. 97.4, but are located in a State
that is included in the Federal NOX Budget Trading Program
and wish to voluntarily enter (i.e., opt into) the trading program. The
opt-in provisions can further reduce the cost of achieving
NOX reductions by allowing these units to join the
NOX Budget Trading Program and make incremental, lower cost
reductions, freeing NOX allowances for use by other
NOX Budget units. There are potentially individual sources
not included in the trading program that may emit significant amounts
of NOX and are able to achieve cost-effective reductions;
allowing these sources to join the program would reduce the overall
cost of compliance for the program. The EPA proposes in subpart I to
allow individual combustion sources that are located in a State for
which a section 126 remedy in promulgated, vent to a stack, and can
monitor NOX mass emissions, the opportunity to opt-in to the
Federal program for purposes of the section 126 remedy. The EPA
solicits comment on the appropriateness of these opt-in provisions.
Subpart I addresses, among other things, the applicability
requirements, allocations, procedures for applying for a NOX
Budget opt-in permit, the process of reviewing and approving or denying
the permit, contents of the permit, procedures for withdrawing as a
NOX Budget opt-in source, and changes in regulatory status.
The provisions of this subpart are similar to the opt-in provisions in
part 96, with cross references to the appropriate sections in part 97,
though the Administrator plays a greater role than in part 96 with
regard to actions on opt-in permits, allocations, and other related
opt-in submissions. For example, under the Federal trading program,
NOX budget opt-in permit applications are submitted to both
the Administrator and the permitting authority, but only the
Administrator may determine whether the unit qualifies as a
NOX Budget opt-in source. Furthermore the Administrator,
rather than the permitting authority, allocates allowances to sources
in the Federal NOX Budget Trading Program. The EPA is
proposing these part 97 provisions for the reasons set forth both in
the proposed NOX SIP call (63 FR 25940-42) and the final
NOX SIP call, and in order to minimize differences between
the Federal and State NOX Budget Trading Programs.
g. Program administration. As discussed above, the Federal
NOX Budget Trading Program would be run by EPA. The EPA
would identify the units covered by the program, determine and record
the NOX allowance allocations, receive and review monitoring
plans and monitoring certification applications, and take the lead in
enforcement. As discussed above, States would still be responsible for
permitting.
C. New Source Review
As discussed in the proposed and final NOX SIP call, the
EPA believes that nonattainment New Source Review (NSR) offset
requirements of the CAA can be met using the mechanism of the State
NOX Budget Trading Program under part 96. However, because
the Agency is continuing to evaluate a number of complex issues
involved with integrating NSR and the trading program, it will not be
providing guidance at this time. The EPA intends
[[Page 56321]]
to provide such guidance as soon as possible. At that time, the EPA
will also address integrating NSR with the trading program under part
97.
IV. Non-Ozone Benefits to NOX Reductions
In addition to contributing to attainment of the ozone NAAQS,
decreases of NOX emissions will also likely help improve the
environment in several important ways. On a national scale, decreases
in NOX emissions will also decrease acid deposition,
nitrates in drinking water, excessive nitrogen loadings to aquatic and
terrestrial ecosystems, and ambient concentrations of nitrogen dioxide,
particulate matter, and toxics. On a global scale, decreases in
NOX emissions will, to some degree, reduce greenhouse gases
and stratospheric ozone depletion. Thus, management of NOX
emissions is important to both air quality and watershed protection on
national and global scales. In its July 8, 1997 final recommendations,
OTAG stated that it ``recognizes that NOX controls for ozone
reductions purposes have collateral public health and environmental
benefits, including reductions in acid deposition, eutrophication,
nitrification, fine particle pollution, and regional haze.'' These and
other public health and environmental benefits associated with
decreases in NOX emissions are summarized
below.16
---------------------------------------------------------------------------
\16\ U.S. Environmental Protection Agency, ``Nitrogen Oxides:
Impacts on Public Health and the Environment,'' EPA-452/R-97-002,
August 1997.
---------------------------------------------------------------------------
Acid Deposition: Sulfur dioxide and NOX are the two key
air pollutants that cause acid deposition (wet and dry particles and
gases) and result in the adverse effects on aquatic and terrestrial
ecosystems, materials, visibility, and public health. Nitric acid
deposition plays a dominant role in the acid pulses associated with the
fish kills observed during the springtime melt of the snowpack in
sensitive watersheds and recently has also been identified as a major
contributor to chronic acidification of certain sensitive surface
waters.
Drinking Water Nitrate: High levels of nitrate in drinking water is
a health hazard, especially for infants. Atmospheric nitrogen
deposition in sensitive watersheds can increase stream water nitrate
concentrations; the added nitrate can remain in the water and be
transported long distances downstream.
Eutrophication: NOX emissions contribute directly to the
widespread accelerated eutrophication of United States coastal waters
and estuaries. Atmospheric nitrogen deposition onto surface waters and
deposition to watershed and subsequent transport into the tidal waters
has been documented to contribute from 12 to 44 percent of the total
nitrogen loadings to United States coastal water bodies. Nitrogen is
the nutrient limiting growth of algae in most coastal waters and
estuaries. Thus, addition of nitrogen results in accelerated algae and
aquatic plant growth causing adverse ecological effects and economic
impacts that range from nuisance algal blooms to oxygen depletion and
fish kills.
Global Warming: Nitrous oxide (N2O) is a greenhouse gas.
Anthropogenic N2O emissions in the United States contribute
about 2 percent of the greenhouse effect, relative to total United
States anthropogenic emissions of greenhouse gases. In addition,
emissions of NOX lead to the formation of tropospheric
ozone, which is another greenhouse gas.
Nitrogen Dioxide (NO2): Exposure to NO2 is
associated with a variety of acute and chronic health effects. The
health effects of most concern at ambient or near-ambient
concentrations of NO2 include mild changes in airway
responsiveness and pulmonary function in individuals with pre-existing
respiratory illnesses and increases in respiratory illnesses in
children. Currently, all areas of the United States monitoring
NO2 are below EPA's threshold for health effects.
Nitrogen Saturation of Terrestrial Ecosystems: Nitrogen accumulates
in watersheds with high atmospheric nitrogen deposition. Because most
North American terrestrial ecosystems are nitrogen limited, nitrogen
deposition often has a fertilizing effect, accelerating plant growth.
Although this effect is often considered beneficial, nitrogen
deposition is causing important adverse changes in some terrestrial
ecosystems, including shifts in plant species composition and decreases
in species diversity or undesirable nitrate leaching to surface and
ground water and decreased plant growth.
Particulate Matter (PM): NOX compounds react with other
compounds in the atmosphere to form nitrate particles and acid
aerosols. Because of their small size nitrate particles have a
relatively long atmospheric lifetime; these small particles can also
penetrate deeply into the lungs. The PM has a wide range of adverse
health effects.
Stratospheric Ozone Depletion: A layer of ozone located in the
upper atmosphere (stratosphere) protects people, plants, and animals on
the surface of the earth (troposphere) from excessive ultraviolet
radiation. The N2O, which is very stable in the troposphere,
slowly migrates to the stratosphere. In the stratosphere, solar
radiation breaks it into nitric oxide (NO) and nitrogen (N). The NO
reacts with ozone to form NO2 and molecular oxygen. Thus,
decreasing N2O emissions would result in some decrease in
the depletion of stratospheric ozone.
Toxic Products: Airborne particles derived from NOX
emissions react in the atmosphere to form various nitrogen containing
compounds, some of which may be mutagenic. Examples of transformation
products thought to contribute to increased mutagenicity include the
nitrate radical, peroxyacetyl nitrates, nitroarenes, and nitrosamines.
Visibility and Regional Haze: The NOX emissions lead to
the formation of compounds that can interfere with the transmission of
light, limiting visual range and color discrimination. Most visibility
and regional haze problems can be traced to airborne particles in the
atmosphere that include carbon compounds, nitrate and sulfate aerosols,
and soil dust. The major cause of visibility impairment in the eastern
United States is sulfates, while in the West the other particle types
play a greater role.
Justification for Rulemaking: While EPA believes the information is
important for the public to understand and, thus, needs to be described
as part of the rulemaking and RIA, there should be no misunderstanding
as to the legal basis for the rulemaking, which is described in Section
I, Background, of this notice and does not depend on the non-ozone
benefits. The non-ozone benefits did not affect the method in which EPA
determined significant contribution nor the proposed control
requirements.
V. Administrative Requirements
A. Executive Order 12866: Regulatory Impact Analysis
Under Executive Order 12866 (58 FR 51735, October 4, 1993), the
Agency must determine whether a regulatory action is ``significant''
and therefore subject to Office of Management and Budget (OMB) review
and the requirements of the Executive Order. The Order defines
``significant regulatory action'' as one that is likely to result in a
rule that may:
(1) Have an annual effect on the economy of $100 million or more or
adversely affect in a material way the economy, a sector of the
economy, productivity, competition, jobs, the environment, public
health or safety, or State, local, or tribal governments or
communities;
[[Page 56322]]
(2) Create a serious inconsistency or otherwise interfere with an
action taken or planned by another agency;
(3) Materially alter the budgetary impact of entitlements, grants,
user fees, or loan programs or the rights and obligations of recipients
thereof; or
(4) Raise novel legal or policy issues arising out of legal
mandates, the President's priorities, or the principles set forth in
the Executive Order.
The EPA believes that this action is a ``significant regulatory
action'' because it raises novel legal and policy issues arising from
the Agency's obligation to respond to the section 126 petitions, and
because the action could have an annual effect on the economy of more
than $100 million. As a result, the proposed rulemaking was submitted
to OMB for review, and EPA has prepared a RIA titled ``Regulatory
Impact Analysis of Proposed CAA Section 126 Petitions for
NOX, September 1998.'' This RIA assesses the costs,
benefits, and economic impacts associated with Federally-imposed
requirements to mitigate NOX emissions from sources
contributing to downwind nonattainment of the ozone NAAQS. Any written
comments from OMB to EPA and any written EPA response to those comments
are included in the docket. The docket is available for public
inspection at the EPA's Air Docket Section, which is listed in the
ADDRESSES section of this preamble. The RIA is available in hard copy
by contacting the EPA Library at the address under ``Availability of
Related Information'' and in electronic form as discussed above in that
same section.
The RIA for the section 126 petitions addresses the costs and
benefits associated with reducing emissions at sources affected under
the petitions in the broader context of those sources potentially
affected by the final NOX SIP call and its associated FIP.
There is a high likelihood that sources named in the section 126
petitions will also be controlled under SIPs that will be revised to
meet final NOX budgets. In the event that States fail to
submit approvable SIPs, FIPs will be enacted. Therefore, from the
perspective of a regulatory analysis that is focused on the year 2007,
the sources named in section 126 petitions will be complying with
either State or Federal regulations of generally equivalent stringency.
The RIA for the NOX SIP call concludes that the national
annual cost of possible State actions to comply with the NOX
SIP call are approximately $1.7 billion (1990 dollars). The sources
named in the section 126 petitions will bear some portion of that total
cost. The associated benefits, in terms of improvements in health,
visibility, and ecosystem protection, that EPA has quantified and
monetized range from $1.1 billion to $4.2 billion, with EPA's best
estimate being $3.4 billion. Due to practical analytical limitations,
the EPA is not able to quantify and/or monetize all potential benefits
of the NOX SIP call action.
B. Impact on Small Entities
1. Regulatory Flexibility
The Regulatory Flexibility Act (RFA), as amended by the Small
Business Regulatory Enforcement Fairness Act (SBREFA), provides that
whenever an agency is required to publish a general notice of proposed
rulemaking, it must prepare and make available an initial regulatory
flexibility analysis, unless it certifies that the proposed rule, if
promulgated, will not have ``a significant economic impact on a
substantial number of small entities.''
In the process of developing this rulemaking, EPA worked with SBA
and OMB and obtained input from small businesses, small governmental
jurisdictions, and small organizations. On June 23, 1998, EPA's Small
Business Advocacy Chairperson convened a Small Business Advocacy Review
Panel under section 609(b) of the RFA as amended by SBREFA. In addition
to its chairperson, the Panel consists of EPA's Director of the Office
of Air Quality Planning and Standards within the Office of Air and
Radiation, the Administrator of the Office of Information and
Regulatory Affairs within the OMB, and the Chief Counsel for Advocacy
of the SBA.
As described below, this Panel conducted an outreach effort and
completed a report on the section 126 proposal. The report provides
background information on the proposed rule being developed and the
types of small entities that would be subject to the proposed rule,
describes efforts to obtain the advice and recommendations of
representatives of those small entities, summarizes the comments that
have been received to date from those representatives, and presents the
findings and recommendations of the Panel; the completed report,
comments of the small entity representatives, and other information are
contained in the docket for this rulemaking.
It is important to note that the Panel's findings and discussion
are based on the information available at the time this report was
drafted. The EPA is continuing to conduct analyses relevant to the
proposed rule, and additional information may be developed or obtained
during the remainder of the rule development process. The Panel makes
its report at a preliminary stage of rule development and its report
should be considered in that light. At the same time, the report
provides the Panel and the Agency with an opportunity to identify and
explore potential ways of shaping the proposed rule to minimize the
burden of the rule on small entities while achieving the rule's
statutory purposes. Any options the Panel identifies for reducing the
rule's regulatory impact on small entities may require further analysis
and/or data collection to ensure that the options are practicable,
enforceable, environmentally sound and consistent with the statute
authorizing the proposed rule.
2. Outreach to Small Entity Representatives
In consultation with the SBA, EPA invited small entity
representatives to participate in its outreach efforts on this
proposal. The EPA, OMB, and SBA held an initial outreach meeting with a
group of small-entity representatives in Washington, DC, on April 14,
1998. The purpose of this meeting was to familiarize the small-entity
representatives with the substance of the rulemaking and the kinds of
sources being considered for regulation, and to solicit comment on
these topics. Subsequent to the meeting, the representatives submitted
follow-up comments in writing. The primary outreach was accomplished by
a meeting with the small-entity representatives in Washington, D.C. on
August 4, 1998. The purpose of this meeting was to present the results
of EPA's analysis on small-entity impacts, and to solicit comment on
this analysis and on suggestions for impact mitigation. Subsequent to
the meeting, the representatives submitted follow-up comments in
writing.
To define small entities, EPA used the SBA industry-specific
criteria published in 13 CFR part 121. The SBA size standards have been
established for each type of economic activity under the Standard
Industrial Classification (SIC) System. Due to their NOX-
emitting properties, the following industries have the potential to be
affected by the section 126 rulemaking:
SIC Codes in Division D: Manufacturing
2611--Pulp mills
2819--Industrial Inorganic Materials
2821--Plastics Materials, Synthetic Resins, and Nonvulcanizable
Elastomers
2869--Industrial Organic Chemicals
3312--Steel Works, Blast Furnaces, and Rolling Mills
3511--Steam, Gas, and Hydraulic Turbines
[[Page 56323]]
3519--Stationary Internal Combustion Engines
3585--Air-Conditioning and Warm-Air Heating Equipment and Commercial
and Industrial Refrigeration Equipment
SIC Codes in Division E: Transportation, Communications, Electric, Gas,
and Sanitary Services
SIC Major Group 49: Electric, Gas, and Sanitary Services,
including:
4911--Electric Utilities
4922--Natural Gas Transmission
4931--Electric and other Gas Services
4961--Steam and Air Conditioning Supply
3. Potentially Affected Small Entities
The primary topic of Panel discussion was the applicability of the
section 126 rule to the various categories of NOX-emitting
sources, the costs the rule would impose, and the possibility of
further reducing rule applicability. Secondary topics included
emissions monitoring and other potentially duplicative Federal rules.
These discussions are summarized below.
The section 126 rulemaking is potentially applicable to all
NOX-emitting entities named in one or more of the section
126 petitions. Since this is a subset of the entities covered by the
FIP proposal, any impacts from the section 126 rule will be a subset of
the FIP impacts, and the FIP proposal represents the worst case that
could result if all eight section 126 petitions were granted.
Therefore, EPA has applied its limited time and resources to developing
estimates of impact based on the FIP proposal, with the knowledge that
it represents the worst case in terms of impact on small entities.
The EPA estimates that the total number of such entities named in
the section 126 petitions is approximately 5200, of which about 1200
are small entities. The EPA is considering reducing this applicability
based on several factors including input from this Panel,
considerations of overall cost effectiveness, and administrative
efficiency. Specifically, EPA is proposing to exempt a number of
sources from being subject to this regulation based on factors such as
low relative emissions and lack of specific source information. These
factors are discussed in detail elsewhere in this notice. Additional
sources are being considered for exemption because they may not be
highly cost effective to control, with EPA considering an average cost
effectiveness of $2000 per ton of NOX removed as the upper
limit for highly cost-effective reductions.
If EPA takes final action as proposed today with this reduced-
applicability approach, the section 126 rulemaking will apply only to
the following types of sources: Large electric generating units (EGUs),
industrial boilers, and combustion turbines. The stringency levels of
control EPA currently intends to propose for these types of sources is
as follows: For EGUs, an emission rate of 0.15 pounds of NOX
per million BTU and for industrial boilers and combustion turbines, an
emission reduction of 60 percent. At these stringency levels, the
estimated number of small entities that would be affected is as
follows:
Electric Generating Units--114 small entities
Industrial Boilers and/or Combustion Turbines--31 small entities
The EPA has further estimated that, of these affected small
entities, the following would experience compliance costs equal or
greater to 1 percent of their estimated revenues:
Electric Generating Units--32 small entities
Industrial Boilers and Combustion Turbines--7 small entities
Of these, EPA estimates that about 18 small entities with electric
generating units and 4 small entities with industrial boilers or
turbines would experience costs greater than 3 percent of their
estimated revenues.
Focusing the rule on this limited group of sources would constitute
a reduction of over 85 percent in the number of small entities
potentially affected by the rule: out of 1200 potentially-affected
small entities, over 1000 would be exempted, with only 145 small
entities remaining. The Panel received written comments from three
small-entity representatives strongly endorsing these exemptions.
4. Panel Findings and EPA Actions
a. Exemptions. The Panel agreed with the general approach EPA is
proposing to define the scope of the rule. The Panel recommended that
the exemptions noted above be included in the proposal, and further
recommended that the applicability of EPA's proposed rule be limited to
the sources shown in that section. As discussed earlier in this notice,
EPA is proposing to limit applicability as recommended by the Panel.
Furthermore, as described below, the Panel considered it appropriate to
explore additional options for reducing the impact of the rule.
Several of the small entity representatives suggested that EPA
exempt all small entities from this rulemaking. Although EPA does not
feel that a blanket, across-the-board exemption could be supported, EPA
is receptive to proposals for further exemptions, up to and including
exempting all small entities if that could be shown to be appropriate.
As recommended by the Panel, EPA solicits comment on additional types
of small-entity exemptions and the rational bases on which such
exemptions could be made, such as disproportionate ability to bear
costs and administrative burden.
b. Continuous Emissions Monitoring Systems (CEMS). The Panel
received both written and oral comments to the effect that CEMS would
be prohibitively costly for many industrial boilers, representing a
significant part of the cost of the rule. The OMB and SBA share the
commenters' concern for the potentially high cost of CEMS requirements.
The EPA believes that it is necessary for all sources in the trading
program to be subject to accurate and consistent monitoring
requirements designed to demonstrate compliance with a mass emission
limitation, and therefore intends to require all large units to monitor
NOX mass emissions using CEMS (including units opting-in to
the trading program). In the proposed section 126 rule, all affected
sources are included in the trading program. However, EPA does believe
that it is appropriate to provide lower cost monitoring options for
units with low NOX mass emissions, and therefore intends to
allow non-CEMS alternatives for units that have emissions of less than
50 tons per year of NOX. This cutoff will provide relief for
boilers large enough to be covered by the rule, but that run for a
smaller number of hours each year, including any such boilers owned by
small entities.
c. Electric Generating Units. The next area considered by the Panel
was electric generating units (EGUs). The EPA's analysis shows that
slightly more than 30 EGUs may experience costs above 1 percent of
revenues, and that 18 of these might exceed 3 percent. From comments
made by small utilities, the Panel suspects that many of these high-
cost-to-revenue situations may involve peaking units, which run only a
small percentage of the time and thus may be inefficient to control. To
address this problem, the Panel recommended that EPA solicit comment on
whether to allow electric generating units to obtain a Federally-
enforceable NOX emission tonnage limit (e.g., 25 tons during
the ozone season) and thereby obtain an exemption. The EPA solicits
comment on the necessity for and appropriateness of such an option.
d. Industrial Boilers. Individual Panel members conceived of other
potential ways to mitigate impact on small entities, such as raising
the size cutoff for small entities and/or lessening the required
percentage reduction in NOX emissions required from small
entities. The SBA encouraged the Agency to
[[Page 56324]]
conduct analyses to determine the impact of 40 percent reduction being
applied solely to small entities and 60 percent solely to large
entities, and the resulting effect on control levels for sources
regulated in the proposal. The EPA solicits comment on whether
requirements should be reduced on small-entity-owned industrial boilers
by some combination of raising the size cutoff and/or lessening the
required reduction; which, if any, of these options is preferable; the
necessity and appropriateness of any such option; the appropriate level
(e.g., 40 percent reduction instead of 60 percent); and information to
support any comments submitted.
e. EPA Guidance to States on Small Entities. Finally, the Panel
noted that several small entity representatives expressed concern that
regardless of the sensitivity to small-entity concerns EPA shows in the
(FIP or) section 126 rulemaking, the States may nevertheless see fit to
target small entities in their SIPs. To help address this problem, the
Panel recommended that, subsequent to the FIP and section 126
proposals, EPA issue guidance that conveys to the States the kinds of
options and alternatives EPA has considered in addressing small-entity
concerns, explain the rationale behind these kinds of options, and
recommended that the States consider adopting similar alternatives in
their SIPs. The EPA intends to address this issue as it develops
implementation guidance for the States to use in developing SIPs.
C. Unfunded Mandates Reform Act
Title II of the Unfunded Mandates Reform Act of 1995 (UMRA), Pub.L.
104-4, establishes requirements for Federal agencies to assess the
effects of their regulatory actions on State, local, and tribal
governments and the private sector. Under section 202 of the UMRA, 2
U.S.C. 1532, EPA generally must prepare a written statement, including
a cost-benefit analysis, for any proposed or final rule that ``includes
any Federal mandate that may result in the expenditure by State, local,
and tribal governments, in the aggregate, or by the private sector, of
$100,000,000 or more ... in any one year.'' A ``Federal mandate'' is
defined under section 421(6), 2 U.S.C. 658(6), to include a ``Federal
intergovernmental mandate'' and a ``Federal private sector mandate.'' A
``Federal intergovernmental mandate,'' in turn, is defined to include a
regulation that ``would impose an enforceable duty upon State, local,
or tribal governments,'' section 421(5)(A)(i), 2 U.S.C. 658(5)(A)(i),
except for, among other things, a duty that is ``a condition of Federal
assistance,'' section 421(5)(A)(i)(I). A ``Federal private sector
mandate'' includes a regulation that ``would impose an enforceable duty
upon the private sector,'' with certain exceptions, section 421(7)(A),
2 U.S.C. 658(7)(A).
The EPA is taking the position that the requirements of UMRA apply
because this action could result in the establishment of enforceable
mandates directly applicable to sources (including sources owned by
State and local governments) that would result in costs greater than
$100 million in any one year. The UMRA generally requires EPA to
identify and consider a reasonable number of regulatory alternatives
and adopt the least-costly, most cost-effective or least-burdensome
alternative that achieves the objectives of the rule. The EPA's UMRA
analysis, ``Unfunded Mandates Reform Act Analysis For the Proposed
Section 126 Petitions Under the Clean Air Act Amendments Title I,'' is
contained in the docket for this action and is summarized below.
This UMRA analysis examines the impacts of the proposed section 126
rulemaking on both EGUs and non-EGUs that are owned by State, local,
and tribal governments, as well as sources owned by private entities.
This proposal potentially affects 65 EGUs that are owned by one State
and 24 municipalities (Massachusetts owns 6 units, and the
municipalities own the remaining 59 units). In addition, 7 non-EGUs
owned by 2 States and 5 municipalities are potentially affected. The
EPA has not identified any units on Tribal lands that would be subject
to the proposed requirements. The overall costs are dominated by the 65
EGUs and are about $30 million per year. Their cost impacts are only
slightly higher than their production share, in comparison to all units
in the region.
Under section 203 of UMRA, 2 U.S.C. 1533, before EPA establishes
any regulatory requirements ``that might significantly or uniquely
affect small governments,'' EPA must have developed a small government
agency plan. The plan must provide for notifying potentially affected
small governments; enabling officials of affected small governments to
have meaningful and timely input in the development of EPA regulatory
proposals with significant Federal intergovernmental mandates; and
informing, educating, and advising small governments on compliance with
the regulatory requirements. The proposed requirements do not
distinguish EGUs based on ownership, either for those units that are
included within the scope of the proposed rule or for those units that
are exempted by the generating capacity cut-off. Consequently, the
proposed rule has no requirements that uniquely affect small
governments that own or operate EGUs within the affected region. With
respect to the significance of the rule's provisions, EPA's UMRA
analysis (cited above) demonstrates that the economic impact of the
rule will not significantly affect State or municipal EGUs or non-EGUs,
either in terms of total cost incurred and the impact of the costs on
revenue, or increased cost of electricity to consumers. Therefore,
development of a small government plan under section 203 of the Act is
not required.
Under section 204 of UMRA, 2 U.S.C. 1534, if an agency proposes a
rule that contains a ``significant Federal intergovernmental mandate'',
the agency must develop a process to permit elected officials of State,
local, and tribal governments to provide input into the development of
the proposal.'' In order to fulfill UMRA requirements that publicly-
elected officials be given meaningful and timely input in the process
of regulatory development, EPA has sent letters to five national
associations whose members include elected officials. The letters
provide background information, request the associations to notify
their membership of the proposed rulemaking, and encourage interested
parties to comment on the proposed actions by sending comments during
the public comment period and presenting testimony at the public
hearing on the proposal. Any comments will be taken into consideration
as the action moves toward final rulemaking.
In addition, during the NOX SIP call, EPA provided
direct notification to potentially affected State and municipally-owned
utilities as part of the public comment and hearing process attendant
to proposal of the NOX SIP call and supplemental notice of
proposed rulemaking. These procedures helped ensure that small
governments had an opportunity to give timely input and obtain
information on compliance. The EPA provided the 26 State and
municipality-owned utilities and appropriate elected officials with a
brief summary of the proposal and the estimated impacts. The public
rulemaking also elicited numerous comments from State and municipal
utilities and groups representing utility interests.
Furthermore, for the section 126 rulemaking, EPA published an ANPR
that served to provide notice of the Agency's intention to propose
emissions limits and to solicit early input on the proposal. This
process helped to ensure
[[Page 56325]]
that small governments had an opportunity to give timely input and
obtain information on compliance.
D. Paperwork Reduction Act
The information collection requirements in this proposed rule have
been submitted for approval to the OMB under the Paperwork Reduction
Act, 44 U.S.C. 3501 et seq. An Information Collection Request (ICR)
document has been prepared by EPA (ICR No. 1889.01) and a copy may be
obtained from Sandy Farmer, OPPE Regulatory Information Division, US
Environmental Protection Agency (2137), 401 M St., SW, Washington, DC
20460 or by calling (202) 260-2740.
The EPA believes that it is essential that sources for whom
findings are made under section 126 of the CAA demonstrate that they
are achieving their required reductions. This is achieved through the
monitoring and reporting of emissions. Accurate and consistent
monitoring of emissions also facilitates the trading program which
helps ensure that emission reductions are achieved in the most cost
affective way possible.
Respondents/Affected Entities: Large fossil fuel boilers, turbines
and combined cycle units which are included in the section 126
proposal.
Number of Respondents: 2011.
Frequency of Response:
--Emissions reports quarterly for some units, twice during ozone season
for others
--Test notifications and allowance transfers on an infrequent basis
--Compliance certifications on an annual basis
Estimated Annual Hour Burden per Respondent: 107.
Estitmated Annual Cost per Respondent: $7,943.
Estimated Total Annual Hour Burden: 216,671.
Estimated Total Annualized Cost: $13,859,599.
Note that these are an average estimate for the first three years of
the program. The EPA estimates lower costs in the first two years of
the program because less units will be participating at that time. The
units that will be participating at that time are units that are
applying for early reduction credits. The EPA also estimates that the
highest compliance costs will occur in 2002, when the majority of the
units that have to install and certify new monitors to comply with the
program will do so. The EPA believes that the year 2003 will be more
representative of the actual ongoing costs of the program. At that time
EPA estimates a burden of 179 hours per source and a cost of $27,670
per source.
Burden means the total time, effort, or financial resources
expended by persons to generate, maintain, retain, or disclose or
provide information to or for a federal agency. This includes the time
needed to review instructions; develop, acquire, install, and utilize
technology and systems for the purposes of collecting, validating, and
verifying information, processing and maintaining information, and
disclosing and providing information; adjust the existing ways to
comply with any previously applicable instructions and requirements;
train personnel to be able to respond to a collection of information;
search data sources; complete and review the collection of information;
and transmit or otherwise disclose the information.
An agency may not conduct or sponsor, and a person is not required
to respond to a collection of information unless it displays a
currently valid OMB control number. The OMB control numbers for EPA's
regulations are listed in 40 CFR part 9 and 48 CFR ch. 15.
Comments are requested on the Agency's need for this information,
the accuracy of the provided burden estimates, and any suggested
methods for minimizing respondent burden, including through the use of
automated collection techniques to the Director, Office of Policy,
Regulatory Information Division, US Environmental Protection Agency
(2137), 401 M St., SW, Washington, DC 20460; and to the Office of
Information and Regulatory Affairs, Office of Management and Budget,
725 17th St., NW, Washington, DC 20503, marked ``Attention: Desk
Officer for EPA.'' Comments are requested by December 7, 1998. Please
include the ICR number in any correspondence.
E. Executive Order 13045: Protection of Children From Environmental
Health Risks and Safety Risks
1. Applicability of Executive Order 13045
The Executive Order 13045 applies to any rule that EPA determines
(1) ``economically significant'' as defined under Executive Order
12866, and (2) the environmental health or safety risk addressed by the
rule has a disproportionate effect on children. If the regulatory
action meets both criteria, the Agency must evaluate the environmental
health or safety effects of the planned rule on children; and explain
why the planned regulation is preferable to other potentially effective
and reasonably feasible alternatives considered by the Agency. This
proposed rule is not subject to Executive Order 13045, entitled
``Protection of Children from Environmental Health Risks and Safety
Risks'' (62 FR 19885, April 23, 1997), because it does not involve
decisions on environmental health risks or safety risks that may
disproportionately affect children.
2. Children's Health Protection
In accordance with section 5(501), the Agency has evaluated the
environmental health or safety effects of the rule on children, and
found that the rule does not separately address any age groups.
However, in conjunction with the final NOX SIP call
rulemaking, the Agency has conducted a general analysis of the
potential changes in ozone and PM levels experienced by children as a
result of the NOX SIP call; these findings are presented in
the RIA. The findings include population-weighted exposure
characterizations for projected 2007 ozone and PM concentrations. The
population data includes a census-derived subdivision for the under 18
group.
F. Executive Order 12898: Environmental Justice
Executive Order 12848 requires that each Federal agency make
achieving environmental justice part of its mission by identifying and
addressing, as appropriate, disproportionately high and adverse human
health or environmental effects of its programs, policies, and
activities on minorities and low-income populations. In conjunction
with the final NOX SIP call rulemaking, the Agency has
conducted a general analysis of the potential changes in ozone and PM
levels that may be experienced by minority and low-income populations
as a result of the NOX SIP call; these findings are
presented in the RIA. The findings include population-weighted exposure
characterizations for projected ozone concentrations and PM
concentrations. The population data includes census-derived
subdivisions for whites and non-whites, and for low-income groups.
G. Executive Order 12875: Enhancing the Intergovernmental Partnership
Under Executive Order 12875, EPA may not issue a regulation that is
not required by statute and that creates a mandate upon a State, local
or tribal government, unless the Federal government provides the funds
necessary to pay the direct compliance costs incurred by those
governments or EPA consults with those governments. If the mandate is
unfunded, EPA must provide to the Office of Management and Budget a
description of the extent of EPA's prior consultation with
[[Page 56326]]
representatives of affected State, local and tribal governments, the
nature of their concerns, copies of any written communications from the
governments, and a statement supporting the need to issue the
regulation. In addition, Executive Order 12875 requires EPA to develop
an effective process permitting elected officials and other
representatives of State, local and tribal governments ``to provide
meaningful and timely input in the development of regulatory proposals
containing significant unfunded mandates.''
The EPA has concluded that this rule may create a mandate on State
and local governments and that the Federal government will not provide
the funds necessary to pay the direct costs incurred by the State and
local governments in complying with the mandate. In order to provide
meaningful and timely input in the development of this regulatory
action, EPA has sent letters to five national associations whose
members include elected officials. The letters provide background
information, request the associations to notify their membership of the
proposed rulemaking, and encourage interested parties to comment on the
proposed actions by sending comments during the public comment period
and presenting testimony at the public hearing on the proposal. Any
comments will be taken into consideration as the action moves toward
final rulemaking.
Furthermore, for the section 126 rulemaking, EPA published an ANPR
that served to provide notice of the Agency's intention to propose
emissions limits and to solicit early input on the proposal. This
process helped to ensure that small governments had an opportunity to
give timely input and obtain information on compliance.
H. Executive Order 13084: Consultation and Coordination With Indian
Tribal Governments
Under Executive Order 13084, EPA may not issue a regulation that is
not required by statute, that significantly or uniquely affects the
communities of Indian tribal governments, and that imposes substantial
direct compliance costs on those communities, unless the government
provides the funds necessary to pay the direct compliance costs
incurred by the tribal governments. If the mandate is unfunded, EPA
must provide to the Office of Management and Budget, in a separately
identified section of the preamble to the rule, a description of the
extent of EPA's prior consultation with representatives of affected
tribal governments, a summary of the nature of their concerns, and a
statement supporting the need to issue the regulation. In addition,
Executive Order 13084 requires EPA to develop an effective process
permitting elected and other representatives of Indian tribal
governments ``to provide meaningful and timely input in the development
of regulatory policies on matters that significantly or uniquely affect
their communities.''
Today's rule does not significantly or uniquely affect the
communities of Indian tribal governments and, in any event, will not
impose substantial direct compliance costs on such communities. The EPA
is not aware of sources located on tribal lands that could be subject
to the requirements EPA is proposing in this notice. Accordingly, the
requirements of section 3(b) of Executive Order 13084 do not apply.
I. National Technology Transfer and Advancement Act
Section 12(d) of the National Technology Transfer and Advancement
Act of 1995 (NTTAA), Pub L. 104-113, Sec. 12(d) (15 U.S.C. 272 note)
directs EPA to use voluntary consensus standards in its regulatory
activities unless to do so would be inconsistent with applicable law or
otherwise impractical. Voluntary consensus standards are technical
standards (e.g., materials specifications, test methods, sampling
procedures, and business practices) that are developed or adopted by
voluntary consensus standards bodies. The NTTAA directs EPA to provide
Congress, through OMB, explanations when the Agency decides not to use
available and applicable voluntary consensus standards.
This proposed rulemaking would require all sources that participate
in the trading program under proposed part 97 to meet the applicable
monitoring requirements of part 75. Part 75 already incorporates a
number of voluntary consensus standards. In addition, EPA's proposed
revisions to part 75 proposed to add two more voluntary consensus
standards to the rule (see 63 FR at 28116-17, discussing ASTM D5373-93
``Standard Methods for Instrumental Determination of Carbon, Hydrogen
and Nitrogen in laboratory samples of Coal and Coke,'' and API Section
2 ``Conventional Pipe Provers'' from Chapter 4 of the Manual of
Petroleum Measurement Standards, October 1988 edition). The EPA's
proposed part 75 revisions also requested comments on the inclusion of
additional voluntary consensus standards. The EPA has recently
finalized revisions to part 75 addressing some of the topics raised in
EPA's proposed revisions to part 75. As part of this rule finalization,
EPA incorporated two new voluntary consensus standards:
(1) American Petroleum Institute (API) Petroleum Measurement
Standards, Chapter 3, Tank Gauging: Section 1A, Standard Practice for
the Manual Gauging of Petroleum and Petroleum Products, December 1994;
Section 1B, Standard Practice for Level Measurement of Liquid
Hydrocarbons in Stationary Tanks by Automatic Tank Gauging, April 1992
(reaffirmed January 1997); Section 2, Standard Practice for Gauging
Petroleum and Petroleum Products in Tank Cars, September 1995; Section
3, Standard Practice for Level Measurement of Liquid Hydrocarbons in
Stationary Pressurized Storage Tanks by Automatic Tank Gauging, June
1996; Section 4, Standard Practice for Level Measurement of Liquid
Hydrocarbons on Marine Vessels by Automatic Tank Gauging, April 1995;
and Section 5, Standard Practice for Level Measurement of Light
Hydrocarbon Liquids Onboard Marine Vessels by Automatic Tank Gauging,
March 1997; and
(2) Shop Testing of Automatic Liquid Level Gages, Bulletin 2509 B,
December 1961 (Reaffirmed October 1992), for Sec. 75.19.
The EPA intends to finalize other revisions to part 75 and address
comments related to additional voluntary consensus standards at that
time.
This proposed rulemaking involves environmental monitoring or
measurement. Sources that participate in the trading program would be
required to meet the monitoring requirements under part 75. Consistent
with the Agency's Performance Based Measurement System (PBMS), part 75
sets forth performance criteria that allow the use of alternative
methods to the ones set forth in part 75. The PBMS approach is intended
to be more flexible and cost effective for the regulated community; it
is also intended to encourage innovation in analytical technology and
improved data quality. The EPA is not precluding the use of any method,
whether it constitutes a voluntary consensus standard or not, as long
as it meets the performance criteria specified, however, any
alternative methods must be approved in advance before they may be used
under part 75.
The EPA welcomes comments on this aspect of the proposed rulemaking
and, specifically, invites the public to identify potentially
applicable voluntary consensus standards and to explain why such
standards should be used in this regulation.
[[Page 56327]]
List of Subjects
40 CFR Part 52
Environmental protection, Air pollution control, Emissions trading,
Nitrogen oxides, Ozone transport, Reporting and recordkeeping
requirements.
40 CFR Part 97
Environmental protection, Air pollution control, Emissions trading,
Nitrogen oxides, Ozone transport, Reporting and recordkeeping
requirements.
Dated: September 24, 1998.
Carol M. Browner,
Administrator.
For the reasons set forth in the preamble, parts 52 and 97 of
chapter I of title 40 of the Code of Federal Regulations are proposed
to be amended as follows:
PART 52--APPROVAL AND PROMULGATION OF IMPLEMENTATION PLANS
1. The authority citation for part 52 continues to read as follows:
Authority: 42 U.S.C. 7401-7671q.
Subpart A--General Provisions
2. Subpart A is amended to add Sec. 52.34 to read as follows:
Sec. 52.34 Action on petitions submitted under section 126 relating to
emissions of nitrogen oxides.
(a) Purpose and applicability. Paragraphs (b) through (i) of this
section set forth EPA's affirmative and negative technical
determinations regarding whether, with respect to the national ambient
air quality standards (NAAQS) for ozone, certain new and existing
sources of emissions of nitrogen oxides (``NOX'') in certain
States emit NOX in amounts that will contribute
significantly to nonattainment in, or interfere with maintenance by,
one or more States that submitted petitions in 1997 addressing such
NOX emissions under section 126 of the Clean Air Act. (As
used in this section, the term new source includes modified sources, as
well.) The States that submitted such petitions are Connecticut, Maine,
Massachusetts, New Hampshire, New York, Pennsylvania, Rhode Island, and
Vermont (each of which, hereinafter in this section, may be referred to
also as a ``petitioning State''). Paragraph (j) of this section sets
forth EPA's decisions about whether to grant or deny each of those
petitions, and paragraph (k) of this section sets forth the emissions-
reduction requirements that will apply to the affected NOX
sources to the extent any of the petitions is granted. Appendix A of
part 97 of this chapter contains a list of the existing NOX
sources that as of date of signature are covered by the affirmative
technical determinations described herein, and that would be required
to meet such pollution-control requirements to the extent a petition
covering such sources is granted.
(b) Technical determinations relating to impacts on ozone levels in
Connecticut.--(1) Affirmative technical determinations with respect to
the 1-hour ozone standard in Connecticut. The Administrator of EPA
finds that any existing or new major source or group of stationary
sources emits or would emit NOX in amounts that contribute
significantly to nonattainment in the State of Connecticut with respect
to the 1-hour NAAQS for ozone if it is or will be:
(i) In a category of sources described in 40 CFR 97.4;
(ii) Located in one of the States (or portions thereof) listed in
paragraph (b)(2) of this section; and
(iii) Within one of the ``Named Source Categories'' listed in the
portion of Table F-1 in appendix F of this part describing the sources
covered by the petition of the State of Connecticut.
(2) States or portions of states that contain sources for which EPA
is making an affirmative technical determination with respect to the 1-
hour ozone standard in Connecticut. The States, or portions of States,
that contain sources for which EPA is making an affirmative technical
determination are:
(i) Delaware.
(ii) District of Columbia.
(iii) Portion of Indiana located in OTAG Subregions 2 and 6, as
shown in appendix F, Figure F-2 of this part.
(iv) Portion of Kentucky located in OTAG Subregion 6, as shown in
appendix F, Figure F-2 of this part.
(v) Maryland.
(vi) Portion of Michigan located in OTAG Subregion 2, as shown in
appendix F, Figure F-2 of this part.
(vii) Portion of North Carolina located in OTAG Subregion 7, as
shown in appendix F, Figure F-2 of this part.
(viii) New Jersey.
(ix) Portion of New York extending west and south of Connecticut,
as shown in appendix F, Figure F-2 of this part.
(x) Ohio.
(xi) Pennsylvania.
(xii) Virginia.
(xiii) West Virginia.
(3) Negative technical determinations with respect to the 1-hour
ozone standard in Connecticut. The Administrator of EPA finds that any
existing or new major source or group of stationary sources that is or
will be located in one of the States (or portions thereof) listed in
paragraph (b)(4) of this section does not or would not emit
NOX in amounts that contribute significantly to
nonattainment in the State of Connecticut, with respect to the 1-hour
NAAQS for ozone. The Administrator also finds that any existing or new
major source or group of stationary sources does not or would not emit
NOX in such amounts if it:
(i) Is or will be located in one of the States (or portions
thereof) listed in paragraph (b)(2) of this section; and
(ii) Is or will be within one of the ``Named Source Categories''
listed in the portion of Table F-1 in appendix F of this part
describing the sources covered by the petition of the State of
Connecticut; but
(iii) Is not in a category of sources described in 40 CFR 97.4.
(4) States or portions of States that contain no sources for which
EPA is making an affirmative technical determination with respect to
the 1-hour ozone standard in Connecticut. The States or portions
thereof described in paragraph (b)(3) of this section are:
(i) Portion of Tennessee located in OTAG Subregion 6, as shown in
appendix F, Figure F-2.
(c) Technical determinations relating to impacts on ozone levels in
Maine.--(1) Affirmative technical determinations with respect to the 1-
hour ozone standard in Maine. The Administrator of EPA finds that any
existing or new major source or group of stationary sources emits or
would emit NOX in amounts that contribute significantly to
nonattainment in the State of Maine, with respect to the 1-hour NAAQS
for ozone if it is or will be:
(I) In a category of sources described in 40 CFR 97.4;
(ii) Located in one of the States (or portions thereof) listed in
paragraph (c)(2) of this section; and
(iii) Within one of the ``Named Source Categories'' listed in the
portion of Table F-1 in appendix F of this part describing the sources
covered by the petition of the State of Maine.
(2) States or portions of States that contain sources for which EPA
is making an affirmative technical determination with respect to the 1-
hour ozone standard in Maine. The States, or portions of States, that
contain sources for which EPA is making an affirmative technical
determination are:
(i) Connecticut.
(ii) Delaware.
(iii) District of Columbia.
(iv) Maryland.
[[Page 56328]]
(v) Massachusetts.
(vi) New Jersey.
(vii) New York.
(viii) Pennsylvania.
(ix) Rhode Island.
(3) Negative technical determinations with respect to the 1-hour
ozone standard in Maine. The Administrator of EPA finds that any
existing or new major source or group of stationary sources that is or
will be located in one of the States (or portions thereof) listed in
paragraph (c)(4) of this section does not or would not emit
NOX in amounts that contribute significantly to
nonattainment in the State of Maine, with respect to the 1-hour NAAQS
for ozone. The Administrator also finds that any existing or new major
source or group of stationary sources that does not or would not emit
NOX in such amounts if it:
(i) Is or will be located in one of the States (or portions
thereof) listed in paragraph (c)(2) of this section; and
(ii) Is or will be within one of the ``Named Source Categories''
listed in the portion of Table F-1 in appendix F of this part
describing the sources covered by the petition of the State of Maine;
but
(iii) Is not in a category of sources described in 40 CFR 97.4.
(4) States or portions of States that contain no sources for which
EPA is making an affirmative technical determination with respect to
the 1-hour ozone standard in Maine. The States or portions thereof
described in paragraph (c)(3) of this section are:
(i) Portion of North Carolina within a 600 mile radius of Maine's
ozone nonattainment areas, as shown in appendix F, Figure F-3 of this
part.
(ii) New Hampshire.
(iii) Portion of Ohio within a 600 mile radius of Maine's ozone
nonattainment areas, as shown in appendix F, Figure F-3 of this part.
(iv) Vermont.
(v) Portion of Virginia within a 600 mile radius of Maine's ozone
nonattainment areas, as shown in appendix F, Figure F-3 of this part.
(vi) Portion of West Virginia within a 600 mile radius of Maine's
ozone nonattainment areas, as shown in appendix F, Figure F-3 of this
part.
(d) Technical determinations relating to impacts on ozone levels in
Massachusetts.--(1) Affirmative technical determinations with respect
to the 1-hour ozone standard in Massachusetts. The Administrator of EPA
finds that any existing or new major source or group of stationary
sources emits or would emit NOx in amounts that contribute
significantly to nonattainment in the State of Massachusetts, with
respect to the 1-hour NAAQS for ozone if it is or will be:
(i) In a category of sources described in 40 CFR 97.4;
(ii) Located in one of the States (or portions thereof) listed in
paragraph (d)(2) of this section; and
(iii) Within one of the ``Named Source Categories'' listed in the
portion of Table F-1 in appendix F of this part describing the sources
covered by the petition of the State of Massachusetts.
(2) States or portions of states that contain sources for which EPA
is making an affirmative technical determination with respect to the 1-
hour ozone standard in Massachusetts. The States or portions of States
that contain sources for which EPA is making an affirmative technical
determination are:
(i) All counties in Ohio located within a 3-county-wide band of the
Ohio River, as shown in appendix F, Figure F-4 of this part.
(ii) All counties in West Virginia located within a 3-county-wide
band of the Ohio River, as shown in appendix F, Figure F-4 of this
part.
(3) Negative technical determinations with respect to the 1-hour
ozone standard in Massachusetts. The Administrator of EPA finds that
any existing or new major source or group of stationary sources that is
or will be located in one of the States (or portions thereof) listed in
paragraph (d)(4) of this section does not or would not emit NOx in
amounts that contribute significantly to nonattainment in the State of
Massachusetts, with respect to the 1-hour NAAQS for ozone. The
Administrator also finds that any existing or new major source or group
of stationary sources does not or would not emit NOx in such amounts if
it:
(i) Is or will be located in one of the States (or portions
thereof) listed in paragraph (d)(2) of this section; and
(ii) Is or will be within one of the ``Named Source Categories''
listed in the portion of Table F-1 in appendix F of this part
describing the sources covered by the petition of the State of
Massachusetts; but
(iii) is not in a category of sources described in 40 CFR 97.4.
(4) States or portions of States that contain no sources for which
EPA is making an affirmative technical determination with respect to
the 1-hour ozone standard in Massachusetts. The States or portions
thereof described in paragraph (d)(3) of this section are:
(i) All counties in Kentucky located within a 3-county-wide band of
the Ohio River, as shown in appendix F, Figure F-4 of this part.
(ii) All counties in Indiana located within a 3-county-wide band of
the Ohio River, as shown in appendix F, Figure F-4 of this part.
(5) Affirmative technical determinations with respect to the 8-hour
ozone standard in Massachusetts. The Administrator of EPA finds that
any existing or new major source or group of stationary sources emits
or would emit NOx in amounts that contribute significantly to
nonattainment in, or interfere with maintenance by, the State of
Massachusetts, with respect to the 8-hour NAAQS for ozone if it is or
will be:
(i) In a category of sources described in 40 CFR 97.4;
(ii) Located in one of the States (or portions thereof) listed in
paragraph (d)(6) of this section; and
(iii) Within one of the ``Named Source Categories'' listed in the
portion of Table F-1 in appendix F of this part describing the sources
covered by the petition of the State of Massachusetts.
(6) States or portions of states that contain sources for which EPA
is making an affirmative technical determination with respect to the 8-
hour ozone standard in Massachusetts. The States, or portions of
States, that contain sources for which EPA is making an affirmative
technical determination are:
(i) All counties in Ohio located within a 3-county-wide band of the
Ohio River, as shown in appendix F, Figure F-4 of this part.
(ii) All counties in West Virginia located within a 3-county-wide
band of the Ohio River, as shown in appendix F, Figure F-4 of this
part.
(7) Negative technical determinations with respect to the 8-hour
ozone standard in Massachusetts. The Administrator of EPA finds that
any existing or new major source or group of stationary sources that is
or will be located in one of the States (or portions thereof) listed in
paragraph (d)(8) of this section does not or would not emit
NOX in amounts that contribute significantly to
nonattainment in, or interfere with maintenance by, the State of
Massachusetts, with respect to the 8-hour NAAQS for ozone. The
Administrator also finds that any existing or new major source or group
of stationary sources does not or would not emit NOX in such
amounts if it is or will be:
(i) Is or will be located in one of the States (or portions
thereof) listed in paragraph (d)(6) of this section; and
(ii) Is or will be within one of the ``Named Source Categories''
listed in the portion of Table F-1 in appendix F of this part
describing the sources covered by the petition of the State of
Massachusetts; but
[[Page 56329]]
(iii) is not in a category of sources described in 40 CFR 97.4.
(8) States or portions of States that contain no sources for which
EPA is making an affirmative technical determination with respect to
the 8-hour ozone standard in Massachusetts. The States or portions
thereof described in paragraph (d)(7) of this section are:
(i) All counties in Indiana located within a 3-county-wide band of
the Ohio River, as shown in appendix F, Figure F-4 of this part.
(ii) All counties in Kentucky located within a 3-county-wide band
of the Ohio River, as shown in appendix F, Figure F-4 of this part.
(e) Technical determinations relating to impacts on ozone levels in
New Hampshire.--(1) Affirmative technical determinations with respect
to the 1-hour ozone standard in New Hampshire. The Administrator of EPA
finds that any existing or new major source or group of stationary
sources emits or would emit NOX in amounts that contribute
significantly to nonattainment in the State of New Hampshire, with
respect to the 1-hour NAAQS for ozone if it is or will be:
(i) In a category of sources described in 40 CFR 97.4;
(ii) Located in one of the States (or portions thereof) listed in
paragraph (e)(2) of this section; and
(iii) Within one of the ``Named Source Categories'' listed in the
portion of Table F-1 in appendix F of this part describing the sources
covered by the petition of the State of New Hampshire.
(2) States or portions of States that contain sources for which EPA
is making an affirmative technical determination with respect to the 1-
hour ozone standard in New Hampshire. The States, or portions of
States, that contain sources for which EPA is making an affirmative
technical determination are:
(i) Connecticut.
(ii) Delaware.
(iii) District of Columbia.
(iv) Maryland.
(v) Massachusetts.
(vi) New Jersey.
(vii) New York.
(viii) Pennsylvania.
(ix) Rhode Island.
(x) Virginia.
(3) Negative technical determinations with respect to the 1-hour
ozone standard in New Hampshire. The Administrator of EPA finds that
any existing or new major source or group of stationary sources that is
or will be located in one of the States (or portions thereof) listed in
paragraph (e)(4) of this section does not or would not emit
NOX in amounts that contribute significantly to
nonattainment in the State of New Hampshire, with respect to the 1-hour
NAAQS for ozone. The Administrator also finds that any existing or new
major source or group of stationary sources does not or would not emit
NOX in such amounts if it:
(i) Is or will be located in one of the States (or portions
thereof) listed in paragraph (e)(2) of this section; and
(ii) Is or will be within one of the ``Named Source Categories''
listed in the portion of Table F-1 in appendix F of this part
describing the sources covered by the petition of the State of New
Hampshire; but
(iii) is not in a category of sources described in 40 CFR 97.4.
(4) States or portions of States that contain no sources for which
EPA is making an affirmative technical determination with respect to
the 1-hour ozone standard in New Hampshire. The States or portions
thereof described in paragraph (e)(3) of this section are:
(i) Illinois.
(ii) Indiana.
(iii) Portion of Iowa within OTAG Subregion 1, as shown in appendix
F, Figure F-5 of this part.
(iv) Kentucky.
(v) Maine.
(vi) Portion of Michigan within OTAG Subregions 1 and 2, as shown
in appendix F, Figure F-5 of this part.
(vii) Portion of Missouri within OTAG Subregion 5, as shown in
appendix F, Figure F-5 of this part.
(viii) North Carolina.
(ix) Ohio.
(x) Tennessee.
(xi) West Virginia.
(xii) Portion of Wisconsin within OTAG Subregion 1, as shown in
appendix F, Figure F-5 of this part.
(xiii) Vermont.
(f) Technical determinations relating to impacts on ozone levels in
the State of New York.--(1) Affirmative technical determinations with
respect to the 1-hour ozone standard in the State of New York. The
Administrator of EPA finds that any existing or new major source or
group of stationary sources emits or would emit NOX in
amounts that contribute significantly to nonattainment in the State of
New York, with respect to the 1-hour NAAQS for ozone:
(i) In a category of sources described in 40 CFR 97.4;
(ii) Located in one of the States (or portions thereof) listed in
paragraph (f)(2) of this section; and
(iii) Within one of the ``Named Source Categories'' listed in the
portion of Table F-1 in appendix F of this part describing the sources
covered by the petition of the State of New York.
(2) States or portions of States that contain sources for which EPA
is making an affirmative technical determination with respect to the 1-
hour ozone standard in the State of New York. The States, or portions
of States, that contain sources for which EPA is making an affirmative
technical determination are:
(i) Delaware.
(ii) District of Columbia.
(iii) Portion of Indiana located in OTAG Subregions 2 and 6, as
shown in appendix F, Figure F-6 of this part.
(iv) Portion of Kentucky located in OTAG Subregion 6, as shown in
appendix F, Figure F-6 of this part.
(v) Maryland.
(vi) Portion of Michigan located in OTAG Subregion 2, as shown in
appendix F, Figure F-6 of this part.
(vii) Portion of North Carolina located in OTAG Subregions 6 and 7,
as shown in appendix F, Figure F-6 of this part.
(viii) New Jersey.
(ix) Ohio.
(x) Pennsylvania.
(xi) Virginia.
(xii) West Virginia.
(3) Negative technical determinations with respect to the 1-hour
ozone standard in the State of New York. The Administrator of EPA finds
that any existing or new major source or group of stationary sources
that is or will be located in one of the States (or portions thereof)
listed in paragraph (f)(4) of this section does not or would not emit
NOX in amounts that contribute significantly to
nonattainment in the State of New York, with respect to the 1-hour
NAAQS for ozone. The Administrator also finds that any existing or new
major source or group of stationary sources does not or would not emit
NOX in such amounts if it:
(i) Is or will be located in one of the States (or portions
thereof) listed in paragraph (f)(2) of this section; and
(ii) Is or will be within one of the ``Named Source Categories''
listed in the portion of Table F-1 in appendix F of this part
describing the sources covered by the petition of the State of New
York; but
(iii) Is not in a category of sources described in 40 CFR 97.4.
(4) States or portions of States that contain no sources for which
EPA is making an affirmative technical determination with respect to
the 1-hour ozone standard in the State of New York. The States or
portions thereof described in paragraph (f)(3) of this section are:
(i) Portion of Tennessee located in OTAG Subregion 6, as shown in
appendix F, Figure F-6 of this part.
(g) Technical determinations relating to impacts on ozone levels in
Pennsylvania.--(1) Affirmative
[[Page 56330]]
technical determinations with respect to the 1-hour ozone standard in
Pennsylvania. The Administrator of EPA finds that any existing or new
major source or group of stationary sources emits or would emit
NOX in amounts that contribute significantly to
nonattainment in the State of Pennsylvania, with respect to the 1-hour
NAAQS for ozone if it is or will be:
(i) In a category of sources described in 40 CFR 97.4;
(ii) Located in one of the States (or portions thereof) listed in
paragraph (g)(2) of this section; and
(iii) Within one of the ``Named Source Categories'' listed in the
portion of Table F-1 in appendix F of this part describing the sources
covered by the petition of the State of Pennsylvania.
(2) States or portions of States that contain sources for which EPA
is making an affirmative technical determination with respect to the 1-
hour ozone standard in Pennsylvania. The States, or portions of States,
that contain sources for which EPA is making an affirmative technical
determination are:
(i) North Carolina.
(ii) Ohio.
(iii) Virginia.
(iv) West Virginia.
(3) Negative technical determinations with respect to the 1-hour
ozone standard in Pennsylvania. The Administrator of EPA finds that any
existing or new major source or group of stationary sources that is or
will be located in one of the States (or portions thereof) listed in
paragraph (g)(4) of this section does not or would not emit
NOX in amounts that contribute significantly to
nonattainment in the State of Pennsylvania, with respect to the 1-hour
NAAQS for ozone. The Administrator also finds that any existing or new
major source or group of stationary sources does not or would not emit
NOX in such amounts if it:
(i) Is or will be located in one of the States (or portions
thereof) listed in paragraph (g)(2) of this section; and
(ii) Is or will be within one of the ``Named Source Categories''
listed in the portion of Table F-1 in appendix F of this part
describing the sources covered by the petition of the State of
Pennsylvania; but
(iii) Is not in a category of sources described in 40 CFR 97.4.
(4) States or portions of States that contain no sources for which
EPA is making an affirmative technical determination with respect to
the 1-hour ozone standard in Pennsylvania. The States or portions
thereof described in paragraph (g)(3) of this section are:
(i) Alabama.
(ii) Arkansas.
(iii) Georgia.
(iv) Illinois.
(v) Indiana
(vi) Iowa.
(vii) Kentucky.
(viii) Louisiana.
(ix) Michigan.
(x) Minnesota.
(xi) Mississippi.
(xii) Missouri.
(xiii) South Carolina.
(xiv) Tennessee.
(xv) Wisconsin.
(5) Affirmative technical determinations with respect to the 8-hour
ozone standard in Pennsylvania. The Administrator of EPA finds that any
existing or new major source or group of stationary sources emits or
would emit NOX in amounts that contribute significantly to
nonattainment in, or interfere with maintenance by, the State of
Pennsylvania, with respect to the 8-hour NAAQS for ozone:
(i) In a category of sources described in 40 CFR 97.4;
(ii) Located in one of the States (or portions thereof) listed in
paragraph (g)(6) of this section; and
(iii) Within one of the ``Named Source Categories'' listed in the
portion of Table F-1 in appendix F of this part describing the sources
covered by the petition of the State of Pennsylvania.
(6) States or portions of States that contain sources for which EPA
is making an affirmative technical determination with respect to the 8-
hour ozone standard in Pennsylvania. The States, or portions of States,
that contain sources for which EPA is making an affirmative technical
determination are:
(i) Alabama.
(ii) Illinois.
(iii) Indiana.
(iv) Kentucky.
(v) Michigan.
(vi) Missouri.
(vii) North Carolina.
(viii) Ohio.
(ix) Tennessee.
(x) Virginia.
(xi) West Virginia.
(7) Negative technical determinations with respect to the 8-hour
ozone standard in Pennsylvania. The Administrator of EPA finds that any
existing or new major source or group of stationary sources that is or
will be located in one of the States (or portions thereof) listed in
paragraph (g)(8) of this section does not or would not emit
NOX in amounts that contribute significantly to
nonattainment in, or interfere with maintenance by, the State of
Pennsylvania, with respect to the 8-hour NAAQS for ozone. The
Administrator also finds that any existing or new major source or group
of stationary sources does not or would not emit NOX in such
amounts if it:
(i) Is or will be located in one of the States (or portions
thereof) listed in paragraph (g)(6) of this section; and
(ii) Is or will be within one of the ``Named Source Categories''
listed in the portion of Table F-1 in appendix F of this part
describing the sources covered by the petition of the State of
Pennsylvania; but
(iii) Is not in a category of sources described in 40 CFR 97.4.
(8) States or portions of States that contain no sources for which
EPA is making an affirmative technical determination with respect to
the 8-hour ozone standard in Pennsylvania. The States or portions
thereof described in paragraph (g)(7) of this section are:
(i) Arkansas.
(ii) Georgia.
(iii) Iowa.
(iv) Louisiana.
(v) Minnesota.
(vi) Mississippi.
(vii) South Carolina.
(viii) Wisconsin.
(h) Technical determinations relating to impacts on ozone levels in
Rhode Island.--(1) Affirmative technical determinations with respect to
the 1-hour ozone standard in Rhode Island. The Administrator of EPA
finds that any existing or new major source or group of stationary
sources emits or would emit NOX in amounts that contribute
significantly to nonattainment in the State of Rhode Island, with
respect to the 1-hour NAAQS for ozone if it is or will be:
(i) In a category of sources described in 40 CFR 97.4;
(ii) Located in one of the States (or portions thereof) listed in
paragraph (h)(2) of this section; and
(iii) Within one of the ``Named Source Categories'' listed in the
portion of Table F-1 in appendix F of this part describing the sources
covered by the petition of the State of Rhode Island.
(2) States or portions of States that contain sources for which EPA
is making an affirmative technical determination with respect to the 1-
hour ozone standard in Rhode Island. The States, or portions of States,
that contain sources for which EPA is making an affirmative technical
determination are:
(i) All counties in Ohio located within a 3-county-wide band of the
Ohio River, as shown in appendix F, Figure F-8 of this part.
(ii) All counties in West Virginia located within a 3-county-wide
band of the Ohio River, as shown in appendix F, Figure F-8 of this
part.
(3) Negative technical determinations with respect to the 1-hour
ozone
[[Page 56331]]
standard in Rhode Island. The Administrator of EPA finds that any
existing or new major source or group of stationary sources that is or
will be located in one of the States (or portions thereof) listed in
paragraph (h)(4) of this section does not or would not emit
NOX in amounts that contribute significantly to
nonattainment in the State of Rhode Island, with respect to the 1-hour
NAAQS for ozone. The Administrator also finds that any existing or new
major source or group of stationary sources does not or would not emit
NOX in such amounts if it:
(i) Is or will be located in one of the States (or portions
thereof) listed in paragraph (h)(2) of this section; and
(ii) Is or will be within one of the ``Named Source Categories''
listed in the portion of Table F-1 in Appendix F of this part
describing the sources covered by the petition of the State of Rhode
Island; but
(iii) Is not in a category of sources described in 40 CFR 97.4.
(4) States or portions of States that contain no sources for which
EPA is making an affirmative technical determination with respect to
the 1-hour ozone standard in Rhode Island. The States or portions
thereof described in paragraph (h)(3) of this section are:
(i) All counties in Kentucky located within a 3-county-wide band of
the Ohio River, as shown in appendix F, Figure F-8 of this part.
(ii) All counties in Indiana located within a 3-county wide-band of
the Ohio River, as shown in appendix F, Figure F-8 of this part.
(i) Technical determinations relating to impacts on ozone levels in
Vermont.--(1) Negative technical determinations with respect to the 1-
hour ozone standard in Vermont. The Administrator of EPA finds that any
existing or new major source or group of stationary sources that is or
will be located in one of the States (or portions thereof) listed in
paragraph (i)(2) of this section does not or would not emit
NOX in amounts that contribute significantly to
nonattainment in the State of Vermont, with respect to the 1-hour NAAQS
for ozone.
(2) States or portions of States that contain no sources for which
EPA is making an affirmative technical determination with respect to
the 1-hour ozone standard in Vermont. The States or portions thereof
described in paragraph (i)(1) of this section are:
(i) Portion of Alabama within 1000 miles southwest from Bennington,
VT, as shown in appendix F, Figure F-9 of this part.
(ii) Portion of Connecticut within 1000 miles southwest from
Bennington, VT, as shown in appendix F, Figure F-9 of this part.
(iii) Delaware.
(iv) District of Columbia.
(v) Portion of Georgia within 1000 miles southwest from Bennington,
VT, as shown in appendix F, Figure F-9 of this part.
(vi) Illinois.
(vii) Indiana.
(viii) Portion of Iowa within 1000 miles southwest from Bennington,
VT, as shown in appendix F, Figure F-9 of this part.
(ix) Kentucky.
(x) Maryland.
(xi) Portion of Massachusetts within 1000 miles southwest from
Bennington, VT, as shown in appendix F, Figure F-9 of this part.
(xii) Portion of Michigan within 1000 miles southwest from
Bennington, VT, as shown in appendix F, Figure F-9 of this part.
(xiii) Portion of Missouri within 1000 miles southwest from
Bennington, VT, as shown in appendix F, Figure F-9 of this part.
(xiv) New Jersey.
(xv) Portion of New York within 1000 miles southwest from
Bennington, VT, as shown in appendix F, Figure F-9 of this part.
(xvi) North Carolina.
(xvii) Ohio.
(xviii) Pennsylvania.
(xix) South Carolina.
(xx) Portion of Tennessee within 1000 miles southwest from
Bennington, VT, as shown in appendix F, Figure F-9 of this part.
(xxi) Virginia.
(xxii) West Virginia.
(xxiii) Portion of Wisconsin within 1000 miles southwest from
Bennington, VT, as shown in appendix F, Figure F-9 of this part.
(3) Negative technical determinations with respect to the 8-hour
ozone standard in Vermont. The Administrator of EPA finds that any
existing or new major source or group of stationary sources that is or
will be located in one of the States (or portions thereof) listed in
paragraph (i)(4) of this section does not or would not emit
NOX in amounts that contribute significantly to
nonattainment in, or interfere with maintenance by, the State of
Vermont, with respect to the 8-hour NAAQS for ozone.
(4) States or portions of States that contain no sources for which
EPA is making an affirmative technical determination with respect to
the 8-hour ozone standard in Vermont. The States or portions thereof
described in paragraph (i)(3) of this section are:
(i) Portion of Alabama within 1000 miles southwest from Bennington,
VT, as shown in appendix F, Figure F-9 of this part.
(ii) Portion of Connecticut within 1000 miles southwest from
Bennington, VT, as shown in appendix F, Figure F-9 of this part.
(iii) Delaware.
(iv) District of Columbia.
(v) Portion of Georgia within 1000 miles southwest from Bennington,
VT, as shown in appendix F, Figure F-9 of this part.
(vi) Illinois.
(vii) Indiana.
(viii) Portion of Iowa within 1000 miles southwest from Bennington,
VT, as shown in appendix F, Figure F-9 of this part.
(ix) Kentucky.
(x) Maryland.
(xi) Portion of Massachusetts within 1000 miles southwest from
Bennington, VT, as shown in appendix F, Figure F-9 of this part.
(xii) Portion of Michigan within 1000 miles southwest from
Bennington, VT, as shown in appendix F, Figure F-9 of this part.
(xiii) Portion of Missouri within 1000 miles southwest from
Bennington, VT, as shown in appendix F, Figure F-9 of this part.
(xiv) New Jersey.
(xv) Portion of New York within 1000 miles southwest from
Bennington, VT, as shown in appendix F, Figure F-9 of this part.
(xvi) North Carolina.
(xvii) Ohio.
(xviii) Pennsylvania.
(xix) South Carolina.
(xx) Portion of Tennessee within 1000 miles southwest from
Bennington, VT, as shown in appendix F, Figure F-9 of this part.
(xxi) Virginia.
(xxii) West Virginia.
(xxiii) Portion of Wisconsin within 1000 miles southwest from
Bennington, VT, as shown in appendix F, Figure F-9 of this part.
(j) Action on petitions for section 126(b) findings. (1) For each
existing or new major source or group of stationary sources for which
the Administrator has made an affirmative technical determination as
described in paragraphs (b) through (i) of this section as to impacts
on nonattainment or maintenance of a particular NAAQS for ozone in a
particular petitioning State, a finding of the Administrator that each
such major source or group of stationary sources emits or would emit
NOX in violation of the prohibition of Clean Air Act section
110(a)(2)(D)(i)(I) with the respect to nonattainment or maintenance of
such standard in such petitioning State will be deemed to be made:
[[Page 56332]]
(i) As of November 30, 1999, if by such date EPA does not issue
either:
(A) A proposed approval, under section 110(k) of the Clean Air Act,
of a State implementation plan revision submitted by such State to
comply with the requirements of section 110(a)(2)(D)(i)(I) of the Clean
Air Act; or
(B) A final Federal implementation plan meeting such requirements
for such State.
(ii) As of May 1, 2000, if by November 30, 1999, EPA takes the
action described in paragraph (j)(1)(i) of this section for such State,
but, by May 1, 2000, EPA does not approve or promulgate implementation
plan provisions meeting such requirements for such State.
(2) The making of any such finding as to any such major source or
group of stationary sources shall be considered to be the making of a
finding under subsection (b) of section 126 of the Clean Air Act as to
such major source or group of stationary sources. Each aspect of a
petition as to which the Administrator has made an affirmative
technical determination (as described in paragraphs (b) through (i) of
this section) shall be deemed denied as of May 1, 2000, if a section
126(b) finding has not been deemed to have been made by that date.
Notwithstanding any other provision of this paragraph or section, after
such a finding has been deemed to be made under this paragraph as to a
particular major source or group of stationary sources in a particular
State, such finding will be deemed to be withdrawn, and the
corresponding part of the relevant petition(s) denied, if the
Administrator issues a final action putting in place implementation
plan provisions that comply with the requirements of section
110(a)(2)(D)(i)(I) of the Clean Air Act for such State.
(3) For each new or existing major source or group of stationary
sources for which the Administrator has made a negative technical
determination in any of paragraphs (b) through (i) of this section as
to impacts on a particular petitioning State with respect to a
particular NAAQS for ozone, the Administrator hereby denies the
petition of such petitioning State and determines that such new or
existing major source or group of stationary sources does not emit or
would not emit in violation of the prohibition in Clean Air Act section
110(a)(2)(D)(i)(I) with respect to impacts on nonattainment or
maintenance of such standard in such petitioning State.
(k) The provisions of part 97 of this chapter apply to the owner or
operator of any new or existing major source, or other source within
any group of stationary sources, as to which the Administrator makes a
finding under section 126(b) of the Clean Air Act pursuant to the
provisions of paragraph (j) of this section.
3. Appendix F is added to part 52 to read as follows:
Appendix F to This Part--Clean Air Act Section 126 Petitions From
Eight Northeastern States: Named Source Categories and Geographic
Coverage
The table and figures in this appendix are cross-referenced in
Sec. 52.34.
Table F-1.--Named Source Categories in Section 126 Petitions
------------------------------------------------------------------------
Petitioning State Named source categories
------------------------------------------------------------------------
Connecticut.................. Fossil fuel-fired boilers or other
indirect heat exchangers with a maximum
gross heat input rate of 250 mmBtu/hr or
greater and electric utility generating
facilities with a rated output of 15 MW
or greater.
Maine........................ Electric utilities and steam-generating
units with a heat input capacity of 250
mmBtu/hr or greater.
Massachusetts................ Electricity generating plants.
New Hampshire................ Fossil fuel-fired indirect heat exchange
combustion units and fossil fuel-fired
electric generating facilities which
emit ten tons of NOX or more per day.
New York..................... Fossil fuel-fired boilers or indirect
heat exchangers with a maximum heat
input rate of 250 mmBtu/hr or greater
and electric utility generating
facilities with a rated output of 15 MW
or greater.
Pennsylvania................. Fossil fuel-fired indirect heat exchange
combustion units with a maximum rated
heat input capacity of 250 mmBtu/hr or
greater, and fossil fuel-fired electric
generating facilities rated at 15 MW or
greater.
Rhode Island................. Electricity generating plants.
Vermont...................... Fossil fuel-fired electric utility
generating facilities with a maximum
gross heat input rate of 250 mmBtu/hr or
greater and potentially other
unidentified major sources.
------------------------------------------------------------------------
BILLING CODE 6560-50-P
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BILLING CODE 6560-50-C
PART 97--FEDERAL NOX BUDGET TRADING PROGRAM
4. Part 97 is added to read as follows:
Subpart A--Federal NOX Budget Trading Program General
Provisions
Sec.
97.1 Purpose.
97.2 Definitions.
97.3 Measurements, abbreviations, and acronyms.
97.4 Applicability.
97.5 Retired unit exemption.
97.6 Standard requirements.
97.7 Computation of time.
Subpart B--NOX Authorized Account Representative for
NOX Budget Sources
97.10 Authorization and responsibilities of the NOX
authorized account representative.
97.11 Alternate NOX authorized account representative.
97.12 Changing the NOX authorized account
representative, and the alternate NOX authorized account
representative; changes in the owners and operators.
97.13 Account certificate of representation.
97.14 Objections concerning the NOX authorized account
representative.
Subpart C--Permits
97.20 General NOX budget trading program permit
requirements.
97.21 NOX Budget permit applications.
97.22 Information requirements for NOX Budget permit
applications.
97.23 NOX Budget permit contents.
97.24 Effective date of initial NOX Budget permit.
97.25 NOX Budget permit revisions.
Subpart D--Compliance Certification
97.30 Compliance certification report.
97.31 Administrator's action on compliance certifications.
Subpart E--NOX Allowance Allocations
97.40 Trading program budget.
97.41 Timing requirements for NOX allowance allocations.
97.42 NOX allowance allocations.
Subpart F--NOX Allowance Tracking System
97.50 NOX Allowance Tracking System accounts.
97.51 Establishment of accounts.
97.52 NOX Allowance Tracking System responsibilities of
NOX authorized account representative.
97.53 Recordation of NOX allowance allocations.
97.54 Compliance.
97.55 Banking.
97.56 Account error.
97.57 Closing of general accounts.
Subpart G--NOX Allowance Transfers
97.60 Submission of NOX allowance transfers.
97.61 EPA recordation.
97.62 Notification.
Subpart H--Monitoring and Reporting
97.70 General requirements.
97.71 Initial certification and recertification procedures.
97.72 Out of control periods.
97.73 Notifications.
97.74 Recordkeeping and reporting.
97.75 Petitions.
97.76 Additional requirements to provide heat data imput.
Subpart I--Individual Unit Opt-ins
97.80 Applicability.
97.81 General.
97.82 Applying for NOX authorized account
representative.
97.83 Applying for NOX Budget opt-in permit.
97.84 Opt-in process.
97.85 NOX Budget opt-in permit contents.
97.86 Withdrawal from NOX Budget Trading Program.
97.87 Change in regulatory status.
97.88 NOX allowance allocations to opt-in units.
Appendix A to Part 97--NOX Allowance Allocation Tables
for Affected Sources Under Section 126 of the Act
Appendix B to Part 97--NOX Allowance Allocation Tables
for Affected Sources Under Section 110 of the Act in Georgia, South
Carolina, and Wisconsin
Appendix C to Part 97--State-By-State Maximum Summer NOX
Emission Levels and Allocation Aggregates
Authority: 42 U.S.C. 7401, 7403, 7410, and 7601.
Subpart A--Federal NOX Budget Trading Program General
Provisions
Sec. 97.1 Purpose.
This part establishes general provisions and the applicability,
permitting, allowance, excess emissions, monitoring, and opt-in
provisions for the federal NOX Budget Trading Program, under
section 110(c) or section 126 of the Act, as a means of mitigating the
interstate transport of ozone and nitrogen oxides, an ozone precursor.
The owner or operator of a unit, or any other person, shall comply with
[[Page 56338]]
requirements of this part as a matter of federal law only if such
compliance is required by Sec. 52.34 or Sec. 52.35 of this chapter.
Sec. 97.2 Definitions.
The terms used in this part shall have the meanings set forth in
this section as follows:
Account certificate of representation means the completed and
signed submission required by subpart B of this part for certifying the
designation of a NOX authorized account representative for a
NOX Budget source or a group of identified NOX
Budget sources who is authorized to represent the owners and operators
of such source or sources and of the NOX Budget units at
such source or sources with regard to matters under the NOX
Budget Trading Program.
Account number means the identification number given by the
Administrator to each NOX Allowance Tracking System account.
Acid Rain emissions limitation means, as defined in Sec. 72.2 of
this chapter, a limitation on emissions of sulfur dioxide or nitrogen
oxides under the Acid Rain Program under title IV of the Clean Air Act.
Administrator means the Administrator of the United States
Environmental Protection Agency or the Administrator's duly authorized
representative.
Allocate or allocation means the determination by the permitting
authority or the Administrator of the number of NOX
allowances to be initially credited to a NOX Budget unit or
an allocation set-aside.
Automated data acquisition and handling system or DAHS means that
component of the CEMS, or other emissions monitoring system approved
for use under subpart H of this part, designed to interpret and convert
individual output signals from pollutant concentration monitors, flow
monitors, diluent gas monitors, and other component parts of the
monitoring system to produce a continuous record of the measured
parameters in the measurement units required by subpart H of this part.
Boiler means an enclosed fossil or other fuel-fired combustion
device used to produce heat and to transfer heat to recirculating
water, steam, or other medium.
Clean Air Act means the Clean Air Act, 42 U.S.C. 7401, et seq., as
amended by Pub. L. No. 101-549 (November 15, 1990).
Combined cycle system means a system comprised of one or more
combustion turbines, heat recovery steam generators, and steam turbines
configured to improve overall efficiency of electricity generation or
steam production.
Combustion turbine means an enclosed fossil or other fuel-fired
device that is comprised of a compressor, a combustor, and a turbine,
and in which the flue gas resulting from the combustion of fuel in the
combustor passes through the turbine, rotating the turbine.
Commence commercial operation means, with regard to a unit that
serves a generator, to have begun to produce steam, gas, or other
heated medium used to generate electricity for sale or use, including
test generation. Except as provided in Sec. 97.5, for a unit that is a
NOX Budget unit under Sec. 97.4 on the date the unit
commences commercial operation, such date shall remain the unit's date
of commencement of commercial operation even if the unit is
subsequently modified, reconstructed, or repowered. Except as provided
in Sec. 97.5 or subpart I of this part, for a unit that is not a
NOX Budget unit under Sec. 97.4 on the date the unit
commences commercial operation, the date the unit becomes a
NOX Budget unit under Sec. 97.4 shall be the unit's date of
commencement of commercial operation.
Commence operation means to have begun any mechanical, chemical, or
electronic process, including, with regard to a unit, start-up of a
unit's combustion chamber. Except as provided in Sec. 97.5, for a unit
that is a NOX Budget unit under Sec. 97.4 on the date of
commencement of operation, such date shall remain the unit's date of
commencement of operation even if the unit is subsequently modified,
reconstructed, or repowered. Except as provided in Sec. 97.5 or subpart
I of this part, for a unit that is not a NOX Budget unit
under Sec. 97.4 on the date of commencement of operation, the date the
unit becomes a NOX Budget unit under Sec. 97.4 shall be the
unit's date of commencement of operation.
Common stack means a single flue through which emissions from two
or more units are exhausted.
Compliance certification means a submission to the permitting
authority or the Administrator, as appropriate, that is required under
subpart D of this part to report a NOX Budget source's or a
NOX Budget unit's compliance or noncompliance with this part
and that is signed by the NOX authorized account
representative in accordance with subpart B of this part.
Compliance account means a NOX Allowance Tracking System
account, established by the Administrator for a NOX Budget
unit under subpart F of this part, in which the NOX
allowance allocations for the unit are initially recorded and in which
are held NOX allowances available for use by the unit for a
control period for the purpose of meeting the unit's NOX
Budget emissions limitation.
Continuous emission monitoring system or CEMS means the equipment
required under subpart H of this part to sample, analyze, measure, and
provide, by readings taken at least once every 15 minutes of the
measured parameters, a permanent record of nitrogen oxides emissions,
expressed in tons per hour for nitrogen oxides. The following systems
are component parts included, consistent with part 75 of this chapter,
in a continuous emission monitoring system:
(1) Flow monitor;
(2) Nitrogen oxides pollutant concentration monitors;
(3) Diluent gas monitor (oxygen or carbon dioxide) when such
monitoring is required by subpart H of this part;
(4) A continuous moisture monitor when such monitoring is required
by subpart H of this part; and
(5) An automated data acquisition and handling system.
Control period means the period beginning May 1 of a year and
ending on September 30 of the same year, inclusive.
Emissions means air pollutants exhausted from a unit or source into
the atmosphere, as measured, recorded, and reported to the
Administrator by the NOX authorized account representative
and as determined by the Administrator in accordance with subpart H of
this part.
Energy Information Administration means the Energy Information
Administration of the United States Department of Energy.
Excess emissions means any tonnage of nitrogen oxides emitted by a
NOX Budget unit during a control period that exceeds the
NOX Budget emissions limitation for the unit.
Fossil fuel means natural gas, petroleum, coal, or any form of
solid, liquid, or gaseous fuel derived from such material.
Fossil fuel-fired means, with regard to a unit:
(1)The combustion of fossil fuel, alone or in combination with any
other fuel, where fossil fuel actually combusted comprises more than 50
percent of the annual heat input on a Btu basis during any year
starting in 1995 or, if a unit had no heat input starting in 1995,
during the last year of operation of the unit prior to 1995; or
(2)The combustion of fossil fuel, alone or in combination with any
other fuel,
[[Page 56339]]
where fossil fuel is projected to comprise more than 50 percent of the
annual heat input on a Btu basis during any year; provided that the
unit shall be ``fossil fuel-fired'' as of the date, during such year,
on which the unit begins combusting fossil fuel.
General account means a NOX Allowance Tracking System
account, established under subpart F of this part, that is not a
compliance account or an overdraft account.
Generator means a device that produces electricity.
Heat input means the product (in mmBtu/time) of the gross calorific
value of the fuel (in Btu/lb) and the fuel feed rate into a combustion
device (in mass of fuel/time), as measured, recorded, and reported to
the Administrator by the NOX authorized account
representative and as determined by the Administrator in accordance
with subpart H of this part, and does not include the heat derived from
preheated combustion air, recirculated flue gases, or exhaust from
other sources.
Life-of-the-unit, firm power contractual arrangement means a unit
participation power sales agreement under which a utility or industrial
customer reserves, or is entitled to receive, a specified amount or
percentage of nameplate capacity and associated energy from any
specified unit and pays its proportional amount of such unit's total
costs, pursuant to a contract:
(1) For the life of the unit;
(2) For a cumulative term of no less than 30 years, including
contracts that permit an election for early termination; or
(3) For a period equal to or greater than 25 years or 70 percent of
the economic useful life of the unit determined as of the time the unit
is built, with option rights to purchase or release some portion of the
nameplate capacity and associated energy generated by the unit at the
end of the period.
Maximum design heat input means the ability of a unit to combust a
stated maximum amount of fuel per hour on a steady state basis, as
determined by the physical design and physical characteristics of the
unit.
Maximum potential hourly heat input means an hourly heat input used
for reporting purposes when a unit lacks certified monitors to report
heat input. If the unit intends to use appendix D of part 75 of this
chapter to report heat input, this value should be calculated, in
accordance with part 75 of this chapter, using the maximum fuel flow
rate and the maximum gross calorific value. If the unit intends to use
a flow monitor and a diluent gas monitor, this value should be
reported, in accordance with part 75 of this chapter, using the maximum
potential flowrate and either the maximum carbon dioxide concentration
(in percent CO2) or the minimum oxygen concentration (in
percent O2).
Maximum potential NOX emission rate means the emission
rate of nitrogen oxides (in lb/mmBtu) calculated in accordance with
section 3 of appendix F of part 75 of this chapter, using the maximum
potential nitrogen oxides concentration as defined in section 2 of
appendix A of part 75 of this chapter, and either the maximum oxygen
concentration (in percent O2) or the minimum carbon dioxide
concentration (in percent CO2), under all operating
conditions of the unit except for unit start up, shutdown, and upsets.
Maximum rated hourly heat input means a unit specific maximum
hourly heat input (mmBtu) which is the higher of the manufacturers
maximum rated hourly heat input or the highest observed hourly heat
input.
Monitoring system means any monitoring system that meets the
requirements of subpart H of this part, including a continuous
emissions monitoring system, an excepted monitoring system, or an
alternative monitoring system.
Most stringent State or Federal NOX emissions limitation
means, with regard to a NOX Budget opt-in source, the lowest
NOX emissions limitation (in terms of lb/mmBtu) that is
applicable to the unit under State or Federal law, regardless of the
averaging period to which the emissions limitation applies.
Nameplate capacity means the maximum electrical generating output
(in MWe) that a generator can sustain over a specified period of time
when not restricted by seasonal or other deratings as measured in
accordance with the United States Department of Energy standards.
Non-title V permit means a federally enforceable permit
administered by the permitting authority pursuant to the Clean Air Act
and regulatory authority under the Clean Air Act, other than title V of
the Clean Air Act and part 70 or 71 of this chapter.
NOX allowance means an authorization by the permitting
authority or the Administrator under the NOX Budget Trading
Program to emit up to one ton of nitrogen oxides during the control
period of the specified year or of any year thereafter.
NOX allowance deduction or deduct NOX
allowances means the permanent withdrawal of NOX allowances
by the Administrator from a NOX Allowance Tracking System
compliance account or overdraft account to account for the number of
tons of NOX emissions from a NOX Budget unit for
a control period, determined in accordance with subparts H and F of
this part, or for any other allowance surrender obligation under this
part.
NOX allowances held or hold NOX allowances
means the NOX allowances recorded by the Administrator, or
submitted to the Administrator for recordation, in accordance with
subparts F and G of this part, in a NOX Allowance Tracking
System account.
NOX Allowance Tracking System means the system by which
the Administrator records allocations, deductions, and transfers of
NOX allowances under the NOX Budget Trading
Program.
NOX Allowance Tracking System account means an account
in the NOX Allowance Tracking System established by the
Administrator for purposes of recording the allocation, holding,
transferring, or deducting of NOX allowances.
NOX allowance transfer deadline means midnight of
November 30 or, if November 30 is not a business day, midnight of the
first business day thereafter and is the deadline by which
NOX allowances may be submitted for recordation in a
NOX Budget unit's compliance account, or the overdraft
account of the source where the unit is located, in order to meet the
unit's NOX Budget emissions limitation for the control
period immediately preceding such deadline.
NOX authorized account representative means, for a
NOX Budget source or NOX Budget unit at the
source, the natural person who is authorized by the owners and
operators of the source and all NOX Budget units at the
source, in accordance with subpart B of this part, to represent and
legally bind each owner and operator in matters pertaining to the
NOX Budget Trading Program or, for a general account, the
natural person who is authorized, in accordance with subpart F of this
part, to transfer or otherwise dispose of NOX allowances
held in the general account.
NOX Budget emissions limitation means, for a
NOX budget unit, the tonnage equivalent of the
NOX allowances available for compliance deduction for the
unit under Sec. 97.54 (a) and (b) in a control period adjusted by
deductions of such NOX allowances to account for actual
utilization under Sec. 97.42(e) for the control period, or to account
for excess emissions for a prior control period under Sec. 97.54(d) or
to account for withdrawal from the NOX budget trading
program or for a change
[[Page 56340]]
in regulatory states, of a NOX budget opt-in source under
Sec. 97.86 or Sec. 97.88.
NOX Budget opt-in permit means a NOX Budget
permit covering a NOX Budget opt-in source.
NOX Budget opt-in source means a unit that has been
elected to become a NOX Budget unit under the NOX
Budget Trading Program and whose NOX budget opt-in permit
has been issued and is in effect under subpart I of this part.
NOX Budget permit means the legally binding and
federally enforceable written document, or portion of such document,
issued by the permitting authority under this part, including any
permit revisions, specifying the NOX Budget Trading Program
requirements applicable to a NOX Budget source, to each
NOX Budget unit at the NOX Budget source, and to
the owners and operators and the NOX authorized account
representative of the NOX Budget source and each
NOX Budget unit.
NOX Budget source means a source that includes one or
more NOX Budget units.
NOX Budget Trading Program means a multi-state nitrogen
oxides air pollution control and emission reduction program established
in accordance with this part and pursuant to Sec. 52.34 or Sec. 52.35
of this chapter, as a means of mitigating the interstate transport of
ozone and nitrogen oxides, an ozone precursor.
NOX Budget unit means a unit that is subject to the
NOX Budget Trading Program emissions limitation under
Sec. 97.4 or Sec. 97.80.
Operating means, with regard to a unit under Secs. 97.22(d)(2) and
97.80, having documented heat input for more than 876 hours in the 6
months immediately preceding the submission of an application for an
initial NOX Budget permit under Sec. 97.83(a).
Operator means any person who operates, controls, or supervises a
NOX Budget unit, a NOX Budget source, or unit for
which an application for a NOX Budget opt-in permit under
Sec. 97.83 is submitted and not denied or withdrawn and shall include,
but not be limited to, any holding company, utility system, or plant
manager of such a unit or source.
Opt-in means to be elected to become a NOX Budget unit
under the NOX Budget Trading Program through a final,
effective NOX Budget opt-in permit under subpart I of this
part.
Overdraft account means the NOX Allowance Tracking
System account, established by the Administrator under subpart F of
this part, for each NOX Budget source where there are two or
more NOX Budget units.
Owner means any of the following persons:
(1) Any holder of any portion of the legal or equitable title in a
NOX Budget unit or in a unit for which an application for a
NOX Budget opt-in permit under Sec. 97.83 submitted and not
denied or withdrawn; or
(2) Any holder of a leasehold interest in a NOX Budget
unit or in a unit for which an application for a NOX Budget
opt-in permit under Sec. 97.83 is submitted and not denied or
withdrawn; or
(3) Any purchaser of power from a NOX Budget unit or
from a unit for which an application for a NOX Budget opt-in
permit under Sec. 97.83 is submitted and not denied or withdrawn under
a life-of-the-unit, firm power contractual arrangement. However, unless
expressly provided for in a leasehold agreement, owner shall not
include a passive lessor, or a person who has an equitable interest
through such lessor, whose rental payments are not based, either
directly or indirectly, upon the revenues or income from the
NOX Budget unit or the unit for which an application for a
NOX Budget opt-in permit under Sec. 97.83 is submitted and
not denied or withdrawn; or
(4) With respect to any general account, any person who has an
ownership interest with respect to the NOX allowances held
in the general account and who is subject to the binding agreement for
the NOX authorized account representative to represent that
person's ownership interest with respect to NOX allowances.
Permitting authority means the State air pollution control agency,
local agency, other State agency, or other agency authorized by the
Administrator to issue or revise permits to meet the requirements of
the NOX Budget Trading Program in accordance with subpart C
of this part.
Receive or receipt of means, when referring to the permitting
authority or the Administrator, to come into possession of a document,
information, or correspondence (whether sent in writing or by
authorized electronic transmission), as indicated in an official
correspondence log, or by a notation made on the document, information,
or correspondence, by the permitting authority or the Administrator in
the regular course of business.
Recordation, record, or recorded means, with regard to
NOX allowances, the movement of NOX allowances by
the Administrator from one NOX Allowance Tracking System
account to another, for purposes of allocation, transfer, or deduction.
Reference method means any direct test method of sampling and
analyzing for an air pollutant as specified in appendix A of part 60 of
this chapter.
Serial number means, when referring to NOX allowances,
the unique identification number assigned to each NOX
allowance by the Administrator, under Sec. 97.53(c).
Source means any governmental, institutional, commercial, or
industrial structure, installation, plant, building, or facility that
emits or has the potential to emit any regulated air pollutant under
the Clean Air Act. For purposes of section 502(c) of the Clean Air Act,
a ``source,'' including a ``source'' with multiple units, shall be
considered a single ``facility.''
State means one of the 48 contiguous States and the District of
Columbia specified in Sec. 52.34 or Sec. 52.35 of this chapter, or any
non-federal authority in or including such States or the District of
Columbia (including local agencies, and Statewide agencies) or any
eligible Indian tribe in an area of such State or the District of
Columbia, for which the NOX Budget Trading Program is
promulgated pursuant to Sec. 52.34 or Sec. 52.35 of this chapter.
Submit or serve means to send or transmit a document, information,
or correspondence to the person specified in accordance with the
applicable regulation:
(1) In person;
(2) By United States Postal Service; or
(3) By other means of dispatch or transmission and delivery.
Compliance with any ``submission,'' ``service,'' or ``mailing''
deadline shall be determined by the date of dispatch, transmission, or
mailing and not the date of receipt.
Title V operating permit means a permit issued under title V of the
Clean Air Act and part 70 or part 71 of this chapter.
Title V operating permit regulations means the regulations that the
Administrator has approved or issued as meeting the requirements of
title V of the Clean Air Act and part 70 or 71 of this chapter.
Ton or tonnage means any ``short ton'' (i.e., 2,000 pounds). For
the purpose of determining compliance with the NOX Budget
emissions limitation, total tons for a control period shall be
calculated as the sum of all recorded hourly emissions (or the tonnage
equivalent of the recorded hourly emissions rates) in accordance with
subpart H of this part, with any remaining fraction of a ton equal to
or greater than 0.50 ton deemed to equal one ton and any fraction of a
ton less than 0.50 ton deemed to equal zero tons.
Trading program budget means the total number of NOX
tons apportioned to all NOX Budget units in a State in
[[Page 56341]]
accordance with the NOX Budget Trading Program, under
section 110(c) or section 126 of the Act, for use in a given control
period. For purposes of the NOX Budget Trading Program under
section 110(c), the trading program budget is the sum of the aggregate
emission levels for large EGUs and large non-EGUs in a State set forth
for each State in appendix C of this part. For purposes of the
NOX Budget Trading Program under section 126, the trading
program budget is the ``126 trading program budget for the State'', and
is determined in the same manner and is also set forth in appendix C of
this part.
Unit means a fossil fuel-fired stationary boiler, combustion
turbine, or combined cycle system.
Unit load means the total (i.e., gross) output of a unit in any
control period (or other specified time period) produced by combusting
a given heat input of fuel, expressed in terms of:
(1) The total electrical generation (MWe) produced by the unit,
including generation for use within the plant; or
(2) In the case of a unit that uses heat input for purposes other
than electrical generation, the total steam in pounds of steam per hour
produced by the unit, including steam for use by the unit.
Unit operating day means a calendar day in which a unit combusts
any fuel.
Unit operating hour or hour of unit operation means any hour (or
fraction of an hour) during which a unit combusts any fuel.
Utilization means the heat input (expressed in mmBtu/time) for a
unit. The unit's total heat input for the control period in each year
will be determined in accordance with part 75 of this chapter if the
NOX Budget unit was otherwise subject to the requirements of
part 75 of this chapter for the year, or will be based on the best
available data reported to the Administrator for the unit if the unit
was not otherwise subject to the requirements of part 75 of this
chapter for the year.
Sec. 97.3 Measurements, abbreviations, and acronyms.
Measurements, abbreviations, and acronyms used in this part are
defined as follows:
Btu--British thermal unit.
hr--hour.
Kwh--kilowatt hour.
lb--pounds.
mmBtu--million Btu.
MWe--megawatt electrical.
ton--2000 pounds
CO2--carbon dioxide.
NOX--nitrogen oxides.
O2--oxygen.
Sec. 97.4 Applicability.
(a) The following units in a State shall be NOX Budget
units, and any source that includes one or more such units shall be a
NOX Budget source, subject to the requirements of this part:
(1) Any unit that, any time on or after January 1, 1995, serves a
generator with a nameplate capacity greater than 25 MWe and sells any
amount of electricity; or
(2) Any unit that is not a unit under paragraph (a) of this section
and that has a maximum design heat input greater than 250 mmBtu/hr.
(b) Notwithstanding paragraph (a) of this section, a unit under
paragraph (a)(1) or (a)(2) of this section that has a federally
enforceable permit that includes a NOX emission limitation
restricting NOX emissions during a control period to 25 tons
or less shall not be subject to the requirements of this part for any
year in which the control period is covered by such emission limitation
in the unit's federally enforceable permit. However, if such emission
limitation is removed from the unit's federally enforceable permit or
otherwise becomes no longer applicable to any control period starting
in 2003 or if the unit does not comply with such emission limitation
during any control period starting in 2003, the unit shall be subject
to the requirements of this part and shall be treated as commencing
operation and, if the unit is covered by paragraph (a)(1) of this
section, commencing commercial operation on September 30 of the control
period for which the emission limitation is no longer applicable or
during which the unit does not comply with the emission limitation. The
permitting authority that issues the federally enforceable permit with
such emission limitation will provide the Administrator written
notification of each unit under paragraph (a)(1) or (a)(2) of this
section for which the permitting authority issued such a permit. A unit
subject to a federally enforceable permit with such emission limitation
shall be subject to the following requirements:
(1) The unit shall keep on site records demonstrating that
conditions of the permit were met, including restrictions on operating
time.
(2) The unit shall report hours of operation during the control
period to the permitting authority by November 1 of each year in which
the unit is subject to a federally enforceable permit with such
emission limitation.
(3) The unit shall determine the appropriate restrictions on its
operating time by dividing 25 tons by the unit's maximum potential
hourly NOX mass emissions where the unit's maximum potential
hourly NOX mass emissions would be determined by multiplying
the highest default emission rates otherwise applicable under
Sec. 75.19 of this chapter by the maximum rated hourly heat input of
the unit.
Sec. 97.5 Retired unit exemption.
(a) This section applies to any NOX Budget unit, other
than a NOX Budget opt-in source, that is permanently
retired.
(b)(1) Any NOX Budget unit, other than a NOX
Budget opt-in source, that is permanently retired shall be exempt from
the NOX Budget Trading Program, except for the provisions of
this section, Secs. 97.2, 97.3, 97.4, 97.7 and subparts E, F, and G of
this part.
(2) The exemption under paragraph (b)(1) of this section shall
become effective the day on which the unit is permanently retired.
Within 30 days of permanent retirement, the NOX authorized
account representative (authorized in accordance with subpart B of this
part) shall submit a statement to the permitting authority otherwise
responsible for administering any NOX Budget permit for the
unit. A copy of the statement shall be submitted to the Administrator.
The statement shall state (in a format prescribed by the permitting
authority) that the unit is permanently retired and will comply with
the requirements of paragraph (c) of this section.
(3) After receipt of the notice under paragraph (b)(2) of this
section, the permitting authority will amend any permit covering the
source at which the unit is located to add the provisions and
requirements of the exemption under paragraphs (b)(1) and (c) of this
section.
(c) Special provisions.
(1) A unit exempt under this section shall not emit any nitrogen
oxides, starting on the date that the exemption takes effect. The
owners and operators of the unit will be allocated allowances in
accordance with subpart E of this part.
(2)(i) A unit exempt under this section and located at a source
that is required, or but for this exemption would be required, to have
a title V operating permit shall not resume operation unless the
NOX authorized account representative of the source submits
a complete NOX Budget permit application under Sec. 97.22
for the unit not less than 18 months (or such lesser time provided
under the permitting authority for final action on a permit
application) prior to the later of May 1, 2003 or the date on which the
unit is to first resume operation.
[[Page 56342]]
(ii) A unit exempt under this section and located at a source that
is required, or but for this exemption would be required, to have a
non-title V permit shall not resume operation unless the NOX
authorized account representative of the source submits a complete
NOX Budget permit application under Sec. 97.22 for the unit
not less than 18 months (or such lesser time provided under the
permitting authority for final action on a permit application) prior to
the later of May 1, 2003 or the date on which the unit is to first
resume operation.
(3) The owners and operators and, to the extent applicable, the
NOX authorized account representative of a unit exempt under
this section shall comply with the requirements of the NOX
Budget Trading Program concerning all periods for which the exemption
is not in effect, even if such requirements arise, or must be complied
with, after the exemption takes effect.
(4) A unit that is exempt under this section is not eligible to be
a NOX Budget opt-in source under subpart I of this part.
(5) For a period of 5 years from the date the records are created,
the owners and operators of a unit exempt under this section shall
retain at the source that includes the unit, records demonstrating that
the unit is permanently retired. The 5-year period for keeping records
may be extended for cause, at any time prior to the end of the period,
in writing by the permitting authority or the Administrator. The owners
and operators bear the burden of proof that the unit is permanently
retired.
(6) Loss of exemption.
(i) On the earlier of the following dates, a unit exempt under
paragraph (b) of this section shall lose its exemption:
(A) The date on which the NOX authorized account
representative submits a NOX Budget permit application under
paragraph (c)(2) of this section; or
(B) The date on which the NOX authorized account
representative is required under paragraph (c)(2) of this section to
submit a NOX Budget permit application.
(ii) For the purpose of applying monitoring requirements under
subpart H of this part, a unit that loses its exemption under this
section shall be treated as a unit that commences operation or
commercial operation on the first date on which the unit resumes
operation.
Sec. 97.6 Standard requirements.
(a) Permit requirements. (1) The NOX authorized account
representative of each NOX Budget source required to have a
federally enforceable permit and each NOX Budget unit
required to have a federally enforceable permit at the source shall:
(i) Submit to the permitting authority a complete NOX
Budget permit application under Sec. 97.22 in accordance with the
deadlines specified in Sec. 97.21(b) and (c);
(ii) Submit in a timely manner any supplemental information that
the permitting authority determines is necessary in order to review a
NOX Budget permit application and issue or deny a
NOX Budget permit.
(2) The owners and operators of each NOX Budget source
required to have a federally enforceable permit and each NOX
Budget unit required to have a federally enforceable permit at the
source shall have a NOX Budget permit issued by the
permitting authority and operate the unit in compliance with such
NOX Budget permit.
(3) The owners and operators of a NOX Budget source that
is not otherwise required to have a federally enforceable permit are
not required to submit a NOX Budget permit application, and
to have a NOX Budget permit, under subpart C of this part
for such NOX Budget source.
(b) Monitoring requirements. (1) The owners and operators and, to
the extent applicable, the NOX authorized account
representative of each NOX Budget source and each
NOX Budget unit at the source shall comply with the
monitoring requirements of subpart H of this part.
(2) The emissions measurements recorded and reported in accordance
with subpart H of this part shall be used to determine compliance by
the unit with the NOX Budget emissions limitation under
paragraph (c) of this section.
(c) Nitrogen oxides requirements. (1) The owners and operators of
each NOX Budget source and each NOX Budget unit
at the source shall hold NOX allowances available for
compliance deductions under Sec. 97.54, as of the NOX
allowance transfer deadline, in the unit's compliance account and the
source's overdraft account in an amount not less than the total
NOX emissions for the control period from the unit, as
determined in accordance with subpart H of this part, plus any amount
necessary to account for actual utilization under Sec. 97.42(e) for the
control period.
(2) Each ton of nitrogen oxides emitted in excess of the
NOX Budget emissions limitation shall constitute a separate
violation of this part, the Clean Air Act, and applicable State law.
(3) A NOX Budget unit shall be subject to the
requirements under paragraph (c)(1) of this section starting on the
later of May 1, 2003 or the date on which the unit commences operation.
(4) NOX allowances shall be held in, deducted from, or
transferred among NOX Allowance Tracking System accounts in
accordance with subparts E, F, G, and I of this part.
(5) A NOX allowance shall not be deducted, in order to
comply with the requirements under paragraph (c)(1) of this section,
for a control period in a year prior to the year for which the
NOX allowance was allocated.
(6) A NOX allowance allocated by the permitting
authority or the Administrator under the NOX Budget Trading
Program is a limited authorization to emit one ton of nitrogen oxides
in accordance with the NOX Budget Trading Program. No
provision of the NOX Budget Trading Program, the
NOX Budget permit application, the NOX Budget
permit, or an exemption under Sec. 97.5 and no provision of law shall
be construed to limit the authority of the United States or the State
to terminate or limit such authorization.
(7) A NOX allowance allocated by the Administrator under
the NOX Budget Trading Program does not constitute a
property right.
(8) Upon recordation by the Administrator under subpart F, G, or I
of this part, every allocation, transfer, or deduction of a
NOX allowance to or from a NOX Budget unit's
compliance account or the overdraft account of the source where the
unit is located is deemed to amend automatically, and become a part of,
any NOX Budget permit of the NOX Budget unit by
operation of law without any further review.
(d) Excess emissions requirements.
(1) The owners and operators of a NOX Budget unit that
has excess emissions in any control period shall:
(i) Surrender the NOX allowances required for deduction
under Sec. 97.54(d)(1); and
(ii) Pay any fine, penalty, or assessment or comply with any other
remedy imposed under Sec. 97.54(d)(3).
(e) Recordkeeping and reporting requirements. (1) Unless otherwise
provided, the owners and operators of the NOX Budget source
and each NOX Budget unit at the source shall keep on site at
the source each of the following documents for a period of 5 years from
the date the document is created. This period may be extended for
cause, at any time prior to the end of 5 years, in writing by the
permitting authority or the Administrator.
(i) The account certificate of representation for the
NOX authorized account representative for the source
[[Page 56343]]
and each NOX Budget unit at the source and all documents
that demonstrate the truth of the statements in the account certificate
of representation, in accordance with Sec. 97.13; provided that the
certificate and documents shall be retained on site at the source
beyond such 5-year period until such documents are superseded because
of the submission of a new account certificate of representation
changing the NOX authorized account representative.
(ii) All emissions monitoring information, in accordance with
subpart H of this part; provided that to the extent that subpart H of
this part provides for a 3-year period for recordkeeping, the 3-year
period shall apply.
(iii) Copies of all reports, compliance certifications, and other
submissions and all records made or required under the NOX
Budget Trading Program.
(iv) Copies of all documents used to complete a NOX
Budget permit application and any other submission under the
NOX Budget Trading Program or to demonstrate compliance with
the requirements of the NOX Budget Trading Program.
(2) The NOX authorized account representative of a
NOX Budget source and each NOX Budget unit at the
source shall submit the reports and compliance certifications required
under the NOX Budget Trading Program, including those under
subparts D, H, or I of this part.
(f) Liability. (1) Any person who knowingly violates any
requirement or prohibition of the NOX Budget Trading
Program, a NOX Budget permit, or an exemption under
Sec. 97.5 shall be subject to enforcement pursuant to applicable State
or Federal law.
(2) Any person who knowingly makes a false material statement in
any record, submission, or report under the NOX Budget
Trading Program shall be subject to criminal enforcement pursuant to
the applicable State or Federal law.
(3) No permit revision shall excuse any violation of the
requirements of the NOX Budget Trading Program that occurs
prior to the date that the revision takes effect.
(4) Each NOX Budget source and each NOX
Budget unit shall meet the requirements of the NOX Budget
Trading Program.
(5) Any provision of the NOX Budget Trading Program that
applies to a NOX Budget source (including a provision
applicable to the NOX authorized account representative of a
NOX Budget source) shall also apply to the owners and
operators of such source and of the NOX Budget units at the
source.
(6) Any provision of the NOX Budget Trading Program that
applies to a NOX Budget unit (including a provision
applicable to the NOX authorized account representative of a
NOX budget unit) shall also apply to the owners and
operators of such unit. Except with regard to the requirements
applicable to units with a common stack under subpart H of this part,
the owners and operators and the NOX authorized account
representative of one NOX Budget unit shall not be liable
for any violation by any other NOX Budget unit of which they
are not owners or operators or the NOX authorized account
representative and that is located at a source of which they are not
owners or operators or the NOX authorized account
representative.
(g) Effect on other authorities. No provision of the NOX
Budget Trading Program, a NOX Budget permit application, a
NOX Budget permit, or an exemption under Sec. 97.5 shall be
construed as exempting or excluding the owners and operators and, to
the extent applicable, the NOX authorized account
representative of a NOX Budget source or NOX
Budget unit from compliance with any other provision of the applicable,
approved State implementation plan, a federally enforceable permit, or
the Clean Air Act.
Sec. 97.7 Computation of time.
(a) Unless otherwise stated, any time period scheduled, under the
NOX Budget Trading Program, to begin on the occurrence of an
act or event shall begin on the day the act or event occurs.
(b) Unless otherwise stated, any time period scheduled, under the
NOX Budget Trading Program, to begin before the occurrence
of an act or event shall be computed so that the period ends the day
before the act or event occurs.
(c) Unless otherwise stated, if the final day of any time period,
under the NOX Budget Trading Program, falls on a weekend or
a State or Federal holiday, the time period shall be extended to the
next business day.
Subpart B--NOX Authorized Account Representative for
NOX Budget Sources
Sec. 97.10 Authorization and responsibilities of the NOX
authorized account representative.
(a) Except as provided under Sec. 97.11, each NOX Budget
source, including all NOX Budget units at the source, shall
have one and only one NOX authorized account representative,
with regard to all matters under the NOX Budget Trading
Program concerning the source or any NOX Budget unit at the
source.
(b) The NOX authorized account representative of the
NOX Budget source shall be selected by an agreement binding
on the owners and operators of the source and all NOX Budget
units at the source.
(c) Upon receipt by the Administrator of a complete account
certificate of representation under Sec. 97.13, the NOX
authorized account representative of the source shall represent and, by
his or her representations, actions, inactions, or submissions, legally
bind each owner and operator of the NOX Budget source
represented and each NOX Budget unit at the source in all
matters pertaining to the NOX Budget Trading Program, not
withstanding any agreement between the NOX authorized
account representative and such owners and operators. The owners and
operators shall be bound by any decision or order issued to the
NOX authorized account representative by the permitting
authority, the Administrator, or a court regarding the source or unit.
(d) No NOX Budget permit shall be issued, and no
NOX Allowance Tracking System account shall be established
for a NOX Budget unit at a source, until the Administrator
has received a complete account certificate of representation under
Sec. 97.13 for a NOX authorized account representative of
the source and the NOX Budget units at the source.
(e)(1) Each submission under the NOX Budget Trading
Program shall be submitted, signed, and certified by the NOX
authorized account representative for each NOX Budget source
on behalf of which the submission is made. Each such submission shall
include the following certification statement by the NOX
authorized account representative: ``I am authorized to make this
submission on behalf of the owners and operators of the NOX
Budget sources or NOX Budget units for which the submission
is made. I certify under penalty of law that I have personally
examined, and am familiar with, the statements and information
submitted in this document and all its attachments. Based on my inquiry
of those individuals with primary responsibility for obtaining the
information, I certify that the statements and information are to the
best of my knowledge and belief true, accurate, and complete. I am
aware that there are significant penalties for submitting false
statements and information or omitting required statements and
information, including the possibility of fine or imprisonment.''
(2) The permitting authority and the Administrator will accept or
act on a submission made on behalf of owner or operators of a
NOX Budget source or a
[[Page 56344]]
NOX Budget unit only if the submission has been made,
signed, and certified in accordance with paragraph (e)(1) of this
section.
Sec. 97.11 Alternate NOX authorized account representative.
(a) An account certificate of representation may designate one and
only one alternate NOX authorized account representative who
may act on behalf of the NOX authorized account
representative. The agreement by which the alternate NOX
authorized account representative is selected shall include a procedure
for authorizing the alternate NOX authorized account
representative to act in lieu of the NOX authorized account
representative.
(b) Upon receipt by the Administrator of a complete account
certificate of representation under Sec. 97.13, any representation,
action, inaction, or submission by the alternate NOX
authorized account representative shall be deemed to be a
representation, action, inaction, or submission by the NOX
authorized account representative.
(c) Except in this section and Secs. 97.10(a), 97.12, 97.13, and
97.51, whenever the term ``NOX authorized account
representative'' is used in this part, the term shall be construed to
include the alternate NOX authorized account representative.
Sec. 97.12 Changing the NOX authorized account
representative and the alternate NOX authorized account
representative; changes in the owners and operators.
(a) Changing the NOX authorized account representative.
The NOX authorized account representative may be changed at
any time upon receipt by the Administrator of a superseding complete
account certificate of representation under Sec. 97.13. Notwithstanding
any such change, all representations, actions, inactions, and
submissions by the previous NOX authorized account
representative prior to the time and date when the Administrator
receives the superseding account certificate of representation shall be
binding on the new NOX authorized account representative and
the owners and operators of the NOX Budget source and the
NOX Budget units at the source.
(b) Changing the alternate NOX authorized account
representative. The alternate NOX authorized account
representative may be changed at any time upon receipt by the
Administrator of a superseding complete account certificate of
representation under Sec. 97.13. Notwithstanding any such change, all
representations, actions, inactions, and submissions by the previous
alternate NOX authorized account representative prior to the
time and date when the Administrator receives the superseding account
certificate of representation shall be binding on the new alternate
NOX authorized account representative and the owners and
operators of the NOX Budget source and the NOX
Budget units at the source.
(c) Changes in the owners and operators. (1) In the event a new
owner or operator of a NOX Budget source or a NOX
Budget unit is not included in the list of owners and operators
submitted in the account certificate of representation, such new owner
or operator shall be deemed to be subject to and bound by the account
certificate of representation, the representations, actions, inactions,
and submissions of the NOX authorized account representative
and any alternate NOX authorized account representative of
the source or unit, and the decisions, orders, actions, and inactions
of the permitting authority or the Administrator, as if the new owner
or operator were included in such list.
(2) Within 30 days following any change in the owners and operators
of a NOX Budget source or a NOX Budget unit,
including the addition of a new owner or operator, the NOX
authorized account representative or alternate NOX
authorized account representative shall submit a revision to the
account certificate of representation amending the list of owners and
operators to include the change.
Sec. 97.13 Account certificate of representation.
(a) A complete account certificate of representation for a
NOX authorized account representative or an alternate
NOX authorized account representative shall include the
following elements in a format prescribed by the Administrator:
(1) Identification of the NOX Budget source and each
NOX Budget unit at the source for which the account
certificate of representation is submitted.
(2) The name, address, e-mail address (if any), telephone number,
and facsimile transmission number (if any) of the NOX
authorized account representative and any alternate NOX
authorized account representative.
(3) A list of the owners and operators of the NOX Budget
source and of each NOX Budget unit at the source.
(4) The following certification statement by the NOX
authorized account representative and any alternate NOX
authorized account representative: ``I certify that I was selected as
the NOX authorized account representative or alternate
NOX authorized account representative, as applicable, by an
agreement binding on the owners and operators of the NOX
Budget source and each NOX Budget unit at the source. I
certify that I have all the necessary authority to carry out my duties
and responsibilities under the NOX Budget Trading Program on
behalf of the owners and operators of the NOX Budget source
and of each NOX Budget unit at the source and that each such
owner and operator shall be fully bound by my representations, actions,
inactions, or submissions and by any decision or order issued to me by
the permitting authority, the Administrator, or a court regarding the
source or unit.''
(5) The signature of the NOX authorized account
representative and any alternate NOX authorized account
representative and the dates signed.
(b) Unless otherwise required by the permitting authority or the
Administrator, documents of agreement referred to in the account
certificate of representation shall not be submitted to the permitting
authority or the Administrator. Neither the permitting authority nor
the Administrator shall be under any obligation to review or evaluate
the sufficiency of such documents, if submitted.
Sec. 97.14 Objections concerning the NOX authorized account
representative.
(a) Once a complete account certificate of representation under
Sec. 97.13 has been submitted and received, the permitting authority
and the Administrator will rely on the account certificate of
representation unless and until a superseding complete account
certificate of representation under Sec. 97.13 is received by the
Administrator.
(b) Except as provided in Sec. 97.12(a) or (b), no objection or
other communication submitted to the permitting authority or the
Administrator concerning the authorization, or any representation,
action, inaction, or submission of the NOX authorized
account representative shall affect any representation, action,
inaction, or submission of the NOX authorized account
representative or the finality of any decision or order by the
permitting authority or the Administrator under the NOX
Budget Trading Program.
(c) Neither the permitting authority nor the Administrator will
adjudicate any private legal dispute concerning the authorization or
any representation, action, inaction, or submission of any
NOX authorized account representative, including private
legal disputes
[[Page 56345]]
concerning the proceeds of NOX allowance transfers.
Subpart C--Permits
Sec. 97.20 General NOX budget trading program permit
requirements.
(a) For each NOX Budget source required to have a
federally enforceable permit, such permit shall include a
NOX Budget permit administered by the permitting authority.
(1) For NOX Budget sources required to have a title V
operating permit, the NOX Budget portion of the title V
permit shall be administered in accordance with the permitting
authority's title V operating permits regulations promulgated under
part 70 or 71 of this chapter, except as provided otherwise by this
subpart or subpart I of this part. The applicable provisions of such
title V operating permits regulations shall include, but are not
limited to, those provisions addressing operating permit applications,
operating permit application shield, operating permit duration,
operating permit shield, operating permit issuance, operating permit
revision and reopening, public participation, State review, and review
by the Administrator.
(2) For NOX Budget sources required to have a non-title
V permit, the NOX Budget portion of the non-title V permit
shall be administered in accordance with the permitting authority's
regulations promulgated to administer non-title V permits, except as
provided otherwise by this subpart or subpart I of this part. The
applicable provisions of such non-title V permits regulations may
include, but are not limited to, provisions addressing permit
applications, permit application shield, permit duration, permit
shield, permit issuance, permit revision and reopening, public
participation, State review, and review by the Administrator.
(b) Each NOX Budget permit (including a draft or
proposed NOX Budget permit, if applicable) shall contain all
applicable NOX Budget Trading Program requirements and shall
be a complete and segregable portion of the permit under paragraph (a)
of this section.
Sec. 97.21 NOX Budget permit applications.
(a) Duty to apply. The NOX authorized account
representative of any NOX Budget source required to have a
federally enforceable permit shall submit to the permitting authority a
complete NOX Budget permit application under Sec. 97.22 by
the applicable deadline in paragraph (b) of this section.
(b)(1) For NOX Budget sources required to have a title V
operating permit:
(i) For any source, with one or more NOX Budget units
under Sec. 97.4 that commence operation before January 1, 2000, the
NOX authorized account representative shall submit a
complete NOX Budget permit application under Sec. 97.22
covering such NOX Budget units to the permitting authority
at least 18 months (or such lesser time provided under the permitting
authority's title V operating permits regulations for final action on a
permit application) before May 1, 2003.
(ii) For any source, with any NOX Budget unit under
Sec. 97.4 that commences operation on or after January 1, 2000, the
NOX authorized account representative shall submit a
complete NOX Budget permit application under Sec. 97.22
covering such NOX Budget unit to the permitting authority at
least 18 months (or such lesser time provided under the permitting
authority's title V operating permits regulations for final action on a
permit application) before the later of May 1, 2003 or the date on
which the NOX Budget unit commences operation.
(2) For NOX Budget sources required to have a non-title
V permit:
(i) For any source, with one or more NOX Budget units
under Sec. 97.4 that commence operation before January 1, 2000, the
NOX authorized account representative shall submit a
complete NOX Budget permit application under Sec. 97.22
covering such NOX Budget units to the permitting authority
at least 18 months (or such lesser time provided under the permitting
authority's non-title V permits regulations for final action on a
permit application) before May 1, 2003.
(ii) For any source, with any NOX Budget unit under
Sec. 97.4 that commences operation on or after January 1, 2000, the
NOX authorized account representative shall submit a
complete NOX Budget permit application under Sec. 97.22
covering such NOX Budget unit to the permitting authority at
least 18 months (or such lesser time provided under the permitting
authority's non-title V permits regulations for final action on a
permit application) before the later of May 1, 2003 or the date on
which the NOX Budget unit commences operation.
(c) Duty to Reapply.
(1) For a NOX Budget source required to have a title V
operating permit, the NOX authorized account representative
shall submit a complete NOX Budget permit application under
Sec. 97.22 for the NOX Budget source covering the
NOX Budget units at the source in accordance with the
permitting authority's title V operating permits regulations addressing
operating permit renewal.
(2) For a NOX Budget source required to have a non-title
V permit, the NOX authorized account representative shall
submit a complete NOX Budget permit application under
Sec. 97.22 for the NOX Budget source covering the
NOX Budget units at the source in accordance with the
permitting authority's non-title V permits regulations addressing
permit renewal.
Sec. 97.22 Information requirements for NOX Budget permit
applications.
A complete NOX Budget permit application shall include
the following elements concerning the NOX Budget source for
which the application is submitted, in a format prescribed by the
permitting authority:
(a) Identification of the NOX Budget source, including
plant name and the ORIS (Office of Regulatory Information Systems) or
facility code assigned to the source by the Energy Information
Administration, if applicable;
(b) Identification of each NOX Budget unit at the
NOX Budget source and whether it is a NOX Budget
unit under Sec. 97.4 or under subpart I of this part;
(c) The standard requirements under Sec. 97.6; and
(d) For each NOX Budget opt-in unit at the
NOX Budget source, the following certification statements by
the NOX authorized account representative:
(1) ``I certify that each unit for which this permit application is
submitted under subpart I of this part is not a NOX Budget
unit under 40 CFR 97.4 and is not covered by a retired unit exemption
under 40 CFR 97.5 that is in effect.''
(2) If the application is for an initial NOX Budget opt-
in permit, ``I certify that each unit for which this permit application
is submitted under subpart I is currently operating, as that term is
defined under 40 CFR 97.2.''
Sec. 97.23 NOX Budget permit contents.
(a) Each NOX Budget permit (including any draft or
proposed NOX Budget permit, if applicable) will contain, in
a format prescribed by the permitting authority, all elements required
for a complete NOX Budget permit application under
Sec. 97.22 as approved or adjusted by the permitting authority.
(b) Each NOX Budget permit is deemed to incorporate
automatically the definitions of terms under Sec. 97.2 and, upon
recordation by the Administrator under subparts F, G, or I of this
part, every allocation, transfer, or deduction of a NOX
allowance to or from the compliance accounts of the NOX
Budget
[[Page 56346]]
units covered by the permit or the overdraft account of the
NOX Budget source covered by the permit.
Sec. 97.24 Effective date of initial NOX Budget permit.
The initial NOX Budget permit covering a NOX
Budget unit for which a complete NOX Budget permit
application is timely submitted under Sec. 97.21(b) shall become
effective by the later of:
(a) May 1, 2003;
(b) May 1 of the year in which the NOX Budget unit
commences operation, if the unit commences operation on or before May 1
of that year;
(c) The date on which the NOX Budget unit commences
operation, if the unit commences operation during a control period; or
(d) May 1 of the year following the year in which the
NOX Budget unit commences operation, if the unit commences
operation on or after October 1 of the year.
Sec. 97.25 NOX Budget permit revisions.
(a) For a NOX Budget source with a title V operating
permit, except as provided in Sec. 97.23(b), the permitting authority
will revise the NOX Budget permit, as necessary, in
accordance with the permitting authority's title V operating permits
regulations addressing permit revisions.
(b) For a NOX Budget source with a non-title V permit,
except as provided in Sec. 97.23(b), the permitting authority will
revise the NOX Budget permit, as necessary, in accordance
with the permitting authority's non-title V permits regulations
addressing permit revisions.
Subpart D--Compliance Certification
Sec. 97.30 Compliance certification report.
(a) Applicability and deadline. For each control period in which
one or more NOX Budget units at a source are subject to the
NOX Budget emissions limitation, the NOX
authorized account representative of the source shall submit to the
permitting authority and the Administrator by November 30 of that year,
a compliance certification report for each source covering all such
units.
(b) Contents of report. The NOX authorized account
representative shall include in the compliance certification report
under paragraph (a) of this section the following elements, in a format
prescribed by the Administrator, concerning each unit at the source and
subject to the NOX Budget emissions limitation for the
control period covered by the report:
(1) Identification of each NOX Budget unit;
(2) At the NOX authorized account representative's
option, the serial numbers of the NOX allowances that are to
be deducted from each unit's compliance account under Sec. 97.54 for
the control period;
(3) At the NOX authorized account representative's
option, for units sharing a common stack and having NOX
emissions that are not monitored separately or apportioned in
accordance with subpart H of this part, the percentage of allowances
that is to be deducted from each unit's compliance account under
Sec. 97.54(e);
and (4) The compliance certification under paragraph (c) of this
section.
(c) Compliance certification. In the compliance certification
report under paragraph (a) of this section, the NOX
authorized account representative shall certify, based on reasonable
inquiry of those persons with primary responsibility for operating the
source and the NOX Budget units at the source in compliance
with the NOX Budget Trading Program, whether each
NOX Budget unit for which the compliance certification is
submitted was operated during the calendar year covered by the report
in compliance with the requirements of the NOX Budget
Trading Program applicable to the unit, including:
(1) Whether the unit was operated in compliance with the
NOX Budget emissions limitation;
(2) Whether the monitoring plan that governs the unit has been
maintained to reflect the actual operation and monitoring of the unit,
and contains all information necessary to attribute NOX
emissions to the unit, in accordance with subpart H of this part;
(3) Whether all the NOX emissions from the unit, or a
group of units (including the unit) using a common stack, were
monitored or accounted for through the missing data procedures and
reported in the quarterly monitoring reports, including whether
conditional data were reported in the quarterly reports in accordance
with subpart H of this part. If conditional data were reported, the
owner or operator shall indicate whether the status of all conditional
data has been resolved and all necessary quarterly report resubmissions
has been made;
(4) Whether the facts that form the basis for certification under
subpart H of this part of each monitor at the unit or a group of units
(including the unit) using a common stack, or for using an excepted
monitoring method or alternative monitoring method approved under
subpart H of this part, if any, has changed; and
(5) If a change is required to be reported under paragraph (c)(4)
of this section, specify the nature of the change, the reason for the
change, when the change occurred, and how the unit's compliance status
was determined subsequent to the change, including what method was used
to determine emissions when a change mandated the need for monitor
recertification.
Sec. 97.31 Administrator's action on compliance certifications.
(a) The Administrator may review and conduct independent audits
concerning any compliance certification or any other submission under
the NOX Budget Trading Program and make appropriate
adjustments of the information in the compliance certifications or
other submissions.
(b) The Administrator may deduct NOX allowances from or
transfer NOX allowances to a unit's compliance account or a
source's overdraft account based on the information in the compliance
certifications or other submissions, as adjusted under paragraph (a) of
this section.
Subpart E--NOX Allowance Allocations
Sec. 97.40 Trading program budget.
The trading program budget allocated by the Administrator for a
State under Sec. 97.42 for a control period will equal the sum of the
aggregate emission levels for large electric generating units in the
State and large non-electric generating units in the State as defined
under Appendix C of this part.
Sec. 97.41 Timing requirements for NOX allowance
allocations.
(a) By the following dates, the Administrator will determine the
NOX allowance allocations in accordance with Sec. 97.42 for
the control period in the year that is three years after the year of
the applicable deadline under this paragraph (a):
(i) For the purposes of the NOX Budget Trading Program
under section 110(c) of the Act, by April 1, 2000 and April 1 of the
following two years
(ii) For the purposes of the NOX Budget Trading Program
under 126 of the Act, by April 1, 2000 and April 1 of the following two
years for those sources for which a finding, under Sec. 52.34(j) of
this chapter, of NOX emissions in violation of section
110(a)(2)(D)(I)(I) of the Act is made by April 1, 2000; or as soon as
practicable in the year 2000 and April 1 of the following two years for
those sources for which such a finding is not made by April 1, 2000,
but is made at a later date.
(b) By April 1, 2003 and April 1 of each year thereafter, the
Administrator
[[Page 56347]]
will determine the NOX allowance allocations, in accordance
with Sec. 97.42, for the control period in the year that is three years
after the year of the applicable deadline under this paragraph (b).
(c) By April 1, 2004 and April 1 of each year thereafter, the
Administrator will determine the NOX allowance allocations,
in accordance with Sec. 97.42, for any NOX allowances
remaining in the allocation set-aside for the prior control period.
Sec. 97.42 NOX allowance allocations.
(a)(1) The heat input (in mmBtu) used for calculating
NOX allowance allocations for each NOX Budget
unit under Sec. 97.4 will be:
(i) For a NOX allowance allocation under Sec. 97.41(a),
the average of the two highest amounts of the unit's heat input for the
control periods in 1995, 1996, and 1997 if the unit is under
Sec. 97.4(a)(1) or the control period in 1995 if the unit is under
Sec. 97.4(a)(2); and
(ii) For a NOX allowance allocation under Sec. 97.41(b),
the unit's heat input for the control period in the year that is four
years before the year for which the NOX allocation is being
calculated.
(2) The unit's total heat input for the control period in each year
specified under paragraph (a)(1) of this section will be determined in
accordance with part 75 of this chapter if the NOX Budget
unit was otherwise subject to the requirements of part 75 of this
chapter for the year, or will be based on the best available data
reported to the Administrator for the unit if the unit was not
otherwise subject to the requirements of part 75 of this chapter for
the year.
(b) For each control period under Sec. 97.41, the Administrator
will allocate to all NOX Budget units under Sec. 97.4(a)(1)
in the State that commenced operation before May 1 of the period used
to calculate heat input under paragraph (a)(1) of this section, a total
number of NOX allowances equal to 95 percent in 2003, 2004,
and 2005, or 98 percent thereafter, of the aggregate emission levels
for large electric generating units in the State as defined under
appendix C of this part in accordance with the following procedures:
(1) The Administrator will allocate NOX allowances to
each NOX Budget unit under Sec. 97.4(a)(1) in an amount
equaling 0.15 lb/mmBtu multiplied by the heat input determined under
paragraph (a) of this section, rounded to the nearest whole
NOX allowance as appropriate.
(2) If the initial total number of NOX allowances
allocated to all NOX Budget units under Sec. 97.4(a)(1) in
the State for a control period under paragraph (b)(1) of this section
does not equal 95 percent in 2003, 2004, and 2005, or 98 percent
thereafter, of the aggregate emission level for large electric
generating units in the State as defined under Appendix C of this part,
the Administrator will adjust the total number of NOX
allowances allocated to all such NOX Budget units for the
control period under paragraph (b)(1) of this section so that the total
number of NOX allowances allocated equals 95 percent in
2003, 2004, and 2005, or 98 percent thereafter, of such aggregate
emission level. This adjustment will be made by: multiplying each
unit's allocation by 95 percent in 2003, 2004, and 2005, or 98 percent
thereafter, of the aggregate emission level for large electric
generating units in the State as defined under Appendix C of this part
divided by the total number of NOX allowances allocated
under paragraph (b)(1) of this section, and rounding to the nearest
whole NOX allowance as appropriate.
(c) For each control period under Sec. 97.41, the Administrator
will allocate to all NOX Budget units under Sec. 97.4(a)(2)
in the State that commenced operation before May 1 of the period used
to calculate heat input under paragraph (a)(1) of this section, a total
number of NOX allowances equal to 95 percent in 2003, 2004,
and 2005, or 98 percent thereafter, of the aggregate emission level for
large non-electric generating units in the State as defined under
Appendix C of this part in accordance with the following procedures:
(1) The Administrator will allocate NOX allowances to
each NOX Budget unit under Sec. 97.4(a)(2) in an amount
equaling 0.17 lb/mmBtu multiplied by the heat input determined under
paragraph (a) of this section, rounded to the nearest whole
NOX allowance as appropriate.
(2) If the initial total number of NOX allowances
allocated to all NOX Budget units under Sec. 97.4(a)(2) in
the State for a control period under paragraph (c)(1) of this section
does not equal 95 percent in 2003, 2004, and 2005, or 98 percent
thereafter, of the aggregate emission levels for large non-electric
generating units in the State as defined under appendix C of this part,
the Administrator will adjust the total number of NOX
allowances allocated to all such NOX Budget units for the
control period under paragraph (a)(1) of this section so that the total
number of NOX allowances allocated equals 95 percent in
2003, 2004, and 2005, or 98 percent thereafter, of such aggregate
emission level for large non-electric generating units in the State.
This adjustment will be made by: multiplying each unit's allocation by
95 percent in 2003, 2004, and 2005, or 98 percent thereafter, of the
aggregate emission levels for large non-electric generating units in
the State as defined under Appendix C of this part divided by the total
number of NOX allowances allocated under paragraph (c)(1) of
this section, and rounding to the nearest whole NOX
allowance as appropriate.
(d) For each control period under Sec. 97.41, the Administrator
will allocate NOX allowances to NOX Budget units
under Sec. 97.4 in the State that commenced operation, or are projected
to commerce operation, on or after May 1 of the period used to
calculate heat input under paragraph (a)(1) of this section, in
accordance with the following procedures:
(1) The Administrator will establish one allocation set-aside for
each control period. Each allocation set-aside will be allocated
NOX allowances equal to 5 percent in 2003, 2004, and 2005,
or 2 percent thereafter, of the tons of NOX emissions in the
trading program budget in the State under Sec. 97.40, rounded to the
nearest whole NOX allowance as appropriate.
(2) The NOX authorized account representative of a
NOX Budget unit under paragraph (d) of this section may
submit to the Administrator a request, in writing or in a format
specified by the Administrator, to be allocated NOX
allowances for no more than five consecutive control periods under
Sec. 97.41, starting with the control period during which the
NOX Budget unit commenced, or is projected to commence,
operation and ending with the control season preceding the control
period for which it will receive an allocation under paragraph (b) or
(c) of this section. The NOX allowance allocation request
must be submitted prior to May 1 of the first control period for which
the NOX allowance allocation is requested and after the date
on which the State permitting authority issues a permit to construct
the NOX Budget unit.
(3) In a NOX allowance allocation request under
paragraph (d)(2) of this section, the NOX authorized account
representative for units under Sec. 97.4(a)(1) may request for a
control period NOX allowances in an amount that does not
exceed 0.15 lb/mmBtu multiplied by the NOX Budget unit's
maximum design heat input (in mmBtu/hr) multiplied by the number of
hours remaining in the control period starting with the first day in
the control period on which the unit operated or is projected to
operate.
[[Page 56348]]
(4) In a NOX allowance allocation request under
paragraph (d)(2) of this section, the NOX authorized account
representative for units under Sec. 97.4(a)(2) may request for a
control period NOX allowances in an amount that does not
exceed 0.17 lb/mmBtu multiplied by the NOX Budget unit's
maximum design heat input (in mmBtu/hr) multiplied by the number of
hours remaining in the control period starting with the first day in
the control period on which the unit operated or is projected to
operate.
(5) The Administrator will review, and allocate NOX
allowances pursuant to, each NOX allowance allocation
request under paragraph (d)(2) of this section in the order that the
request is received by the Administrator.
(i) Upon receipt of the NOX allowance allocation
request, the Administrator will determine whether, and will make any
necessary adjustments to the request to ensure that, for units under
Sec. 97.4(a)(1), the control period and the number of allowances
specified are consistent with the requirements of paragraphs (d)(2) and
(3) of this section and, for units under Sec. 97.4(a)(2), the control
period and the number of allowances specified are consistent with the
requirements of paragraphs(d)(2) and (4) of this section.
(ii) If the allocation set-aside for the control period for which
NOX allowances are requested has an amount of NOX
allowances not less than the number requested (as adjusted under
paragraph (d)(5)(i) of this section), the permitting authority or the
Administrator will allocate the amount of the NOX allowances
requested (as adjusted under paragraph (d)(5)(i) of this section) to
the NOX Budget unit.
(iii) If the allocation set-aside for the control period for which
NOX allowances are requested has a smaller amount of
NOX allowances than the number requested (as adjusted under
paragraph (d)(4)(i) of this section), the Administrator will deny in
part the request and allocate only the remaining number of
NOX allowances in the allocation set-aside to the
NOX Budget unit.
(iv) Once an allocation set-aside for a control period has been
depleted of all NOX allowances, the Administrator will deny,
and will not allocate any NOX allowances pursuant to, any
NOX allowance allocation request under which NOX
allowances have not already been allocated for the control period.
(6) Within 60 days of receipt of a NOX allowance
allocation request, the Administrator will take appropriate action
under paragraph (d)(5) of this section and notify the NOX
authorized account representative that submitted the request of the
number of NOX allowances (if any) allocated for the control
period to the NOX Budget unit.
(e) For a NOX Budget unit that is allocated
NOX allowances under paragraph (d) of this section for a
control period, the Administrator will deduct NOX allowances
under Sec. 97.54(b) or (e) to account for the actual utilization of the
unit during the control period. The Administrator will calculate the
number of NOX allowances to be deducted to account for the
unit's actual utilization using the following formulas and rounding to
the nearest whole NOX allowance as appropriate, provided
that the number of NOX allowances to be deducted shall be
zero if the number calculated is less than zero:
NOX allowances deducted for actual utilization for units
under Sec. 97.4(a)(1) = (Unit's NOX allowances allocated
for control period)-(Unit's actual control period utilization x
0.15 lb/mmBtu); and
NOX allowances deducted for actual utilization for units
under Sec. 97.4(a)(2)= (Unit's NOX allowances allocated
for control period)-(Unit's actual control period utilization x
0.17 lb/mmBtu),
Where:
``Unit's NOX allowances allocated for control period'' is
the number of NOX allowances allocated to the unit for
the control period under paragraph (d) of this section; and,
``Unit's actual control period utilization'' is the utilization (in
mmBtu), as defined in Sec. 97.2, of the unit during the control
period.
(f) After making the deductions for compliance under Sec. 97.54(b)
or (e) for a control period, the Administrator will determine whether
any NOX allowances remain in the allocation set-aside for
the control period. The Administrator will allocate any such
NOX allowances to the NOX Budget units in the
State using the following formula and rounding to the nearest whole
NOX allowance as appropriate:
Unit's share of NOX allowances remaining in allocation
set-aside = Total NOX allowances remaining in allocation
set-aside x (Unit's NOX allowance allocation (trading
program budget excluding allocation set-aside)
Where:
Total NOX allowances remaining in allocation set-aside''
is the total number of NOX allowances remaining in the
allocation set-aside for the control period to which the allocation
set-aside applies;
``Unit's NOX allowance allocation'' is the number of
NOX allowances allocated under paragraph (b) or (c) of
this section to the unit for the control period to which the
allocation set-aside applies; and
``Trading program budget excluding allocation set-aside'' is the
trading program budget under Sec. 97.40 for the control period to
which the allocation set-aside applies multiplied by 95 percent if
the control period is in 2003, 2004, or 2005 or 98 percent if the
control period is in any year thereafter, rounded to the nearest
whole allowance as appropriate.
Subpart F--NOX Allowance Tracking System
Sec. 97.50 NOX Allowance Tracking System accounts.
(a) Nature and function of compliance accounts and overdraft
accounts. Consistent with Sec. 97.51(a), the Administrator will
establish one compliance account for each NOX Budget unit
and one overdraft account for each source with one or more
NOX Budget units. Allocations of NOX allowances
pursuant to subpart E of this part or Sec. 97.88, and deductions or
transfers of NOX allowances pursuant to Sec. 97.31,
Sec. 96.54, Sec. 96.56, subpart G of this part, or subpart I of this
part will be recorded in the compliance accounts or overdraft accounts
in accordance with this subpart.
(b) Nature and function of general accounts. Consistent with
Sec. 97.51(b), the Administrator will establish, upon request, a
general account for any person. Transfers of allowances pursuant to
subpart G of this part will be recorded in the general account in
accordance with this subpart.
Sec. 97.51 Establishment of accounts.
(a) Compliance accounts and overdraft accounts. Upon receipt of a
complete account certificate of representation under Sec. 97.13, the
Administrator will establish:
(1) A compliance account for each NOX Budget unit for
which the account certificate of representation was submitted; and
(2) An overdraft account for each source for which the account
certificate of representation was submitted and that has two or more
NOX Budget units.
(b) General accounts.
(1) Any person may apply to open a general account for the purpose
of holding and transferring allowances. A complete application for a
general account shall be submitted to the Administrator and shall
include the following elements in a format prescribed by the
Administrator:
(i) Name, mailing address, e-mail address (if any), telephone
number, and facsimile transmission number (if any) of the
NOX authorized account representative and any alternate
NOX authorized account representative;
[[Page 56349]]
(ii) At the option of the NOX authorized account
representative, organization name and type of organization;
(iii) A list of all persons subject to a binding agreement for the
NOX authorized account representative and any alternate
NOX authorized account representative to represent their
ownership interest with respect to the allowances held in the general
account;
(iv) The following certification statement by the NOX
authorized account representative and any alternate NOX
authorized account representative: ``I certify that I was selected as
the NOX authorized account representative or the
NOX alternate authorized account representative, as
applicable, by an agreement that is binding on all persons who have an
ownership interest with respect to allowances held in the general
account. I certify that I have all the necessary authority to carry out
my duties and responsibilities under the NOX Budget Trading
Program on behalf of such persons and that each such person shall be
fully bound by my representations, actions, inactions, or submissions
and by any order or decision issued to me by the Administrator or a
court regarding the general account.''
(v) The signature of the NOX authorized account
representative and any alternate NOX authorized account
representative and the dates signed.
(vi) Unless otherwise required by the permitting authority or the
Administrator, documents of agreement referred to in the account
certificate of representation shall not be submitted to the permitting
authority or the Administrator. Neither the permitting authority nor
the Administrator shall be under any obligation to review or evaluate
the sufficiency of such documents, if submitted.
(2) Upon receipt by the Administrator of a complete application for
a general account under paragraph (b)(1) of this section:
(i) The Administrator will establish a general account for the
person or persons for whom the application is submitted.
(ii) The NOX authorized account representative and any
alternate NOX authorized account representative for the
general account shall represent and, by his or her representations,
actions, inactions, or submissions, legally bind each person who has an
ownership interest with respect to NOX allowances held in
the general account in all matters pertaining to the NOX
Budget Trading Program, not withstanding any agreement between the
NOX authorized account representative or any alternate
NOX authorized account representative and such person. Any
such person shall be bound by any order or decision issued to the
NOX authorized account representative or any alternate
NOX authorized account representative by the Administrator
or a court regarding the general account.
(iii) Each submission concerning the general account shall be
submitted, signed, and certified by the NOX authorized
account representative or any alternate NOX authorized
account representative for the persons having an ownership interest
with respect to NOX allowances held in the general account.
Each such submission shall include the following certification
statement by the NOX authorized account representative or
any alternate NOX authorizing account representative: ``I am
authorized to make this submission on behalf of the persons having an
ownership interest with respect to the NOX allowances held
in the general account. I certify under penalty of law that I have
personally examined, and am familiar with, the statements and
information submitted in this document and all its attachments. Based
on my inquiry of those individuals with primary responsibility for
obtaining the information, I certify that the statements and
information are to the best of my knowledge and belief true, accurate,
and complete. I am aware that there are significant penalties for
submitting false statements and information or omitting required
statements and information, including the possibility of fine or
imprisonment.''
(iv) The Administrator will accept or act on a submission
concerning the general account only if the submission has been made,
signed, and certified in accordance with paragraph (b)(2)(iii) of this
section.
(3)(i) An application for a general account may designate one and
only one NOX authorized account representative and one and
only one alternate NOX authorized account representative who
may act on behalf of the NOX authorized account
representative. The agreement by which the alternate NOX
authorized account representative is selected shall include a procedure
for authorizing the alternate NOX authorized account
representative to act in lieu of the NOX authorized account
representative.
(ii) Upon receipt by the Administrator of a complete application
for a general account under paragraph (b)(1) of this section, any
representation, action, inaction, or submission by any alternate
NOX authorized account representative shall be deemed to be
a representation, action, inaction, or submission by the NOX
authorized account representative.
(4)(i) The NOX authorized account representative for a
general account may be changed at any time upon receipt by the
Administrator of a superseding complete application for a general
account under paragraph (b)(1) of this section. Notwithstanding any
such change, all representations, actions, inactions, and submissions
by the previous NOX authorized account representative prior
to the time and date when the Administrator receives the superseding
application for a general account shall be binding on the new
NOX authorized account representative and the persons with
an ownership interest with respect to the allowances in the general
account.
(ii) The alternate NOX authorized account representative
for a general account may be changed at any time upon receipt by the
Administrator of a superseding complete application for a general
account under paragraph (b)(1) of this section. Notwithstanding any
such change, all representations, actions, inactions, and submissions
by the previous alternate NOX authorized account
representative prior to the time and date when the Administrator
receives the superseding application for a general account shall be
binding on the new alternate NOX authorized account
representative and the persons with an ownership interest with respect
to the allowances in the general account.
(iii)(A) In the event a new person having an ownership interest
with respect to NOX allowances in the general account is not
included in the list of such persons in the account certificate of
representation, such new person shall be deemed to be subject to and
bound by the account certificate of representation, the representation,
actions, inactions, and submissions of the NOX authorized
account representative and any alternate NOX authorized
account representative of the source or unit, and the decisions,
orders, actions, and inactions of the Administrator, as if the new
person were included in such list.
(B) Within 30 days following any change in the persons having an
ownership interest with respect to NOX allowances in the
general account, including the addition of persons, the NOX
authorized account representative or any alternate NOX
authorized account representative shall submit a revision to the
application for a general account amending the list of persons having
an ownership interest with respect to the NOX allowances in
the general account to include the change.
(5)(i) Once a complete application for a general account under
paragraph (b)(1)
[[Page 56350]]
of this section has been submitted and received, the Administrator will
rely on the application unless and until a superseding complete
application for a general account under paragraph (b)(1) of this
section is received by the Administrator.
(ii) Except as provided in paragraph (b)(4) of this section, no
objection or other communication submitted to the Administrator
concerning the authorization, or any representation, action, inaction,
or submission of the NOX authorized account representative
or any alternative NOX authorized account representative for
a general account shall affect any representation, action, inaction, or
submission of the NOX authorized account representative or
any alternative NOX authorized account representative or the
finality of any decision or order by the Administrator under the
NOX Budget Trading Program.
(iii) The Administrator will not adjudicate any private legal
dispute concerning the authorization or any representation, action,
inaction, or submission of the NOX authorized account
representative or any alternative NOX authorized account
representative for a general account, including private legal disputes
concerning the proceeds of NOX allowance transfers.
(c) Account identification. The Administrator will assign a unique
identifying number to each account established under paragraph (a) or
(b) of this section.
Sec. 97.52 NOX Allowance Tracking System responsibilities
of NOX authorized account representative.
(a) Following the establishment of a NOX Allowance
Tracking System account, all submissions to the Administrator
pertaining to the account, including, but not limited to, submissions
concerning the deduction or transfer of NOX allowances in
the account, shall be made only by the NOX authorized
account representative for the account.
(b) Authorized account representative identification. The
Administrator will assign a unique identifying number to each
NOX authorized account representative.
Sec. 97.53 Recordation of NOX allowance allocations.
(a) The Administrator will record the NOX allowances for
2003 in the NOX Budget units' compliance accounts and the
allocation set-asides, as allocated under subpart E of this part. The
Administrator will also record the NOX allowances allocated
under Sec. 97.88(a)(1) for each NOX Budget opt-in source in
its compliance account.
(b) Each year, after the Administrator has made all deductions from
a NOX Budget unit's compliance account and the overdraft
account pursuant to Sec. 97.54, the Administrator will record
NOX allowances, as allocated to the unit under subpart E of
this part or under Sec. 97.88(a)(2), in the compliance account for the
year after the last year for which allowances were previously allocated
to the compliance account. Each year, the Administrator will also
record NOX allowances, as allocated under subpart E of this
part, in the allocation set-aside for the year after the last year for
which allowances were previously allocated to an allocation set-aside.
(c) Serial numbers for allocated NOX allowances. When
allocating NOX allowances to and recording them in an
account, the Administrator will assign each NOX allowance a
unique identification number that will include digits identifying the
year for which the NOX allowance is allocated.
Sec. 97.54 Compliance.
(a) NOX allowance transfer deadline. The NOX
allowances are available to be deducted for compliance with a unit's
NOX Budget emissions limitation for a control period in a
given year only if the NOX allowances:
(1) Were allocated for a control period in a prior year or the same
year; and
(2) Are held in the unit's compliance account, or the overdraft
account of the source where the unit is located, as of the
NOX allowance transfer deadline for that control period or
are transferred into the compliance account or overdraft account by a
NOX allowance transfer correctly submitted for recordation
under Sec. 97.60 by the NOX allowance transfer deadline for
that control period.
(b) Deductions for compliance.
(1) Following the recordation, in accordance with Sec. 97.61, of
NOX allowance transfers submitted for recordation in the
unit's compliance account or the overdraft account of the source where
the unit is located by the NOX allowance transfer deadline
for a control period, the Administrator will deduct NOX
allowances available under paragraph (a) of this section to cover the
unit's NOX emissions (as determined in accordance with
subpart H of this part), or to account for actual utilization under
Sec. 97.42 (e), for the control period:
(i) From the compliance account; and
(ii) Only if no more NOX allowances available under
paragraph (a) of this section remain in the compliance account, from
the overdraft account. In deducting allowances for units at the source
from the overdraft account, the Administrator will begin with the unit
having the compliance account with the lowest NOX Allowance
Tracking System account number and end with the unit having the
compliance account with the highest NOX Allowance Tracking
System account number (with account numbers sorted beginning with the
left-most character and ending with the right-most character and the
letter characters assigned values in alphabetical order and less than
all numeric characters).
(2) The Administrator will deduct NOX allowances first
under paragraph (b)(1)(i) of this section and then under paragraph
(b)(1)(ii) of this section:
(i) Until the number of NOX allowances deducted for the
control period equals the number of tons of NOX emissions,
determined in accordance with subpart H of this part, from the unit for
the control period for which compliance is being determined, plus the
number of NOX allowances required for deduction to account
for actual utilization under Sec. 97.42(e) for the control period; or
(ii) Until no more NOX allowances available under
paragraph (a) of this section remain in the respective account.
(c)(1) Identification of NOX allowances by serial
number. The NOX authorized account representative for each
compliance account may identify by serial number the NOX
allowances to be deducted from the unit's compliance account under
paragraph (b), (d), or (e) of this section. Such identification shall
be made in the compliance certification report submitted in accordance
with Sec. 97.30.
(2) First-in, first-out. The Administrator will deduct
NOX allowances for a control period from the compliance
account, in the absence of an identification or in the case of a
partial identification of NOX allowances by serial number
under paragraph (c)(1) of this section, or the overdraft account on a
first-in, first-out (FIFO) accounting basis in the following order:
(i) Those NOX allowances that were allocated for the
control period to the unit under subpart E or I of this part;
(ii) Those NOX allowances that were allocated for the
control period to any unit and transferred and recorded in the account
pursuant to subpart G of this part, in order of their date of
recordation;
(iii) Those NOX allowances that were allocated for a
prior control period to the unit under subpart E or I of this part; and
(iv) Those NOX allowances that were allocated for a
prior control period to
[[Page 56351]]
any unit and transferred and recorded in the account pursuant to
subpart G of this part, in order of their date of recordation.
(d) Deductions for excess emissions. (1) After making the
deductions for compliance under paragraph (b) of this section, the
Administrator will deduct from the unit's compliance account or the
overdraft account of the source where the unit is located a number of
NOX allowances, allocated for a control period after the
control period in which the unit has excess emissions, equal to three
times the number of the unit's excess emissions.
(2) If the compliance account or overdraft account does not contain
sufficient NOX allowances, the Administrator will deduct the
required number of NOX allowances, regardless of the control
period for which they were allocated, whenever NOX
allowances are recorded in either account.
(3) Any allowance deduction required under paragraph (d) of this
section shall not affect the liability of the owners and operators of
the NOX Budget unit for any fine, penalty, or assessment, or
their obligation to comply with any other remedy, for the same
violation, as ordered under the Clean Air Act or applicable State law.
The following guidelines will be followed in assessing fines, penalties
or other obligations:
(i) For purposes of determining the number of days of violation, if
a NOX Budget unit has excess emissions for a control period,
each day in the control period (153 days) constitutes a day in
violation unless the owners and operators of the unit demonstrate that
a lesser number of days should be considered.
(ii) Each ton of excess emissions is a separate violation.
(e) Deductions for units sharing a common stack. In the case of
units sharing a common stack and having emissions that are not
separately monitored or apportioned in accordance with subpart H of
this part:
(1) The NOX authorized account representative of the
units may identify the percentage of NOX allowances to be
deducted from each such unit's compliance account to cover the unit's
share of NOX emissions from the common stack for a control
period. Such identification shall be made in the compliance
certification report submitted in accordance with Sec. 97.30.
(2) Notwithstanding paragraph (b)(2)(i) of this section, the
Administrator will deduct NOX allowances for each such unit
until the number of NOX allowances deducted equals the units
identified percentage (under paragraph (e)(1) of this section) of the
number of tons of NOX emissions, as determined in accordance
with subpart H of this part, from the common stack for the control
period for which compliance is being determined, use the number of
allowances required to account for actual utilization under
Sec. 97.42(e) for the control period or, if no percentage is
identified, an equal percentage for each such unit.
(f) The Administrator will record in the appropriate compliance
account or overdraft account all deductions from such an account
pursuant to paragraphs (b), (d), or (e) of this section.
Sec. 97.55 Banking.
(a) NOX allowances may be banked for future use or
transfer in a compliance account, an overdraft account, or a general
account, as follows:
(1) Any NOX allowance that is held in a compliance
account, an overdraft account, or a general account will remain in such
account unless and until the NOX allowance is deducted or
transferred under Sec. 97.31, Sec. 97.54, or Sec. 97.56, subpart G of
this part, or subpart I of this part.
(2) The Administrator will designate, as a ``banked''
NOX allowance, any NOX allowance that remains in
a compliance account, an overdraft account, or a general account after
the Administrator has made all deductions for a given control period
from the compliance account or overdraft account pursuant to
Sec. 97.54.
(b) Each year starting in 2004, after the Administrator has
completed the designation of banked NOX allowances under
paragraph (a)(2) of this section and before May 1 of the year, the
Administrator will determine the extent to which banked NOX
allowances may be used for compliance in the control period for the
current year, as follows:
(1) The Administrator will determine the total number of banked
NOX allowances held in compliance accounts, overdraft
accounts, or general accounts.
(2) If the total number of banked NOX allowances
determined, under paragraph (b)(1) of this section, to be held in
compliance accounts, overdraft accounts, or general accounts is less
than or equal to 10% of the sum of the State trading program budgets
for the control period for the States in which NOX Budget
units are located, any banked NOX allowance may be deducted
for compliance in accordance with Sec. 97.54.
(3) If the total number of banked NOX allowances
determined, under paragraph (b)(1) of this section, to be held in
compliance accounts, overdraft accounts, or general accounts exceeds
10% of the sum of the State trading program budgets for the control
period for the States in which NOX Budget units are located,
any banked allowance may be deducted for compliance in accordance with
Sec. 97.54, except as follows:
(i) The Administrator will determine the following ratio: 0.10
multiplied by the sum of the State trading program budgets for the
control period for the States in which NOX Budget units are
located and divided by the total number of banked NOX
allowances determined, under paragraph (b)(1) of this section, to be
held in compliance accounts, overdraft accounts, or general accounts.
(ii) The Administrator will multiply the number of banked
NOX allowances in each compliance account or overdraft
account. The resulting product is the number of banked NOX
allowances in the account that may be deducted for compliance in
accordance with Sec. 97.54. Any banked NOX allowances in
excess of the resulting product may be deducted for compliance in
accordance with Sec. 97.54, except that, if such NOX
allowances are used to make a deduction, two such NOX
allowances must be deducted for each deduction of one NOX
allowance required under Sec. 97.54.
(c) Any NOX Budget unit may reduce its NOX
emission rate in the 2001 or 2002 control period, the owner or operator
of the unit may request early reduction credits, and the permitting
authority may allocate NOX allowances in 2003 to the unit in
accordance with the following requirements.
(1) Each NOX Budget unit for which the owner or operator
requests any early reduction credits under paragraph (c)(4) of this
section shall monitor NOX emissions in accordance with
subpart H of this part starting in the 2000 control period and for each
control period for which such early reduction credits are requested.
The unit's monitoring system availability shall be not less than 90
percent during the 2000 control period, and the unit must be in full
compliance with any applicable State or Federal emissions or emissions
related requirements.
(2) NOX emission rate and heat input under paragraphs
(c)(3) through (5) of this section shall be determined in accordance
with subpart H of this part.
(3) Each NOX Budget unit for which the owner or operator
requests any early reduction credits under paragraph (c)(4) of this
section shall reduce its NOX emission rate, for each control
period for which early reduction credits are requested, to less than
both 0.25 lb/
[[Page 56352]]
mmBtu and 80 percent of the unit's NOX emission rate in the
2000 control period.
(4) The NOX authorized account representative of a
NOX Budget unit that meets the requirements of paragraphs
(c)(1)and (3) of this section may submit to the permitting authority a
request for early reduction credits for the unit based on
NOX emission rate reductions made by the unit in the control
period for 2001 or 2002 in accordance with paragraph (3) of this
section.
(i) In the early reduction credit request, the NOX
authorized account may request early reduction credits for such control
period in an amount equal to the unit's heat input for such control
period multiplied by the difference between 0.25 lb/mmBtu and the
unit's NOX emission rate for such control period, divided by
2000 lb/ton, and rounded to the nearest ton.
(ii) The early reduction credit request must be submitted, in a
format specified by the permitting authority, by October 31 of the year
in which the NOX emission rate reductions on which the
request is based are made or such later date approved by the permitting
authority.
(5) The permitting authority will allocate NOX
allowances, to NOX Budget units meeting the requirements of
paragraphs (c)(1) and (3) of this section and covered by early
reduction requests meeting the requirements of paragraph (c)(4)(ii) of
this section, in accordance with the following procedures:
(i) Upon receipt of each early reduction credit request, the
permitting authority will accept the request only if the requirements
of paragraphs (c)(1), (3), and (4)(ii) of this section are met and, if
the request is accepted, will make any necessary adjustments to the
request to ensure that the amount of the early reduction credits
requested meets the requirement of paragraphs (c)(2) and (4) of this
section.
(ii) If the State's compliance supplement pool has an amount of
NOX allowances not less than the number of early reduction
credits in all accepted early reduction credit requests for 2001 and
2002 (as adjusted under paragraph (c)(5)(i) of this section), the
permitting authority will allocate to each NOX Budget unit
covered by such accepted requests one allowance for each early
reduction credit requested (as adjusted under paragraph (c)(5)(i) of
this section).
(iii) If the State's compliance supplement pool has a smaller
amount of NOX allowances than the number of early reduction
credits in all accepted early reduction credit requests for 2001 and
2002 (as adjusted under paragraph (c)(5)(i) of this section), the
permitting authority will allocate NOX allowances to each
NOX Budget unit covered by such accepted requests according
to the following formula:
Unit's allocated early reduction credits = [(Unit's adjusted early
reduction credits)/(Total adjusted early reduction credits requested
by all units)] x (Available NOX allowances from the
State's compliance supplement pool)
Where:
``Unit's adjusted early reduction credits'' is the number of early
reduction credits for the unit for 2001 and 2002 in accepted early
reduction credit requests, as adjusted under paragraph (c)(5)(i) of
this section.
``Total adjusted early reduction credits requested by all units'' is
the number of early reduction credits for all units for 2001 and
2002 in accepted early reduction credit requests, as adjusted under
paragraph (c)(5)(i) of this section.
``Available NOX allowances from the State's compliance
supplement pool'' is the number of NOX allowances in the
State's compliance supplement pool and available for early reduction
credits for 2001 and 2002.
(6) By May 1, 2003, the permitting authority will submit to the
Administrator the allocations of NOX allowances determined
under paragraph (c)(5) of this section. The Administrator will record
such allocations to the extent that they are consistent with the
requirements of paragraphs (c)(1) through (5) of this section.
(7) NOX allowances recorded under paragraph (c)(6) of
this section may be deducted for compliance under Sec. 97.54 for the
control periods in 2003 or 2004. Notwithstanding paragraph (a) of this
section, the Administrator will deduct as retired any NOX
allowance that is recorded under paragraph (c)(6) of this section and
is not deducted for compliance in accordance with Sec. 97.54 for the
control period in 2003 or 2004.
(8) NOX allowances recorded under paragraph (c)(6) of
this section are treated as banked allowances in 2004 for the purposes
of paragraphs (a) and (b) of this section.
Sec. 97.56 Account error.
The Administrator may, at his or her sole discretion and on his or
her own motion, correct any error in any NOX Allowance
Tracking System account. Within 10 business days of making such
correction, the Administrator will notify the NOX authorized
account representative for the account.
Sec. 97.57 Closing of general accounts.
(a) The NOX authorized account representative of a
general account may instruct the Administrator to close the account by
submitting a statement requesting deletion of the account from the
NOX Allowance Tracking System and by correctly submitting
for recordation under Sec. 97.60 an allowance transfer of all
NOX allowances in the account to one or more other
NOX Allowance Tracking System accounts.
(b) If a general account shows no activity for a period of a year
or more and does not contain any NOX allowances, the
Administrator may notify the NOX authorized account
representative for the account that the account will be closed and
deleted from the NOX Allowance Tracking System following 20
business days after the notice is sent. The account will be closed
after the 20-day period unless before the end of the 20-day period the
Administrator receives a correctly submitted transfer of NOX
allowances into the account under Sec. 97.60 or a statement submitted
by the NOX authorized account representative demonstrating
to the satisfaction of the Administrator good cause as to why the
account should not be closed.
Subpart G--NOX Allowance Transfers
Sec. 97.60 Submission of NOX allowance transfers.
The NOX authorized account representatives seeking
recordation of a NOX allowance transfer shall submit the
transfer to the Administrator. To be considered correctly submitted,
the NOX allowance transfer shall include the following
elements in a format specified by the Administrator:
(a) The numbers identifying both the transferror and transferee
accounts;
(b) A specification by serial number of each NOX
allowance to be transferred; and
(c) The printed name and signature of the NOX authorized
account representative of the transferror account and the date signed.
Sec. 97.61 EPA recordation.
(a) Within 5 business days of receiving a NOX allowance
transfer, except as provided in paragraph (b) of this section, the
Administrator will record a NOX allowance transfer by moving
each NOX allowance from the transferror account to the
transferee account as specified by the request, provided that:
(1) The transfer is correctly submitted under Sec. 97.60;
(2) The transferror account includes each NOX allowance
identified by serial number in the transfer; and
(3) The transfer meets all other requirements of this part.
(b) A NOX allowance transfer that is submitted for
recordation following the NOX allowance transfer deadline
and
[[Page 56353]]
that includes any NOX allowances allocated for a control
period prior to or the same as the control period to which the
NOX allowance transfer deadline applies will not be recorded
until after completion of the process of recordation of NOX
allowance allocations in Sec. 97.53(b).
(c) Where a NOX allowance transfer submitted for
recordation fails to meet the requirements of paragraph (a) of this
section, the Administrator will not record such transfer.
Sec. 97.62 Notification.
(a) Notification of recordation. Within 5 business days of
recordation of a NOX allowance transfer under Sec. 97.61,
the Administrator will notify each party to the transfer. Notice will
be given to the NOX authorized account representatives of
both the transferror and transferee accounts.
(b) Notification of non-recordation. Within 10 business days of
receipt of a NOX allowance transfer that fails to meet the
requirements of Sec. 97.61(a) the NOX authorized account
representatives of both accounts subject to the transfer of:
(1) A decision not to record the transfer, and
(2) The reasons for such non-recordation.
(c) Nothing in this section shall preclude the submission of a
NOX allowance transfer for recordation following
notification of non-recordation.
Subpart H--Monitoring and Reporting
Sec. 97.70 General Requirements.
The owners and operators, and to the extent applicable, the
NOX authorized account representative of a NOX
Budget unit, shall comply with the monitoring and reporting
requirements as provided in this subpart and in subpart H of part 75 of
this chapter. For purposes of complying with such requirements, the
definitions in Sec. 97.2 and in Sec. 72.2 of this chapter shall apply,
and the terms ``affected unit,'' ``designated representative,'' and
``continuous emission monitoring system'' (or ``CEMS'') in part 75 of
this chapter shall be replaced by the terms ``NOX Budget
unit,'' ``NOX authorized account representative,'' and
``continuous emission monitoring system'' (or ``CEMS''), respectively,
as defined in Sec. 97.2.
(a) Requirements for installation, certification, and data
accounting. The owner or operator of each NOX Budget unit
must meet the following requirements. These provisions also apply to a
unit for which an application for a NOX Budget opt-in permit
is submitted and not denied or withdrawn, as provided in subpart I of
this part:
(1) Install all monitoring systems required under this subpart for
monitoring NOX mass. This includes all systems required to
monitor NOX emission rate, NOX concentration,
heat input, and flow, in accordance with Secs. 75.72 and 75.76.
(2) Install all monitoring systems for monitoring heat input, if
required under Sec. 97.76 for developing NOX allowance
allocations.
(3) Successfully complete all certification tests required under
Sec. 97.71 and meet all other provisions of this subpart and part 75 of
this chapter applicable to the monitoring systems under paragraphs (a)
(1) and (2) of this section.
(4) Record, and report data from the monitoring systems under
paragraphs (a) (1) and (2) of this section.
(b) Compliance dates. The owner or operator must meet the
requirements of paragraphs (a)(1) through (a)(3) of this section on or
before the following dates and must record and report data on and after
the following dates:
(1) NOX Budget units for which the owner or operator
intends to apply for early reduction credits under Sec. 97.55(d) must
comply with the requirements of this subpart by May 1, 2000.
(2) Except for NOX Budget units under paragraph (b)(1)
of this section, NOX Budget units under Sec. 97.4 that
commence operation before January 1, 2002, must comply with the
requirements of this subpart by May 1, 2002.
(3) NOX Budget units under Sec. 97.4 that commence
operation on or after January 1, 2002 and that report on an annual
basis under Sec. 97.74(d) must comply with the requirements of this
subpart by the later of the following dates:
(i) May 1, 2002; or
(ii) the earlier of:
(A) 180 days after the date on which the unit commences operation
or,
(B) For units under Sec. 97.4(a)(1), 90 days after the date on
which the unit commences commercial operation.
(4) NOX Budget units under Sec. 97.4 that commence
operation on or after January 1, 2002 and that report on a control
season basis under Sec. 97.74(d) must comply with the requirements of
this subpart by the later of the following dates:
(i) the earlier of:
(A) 180 days after the date on which the unit commences operation
or,
(B) for units under Sec. 97.4(a)(1), 90 days after the date on
which the unit commences commercial operation.
(ii) However, if the applicable deadline under paragraph (b)(4)(i)
of this section does not occur during a control period, May 1;
immediately following the date determined in accordance with paragraph
(b)(4)(i) of this section.
(5) For a NOX Budget unit with a new stack or flue for
which construction is completed after the applicable deadline under
paragraph (b)(1), (b)(2) or (b)(3) of this section or subpart I of this
part:
(i) 90 days after the date on which emissions first exit to the
atmosphere through the new stack or flue
(ii) However, if the unit reports on a control season basis under
Sec. 97.74(d) and the applicable deadline under paragraph (b)(5)(i) of
this section does not occur during the control period, May 1
immediately following the applicable deadline in paragraph (b)(5)(i) of
this section.
(6) For a unit for which an application for a NOX Budget
opt-in permit is submitted and not denied or withdrawn, the compliance
dates specified under subpart I of this part.
(c) Reporting data prior to initial certification. (1) The owner or
operator of a NOX Budget unit that misses the certification
deadline under paragraph (b)(1) of this section is not eligible to
apply for early reduction credits. The owner or operator of the unit
becomes subject to the certification deadline under paragraph (b)(2) of
this section.
(2) The owner or operator of a NOX Budget under
paragraphs (b)(3) or (b)(4) of this section must determine, record and
report NOX mass, heat input (if required for purposes of
allocations) and any other values required to determine NOX
Mass (e.g. NOX emission rate and heat input or
NOX concentration and stack flow) using the provisions of
Sec. 75.70(g) of this chapter, from the date and hour that the unit
starts operating until all required certification tests are
successfully completed.
(d) Prohibitions. (1) No owner or operator of a NOX
Budget unit or a non-NOX Budget unit monitored under
Sec. 75.72(b)(2)(ii) shall use any alternative monitoring system,
alternative reference method, or any other alternative for the required
continuous emission monitoring system without having obtained prior
written approval in accordance with Sec. 97.75.
(2) No owner or operator of a NOX Budget unit or a non-
NOX Budget unit monitored under Sec. 75.72(b)(2)(ii) shall
operate the unit so as to discharge, or allow to be discharged,
NOX emissions to the atmosphere without accounting for all
such emissions in accordance with the applicable provisions of this
subpart and part 75 of this chapter
[[Page 56354]]
except as provided for in Sec. 75.74 of this chapter.
(3) No owner or operator of a NOX Budget unit or a non-
NOX Budget unit monitored under Sec. 75.72(b)(2)(ii) shall
disrupt the continuous emission monitoring system, any portion thereof,
or any other approved emission monitoring method, and thereby avoid
monitoring and recording NOX mass emissions discharged into
the atmosphere, except for periods of recertification or periods when
calibration, quality assurance testing, or maintenance is performed in
accordance with the applicable provisions of this subpart and part 75
of this chapter except as provided for in Sec. 75.74 of this chapter.
(4) No owner or operator of a NOX Budget unit or a non-
NOX Budget unit monitored under Sec. 75.72(b)(2)(ii) shall
retire or permanently discontinue use of the continuous emission
monitoring system, any component thereof, or any other approved
emission monitoring system under this subpart, except under any one of
the following circumstances:
(i) During the period that the unit is covered by a retired unit
exemption under Sec. 97.5 that is in effect;
(ii) The owner or operator is monitoring emissions from the unit
with another certified monitoring system approved, in accordance with
the applicable provisions of this subpart and part 75 of this chapter,
by the permitting authority for use at that unit that provides emission
data for the same pollutant or parameter as the retired or discontinued
monitoring system; or
(iii) The NOX authorized account representative submits
notification of the date of certification testing of a replacement
monitoring system in accordance with Sec. 97.71(b)(2).
Sec. 97.71 Initial certification and recertification procedures.
(a) The owner or operator of a NOX Budget unit that is
subject to an Acid Rain emissions limitation shall comply with the
initial certification and recertification procedures of part 75 of this
chapter, except that:
(1) If, prior to January 1, 1998, the Administrator approved a
petition under Sec. 75.17 (a) or (b) of this chapter for apportioning
the NOX emission rate measured in a common stack or a
petition under Sec. 75.66 of this chapter for an alternative to a
requirement in Sec. 75.17 of this chapter, the NOX
authorized account representative shall resubmit the petition to the
Administrator under Sec. 97.75(a) to determine if the approval applies
under the NOX Budget Trading Program.
(2) For any additional CEMS required under the common stack
provisions in Sec. 75.72 of this chapter, or for any NOX
concentration CEMS used under the provisions of Sec. 75.71(a)(2) of
this chapter, the owner or operator shall meet the requirements of
paragraph (b) of this section.
(b) The owner or operator of a NOX Budget unit that is
not subject to an Acid Rain emissions limitation shall comply with the
following initial certification and recertification procedures, except
that the owner or operator of a unit that qualifies to use the low mass
emissions excepted monitoring methodology under Sec. 75.19 shall also
meet the requirements of paragraph (c) of this section and the owner or
operator of a unit that qualifies to use an alternative monitoring
system under subpart E of part 75 of this chapter shall also meet the
requirements of paragraph (d) of this section. The owner or operator of
a NOX Budget unit that is subject to an Acid Rain emissions
limitation, but requires additional CEMS under the common stack
provisions in Sec. 75.72 of this chapter, or that uses a NOX
concentration CEMS under Sec. 75.71(a)(2) of this chapter also shall
comply with the following initial certification and recertification
procedures.
(1) Requirements for initial certification. The owner or operator
shall ensure that each monitoring system required by subpart H of part
75 of this chapter (which includes the automated data acquisition and
handling system) successfully completes all of the initial
certification testing required under Sec. 75.20 of this chapter. The
owner or operator shall ensure that all applicable certification tests
are successfully completed by the deadlines specified in Sec. 97.70(b).
In addition, whenever the owner or operator installs a monitoring
system in order to meet the requirements of this part in a location
where no such monitoring system was previously installed, initial
certification according to Sec. 75.20 is required.
(2) Requirements for recertification. Whenever the owner or
operator makes a replacement, modification, or change in a certified
monitoring system that the Administrator determines significantly
affects the ability of the system to accurately measure or record
NOX mass emissions or heat input or to meet the requirements
of Sec. 75.21 of this chapter or appendix B to part 75 of this chapter,
the owner or operator shall recertify the monitoring system according
to Sec. 75.20(b) of this chapter. Furthermore, whenever the owner or
operator makes a replacement, modification, or change to the flue gas
handling system or the unit's operation that the Administrator
determines to significantly change the flow or concentration profile,
the owner or operator shall recertify the continuous emissions
monitoring system according to Sec. 75.20(b) of this chapter. Examples
of changes which require recertification include: Replacement of the
analyzer, change in location or orientation of the sampling probe or
site, or changing of flow rate monitor polynomial coefficients.
(3) Certification approval process for initial certifications and
recertification.
(i) Notification of certification. The NOX authorized
account representative shall submit to the Administrator, the
appropriate EPA Regional Office and the permitting authority a written
notice of the dates of certification in accordance with Sec. 97.73.
(ii) Certification application. The NOX authorized
account representative shall submit to the Administrator, the
appropriate EPA Regional Office and the permitting authority a
certification application for each monitoring system required under
subpart H of part 75 of this chapter. A complete certification
application shall include the information specified in subpart H of
part 75 of this chapter.
(iii) Except for units using the low mass emission excepted
methodology under Sec. 75.19 of this chapter, the provisional
certification date for a monitor shall be determined using the
procedures set forth in Sec. 75.20(a)(3) of this chapter. A
provisionally certified monitor may be used under the NOX
Budget Trading Program for a period not to exceed 120 days after
receipt by the Administrator of the complete certification application
for the monitoring system or component thereof under paragraph
(b)(3)(ii) of this section. Data measured and recorded by the
provisionally certified monitoring system or component thereof, in
accordance with the requirements of part 75 of this chapter, will be
considered valid quality-assured data (retroactive to the date and time
of provisional certification), provided that the Administrator does not
invalidate the provisional certification by issuing a notice of
disapproval within 120 days of receipt of the complete certification
application by the Administrator.
(iv) Certification application formal approval process. The
Administrator will issue a written notice of approval or disapproval of
the certification application to the owner or operator within 120 days
of receipt of the complete certification application under paragraph
(b)(3)(ii) of this section. In the event the Administrator does not
issue
[[Page 56355]]
such a notice within such 120-day period, each monitoring system which
meets the applicable performance requirements of part 75 of this
chapter and is included in the certification application will be deemed
certified for use under the NOX Budget Trading Program.
(A) Approval notice. If the certification application is complete
and shows that each monitoring system meets the applicable performance
requirements of part 75 of this chapter, then the Administrator will
issue a written notice of approval of the certification application
within 120 days of receipt.
(B) Incomplete application notice. A certification application will
be considered complete when all of the applicable information required
to be submitted under paragraph (b)(3)(ii) of this section has been
received by the Administrator. If the certification application is not
complete, then the Administrator will issue a written notice of
incompleteness that sets a reasonable date by which the NOX
authorized account representative must submit the additional
information required to complete the certification application. If the
NOX authorized account representative does not comply with
the notice of incompleteness by the specified date, then the
Administrator may issue a notice of disapproval under paragraph
(b)(3)(iv)(C) of this section.
(C) Disapproval notice. If the certification application shows that
any monitoring system or component thereof does not meet the
performance requirements of this part, or if the certification
application is incomplete and the requirement for disapproval under
paragraph (b)(3)(iv)(B) of this section has been met, the Administrator
will issue a written notice of disapproval of the certification
application. Upon issuance of such notice of disapproval, the
provisional certification is invalidated by the Administrator and the
data measured and recorded by each uncertified monitoring system or
component thereof shall not be considered valid quality-assured data
beginning with the date and hour of provisional certification. The
owner or operator shall follow the procedures for loss of certification
in paragraph (b)(3)(v) of this section for each monitoring system or
component thereof which is disapproved for initial certification.
(D) Audit decertification. The Administrator may issue a notice of
disapproval of the certification status of a monitor in accordance with
Sec. 97.72(b).
(v) Procedures for loss of certification. If the Administrator
issues a notice of disapproval of a certification application under
paragraph (b)(3)(iv)(C) of this section or a notice of disapproval of
certification status under paragraph (b)(3)(iv)(D) of this section,
then:
(A) The owner or operator shall substitute the following values,
for each hour of unit operation during the period of invalid data
beginning with the date and hour of provisional certification and
continuing until the time, date, and hour specified under
Sec. 75.20(a)(5)(i) of this chapter:
(1) For units using or intending to monitor for NOX
emission rate and heat input or for units using the low mass emission
excepted methodology under Sec. 75.19 of this chapter, the maximum
potential NOX emission rate and the maximum potential hourly
heat input of the unit.
(2) For units intending to monitor for NOX mass
emissions using a NOX pollutant concentration monitor and a
flow monitor, the maximum potential concentration of NOX and
the maximum potential flow rate of the unit under section 2.1 of
appendix A of part 75 of this chapter;
(B) The NOX authorized account representative shall
submit a notification of certification retest dates and a new
certification application in accordance with paragraphs (b)(3)(i) and
(ii) of this section; and (C) The owner or operator shall repeat all
certification tests or other requirements that were failed by the
monitoring system, as indicated in the Administrator's notice of
disapproval, no later than 30 unit operating days after the date of
issuance of the notice of disapproval.
(c) Initial certification and recertification procedures for low
mass emission units using the excepted methodologies under Sec. 75.19
of this chapter. The owner or operator of a gas-fired or oil-fired unit
using the low mass emissions excepted methodology under Sec. 75.19 of
this chapter shall meet the applicable general operating requirements
of Sec. 75.10 of this chapter, the applicable requirements of
Sec. 75.19 of this chapter, and the applicable certification
requirements of Sec. 97.71 of this chapter, except that the excepted
methodology shall be deemed provisionally certified for use under the
NOX Budget Trading Program, as of the following dates:
(i) For units that are reporting on an annual basis under
Sec. 97.74(d)
(A) For a unit that has commences operation before its compliance
deadline under Sec. 97.71(b), from January 1 of the year following
submission of the certification application for approval to use the low
mass emissions excepted methodology under Sec. 75.19 of this chapter
until the completion of the period for the Administrator's review; or
(B) For a unit that commences operation after its compliance
deadline under Sec. 97.71(b), the date of submission of the
certificaation application for approval to use the low mass emissions
excepted methodology under Sec. 75.19 of this chapter until the
completion of the period for the Administrator's review, or
(ii) For units that are reporting on a control period basis under
Sec. 97.74(b)(3)(ii) of this part:
(A) For a unit that commenced operation before its compliance
deadline under Sec. 97.71(b), where the certification application is
submitted before May 1, from May 1 of the year of the submission of the
certification application for approval to use the low mass emissions
excepted methodology under Sec. 75.19 of this chapter until the
completion of the period for the Administrator's review; or
(B) For a unit that commenced operation before its compliance
deadline under Sec. 97.71(b), where the certification application is
submitted after May 1, from May 1 of the year following submission of
the certification application for approval to use the low mass
emissions excepted methodology under Sec. 75.19 of this chapter until
the completion of the period for the Administrator's review; or
(C) For a unit that commences operation after its compliance
deadline under Sec. 97.71(b), where the unit commences operation before
May 1, from May 1 of the year that the unit commenced operation, until
the completion of the period for the Administrator's review.
(D) For a unit that has not operated after its compliance deadline
under Sec. 97.71(b), where the certification application is submitted
after May 1, but before October 1st, from the date of submission of a
certification application for approval to use the low mass emissions
excepted methodology under Sec. 75.19 of this chapter until the
completion of the period for the Administrator's review.
(d) Certification/recertification procedures for alternative
monitoring systems. The NOX authorized account
representative representing the owner or operator of each unit applying
to monitor using an alternative monitoring system approved by the
Administrator under subpart E of part 75 of this chapter shall apply
for certification to the administrator prior to use of the system under
the NOX Trading Program. The NOX authorized
account representative shall apply for recertification following a
replacement, modification or change according to the procedures in
paragraph (b) of this
[[Page 56356]]
section. The owner or operator of an alternative monitoring system
shall comply with the notification and application requirements for
certification according to the procedures specified in paragraph (b)(3)
of this section and Sec. 75.20(f) of this chapter.
Sec. 97.72 Out of control periods.
(a) Whenever any monitoring system fails to meet the quality
assurance requirements of appendix B of part 75 of this chapter, data
shall be substituted using the applicable procedures in subpart D,
appendix D, or appendix E of part 75 of this chapter.
(b) Audit decertification. Whenever both an audit of a monitoring
system and a review of the initial certification or recertification
application reveal that any system or component should not have been
certified or recertified because it did not meet a particular
performance specification or other requirement under Sec. 97.71 or the
applicable provisions of part 75 of this chapter, both at the time of
the initial certification or recertification application submission and
at the time of the audit, the Administrator will issue a notice of
disapproval of the certification status of such system or component.
For the purposes of this paragraph, an audit shall be either a field
audit or an audit of any information submitted to the permitting
authority or the Administrator. By issuing the notice of disapproval,
the Administrator revokes prospectively the certification status of the
system or component. The data measured and recorded by the system or
component shall not be considered valid quality-assured data from the
date of issuance of the notification of the revoked certification
status until the date and time that the owner or operator completes
subsequently approved initial certification or recertification tests.
The owner or operator shall follow the initial certification or
recertification procedures in Sec. 97.71 for each disapproved system.
Sec. 97.73 Notifications.
(a) The NOX authorized account representative for a
NOX Budget unit shall submit written notice to the
permitting authority, the appropriate EPA Regional Office and the
Administrator in accordance with Sec. 75.61 of this chapter.
(b) For any unit that does not have an acid rain emissions
limitation, the permitting authority may waive the requirements to
notify the permitting authority in paragraph (a) of this section and
the notification requirements in Sec. 97.71(b)(2)(i).
Sec. 97.74 Recordkeeping and reporting.
(a) General provisions. (1) The NOX authorized account
representative shall comply with all recordkeeping and reporting
requirements in this section and with the requirements of
Sec. 97.10(e).
(2) If the NOX authorized account representative for a
NOX Budget unit subject to an Acid Rain Emission limitation
who signed and certified any submission that is made under subpart F or
G of part 75 of this chapter and which includes data and information
required under this subpart or subpart H of part 75 of this chapter is
not the same person as the designated representative or the alternative
designated representative for the unit under part 72 of this chapter,
the submission must also be signed by the designated representative or
the alternative designated representative.
(b) Monitoring plans. (1) The owner or operator of a unit subject
to an Acid Rain emissions limitation shall comply with requirements of
Sec. 75.62 of this chapter, except that the monitoring plan shall also
include all of the information required by subpart H of part 75 of this
chapter.
(2) The owner or operator of a unit that is not subject to an Acid
Rain emissions limitation shall comply with requirements of Sec. 75.62
of this chapter, except that the monitoring plan is only required to
include the information required by subpart H of part 75 of this
chapter.
(c) Certification applications. The NOX authorized
account representative shall submit an application to the permitting
authority, the appropriate EPA Regional Office and the Administrator
within 45 days after completing all initial certification or
recertification tests required under Sec. 97.71 including the
information required under subpart H of part 75 of this chapter.
(d) Quarterly reports. The NOX authorized account
representative shall submit quarterly reports, as follows:
(1) If a unit is subject to an Acid Rain emission limitation or if
the owner or operator of the NOX budget unit chooses to meet
the annual reporting requirements of this subpart H, the NOX
authorized account representative shall submit a quarterly report for
each calendar quarter beginning with:
(i) For units that elect to comply with the early reduction credit
provisions under Sec. 97.55, the calender quarter that includes the
date of initial provisional certification under Sec. 97.71(b)(3)(iii).
Data shall be reported from the date and hour corresponding to the date
and hour of provisional certification ; or
(ii) For units commencing operation prior to May 1, 2002 that are
not required to certify monitors by May 1, 2000 under Sec. 97.70(b)(1),
the earlier of the calender quarter that includes the date of initial
provisional certification under Sec. 97.71(b)(3)(iii) or, if the
certification tests are not completed by May 1, 2002, the partial
calender quarter from May 1, 2002 through June 30, 2002. Data shall be
recorded and reported from the earlier of the date and hour
corresponding to the date and hour of provisional certification or the
first hour on May 1, 2002; or
(iii) For a unit that commences operation after May 1, 2002, the
calendar quarter in which the unit commences operation, Data shall be
reported from the date and hour corresponding to when the unit
commenced operation.
(2) If a NOX budget unit is not subject to an Acid Rain
emission limitation, then the NOX authorized account
representative shall either:
(i) Meet all of the requirements of part 75 of this chapter related
to monitoring and reporting NOX mass emissions during the
entire year and meet the reporting deadlines specified in paragraph
(d)(1) of this section; or
(ii) submit quarterly reports only for the periods from the earlier
of May 1 or the date and hour that the owner or operator successfully
completes all of the recertification tests required under
Sec. 75.74(d)(3) through September 30 of each year in accordance with
the provisions of Sec. 75.74(b) of this chapter. The NOX
authorized account representative shall submit a quarterly report for
each calendar quarter, beginning with:
(A) For units that elect to comply with the early reduction credit
provisions under Sec. 97.55, the calender quarter that includes the
date of initial provisional certification under Sec. 97.71(b)(3)(iii).
Data shall be reported from the date and hour corresponding to the date
and hour of provisional certification; or
(B) For units commencing operation prior to May 1, 2002 that are
not required to certify monitors by May 1, 2000 under Sec. 97.70(b)(1),
the earlier of the calender quarter that includes the date of initial
provisional certification under Sec. 97.71(b)(3)(iii), or if the
certification tests are not completed by May 1, 2002, the partial
calender quarter from May 1, 2002 through June 30, 2002. Data shall be
reported from the earlier of the date and hour corresponding to the
date and hour of provisional certification or the first hour of May 1,
2002; or
(C) For units that commence operation after May 1, 2002 during the
[[Page 56357]]
control period, the calender quarter in which the unit commences
operation. Data shall be reported from the date and hour corresponding
to when the unit commenced operation; or
(D) For units that commence operation after May 1, 2002 and before
May 1 of the year in which the unit commences operation, the earlier of
the calender quarter that includes the date of initial provisional
certification under Sec. 97.71(b)(3)(iii) or, if the certification
tests are not completed by May 1 of the year in which the unit
commences operation, May 1 of the year in which the unit commences
operation. Data shall be reported from the earlier of the date and hour
corresponding to the date and hour of provisional certification or the
first hour of May 1 of the year after the unit commences operation.
(E) For units that commence operation after May 1, 2002 and after
September 30 of the year in which the unit commences operation, the
earlier of the calender quarter that includes the date of initial
provisional certification under Sec. 97.71(b)(3)(iii) or, if the
certification tests are not completed by May 1 of the year after the
unit commences operation, May 1 of the year after the unit commences
operation. Data shall be reported from the earlier of the date and hour
corresponding to the date and hour of provisional certification or the
first hour of May 1 of the year after the unit commences operation.
(3) The NOX authorized account representative shall
submit each quarterly report to the Administrator within 30 days
following the end of the calendar quarter covered by the report.
Quarterly reports shall be submitted in the manner specified in subpart
H of part 75 of this chapter and Sec. 75.64 of this chapter.
(i) For units subject to an Acid Rain Emissions limitation,
quarterly reports shall include all of the data and information
required in subpart H of part 75 of this chapter for each
NOX Budget unit (or group of units using a common stack) as
well as information required in subpart G of part 75 of this chapter.
(ii) For units not subject to an Acid Rain Emissions limitation,
quarterly reports are only required to include all of the data and
information required in subpart H of part 75 of this chapter for each
NOX Budget unit (or group of units using a common stack).
(4) Compliance certification. The NOX authorized account
representative shall submit to the Administrator a compliance
certification in support of each quarterly report based on reasonable
inquiry of those persons with primary responsibility for ensuring that
all of the unit's emissions are correctly and fully monitored. The
certification shall state that:
(i) The monitoring data submitted were recorded in accordance with
the applicable requirements of this subpart and part 75 of this
chapter, including the quality assurance procedures and specifications;
and
(ii) For a unit with add-on NOX emission controls and
for all hours where data are substituted in accordance with
Sec. 75.34(a)(1) of this chapter, the add-on emission controls were
operating within the range of parameters listed in the monitoring plan
and the substitute values do not systematically underestimate
NOX emissions; and
(iii) For a unit that is reporting on a control period basis under
Sec. 97.74(d) the NOX emission rate and NOX
concentration values substituted for missing data under subpart D of
part 75 of this chapter are calculated using only values from a control
period and do not systematically underestimate NOX
emissions.
Sec. 97.75 Petitions
(a) The NOX authorized account representative of a
NOX Budget unit may submit a petition under Sec. 75.66 of
this chapter to the Administrator requesting approval to apply an
alternative to any requirement of this subpart.
(b) Application of an alternative to any requirement of this
subpart is in accordance with this subpart only to the extent that the
petition is approved by the Administrator.
Sec. 97.76 Additional requirements to provide heat input data.
(a) The owner or operator of a unit that elects to monitor and
report NOX Mass emissions using a NOX
concentration system and a flow system shall also monitor and report
heat input at the unit level using the procedures set forth in part 75
of this chapter.
(b) The owner or operator of a unit that monitor and report
NOX Mass emissions using a NOX concentration
system and a flow system shall also monitor and report heat input at
the unit level using the procedures set forth in part 75 of this
chapter for any source that is applying for early reduction credits
under Sec. 97.55.
Subpart I--Individual Opt-Ins
Sec. 97.80 Applicability.
A unit that is in the State, is not a NOX Budget unit
under Sec. 97.4, vents all of its emissions to a stack, and is
operating, may qualify, under this subpart, to become a NOX
Budget opt-in source. A unit that is a NOX Budget unit, is
covered by a retired unit exemption under Sec. 97.5 that is in effect,
or is not operating is not eligible to become a NOX Budget
opt-in source.
Sec. 97.81 General.
Except otherwise as provided in this part, a NOX Budget
opt-in source shall be treated as a NOX Budget unit for
purposes of applying subparts A through H of this part.
Sec. 97.82 NOX authorized account representative.
A unit for which an application for a NOX Budget opt-in
permit is submitted, or a NOX Budget opt-in source, located
at the same source as one or more NOX Budget units, shall
have the same NOX authorized account representative as such
NOX Budget units.
Sec. 97.83 Applying for NOX Budget opt-in permit.
(a) Applying for initial NOX Budget opt-in permit. In
order to apply for an initial NOX Budget opt-in permit, the
NOX authorized account representative of a unit qualified
under Sec. 97.80 may submit to the Administrator and the permitting
authority at any time, except as provided under Sec. 97.86(g):
(1) A complete NOX Budget permit application under
Sec. 97.22;
(2) A monitoring plan submitted in accordance with subpart H of
this part; and
(3) A complete account certificate of representation under
Sec. 97.13, if no NOX authorized account representative has
been previously designated for the unit.
(b) Duty to reapply. The NOX authorized account
representative of a NOX Budget opt-in source shall submit to
the Administrator and permitting authority a complete NOX
Budget permit application under Sec. 97.22 to renew the NOX
Budget opt-in permit in accordance with Sec. 97.21(c) and, if
applicable, an updated monitoring plan in accordance with subpart H of
this part.
Sec. 97.84 Opt-in process.
The permitting authority will issue or deny a NOX Budget
opt-in permit for a unit for which an initial application for a
NOX Budget opt-in permit under Sec. 97.83 is submitted, in
accordance with Sec. 97.20 and the following:
(a) Interim review of monitoring plan. The Administrator will
determine, on an interim basis, the sufficiency of the monitoring plan
accompanying the initial application for a NOX Budget opt-in
permit under Sec. 97.83. A monitoring plan is sufficient, for purposes
of interim review, if the plan appears to contain information
demonstrating that
[[Page 56358]]
the NOX emissions rate and heat input of the unit are
monitored and reported in accordance with subpart H of this part. A
determination of sufficiency shall not be construed as acceptance or
approval of the unit's monitoring plan.
(b) If the Administrator determines that the unit's monitoring plan
is sufficient under paragraph (a) of this section and after completion
of monitoring system certification under subpart H of this part, the
NOX emissions rate and the heat input of the unit shall be
monitored and reported in accordance with subpart H of this part for
one full control period during which monitoring system availability is
not less than 90 percent and during which the unit is in full
compliance with any applicable State or Federal emissions or emissions-
related requirements. Solely for purposes of applying the requirements
in the prior sentence, the unit shall be treated as a ``NOX
Budget unit'' prior to issuance of a NOX Budget opt-in
permit covering the unit.
(c) Based on the information monitored and reported under paragraph
(b) of this section, the unit's baseline heat rate shall be calculated
as the unit's total heat input (in mmBtu) for the control period and
the unit's baseline NOX emissions rate shall be calculated
as the unit's total NOX mass emissions (in lb) for the
control period divided by the unit's baseline heat rate.
(d) After calculating the baseline heat input and the baseline
NOX emissions rate for the unit under paragraph (c) of this
section, the Administrator will provide this information to the
permitting authority so the permitting authority can serve a draft
NOX Budget opt-in permit on the NOX authorized
account representative of the unit.
(e) Confirmation of intention to opt-in. Within 20 days after the
issuance of the draft NOX Budget opt-in permit, the
NOX authorized account representative of the unit must
submit to the Administrator and the permitting authority a confirmation
of the intention to opt in the unit or a withdrawal of the application
for a NOX Budget opt-in permit under Sec. 97.83. The
permitting authority will treat the failure to make a timely submission
as a withdrawal of the NOX Budget opt-in permit application.
(f) Issuance of draft NOX Budget opt-in permit. If the
NOX authorized account representative confirms the intention
to opt in the unit under paragraph (e) of this section, the permitting
authority will issue the draft NOX Budget opt-in permit in
accordance with Sec. 97.20.
(g) Not withstanding paragraphs (a) through (f) of this section, if
at any time before issuance of a draft NOX Budget opt-in
permit for the unit, the Administrator or the permitting authority
determines that the unit does not qualify as a NOX Budget
opt-in source under Sec. 97.80, the permitting authority will issue a
draft denial of a NOX Budget opt-in permit for the unit in
accordance with Sec. 97.20.
(h) Withdrawal of application for NOX Budget opt-in
permit. A NOX authorized account representative of a unit
may withdraw its application for a NOX Budget opt-in permit
under Sec. 97.83 at any time prior to the issuance of the final
NOX Budget opt-in permit. Once the application for a
NOX Budget opt-in permit is withdrawn, a NOX
authorized account representative wanting to reapply must submit a new
application for a NOX Budget permit under Sec. 97.83.
(i) Effective date. The effective date of the initial
NOX Budget opt-in permit shall be May 1 of the first control
period starting after the issuance of the initial NOX Budget
opt-in permit by the permitting authority. The unit shall be a
NOX Budget opt-in source and a NOX Budget unit as
of the effective date of the initial NOX Budget opt-in
permit.
Sec. 97.85 NOX Budget opt-in permit contents.
(a) Each NOX Budget opt-in permit (including any draft
or proposed NOX Budget opt-in permit, if applicable) will
contain all elements required for a complete NOX Budget opt-
in permit application under Sec. 97.22 as approved or adjusted by the
Administrator or the permitting authority.
(b) Each NOX Budget opt-in permit is deemed to
incorporate automatically the definitions of terms under Sec. 97.2 and,
upon recordation by the Administrator under subpart F, G, or I of this
part, every allocation, transfer, or deduction of NOX
allowances to or from the compliance accounts of each NOX
Budget opt-in source covered by the NOX Budget opt-in permit
or the overdraft account of the NOX Budget source where the
NOX Budget opt-in source is located.
Sec. 97.86 Withdrawal from NOX Budget Trading Program.
(a) Requesting withdrawal. To withdraw from the NOX
Budget Trading Program, the NOX authorized account
representative of a NOX Budget opt-in source shall submit to
the Administrator and the permitting authority a request to withdraw
effective as of a specified date prior to May 1 or after September 30.
The submission shall be made no later than 90 days prior to the
requested effective date of withdrawal.
(b) Conditions for withdrawal. Before a NOX Budget opt-
in source covered by a request under paragraph (a) of this section may
withdraw from the NOX Budget Trading Program and the
NOX Budget opt-in permit may be terminated under paragraph
(e) of this section, the following conditions must be met:
(1) For the control period immediately before the withdrawal is to
be effective, the NOX authorized account representative must
submit or must have submitted to the Administrator and the permitting
authority an annual compliance certification report in accordance with
Sec. 97.30.
(2) If the NOX Budget opt-in source has excess emissions
for the control period immediately before the withdrawal is to be
effective, the Administrator will deduct or has deducted from the
NOX Budget opt-in source's compliance account, or the
overdraft account of the NOX Budget source where the
NOX Budget opt-in source is located, the full amount
required under Sec. 97.54(d) for the control period.
(3) After the requirements for withdrawal under paragraphs (b)(1)
and (2) of this section are met, the Administrator will deduct from the
NOX Budget opt-in source's compliance account, or the
overdraft account of the NOX Budget source where the
NOX Budget opt-in source is located, NOX
allowances equal in number to and allocated for the same or a prior
control period as any NOX allowances allocated to that
source under Sec. 97.88 for any control period for which the withdrawal
is to be effective. The Administrator will close the NOX
Budget opt-in source's compliance account and will establish, and
transfer any remaining allowances to, a new general account for the
owners and operators of the NOX Budget opt-in source. The
NOX authorized account representative for the NOX
Budget opt-in source shall become the NOX authorized account
representative for the general account.
(c) A NOX Budget opt-in source that withdraws from the
NOX Budget Trading Program shall comply with all
requirements under the NOX Budget Trading Program concerning
all years for which such NOX Budget opt-in source was a
NOX Budget opt-in source, even if such requirements arise or
must be complied with after the withdrawal takes effect.
(d) Notification.
(1) After the requirements for withdrawal under paragraphs (a) and
(b) of this section are met (including deduction of the full amount of
NOX allowances required), the Administrator will issue a
notification to the
[[Page 56359]]
permitting authority and the NOX authorized account
representative of the NOX Budget opt-in source of the
acceptance of the withdrawal of the NOX Budget opt-in source
as of a specified effective date that is after such requirements have
been met and that is prior to May 1 or after September 30.
(2) If the requirements for withdrawal under paragraphs (a) and (b)
of this section are not met, the Administrator will issue a
notification to the permitting authority and the NOX
authorized account representative of the NOX Budget opt-in
source that the NOX Budget opt-in source's request to
withdraw is denied. If the NOX Budget opt-in source's
request to withdraw is denied, the NOX Budget opt-in source
shall remain subject to the requirements for a NOX Budget
opt-in source.
(e) Permit amendment. After the Administrator issues a notification
under paragraph (d)(1) of this section that the requirements for
withdrawal have been met, the permitting authority will revise the
NOX Budget permit covering the NOX Budget opt-in
source to terminate the NOX Budget opt-in permit as of the
effective date specified under paragraph (d)(1) of this section. A
NOX Budget opt-in source shall continue to be a
NOX Budget opt-in source until the effective date of the
termination.
(f) Reapplication upon failure to meet conditions of withdrawal. If
the Administrator denies the NOX Budget opt-in source's
request to withdraw, the NOX authorized account
representative may submit another request to withdraw in accordance
with paragraphs (a) and (b) of this section.
(g) Ability to return to the NOX Budget Trading Program.
Once a NOX Budget opt-in source withdraws from the
NOX Budget Trading Program and its NOX Budget
opt-in permit is terminated under this section, the NOX
authority account representative may not submit another application for
a NOX Budget opt-in permit under Sec. 97.83 for the unit
prior to the date that is 4 years after the date on which the
terminated NOX Budget opt-in permit became effective.
Sec. 97.87 Change in regulatory status.
(a) Notification. When a NOX Budget opt-in source
becomes a NOX Budget unit under Sec. 97.4, the
NOX authorized account representative shall notify in
writing the permitting authority and the Administrator of such change
in the NOX Budget opt-in source's regulatory status, within
30 days of such change.
(b) Permitting authority's and Administrator's action.
(1)(i) When the NOX Budget opt-in source becomes a
NOX Budget unit under Sec. 97.4, the permitting authority
will revise the NOX Budget opt-in source's NOX
Budget opt-in permit to meet the requirements of a NOX
Budget permit under Sec. 97.23 as of an effective date that is the date
on which such NOX Budget opt-in source becomes a
NOX Budget unit under Sec. 97.4.
(ii)(A) The Administrator will deduct from the compliance account
for the NOX Budget unit under paragraph (b)(1)(i) of this
section, or the overdraft account of the NOX Budget source
where the unit is located, NOX allowances equal in number to
and allocated for the same or a prior control period as:
(1) Any NOX allowances allocated to the NOX
Budget unit (as a NOX Budget opt-in source) under Sec. 97.88
for any control period after the last control period during which the
unit's NOX Budget opt-in permit was effective; and
(2) If the effective date of the NOX Budget permit
revision under paragraph (b)(1)(i) of this section is during a control
period, the NOX allowances allocated to the NOX
Budget unit (as a NOX Budget opt-in source) under Sec. 97.88
for the control period multiplied by the ratio of the number of days,
in the control period, starting with the effective date of the permit
revision under paragraph (b)(1)(i) of this section, divided by the
total number of days in the control period.
(B) The NOX authorized account representative shall
ensure that the compliance account of the NOX Budget unit
under paragraph (b)(1)(i) of this section, or the overdraft account of
the NOX Budget source where the unit is located, includes
the NOX allowances necessary for completion of the deduction
under paragraph (b)(1)(ii)(A) of this section. If the compliance
account or overdraft account does not contain sufficient NOX
allowances, the Administrator will deduct the required number of
NOX allowances, regardless of the control period for which
they were allocated, whenever NOX allowances are recorded in
either account.
(iii) (A) For every control period during which the NOX
Budget permit revised under paragraph (b)(1)(i) of this section is
effective, the NOX Budget unit under paragraph (b)(1)(i) of
this section will be treated, solely for purposes of NOX
allowance allocations under Sec. 97.42, as a unit that commenced
operation on the effective date of the NOX Budget permit
revision under paragraph (b)(1)(i) of this section and will be
allocated NOX allowances under Sec. 97.42.
(B) Notwithstanding paragraph (b)(1)(iii)(A) of this section, if
the effective date of the NOX Budget permit revision under
paragraph (b)(1)(i) of this section is during a control period, the
following number of NOX allowances will be allocated to the
NOX Budget unit under paragraph (b)(1)(i) of this section
under Sec. 97.42 for the control period: the number of NOX
allowances otherwise allocated to the NOX Budget unit under
Sec. 97.42 for the control period multiplied by the ratio of the number
of days, in the control period, starting with the effective date of the
permit revision under paragraph (b)(1)(i) of this section, divided by
the total number of days in the control period.
(2)(i) When the NOX authorized account representative of
a NOX Budget opt-in source does not renew its NOX
Budget opt-in permit under Sec. 97.83(b), the Administrator will deduct
from the NOX Budget opt-in unit's compliance account, or the
overdraft account of the NOX Budget source where the
NOX Budget opt-in source is located, NOX
allowances equal in number to and allocated for the same or a prior
control period as any NOX allowances allocated to the
NOX Budget opt-in source under Sec. 97.88 for any control
period after the last control period for which the NOX
Budget opt-in permit is effective. The NOX authorized
account representative shall ensure that the NOX Budget opt-
in source's compliance account or the overdraft account of the
NOX Budget source where the NOX Budget opt-in
source is located includes the NOX allowances necessary for
completion of such deduction. If the compliance account or overdraft
account does not contain sufficient NOX allowances, the
Administrator will deduct the required number of NOX
allowances, regardless of the control period for which they were
allocated, whenever NOX allowances are recorded in either
account.
(ii) After the deduction under paragraph (b)(2)(i) of this section
is completed, the Administrator will close the NOX Budget
opt-in source's compliance account. If any NOX allowances
remain in the compliance account after completion of such deduction and
any deduction under Sec. 97.54, the Administrator will close the
NOX Budget opt-in source's compliance account and will
establish, and transfer any remaining allowances to, a new general
account for the owners and operators of the NOX Budget opt-
in source. The NOX authorized account representative for the
NOX Budget opt-in source shall become the NOX
authorized account representative for the general account.
[[Page 56360]]
Sec. 97.88 NOX allowance allocations to opt-in units.
(a) NOX allowance allocation. (1) By December 31
immediately before the first control period for which the
NOX Budget opt-in permit is effective, the Administrator
will allocate NOX allowances to the NOX Budget
opt-in source for the control period in accordance with paragraph (b)
of this section.
(2) By no later than December 31, after the first control period
for which the NOX Budget opt-in permit is in effect, and
December 31 of each year thereafter, the Administrator will allocate
NOX allowances to the NOX Budget opt-in source
for the next control period, in accordance with paragraph (b) of this
section.
(b) For each control period for which the NOX Budget
opt-in source has an approved NOX Budget opt-in permit, the
NOX Budget opt-in source will be allocated NOX
allowances in accordance with the following procedures:
(1) The heat input (in mmBtu) used for calculating NOX
allowance allocations will be the lesser of:
(i) The NOX Budget opt-in source's baseline heat input
determined pursuant to Sec. 97.84(c); or
(ii) The NOX Budget opt-in source's heat input, as
determined in accordance with subpart H of this part, for the control
period in the year prior to the year of the control period for which
the NOX allocations are being calculated.
(2) The Administrator will allocate NOX allowances to
the NOX Budget opt-in source in an amount equaling the heat
input (in mmBtu) determined under paragraph (b)(1) of this section
multiplied by the lesser of:
(i) The NOX Budget opt-in source's baseline
NOX emissions rate (in lb/mmBtu) determined pursuant to
Sec. 97.84(c); or
(ii) The most stringent State or Federal NOX emissions
limitation applicable to the NOX Budget opt-in source during
the control period.
Appendix A to Part 97--NOX Allowance Allocation Tables
for Affected Sources Under Section 126 of the Act
Table A.1--Allocations to Fossil Fuel-Fired EGUs by mmBtu and MWh
--------------------------------------------------------------------------------------------------------------------------------------------------------
Unit Unit
average of average of
two highest two highest Unit Unit
State Plant ID Point ID Plant of 1995, of 1995, allocations allocations
1996, or 1996, or by HI by MWh
1997, 1997,
summer HI summer MWh
--------------------------------------------------------------------------------------------------------------------------------------------------------
AL........................ 3 1 BARRY....................... 4,444,705 452,203 336 333
AL........................ 3 2 BARRY....................... 4,457,926 453,456 337 334
AL........................ 3 3 BARRY....................... 7,758,632 798,049 587 587
AL........................ 3 4 BARRY....................... 12,886,737 1,375,025 975 1,012
AL........................ 3 5 BARRY....................... 25,069,820 2,649,527 1,897 1,950
AL........................ 56 **4 CHARLES R LOWMAN............ 903,512 68,448 68 50
AL........................ 56 1 CHARLES R LOWMAN............ 2,337,265 205,745 177 151
AL........................ 56 2 CHARLES R LOWMAN............ 8,251,949 786,199 625 578
AL........................ 56 3 CHARLES R LOWMAN............ 7,476,176 712,220 566 524
AL........................ 5 110 CHICKASAW................... 293,278 27,668 22 20
AL........................ 47 1 COLBERT..................... 5,401,036 528,115 409 389
AL........................ 47 2 COLBERT..................... 5,586,222 546,223 423 402
AL........................ 47 3 COLBERT..................... 5,294,661 517,714 401 381
AL........................ 47 4 COLBERT..................... 5,512,314 538,996 417 397
AL........................ 47 5 COLBERT..................... 13,750,384 1,387,106 1,041 1,021
AL........................ 26 1 E C GASTON.................. 7,187,848 760,699 544 560
AL........................ 26 2 E C GASTON.................. 7,037,596 752,765 533 554
AL........................ 26 3 E C GASTON.................. 7,568,867 809,591 573 596
AL........................ 26 4 E C GASTON.................. 7,279,128 767,031 551 564
AL........................ 26 5 E C GASTON.................. 24,100,992 2,589,277 1,824 1,905
AL........................ 7 1 GADSDEN..................... 1,915,860 162,803 145 120
AL........................ 7 2 GADSDEN..................... 1,777,783 151,069 135 111
AL........................ 8 10 GORGAS...................... 24,048,187 2,517,344 1,820 1,852
AL........................ 8 6 GORGAS...................... 3,271,407 292,953 248 216
AL........................ 8 7 GORGAS...................... 3,320,557 302,034 251 222
AL........................ 8 8 GORGAS...................... 6,100,623 624,488 462 460
AL........................ 8 9 GORGAS...................... 6,382,810 673,576 483 496
AL........................ 10 1 GREENE COUNTY............... 8,730,961 907,867 661 668
AL........................ 10 2 GREENE COUNTY............... 7,752,706 806,146 587 593
AL........................ 6002 1 JAMES H MILLER JR........... 20,389,071 2,160,317 1,543 1,590
AL........................ 6002 2 JAMES H MILLER JR........... 20,467,280 2,168,604 1,549 1,596
AL........................ 6002 3 JAMES H MILLER JR........... 22,363,879 2,369,557 1,693 1,744
AL........................ 6002 4 JAMES H MILLER JR........... 24,810,536 2,628,792 1,878 1,934
AL........................ 7063 **1 MCINTOSH-CAES............... 113,793 24,911 9 18
AL........................ 533 **4 MCWILLIAMS.................. 1,130,929 133,050 86 98
AL........................ 52140 1 UNION CAMP CORPORATION--.... 43,647 3,307 3 2
AL........................ 50 1 WIDOWS CREEK................ 3,220,389 295,992 244 218
AL........................ 50 2 WIDOWS CREEK................ 3,004,746 276,171 227 203
AL........................ 50 3 WIDOWS CREEK................ 2,954,318 271,537 224 200
AL........................ 50 4 WIDOWS CREEK................ 3,135,926 288,228 237 212
AL........................ 50 5 WIDOWS CREEK................ 2,946,352 278,352 223 205
AL........................ 50 6 WIDOWS CREEK................ 3,048,563 288,008 231 212
AL........................ 50 7 WIDOWS CREEK................ 14,708,106 1,494,422 1,113 1,100
AL........................ 50 8 WIDOWS CREEK................ 14,313,089 1,445,913 1,083 1,064
CT........................ 10675 AB__mes AES THAMES.................. 4,630,651 436,854 172 160
CT........................ 568 BHB1 BRIDGEPORT HARBOR........... 614,787 60,445 23 22
CT........................ 568 BHB2 BRIDGEPORT HARBOR........... 1,964,426 198,187 73 73
CT........................ 568 BHB3 BRIDGEPORT HARBOR........... 11,910,460 1,235,525 442 454
CT........................ 50498 CW__na) CAPITOL DISTRICT (AETNA).... 626,274 56,421 23 21
CT........................ 544 7 DEVON....................... 3,341,227 340,420 124 125
[[Page 56361]]
CT........................ 544 8 DEVON....................... 3,257,953 331,059 121 122
CT........................ 10567 CW__CH DEXTER CORP. CH............. 474,019 42,704 18 16
CT........................ 569 EB 13 ENGLISH..................... 56,957 3,997 2 1
CT........................ 569 EB 14 ENGLISH..................... 86,982 6,104 3 2
CT........................ 50736 ST__rd) EXETER ENERGY (OXFORD)...... 412,978 38,960 15 14
CT........................ 562 1 MIDDLETOWN.................. 452,331 43,059 17 16
CT........................ 562 2 MIDDLETOWN.................. 2,247,666 231,766 83 85
CT........................ 562 3 MIDDLETOWN.................. 4,056,337 450,955 150 166
CT........................ 562 4 MIDDLETOWN.................. 5,882,211 543,090 218 199
CT........................ 546 5 MONTVILLE................... 1,584,160 158,131 59 58
CT........................ 546 6 MONTVILLE................... 5,312,085 485,344 197 178
CT........................ 6156 NHB1 NEW HAVEN HARBOR............ 10,881,332 1,160,923 404 426
CT........................ 548 1 NORWALK HARBOR.............. 3,099,297 322,005 115 118
CT........................ 548 2 NORWALK HARBOR.............. 3,631,682 379,407 135 139
CT........................ n46 CW__rd) O'BRIEN (HARTFORD).......... 673,659 60,690 25 22
DC........................ 603 15 BENNING..................... 605,207 53,487 89 90
DC........................ 603 16 BENNING..................... 730,757 63,296 107 106
DE........................ 592 B4 DELAWARE CITY............... 546,523 51,559 50 46
DE........................ 52193 ST__1 DELAWARE CITY............... 293,747 27,712 27 25
DE........................ 52193 ST__2 DELAWARE CITY............... 293,747 27,712 27 25
DE........................ 52193 ST__3 DELAWARE CITY............... 494,793 46,679 45 42
DE........................ 593 3 EDGE MOOR................... 2,775,531 268,375 252 241
DE........................ 593 4 EDGE MOOR................... 4,421,018 453,252 401 407
DE........................ 593 5 EDGE MOOR................... 6,515,159 712,351 591 640
DE........................ 7153 **3 HAY ROAD.................... 2,014,002 171,609 183 154
DE........................ 7153 --1 HAY ROAD.................... 156,053 11,822 14 11
DE........................ 7153 --2 HAY ROAD.................... 156,053 11,822 14 11
DE........................ 7153 --4 HAY ROAD.................... 1,056,415 124,284 96 112
DE........................ 594 1 INDIAN RIVER................ 2,118,931 214,271 192 193
DE........................ 594 2 INDIAN RIVER................ 2,201,388 218,804 200 197
DE........................ 594 3 INDIAN RIVER................ 4,022,311 435,315 365 391
DE........................ 594 4 INDIAN RIVER................ 8,277,718 804,521 751 723
DE........................ 599 3 MCKEE RUN................... 1,156,067 103,627 105 93
DE........................ 7318 --1 VAN SANT STATION............ 53,745 3,772 5 3
IL........................ 54780 ST__TS) ABBOTT (7 UNITS)............ 109,017 10,285 8 7
IL........................ ........... ............................. BABCOCK & WILCOX CO 45,900 3,221 3 2
COGENERATION FA.
IL........................ 889 1 BALDWIN..................... 15,218,756 1,493,792 1,074 1,056
IL........................ 889 2 BALDWIN..................... 15,201,447 1,513,184 1,072 1,070
IL........................ 889 3 BALDWIN..................... 16,459,376 1,782,282 1,161 1,260
IL........................ ........... ............................. BALDWIN POWER PLANT......... 3,366 236 0 0
IL........................ ........... ............................. BREESE MUNICIPAL POWER PLANT 6,579 462 0 0
IL........................ ........... ............................. BUSHNELL MUNICIPAL ELECTRIC 306 21 0 0
LIGHT &.
IL........................ ........... ............................. BUSHNELL MUNICIPAL ELECTRIC 306 21 0 0
LIGHT &.
IL........................ ........... ............................. CALUMET PEAKING UNITS....... 306 21 0 0
IL........................ ........... ............................. CARLYLE MUNICIPAL ELECTRIC 306 21 0 0
PLANT.
IL........................ ........... ............................. CARLYLE MUNICIPAL ELECTRIC 918 64 0 0
PLANT.
IL........................ ........... ............................. CENTRAL ILLINOIS LIGHT CO-- 3,366 236 0 0
STERLIN.
IL........................ ........... ............................. CITY OF CARMI............... 765 54 0 0
IL........................ ........... ............................. CITY OF CARMI............... 1,224 86 0 0
IL........................ ........... ............................. CITY OF CARMI............... 1,530 107 0 0
IL........................ ........... ............................. CITY OF CARMI............... 1,836 129 0 0
IL........................ ........... ............................. CITY OF CARMI............... 1,989 140 0 0
IL........................ ........... ............................. CITY OF PERU GENERATING 1,836 129 0 0
STATION.
IL........................ ........... ............................. CITY OF PERU GENERATING 2,907 204 0 0
STATION.
IL........................ ........... ............................. CITY OF RED BUD............. 612 43 0 0
IL........................ ........... ............................. CITY OF RED BUD............. 1,989 140 0 0
IL........................ ........... ............................. CITY OF RED BUD............. 8,109 569 1 0
IL........................ ........... ............................. CITY WATER LIGHT & POWER 63,189 4,434 4 3
DEPT.
IL........................ ........... ............................. CLINTON POWER STATION....... 1,377 97 0 0
IL........................ ........... ............................. CLINTON POWER STATION....... 2,601 183 0 0
IL........................ 861 01 COFFEEN..................... 6,072,017 604,783 428 427
IL........................ 861 02 COFFEEN..................... 11,934,607 1,220,682 842 863
IL........................ 6025 1 COLLINS..................... 4,795,651 482,023 338 341
IL........................ 6025 2 COLLINS..................... 5,305,418 542,809 374 384
IL........................ 6025 3 COLLINS..................... 5,854,107 581,688 413 411
IL........................ 6025 4 COLLINS..................... 3,746,709 362,491 264 256
IL........................ 6025 5 COLLINS..................... 2,488,656 235,356 176 166
IL........................ ........... ............................. COM ED--ELECTRIC JUNCTION 765 54 0 0
PEAKING.
IL........................ ........... ............................. COMMONWEALTH EDISON-WESTERN 306 21 0 0
DIV HQ.
IL........................ 867 7 CRAWFORD.................... 4,358,553 445,979 307 315
IL........................ 867 8 CRAWFORD.................... 5,792,952 607,037 409 429
IL........................ ........... ............................. CRAWFORD.................... 16,983 1,192 1 1
IL........................ 963 31 DALLMAN..................... 2,002,848 179,146 141 127
IL........................ 963 32 DALLMAN..................... 2,398,394 214,910 169 152
IL........................ 963 33 DALLMAN..................... 6,864,473 650,291 484 460
IL........................ 6016 1 DUCK CREEK.................. 12,712,162 1,268,932 897 897
[[Page 56362]]
IL........................ 856 1 E D EDWARDS................. 2,856,940 277,831 202 196
IL........................ 856 2 E D EDWARDS................. 6,511,474 652,845 459 461
IL........................ 856 3 E D EDWARDS................. 8,431,346 874,077 595 618
IL........................ ........... ............................. FAIRFIELD MUNICIPAL LIGHT... 459 32 0 0
IL........................ ........... ............................. FAIRFIELD MUNICIPAL LIGHT... 918 64 0 0
IL........................ 886 19 FISK........................ 6,895,507 739,068 486 522
IL........................ ........... ............................. FISK........................ 306 21 0 0
IL........................ ........... ............................. GENESEO MUNICIPAL UTILITIES. 23,103 1,621 2 1
IL........................ ........... ............................. GENESEO MUNICIPAL UTILITIES. 25,704 1,804 2 1
IL........................ ........... ............................. GENESEO MUNICIPAL UTILITIES. 51,408 3,608 4 3
IL........................ ........... ............................. GENESEO MUNICIPAL UTILITIES. 74,511 5,229 5 4
IL........................ ........... ............................. GENESEO MUNICIPAL UTILITIES. 87,363 6,131 6 4
IL........................ ........... ............................. GENESEO MUNICIPAL UTILITIES. 87,363 6,131 6 4
IL........................ ........... ............................. GENESEO MUNICIPAL UTILITIES. 141,372 9,921 10 7
IL........................ 862 07 GRAND TOWER................. 651,170 62,612 46 44
IL........................ 862 08 GRAND TOWER................. 654,114 62,896 46 44
IL........................ 862 09 GRAND TOWER................. 2,630,056 270,276 186 191
IL........................ 891 9 HAVANA...................... 8,683,730 823,571 613 582
IL........................ 892 1 HENNEPIN.................... 2,009,046 189,586 142 134
IL........................ 892 2 HENNEPIN.................... 6,675,377 751,901 471 531
IL........................ 863 05 HUTSONVILLE................. 2,052,071 201,638 145 143
IL........................ 863 06 HUTSONVILLE................. 1,495,464 148,227 105 105
IL........................ 384 71 JOLIET 29................... 5,594,695 565,406 395 400
IL........................ 384 72 JOLIET 29................... 7,988,169 807,293 564 571
IL........................ 384 81 JOLIET 29................... 5,979,042 606,271 422 429
IL........................ 384 82 JOLIET 29................... 8,727,941 885,007 616 626
IL........................ 874 5 JOLIET 9.................... 7,279,634 745,482 514 527
IL........................ 887 1 JOPPA STEAM................. 6,415,901 612,380 453 433
IL........................ 887 2 JOPPA STEAM................. 6,371,397 627,662 449 444
IL........................ 887 3 JOPPA STEAM................. 6,162,171 610,721 435 432
IL........................ 887 4 JOPPA STEAM................. 6,409,101 622,666 452 440
IL........................ 887 5 JOPPA STEAM................. 6,707,659 630,241 473 445
IL........................ 887 6 JOPPA STEAM................. 6,766,124 648,034 477 458
IL........................ 876 1 KINCAID..................... 9,749,992 914,719 688 647
IL........................ 876 2 KINCAID..................... 11,246,140 1,098,470 793 776
IL........................ 964 7 LAKESIDE.................... 700,482 56,039 49 40
IL........................ 964 8 LAKESIDE.................... 696,352 55,708 49 39
IL........................ ........... ............................. LASALLE COUNTY STATION...... 1,530 107 0 0
IL........................ 976 1 MARION...................... 95,573 7,079 7 5
IL........................ 976 2 MARION...................... 175,085 12,969 12 9
IL........................ 976 3 MARION...................... 584,871 43,324 41 31
IL........................ 976 4 MARION...................... 5,264,312 501,363 371 354
IL........................ ........... ............................. MARISON CO.................. 306 21 0 0
IL........................ ........... ............................. MASCOUTAH POWER PLANT....... 459 32 0 0
IL........................ ........... ............................. MASCOUTAH POWER PLANT....... 765 54 0 0
IL........................ 864 01 MEREDOSIA................... 470,181 45,210 33 32
IL........................ 864 02 MEREDOSIA................... 431,943 41,533 30 29
IL........................ 864 03 MEREDOSIA................... 320,639 30,831 23 22
IL........................ 864 04 MEREDOSIA................... 382,526 36,781 27 26
IL........................ 864 05 MEREDOSIA................... 5,620,207 577,557 396 408
IL........................ 864 06 MEREDOSIA................... 425,393 42,887 30 30
IL........................ 6017 1 NEWTON...................... 15,508,748 1,619,543 1,094 1,145
IL........................ 6017 2 NEWTON...................... 14,958,053 1,596,036 1,055 1,128
IL........................ ........... ............................. OGLESBY GAS TURBINE......... 15,759 1,106 1 1
IL........................ ........... ............................. PHOENIX CHEMICAL COMPANY.... 17,901 1,256 1 1
IL........................ ........... ............................. PHOENIX CHEMICAL COMPANY.... 17,901 1,256 1 1
IL........................ ........... ............................. PHOENIX CHEMICAL COMPANY.... 17,901 1,256 1 1
IL........................ 879 51 POWERTON.................... 9,827,191 899,926 693 636
IL........................ 879 52 POWERTON.................... 10,189,834 933,135 719 660
IL........................ 879 61 POWERTON.................... 9,120,197 876,100 643 619
IL........................ 879 62 POWERTON.................... 9,670,327 928,946 682 657
IL........................ ........... ............................. PRINCETON MUNCIPAL ELECTRIC 153 11 0 0
UTILITY.
IL........................ ........... ............................. PRINCETON MUNCIPAL ELECTRIC 153 11 0 0
UTILITY.
IL........................ ........... ............................. PRINCETON MUNCIPAL ELECTRIC 153 11 0 0
UTILITY.
IL........................ ........... ............................. PRINCETON MUNCIPAL ELECTRIC 153 11 0 0
UTILITY.
IL........................ ........... ............................. QUAD CITIES STATION--CORDOVA 8,415 591 1 0
IL........................ ........... ............................. RANTOUL ELECT GENERATING 38,250 2,684 3 2
PLANT.
IL........................ ........... ............................. RANTOUL ELECT GENERATING 41,310 2,899 3 2
PLANT.
IL........................ ........... ............................. RANTOUL ELECT GENERATING 90,270 6,335 6 4
PLANT.
IL........................ ........... ............................. RANTOUL ELECT GENERATING 160,344 11,252 11 8
PLANT.
IL........................ ........... ............................. ROCHELLE MUNICIPAL DIESEL 306 21 0 0
PLANT.
IL........................ ........... ............................. ROCHELLE MUNICIPAL DIESEL 459 32 0 0
PLANT.
IL........................ ........... ............................. ROCHELLE MUNICIPAL DIESEL 7,038 494 0 0
PLANT.
IL........................ ........... ............................. ROCHELLE MUNICIPAL DIESEL 11,169 784 1 1
PLANT.
IL........................ ........... ............................. ROCHELLE/SOUTH MAIN STREET.. 459 32 0 0
IL........................ ........... ............................. ROCHELLE/SOUTH MAIN STREET.. 765 54 0 0
[[Page 56363]]
IL........................ ........... ............................. ROCK RIVER DIV HEADQUARTERS. 6,732 472 0 0
IL........................ ........... ............................. ST LOUIS AUTO SHREDDING INC. 11,934 837 1 1
IL........................ ........... ............................. STALLIINGS.................. 153 11 0 0
IL........................ ........... ............................. STALLIINGS.................. 153 11 0 0
IL........................ ........... ............................. STALLIINGS.................. 153 11 0 0
IL........................ ........... ............................. STALLIINGS.................. 153 11 0 0
IL........................ ........... ............................. SULLIVAN ELECTRIC UTILITY... 612 43 0 0
IL........................ ........... ............................. SULLIVAN ELECTRIC UTILITY... 1,071 75 0 0
IL........................ ........... ............................. SULLIVAN ELECTRIC UTILITY... 1,377 97 0 0
IL........................ ........... ............................. SULLIVAN ELECTRIC UTILITY... 2,142 150 0 0
IL........................ ........... ............................. U.O.P. CO................... 16,218 1,138 1 1
IL........................ 897 1 VERMILION................... 623,436 56,779 44 40
IL........................ 897 2 VERMILION................... 1,112,049 98,568 78 70
IL........................ ........... ............................. WASTE MANAGEMENT OF IL-- 1,530 107 0 0
MIDWAY LAN.
IL........................ ........... ............................. WATERLOO CITY LIGHT PLANT... 153 11 0 0
IL........................ 883 17 WAUKEGAN.................... 2,836,176 246,624 200 174
IL........................ 883 7 WAUKEGAN.................... 7,481,751 769,490 528 544
IL........................ 883 8 WAUKEGAN.................... 8,846,311 906,291 624 641
IL........................ ........... ............................. WHITE COUNTY COAL CORP--MINE 306 21 0 0
#1.
IL........................ 884 1 WILL COUNTY................. 4,419,934 448,588 312 317
IL........................ 884 2 WILL COUNTY................. 4,350,027 456,025 307 322
IL........................ 884 3 WILL COUNTY................. 5,839,114 615,875 412 435
IL........................ 884 4 WILL COUNTY................. 9,697,974 1,029,181 684 727
IL........................ 898 4 WOOD RIVER.................. 2,014,967 187,998 142 133
IL........................ 898 5 WOOD RIVER.................. 7,180,169 719,312 507 508
IN........................ 6137 1 A B BROWN................... 6,035,177 573,141 468 440
IN........................ 6137 2 A B BROWN................... 6,871,738 668,782 533 514
IN........................ 6137 --4 A B BROWN................... 151,668 11,831 12 9
IN........................ 7336 --ACT1 ANDERSON.................... 67,856 4,762 5 4
IN........................ 7336 --ACT2 ANDERSON.................... 67,856 4,762 5 4
IN........................ 995 7 BAILLY...................... 5,354,149 546,509 415 420
IN........................ 995 8 BAILLY...................... 9,260,589 976,032 719 749
IN........................ 1011 --2 BROADWAY.................... 123,242 9,337 10 7
IN........................ 1001 1 CAYUGA...................... 15,657,595 1,562,790 1,215 1,200
IN........................ 1001 2 CAYUGA...................... 14,571,660 1,475,761 1,131 1,133
IN........................ 1001 --4 CAYUGA...................... 345,558 28,110 27 22
IN........................ 1001 5 CAYUGA...................... 149,834 11,351 12 9
IN........................ 983 1 CLIFTY CREEK................ 7,379,559 784,475 573 602
IN........................ 983 2 CLIFTY CREEK................ 7,176,300 784,209 557 602
IN........................ 983 3 CLIFTY CREEK................ 7,063,406 756,334 548 581
IN........................ 983 4 CLIFTY CREEK................ 6,798,235 732,253 527 562
IN........................ 983 5 CLIFTY CREEK................ 7,400,261 783,096 574 601
IN........................ 983 6 CLIFTY CREEK................ 6,727,925 706,863 522 543
IN........................ ........... 1 CONNERSVILLE................ 16,083 1,129 1 1
IN........................ ........... 2 CONNERSVILLE................ 16,083 1,129 1 1
IN........................ 996 11 DEAN H MITCHELL............. 2,287,384 227,941 177 175
IN........................ 996 4 DEAN H MITCHELL............. 1,842,510 182,734 143 140
IN........................ 996 5 DEAN H MITCHELL............. 3,177,761 322,092 247 247
IN........................ 996 6 DEAN H MITCHELL............. 2,600,547 268,430 202 206
IN........................ 990 10 ELMER W STOUT............... 13,560 1,279 1 1
IN........................ 990 50 ELMER W STOUT............... 2,415,760 232,374 187 178
IN........................ 990 60 ELMER W STOUT............... 2,335,827 224,685 181 173
IN........................ 990 70 ELMER W STOUT............... 9,783,680 941,100 759 723
IN........................ 990 9 ELMER W STOUT............... 15,792 1,490 1 1
IN........................ 990 --GT4 ELMER W STOUT............... 78,478 5,945 6 5
IN........................ 990 --GT5 ELMER W STOUT............... 88,946 6,738 7 5
IN........................ 1012 1 F B CULLEY.................. 669,903 64,414 52 49
IN........................ 1012 2 F B CULLEY.................. 2,593,129 221,257 201 170
IN........................ 1012 3 F B CULLEY.................. 9,584,920 941,544 744 723
IN........................ 1043 1SG1 FRANK E RATTS............... 3,258,718 337,971 253 260
IN........................ 1043 2SG1 FRANK E RATTS............... 3,187,585 328,482 247 252
IN........................ 1008 1 GALLAGHER................... 3,831,362 370,968 297 285
IN........................ 1008 2 GALLAGHER................... 3,401,395 335,476 264 258
IN........................ 1008 3 GALLAGHER................... 4,528,750 444,605 351 341
IN........................ 1008 4 GALLAGHER................... 4,244,584 410,978 329 316
IN........................ 6113 1 GIBSON...................... 19,606,094 2,037,632 1,521 1,565
IN........................ 6113 2 GIBSON...................... 18,199,182 1,859,906 1,412 1,428
IN........................ 6113 3 GIBSON...................... 16,865,898 1,708,977 1,309 1,312
IN........................ 6113 4 GIBSON...................... 16,654,069 1,680,532 1,292 1,290
IN........................ 6113 5 GIBSON...................... 20,380,811 2,015,308 1,581 1,547
IN........................ 991 1 H T PRITCHARD............... 17,262 1,628 1 1
IN........................ 991 2 H T PRITCHARD............... 20,009 1,888 2 1
IN........................ 991 3 H T PRITCHARD............... 658,621 63,329 51 49
IN........................ 991 4 H T PRITCHARD............... 896,604 77,817 70 60
IN........................ 991 5 H T PRITCHARD............... 870,970 75,592 68 58
IN........................ 991 6 H T PRITCHARD............... 2,568,694 222,938 199 171
[[Page 56364]]
IN........................ 6213 1SG1 MEROM....................... 16,068,534 1,640,316 1,247 1,260
IN........................ 6213 2SG1 MEROM....................... 19,329,452 1,986,175 1,500 1,525
IN........................ 997 12 MICHIGAN CITY............... 11,955,128 1,210,523 928 930
IN........................ 997 4 MICHIGAN CITY............... 202,787 19,131 16 15
IN........................ 997 5 MICHIGAN CITY............... 125,850 11,873 10 9
IN........................ 997 6 MICHIGAN CITY............... 193,869 18,289 15 14
IN........................ 1007 1 NOBLESVILLE................. 348,522 33,512 27 26
IN........................ 1007 2 NOBLESVILLE................. 363,142 34,917 28 27
IN........................ 1007 3 NOBLESVILLE................. 385,596 37,077 30 28
IN........................ 994 1 PETERSBURG.................. 7,083,983 684,575 550 526
IN........................ 994 2 PETERSBURG.................. 14,305,783 1,382,468 1,110 1,062
IN........................ 994 3 PETERSBURG.................. 16,278,783 1,573,133 1,263 1,208
IN........................ 994 4 PETERSBURG.................. 16,288,351 1,574,058 1,264 1,209
IN........................ 7335 --RCT1 RICHMOND.................... 67,490 4,736 5 4
IN........................ 7335 --RCT2 RICHMOND.................... 67,490 4,736 5 4
IN........................ 6166 MB1 ROCKPORT.................... 43,122,887 4,412,903 3,346 3,389
IN........................ 6166 MB2 ROCKPORT.................... 45,949,908 4,683,032 3,565 3,596
IN........................ 6085 14 SCHAHFER.................... 12,148,297 1,235,336 943 949
IN........................ 6085 15 SCHAHFER.................... 14,443,963 1,443,963 1,121 1,109
IN........................ 6085 --16A SCHAHFER.................... 147,909 11,205 11 9
IN........................ 6085 --16B SCHAHFER.................... 145,983 11,059 11 8
IN........................ 6085 17 SCHAHFER.................... 10,147,542 1,031,150 787 792
IN........................ 6085 18 SCHAHFER.................... 9,033,005 925,987 701 711
IN........................ 981 3 STATE LINE.................. 4,973,309 527,225 386 405
IN........................ 981 4 STATE LINE.................. 5,883,063 631,027 456 485
IN........................ 988 U1 TANNERS CREEK............... 3,131,631 325,770 243 250
IN........................ 988 U2 TANNERS CREEK............... 3,098,674 328,493 240 252
IN........................ 988 U3 TANNERS CREEK............... 4,041,085 434,899 314 334
IN........................ 988 U4 TANNERS CREEK............... 11,950,298 1,394,271 927 1,071
IN........................ 1010 1 WABASH RIVER................ 851,343 94,804 66 73
IN........................ 1010 2 WABASH RIVER................ 1,727,253 167,046 134 128
IN........................ 1010 3 WABASH RIVER................ 1,705,031 163,067 132 125
IN........................ 1010 4 WABASH RIVER................ 2,662,911 254,678 207 196
IN........................ 1010 5 WABASH RIVER................ 1,897,229 176,536 147 136
IN........................ 1010 6 WABASH RIVER................ 7,024,392 683,706 545 525
IN........................ 6705 1 WARRICK..................... 3,774,805 362,962 293 279
IN........................ 6705 2 WARRICK..................... 3,986,462 383,314 309 294
IN........................ 6705 3 WARRICK..................... 4,055,995 390,000 315 299
IN........................ 6705 4 WARRICK..................... 11,135,585 1,098,184 864 843
IN........................ 1040 1 WHITEWATER VALLEY........... 971,576 93,421 75 72
IN........................ 1040 2 WHITEWATER VALLEY........... 1,877,419 168,122 146 129
KY........................ 1353 BSU1 BIG SANDY................... 7,613,037 812,057 609 655
KY........................ 1353 BSU2 BIG SANDY................... 22,241,768 2,407,118 1,781 1,942
KY........................ 1363 4 CANE RUN.................... 4,925,774 444,084 394 358
KY........................ 1363 5 CANE RUN.................... 4,304,294 417,487 345 337
KY........................ 1363 6 CANE RUN.................... 5,587,828 543,616 447 439
KY........................ 1384 1 COOPER...................... 2,306,853 231,658 185 187
KY........................ 1384 2 COOPER...................... 4,882,718 478,651 391 386
KY........................ 6823 W1 D B WILSON.................. 14,381,701 1,449,768 1,151 1,170
KY........................ 1385 3 DALE........................ 1,906,453 159,723 153 129
KY........................ 1385 4 DALE........................ 1,935,939 164,202 155 132
KY........................ 1355 1 E W BROWN................... 2,464,832 222,357 197 179
KY........................ 1355 2 E W BROWN................... 4,028,960 405,859 323 327
KY........................ 1355 3 E W BROWN................... 10,080,565 954,870 807 770
KY........................ 1355 5 E W BROWN................... 188,516 14,282 15 12
KY........................ 1355 6 E W BROWN................... 188,516 14,282 15 12
KY........................ 1355 7 E W BROWN................... 188,516 14,282 15 12
KY........................ 6018 2 EAST BEND................... 19,048,549 1,915,390 1,525 1,545
KY........................ 1374 1 ELMER SMITH................. 5,140,226 513,099 412 414
KY........................ 1374 2 ELMER SMITH................. 9,068,247 1,021,659 726 824
KY........................ 1356 2 GHENT....................... 13,610,812 1,345,607 1,090 1,086
KY........................ 1356 3 GHENT....................... 13,909,380 1,328,372 1,114 1,072
KY........................ 1356 4 GHENT....................... 14,120,228 1,415,846 1,130 1,142
KY........................ 1357 1 GREEN RIVER................. 312,489 30,047 25 24
KY........................ 1357 2 GREEN RIVER................. 313,882 30,181 25 24
KY........................ 1357 3 GREEN RIVER................. 300,246 28,870 24 23
KY........................ 1357 4 GREEN RIVER................. 2,445,115 199,422 196 161
KY........................ 1357 5 GREEN RIVER................. 2,133,890 190,356 171 154
KY........................ 6041 1 H L SPURLOCK................ 9,369,673 933,792 750 753
KY........................ 6041 2 H L SPURLOCK................ 19,888,084 2,012,964 1,592 1,624
KY........................ 1372 6 HENDERSON I................. 424,577 40,825 34 33
KY........................ 1382 H1 HMP&L STATION 2............. 4,765,405 466,282 382 376
KY........................ 1382 H2 HMP&L STATION 2............. 5,002,527 490,925 400 396
KY........................ 1381 C1 K C COLEMAN................. 4,738,308 471,005 379 380
KY........................ 1381 C2 K C COLEMAN................. 5,366,408 527,411 430 426
KY........................ 1381 C3 K C COLEMAN................. 4,937,546 480,306 395 388
[[Page 56365]]
KY........................ 1364 1 MILL CREEK.................. 7,116,202 701,035 570 566
KY........................ 1364 2 MILL CREEK.................. 7,466,807 706,749 598 570
KY........................ 1364 3 MILL CREEK.................. 12,691,840 1,234,015 1,016 996
KY........................ 1364 4 MILL CREEK.................. 14,102,495 1,387,495 1,129 1,119
KY........................ 1378 1 PARADISE.................... 21,860,472 2,197,916 1,750 1,773
KY........................ 1378 2 PARADISE.................... 24,632,519 2,476,626 1,972 1,998
KY........................ 1378 3 PARADISE.................... 27,629,156 2,743,437 2,212 2,213
KY........................ 1360 3 PINEVILLE................... 588,364 56,573 47 46
KY........................ 1383 R1 R A REID.................... 462,060 41,072 37 33
KY........................ 6639 G1 R D GREEN................... 8,342,047 809,122 668 653
KY........................ 6639 G2 R D GREEN................... 7,435,113 714,228 595 576
KY........................ 1379 1 SHAWNEE..................... 4,299,562 426,671 344 344
KY........................ 1379 10 SHAWNEE..................... 10,578,503 993,473 847 802
KY........................ 1379 2 SHAWNEE..................... 4,324,438 429,139 346 346
KY........................ 1379 3 SHAWNEE..................... 4,428,585 439,475 355 355
KY........................ 1379 4 SHAWNEE..................... 4,240,262 420,786 339 339
KY........................ 1379 5 SHAWNEE..................... 4,409,569 437,587 353 353
KY........................ 1379 6 SHAWNEE..................... 7,296,781 724,102 584 584
KY........................ 1379 7 SHAWNEE..................... 8,781,086 871,399 703 703
KY........................ 1379 8 SHAWNEE..................... 5,000,057 496,185 400 400
KY........................ 1379 9 SHAWNEE..................... 5,884,725 583,976 471 471
KY........................ 6071 1 TRIMBLE COUNTY.............. 16,103,567 1,599,321 1,289 1,290
KY........................ 1361 1 TYRONE...................... 35,370 3,337 3 3
KY........................ 1361 3 TYRONE...................... 35,800 3,377 3 3
KY........................ 1361 4 TYRONE...................... 36,606 3,453 3 3
KY........................ 1361 5 TYRONE...................... 1,019,264 82,685 82 67
MA........................ 50002 CC__(*) ALTRESCO (PITTSFIELD) (*)... 1,121,457 131,936 114 130
MA........................ 50002 CS__(*) ALTRESCO (PITTSFIELD) (*)... 587,755 69,148 60 68
MA........................ 1619 1 BRAYTON POINT............... 7,692,885 785,068 783 773
MA........................ 1619 2 BRAYTON POINT............... 7,497,386 790,530 763 778
MA........................ 1619 3 BRAYTON POINT............... 18,238,259 2,030,082 1,857 1,999
MA........................ 1619 4 BRAYTON POINT............... 5,455,025 511,969 555 504
MA........................ 1599 1 CANAL....................... 11,606,453 1,290,897 1,182 1,271
MA........................ 1599 2 CANAL....................... 10,108,445 1,024,989 1,029 1,009
MA........................ 1682 8 CLEARY FLOOD................ 80,600 6,037 8 6
MA........................ 1682 9 CLEARY FLOOD................ 902,365 102,170 92 101
MA........................ 52026 CA__(*) DARTMOUTH POWER ASSOC (*)... 741,248 66,779 75 66
MA........................ 10029 1 GE COMPANY AIRCRAFT ENGIN... 61,457 4,656 6 5
MA........................ 54586 CC__gia L'ENERGIA................... 876,770 78,988 89 78
MA........................ 10802 1 LOWELL COGENERATION PLANT... 155,520 10,914 16 11
MA........................ 10726 CC__to) MASS POWER (MONSANTO)....... 1,586,869 186,690 162 184
MA........................ 10726 CW__to) MASS POWER (MONSANTO)....... 549,347 64,629 56 64
MA........................ n89 CC__r 1 MASS POWER 1................ 304,660 27,447 31 27
MA........................ n90 CC__r 2 MASS POWER 2................ 304,660 27,447 31 27
MA........................ 1606 1 MOUNT TOM................... 4,711,387 490,616 480 483
MA........................ 1588 4 MYSTIC...................... 1,376,669 139,452 140 137
MA........................ 1588 5 MYSTIC...................... 648,038 60,132 66 59
MA........................ 1588 6 MYSTIC...................... 2,194,462 222,539 223 219
MA........................ 1588 7 MYSTIC...................... 11,802,193 1,229,779 1,202 1,211
MA........................ 1589 1 NEW BOSTON.................. 8,789,339 902,674 895 889
MA........................ 1589 2 NEW BOSTON.................. 9,365,437 952,643 954 938
MA........................ n91 CC__& 2 NORTHEAST ENERGY ASSO 1 &... 3,296,081 387,774 336 382
MA........................ 10522 CC__(*) PEPPERELL (*)............... 376,614 33,929 38 33
MA........................ 1660 --CC2 POTTER STATION 2............ 548,078 49,376 56 49
MA........................ 1626 1 SALEM HARBOR................ 2,754,313 264,711 280 261
MA........................ 1626 2 SALEM HARBOR................ 3,089,594 291,471 315 287
MA........................ 1626 3 SALEM HARBOR................ 5,059,490 490,641 515 483
MA........................ 1626 4 SALEM HARBOR................ 6,294,731 594,123 641 585
MA........................ 1613 8 SOMERSET.................... 3,209,854 294,293 327 290
MA........................ 6081 --1 STONY BROOK................. 90,418 6,850 9 7
MA........................ 6081 --2 STONY BROOK................. 90,418 6,850 9 7
MA........................ 6081 --CT1 STONY BROOK................. 614,254 55,338 63 54
MA........................ 6081 --CT2 STONY BROOK................. 614,254 55,338 63 54
MA........................ 6081 --CT3 STONY BROOK................. 614,254 55,338 63 54
MA........................ 6081 --CW1 STONY BROOK................. 944,989 111,175 96 109
MA........................ 1678 --2 WATERS RIVER................ 42,566 3,733 4 4
MA........................ 1642 3 WEST SPRINGFIELD............ 2,006,248 196,210 204 193
MD........................ 10483 ST NUG BETHLEHEM STEEL NUG........ 3,625,254 342,005 342 313
MD........................ 602 1 BRANDON SHORES.............. 21,502,167 2,151,938 2,029 1,971
MD........................ 602 2 BRANDON SHORES.............. 21,147,845 2,102,171 1,995 1,925
MD........................ 1552 1 C P CRANE................... 5,355,147 524,244 505 480
MD........................ 1552 2 C P CRANE................... 5,060,998 496,371 477 455
MD........................ 1571 1 CHALK POINT................. 9,223,252 993,029 870 909
MD........................ 1571 2 CHALK POINT................. 9,516,601 1,033,739 898 947
MD........................ 1571 3 CHALK POINT................. 3,368,279 316,836 318 290
MD........................ 1571 4 CHALK POINT................. 4,729,925 448,632 446 411
[[Page 56366]]
MD........................ 1571 --GT2 CHALK POINT................. 12,553 881 1 1
MD........................ 1571 --GT3 CHALK POINT................. 95,860 8,206 9 8
MD........................ 1571 --GT4 CHALK POINT................. 98,058 8,394 9 8
MD........................ 1571 --GT5 CHALK POINT................. 167,177 15,561 16 14
MD........................ 1571 --SGT1 CHALK POINT................. 293,306 22,220 28 20
MD........................ 1572 1 DICKERSON................... 5,087,240 538,048 480 493
MD........................ 1572 2 DICKERSON................... 5,102,377 540,392 481 495
MD........................ 1572 3 DICKERSON................... 5,232,608 564,772 494 517
MD........................ 1572 --GT2 DICKERSON................... 134,534 12,841 13 12
MD........................ 1572 --GT3 DICKERSON................... 338,557 32,314 32 30
MD........................ 1580 1 EASTON...................... 66,212 7,790 6 7
MD........................ 1553 3 GOULD STREET................ 584,029 51,766 55 47
MD........................ 1554 1 HERBERT A WAGNER............ 782,492 68,382 74 63
MD........................ 1554 2 HERBERT A WAGNER............ 4,261,160 425,350 402 390
MD........................ 1554 3 HERBERT A WAGNER............ 7,769,439 849,583 733 778
MD........................ 1554 4 HERBERT A WAGNER............ 1,818,482 165,512 172 152
MD........................ 1573 1 MORGANTOWN.................. 14,211,706 1,571,049 1,341 1,439
MD........................ 1573 2 MORGANTOWN.................. 15,148,826 1,673,164 1,429 1,532
MD........................ 1573 --GT3 MORGANTOWN.................. 106,208 7,453 10 7
MD........................ 1573 --GT4 MORGANTOWN.................. 107,406 7,537 10 7
MD........................ 1573 --GT5 MORGANTOWN.................. 108,314 7,601 10 7
MD........................ 1573 --GT6 MORGANTOWN.................. 96,013 6,738 9 6
MD........................ 1556 --GT1 PERRYMAN.................... 51,532 3,616 5 3
MD........................ 1556 --GT2 PERRYMAN.................... 58,312 4,092 6 4
MD........................ 1556 --GT3 PERRYMAN.................... 36,459 2,558 3 2
MD........................ 1556 --GT4 PERRYMAN.................... 56,510 3,966 5 4
MD........................ 1570 11 R P SMITH................... 1,374,337 138,836 130 127
MD........................ 1570 9 R P SMITH................... 87,168 8,381 8 8
MD........................ 1559 4 RIVERSIDE................... 302,110 26,943 29 25
MD........................ 1559 --GT6 RIVERSIDE................... 74,446 5,224 7 5
MD........................ 1564 8 VIENNA...................... 1,495,451 137,601 141 126
MD........................ 1560 --GT5 WESTPORT.................... 214,627 15,062 20 14
MI........................ 7268 --7 491 E. 48TH STREET.......... 7,914 660 1 0
MI........................ 7268 --8 491 E. 48TH STREET.......... 13,441 1,120 1 1
MI........................ 10819 CA__Ltd ADA COGEN LTD............... 318,649 28,707 24 21
MI........................ 1695 4 B C COBB.................... 4,719,074 480,313 349 344
MI........................ 1695 5 B C COBB.................... 4,419,640 448,694 327 321
MI........................ 6034 1 BELLE RIVER................. 21,840,775 2,211,948 1,615 1,584
MI........................ 6034 2 BELLE RIVER................. 23,002,097 2,343,566 1,701 1,678
MI........................ 1702 1 DAN E KARN.................. 6,515,728 696,944 482 499
MI........................ 1702 2 DAN E KARN.................. 7,211,347 773,584 533 554
MI........................ 1702 3 DAN E KARN.................. 2,601,938 239,193 192 171
MI........................ 1702 4 DAN E KARN.................. 2,725,268 227,732 202 163
MI........................ 1831 1 ECKERT STATION.............. 495,985 47,691 37 34
MI........................ 1831 2 ECKERT STATION.............. 335,803 30,561 25 22
MI........................ 1831 3 ECKERT STATION.............. 587,998 53,866 43 39
MI........................ 1831 4 ECKERT STATION.............. 988,838 92,718 73 66
MI........................ 1831 5 ECKERT STATION.............. 1,121,036 103,027 83 74
MI........................ 1831 6 ECKERT STATION.............. 1,340,375 124,732 99 89
MI........................ 1832 1 ERICKSON.................... 5,079,491 526,863 376 377
MI........................ 6035 1 GREENWOOD................... 1,565,824 164,685 116 118
MI........................ 1731 1 HARBOR BEACH................ 768,833 74,818 57 54
MI........................ 1825 3 J B SIMS.................... 1,749,713 158,863 129 114
MI........................ 1720 7 J C WEADOCK................. 4,214,462 426,565 312 305
MI........................ 1720 8 J C WEADOCK................. 4,265,849 432,028 315 309
MI........................ 1710 1 J H CAMPBELL................ 6,547,409 700,108 484 501
MI........................ 1710 2 J H CAMPBELL................ 8,517,252 903,879 630 647
MI........................ 1710 3 J H CAMPBELL................ 21,544,630 2,314,387 1,593 1,657
MI........................ 1723 1 J R WHITING................. 2,881,534 285,413 213 204
MI........................ 1723 2 J R WHITING................. 2,627,628 262,947 194 188
MI........................ 1723 3 J R WHITING................. 3,273,683 325,869 242 233
MI........................ 1830 5 JAMES DE YOUNG.............. 915,620 73,250 68 52
MI........................ n100 CA__act MCV CONTRACT................ 10,055,262 1,182,972 744 847
MI........................ 10745 1 MIDLAND COGENERATION VENT... 5,869,080 444,627 434 318
MI........................ 1822 5 MISTERSKY................... 460,030 43,399 34 31
MI........................ 1822 6 MISTERSKY................... 1,473,716 127,429 109 91
MI........................ 1822 7 MISTERSKY................... 1,315,382 111,237 97 80
MI........................ 1733 1 MONROE...................... 23,198,275 2,547,022 1,716 1,824
MI........................ 1733 2 MONROE...................... 21,371,974 2,310,733 1,581 1,654
MI........................ 1733 3 MONROE...................... 17,719,325 1,928,949 1,310 1,381
MI........................ 1733 4 MONROE...................... 17,764,880 1,924,481 1,314 1,378
MI........................ 1769 2 PRESQUE ISLE................ 282,822 27,194 21 19
MI........................ 1769 3 PRESQUE ISLE................ 1,283,250 120,504 95 86
MI........................ 1769 4 PRESQUE ISLE................ 1,217,723 114,351 90 82
MI........................ 1769 5 PRESQUE ISLE................ 2,646,645 250,392 196 179
MI........................ 1769 6 PRESQUE ISLE................ 2,753,661 260,517 204 187
[[Page 56367]]
MI........................ 1769 7 PRESQUE ISLE................ 2,993,352 260,314 221 186
MI........................ 1769 8 PRESQUE ISLE................ 3,044,818 264,790 225 190
MI........................ 1769 9 PRESQUE ISLE................ 2,837,888 246,794 210 177
MI........................ 1740 1 RIVER ROUGE................. 1,200,116 130,235 89 93
MI........................ 1740 2 RIVER ROUGE................. 8,017,458 871,747 593 624
MI........................ 1740 3 RIVER ROUGE................. 8,515,077 937,268 630 671
MI........................ 10272 1 ROUGE POWERHOUSE #1......... 3,189,437 300,890 236 215
MI........................ 1843 3 SHIRAS...................... 1,360,969 113,084 101 81
MI........................ 1743 1 ST CLAIR.................... 4,264,532 437,119 315 313
MI........................ 1743 2 ST CLAIR.................... 4,042,244 401,375 299 287
MI........................ 1743 3 ST CLAIR.................... 4,704,277 470,287 348 337
MI........................ 1743 4 ST CLAIR.................... 4,400,916 453,796 325 325
MI........................ 1743 5 ST CLAIR.................... 1,519,120 154,523 112 111
MI........................ 1743 6 ST CLAIR.................... 8,503,976 886,200 629 634
MI........................ 1743 7 ST CLAIR.................... 9,260,458 964,029 685 690
MI........................ 50835 ST__ity T.E.S. FILER CITY........... 1,306,965 123,299 97 88
MI........................ 1745 16 TRENTON CHANNEL............. 1,431,549 130,545 106 93
MI........................ 1745 17 TRENTON CHANNEL............. 1,420,802 136,616 105 98
MI........................ 1745 18 TRENTON CHANNEL............. 1,322,166 120,570 98 86
MI........................ 1745 19 TRENTON CHANNEL............. 1,365,139 131,263 101 94
MI........................ 1745 9A TRENTON CHANNEL............. 12,981,225 1,372,948 960 983
MI........................ 1866 7 WYANDOTTE................... 1,115,053 100,176 82 72
MO........................ 2076 1 ASBURY...................... 6,415,029 567,702 465 426
MO........................ 2132 3 BLUE VALLEY................. 430,039 41,350 31 31
MO........................ 2169 2 CHAMOIS..................... 1,523,956 139,263 110 104
MO........................ 2122 --GT1 CHILLICOTHE................. 71,595 5,024 5 4
MO........................ 2122 --GT2 CHILLICOTHE................. 71,595 5,024 5 4
MO........................ 2123 7 COLUMBIA.................... 394,045 39,229 29 29
MO........................ 6223 --1 EMPIRE ENERGY CENTER........ 179,036 13,563 13 10
MO........................ 6223 --2 EMPIRE ENERGY CENTER........ 179,036 13,563 13 10
MO........................ 6074 --4 GREENWOOD ENERGY CTR........ 111,179 8,423 8 6
MO........................ 2079 5 HAWTHORN.................... 10,761,377 1,042,971 779 782
MO........................ 6065 1 IATAN....................... 22,356,034 2,298,585 1,619 1,723
MO........................ 2161 **GT2 JAMES RIVER................. 289,660 21,944 21 16
MO........................ 2161 3 JAMES RIVER................. 1,188,818 114,309 86 86
MO........................ 2161 4 JAMES RIVER................. 1,709,250 164,351 124 123
MO........................ 2161 5 JAMES RIVER................. 2,951,438 283,792 214 213
MO........................ 2161 --GT1 JAMES RIVER................. 1,393,758 125,564 101 94
MO........................ 2103 1 LABADIE..................... 14,988,473 1,455,474 1,085 1,091
MO........................ 2103 2 LABADIE..................... 15,775,674 1,531,916 1,142 1,148
MO........................ 2103 3 LABADIE..................... 18,159,252 1,763,377 1,315 1,322
MO........................ 2103 4 LABADIE..................... 16,185,316 1,571,695 1,172 1,178
MO........................ 2098 5 LAKE ROAD................... 1,557,840 141,409 113 106
MO........................ 2098 --5 LAKE ROAD................... 1,335,767 126,016 97 94
MO........................ 2098 6 LAKE ROAD................... 1,996,600 179,228 145 134
MO........................ 2104 1 MERAMEC..................... 1,667,729 131,909 121 99
MO........................ 2104 2 MERAMEC..................... 1,737,211 137,405 126 103
MO........................ 2104 3 MERAMEC..................... 2,079,846 164,506 151 123
MO........................ 2104 4 MERAMEC..................... 3,782,385 299,168 274 224
MO........................ 6650 --1 MEXICO...................... 112,520 8,524 8 6
MO........................ 6651 --1 MOBERLY..................... 112,520 8,524 8 6
MO........................ 2080 1 MONTROSE.................... 4,826,186 421,317 349 316
MO........................ 2080 2 MONTROSE.................... 4,658,606 424,939 337 319
MO........................ 2080 3 MONTROSE.................... 4,940,056 462,076 358 346
MO........................ 6652 --1 MOREAU...................... 112,520 8,524 8 6
MO........................ 2167 1 NEW MADRID.................. 17,470,625 1,738,371 1,265 1,303
MO........................ 2167 2 NEW MADRID.................. 18,334,306 1,824,309 1,328 1,368
MO........................ 2092 --GT1 RALPH GREEN................. 129,485 9,809 9 7
MO........................ 6155 1 RUSH ISLAND................. 17,761,120 1,742,653 1,286 1,306
MO........................ 6155 2 RUSH ISLAND................. 17,280,487 1,695,495 1,251 1,271
MO........................ 2094 1 SIBLEY...................... 1,456,245 125,538 105 94
MO........................ 2094 2 SIBLEY...................... 1,473,607 139,020 107 104
MO........................ 2094 3 SIBLEY...................... 10,522,347 1,084,778 762 813
MO........................ 6768 1 SIKESTON.................... 9,450,790 895,810 684 672
MO........................ 2107 1 SIOUX....................... 10,860,579 1,004,493 786 753
MO........................ 2107 2 SIOUX....................... 10,688,852 988,610 774 741
MO........................ 6195 1 SOUTHWEST................... 6,345,132 610,109 459 457
MO........................ 6195 --2 SOUTHWEST................... 87,505 6,629 6 5
MO........................ 6195 --GT1 SOUTHWEST................... 87,505 6,629 6 5
MO........................ 7296 --1 STATELINE................... 200,888 15,219 15 11
MO........................ 2168 MB1 THOMAS HILL................. 6,124,730 603,422 443 452
MO........................ 2168 MB2 THOMAS HILL................. 8,842,764 879,877 640 660
MO........................ 2168 MB3 THOMAS HILL................. 22,827,071 2,271,350 1,653 1,703
MO........................ 50969 1 UNIVERSITY OF MISSOURI--CO.. 411 39 0 0
NC........................ 2706 1 ASHEVILLE................... 6,457,822 681,420 524 528
NC........................ 2706 2 ASHEVILLE................... 6,300,506 661,818 511 513
[[Page 56368]]
NC........................ 8042 1 BELEWS CREEK................ 27,520,035 3,056,084 2,233 2,367
NC........................ 8042 2 BELEWS CREEK................ 34,358,912 3,802,447 2,788 2,945
NC........................ 2720 5 BUCK........................ 673,727 64,781 55 50
NC........................ 2720 6 BUCK........................ 579,519 55,723 47 43
NC........................ 2720 7 BUCK........................ 703,911 67,684 57 52
NC........................ 2720 8 BUCK........................ 3,428,909 328,786 278 255
NC........................ 2720 9 BUCK........................ 3,583,849 343,544 291 266
NC........................ 1016 --1 BUTLER WARNER GEN PL........ 524,574 47,259 43 37
NC........................ 1016 --2 BUTLER WARNER GEN PL........ 526,516 47,434 43 37
NC........................ 1016 --3 BUTLER WARNER GEN PL........ 522,524 47,074 42 36
NC........................ 1016 --6 BUTLER WARNER GEN PL........ 556,187 50,107 45 39
NC........................ 1016 --7 BUTLER WARNER GEN PL........ 528,459 47,609 43 37
NC........................ 1016 --8 BUTLER WARNER GEN PL........ 528,459 47,609 43 37
NC........................ 1016 --9 BUTLER WARNER GEN PL........ 1,351,896 121,792 110 94
NC........................ 2708 5 CAPE FEAR................... 3,248,898 338,568 264 262
NC........................ 2708 6 CAPE FEAR................... 4,656,544 503,791 378 390
NC........................ 2721 1 CLIFFSIDE................... 537,878 51,719 44 40
NC........................ 2721 2 CLIFFSIDE................... 688,755 66,226 56 51
NC........................ 2721 3 CLIFFSIDE................... 773,399 59,233 63 46
NC........................ 2721 4 CLIFFSIDE................... 929,143 70,071 75 54
NC........................ 2721 5 CLIFFSIDE................... 12,329,411 1,241,883 1,000 962
NC........................ 10380 ST__OWN COGENTRIX ELIZABETHTOWN..... 901,695 85,066 73 66
NC........................ 10381 ST__LLE COGENTRIX KENANSVILLE....... 901,695 85,066 73 66
NC........................ 10382 ST__TON COGENTRIX LUMBERTON......... 901,695 85,066 73 66
NC........................ 10379 ST__ORO COGENTRIX ROXBORO........... 1,388,705 131,010 113 101
NC........................ 10378 ST__ORT COGENTRIX SOUTHPORT......... 2,748,984 259,338 223 201
NC........................ 10525 ST__RGY CRAVEN COUNTY WOOD ENERGY... 3,035,837 286,400 246 222
NC........................ 2723 1 DAN RIVER................... 1,279,030 96,874 104 75
NC........................ 2723 2 DAN RIVER................... 1,276,869 106,441 104 82
NC........................ 2723 3 DAN RIVER................... 2,946,742 274,601 239 213
NC........................ 2718 1 G G ALLEN................... 3,428,222 329,099 278 255
NC........................ 2718 2 G G ALLEN................... 4,045,742 380,060 328 294
NC........................ 2718 3 G G ALLEN................... 6,731,538 674,909 546 523
NC........................ 2718 4 G G ALLEN................... 6,178,650 628,614 501 487
NC........................ 2718 5 G G ALLEN................... 5,611,834 579,555 455 449
NC........................ 2713 1 L V SUTTON.................. 1,890,914 167,604 153 130
NC........................ 2713 2 L V SUTTON.................. 2,204,273 212,953 179 165
NC........................ 2713 3 L V SUTTON.................. 8,616,341 897,255 699 695
NC........................ 2709 1 LEE......................... 1,613,150 151,555 131 117
NC........................ 2709 2 LEE......................... 1,528,041 141,958 124 110
NC........................ 2709 3 LEE......................... 4,977,693 527,354 404 408
NC........................ 7277 1 LINCOLN..................... 194,033 15,796 16 12
NC........................ 7277 10 LINCOLN..................... 136,184 10,813 11 8
NC........................ 7277 11 LINCOLN..................... 152,253 12,525 12 10
NC........................ 7277 12 LINCOLN..................... 125,731 10,186 10 8
NC........................ 7277 13 LINCOLN..................... 109,354 8,284 9 6
NC........................ 7277 14 LINCOLN..................... 105,132 7,965 9 6
NC........................ 7277 15 LINCOLN..................... 104,102 7,887 8 6
NC........................ 7277 16 LINCOLN..................... 95,106 7,205 8 6
NC........................ 7277 2 LINCOLN..................... 171,449 13,856 14 11
NC........................ 7277 3 LINCOLN..................... 162,933 13,209 13 10
NC........................ 7277 4 LINCOLN..................... 158,799 12,859 13 10
NC........................ 7277 5 LINCOLN..................... 146,360 11,812 12 9
NC........................ 7277 6 LINCOLN..................... 152,529 12,241 12 9
NC........................ 7277 7 LINCOLN..................... 164,582 13,136 13 10
NC........................ 7277 8 LINCOLN..................... 148,870 11,828 12 9
NC........................ 7277 9 LINCOLN..................... 129,158 10,353 10 8
NC........................ 2727 1 MARSHALL.................... 11,833,890 1,281,695 960 993
NC........................ 2727 2 MARSHALL.................... 12,362,967 1,334,373 1,003 1,033
NC........................ 2727 3 MARSHALL.................... 20,893,735 2,350,516 1,695 1,821
NC........................ 2727 4 MARSHALL.................... 20,093,891 2,224,006 1,630 1,723
NC........................ 6250 1A MAYO........................ 16,130,087 1,687,954 1,309 1,307
NC........................ 6250 1B MAYO........................ 9,275,573 970,654 753 752
NC........................ 50555 CT__ary PANDA--ROSEMARY............. 1,775,698 208,906 144 162
NC........................ 50555 CW__ary PANDA--ROSEMARY............. 875,010 102,942 71 80
NC........................ 2732 10 RIVERBEND................... 2,853,031 279,134 232 216
NC........................ 2732 7 RIVERBEND................... 2,152,165 193,836 175 150
NC........................ 2732 8 RIVERBEND................... 2,040,229 182,228 166 141
NC........................ 2732 9 RIVERBEND................... 2,739,141 264,243 222 205
NC........................ 2712 1 ROXBORO..................... 9,164,977 989,311 744 766
NC........................ 2712 2 ROXBORO..................... 18,766,344 2,004,737 1,523 1,553
NC........................ 2712 3A ROXBORO..................... 10,378,439 1,094,195 842 847
NC........................ 2712 3B ROXBORO..................... 10,143,786 1,069,456 823 828
NC........................ 2712 4A ROXBORO..................... 9,067,144 957,460 736 742
NC........................ 2712 4B ROXBORO..................... 9,124,169 963,481 740 746
NC........................ 50509 CW__INC TEXASGULF INC............... 674,329 60,750 55 47
[[Page 56369]]
NC........................ 50221 ST__lle TOBACCOVILLE................ 1,159,307 109,369 94 85
NC........................ 54276 ST__ill UNC--CHAPEL HILL............ 180,339 17,013 15 13
NC........................ 2716 1 W H WEATHERSPOON............ 708,133 68,090 57 53
NC........................ 2716 2 W H WEATHERSPOON............ 839,668 80,737 68 63
NC........................ 2716 3 W H WEATHERSPOON............ 1,840,705 177,674 149 138
NJ........................ 2378 1 B L ENGLAND................. 4,173,971 421,613 391 382
NJ........................ 2378 2 B L ENGLAND................. 4,925,509 497,526 461 451
NJ........................ 2378 3 B L ENGLAND................. 897,904 87,175 84 79
NJ........................ 2397 1 BAYONNE..................... 70,640 4,957 7 4
NJ........................ 2397 2 BAYONNE..................... 70,640 4,957 7 4
NJ........................ 2399 105 BURLINGTON.................. 828,394 74,630 78 68
NJ........................ 2399 7 BURLINGTON.................. 205,362 20,243 19 18
NJ........................ 10566 ST__NUG CCLP NUG................... 5,949,938 561,315 557 509
NJ........................ 50006 CT__DEN COGEN TECH--LINDEN.......... 6,506,951 765,524 609 694
NJ........................ 50006 CW__DEN COGEN TECH--LINDEN.......... 4,254,517 500,531 398 454
NJ........................ 5083 --GT1 CUMBERLAND.................. 160,902 12,190 15 11
NJ........................ 2384 1 DEEPWATER................... 494,926 46,691 46 42
NJ........................ 2384 4 DEEPWATER................... 4,528 427 0 0
NJ........................ 2384 6 DEEPWATER................... 487,149 45,957 46 42
NJ........................ 2384 8 DEEPWATER................... 2,233,052 216,801 209 196
NJ........................ 2400 1-4A EDISON...................... 70,640 4,957 7 4
NJ........................ 2400 1-4B EDISON...................... 70,640 5,352 7 5
NJ........................ 2400 2-1A EDISON...................... 70,640 5,352 7 5
NJ........................ 2400 2-1B EDISON...................... 70,640 5,352 7 5
NJ........................ 2400 2-2A EDISON...................... 70,640 5,352 7 5
NJ........................ 2400 2-2B EDISON...................... 70,640 5,352 7 5
NJ........................ 2400 2-3A EDISON...................... 70,640 5,352 7 5
NJ........................ 2400 2-3B EDISON...................... 70,640 5,352 7 5
NJ........................ 2400 2-4A EDISON...................... 70,640 5,352 7 5
NJ........................ 2400 2-4B EDISON...................... 70,640 5,352 7 5
NJ........................ 2400 3-1A EDISON...................... 70,640 5,352 7 5
NJ........................ 7138 --1 FORKED RIVER................ 65,107 4,569 6 4
NJ........................ 7138 --2 FORKED RIVER................ 65,107 4,569 6 4
NJ........................ 2393 03 GILBERT..................... 549,971 51,884 51 47
NJ........................ 2393 04 GILBERT..................... 725,741 71,827 68 65
NJ........................ 2393 05 GILBERT..................... 718,266 71,087 67 64
NJ........................ 2393 06 GILBERT..................... 712,321 70,499 67 64
NJ........................ 2393 07 GILBERT..................... 693,803 68,666 65 62
NJ........................ 2393 --4 GILBERT..................... 624,436 56,256 58 51
NJ........................ 2393 --5 GILBERT..................... 624,436 56,256 58 51
NJ........................ 2393 --6 GILBERT..................... 649,956 58,555 61 53
NJ........................ 2393 --7 GILBERT..................... 624,436 56,256 58 51
NJ........................ 2393 CT GILBERT..................... 149,451 11,322 14 10
NJ........................ 2393 CT GILBERT..................... 149,451 11,322 14 10
NJ........................ 2403 1 HUDSON...................... 2,064,525 196,921 193 178
NJ........................ 2403 2 HUDSON...................... 10,284,116 1,082,994 963 981
NJ........................ n111 ST__NUG KCS NUG.................. 5,251,399 495,415 492 449
NJ........................ 2404 7 KEARNY...................... 254,120 25,185 24 23
NJ........................ 2404 8 KEARNY...................... 137,711 13,734 13 12
NJ........................ 2406 11 LINDEN...................... 191,246 18,326 18 17
NJ........................ 2406 12 LINDEN...................... 129,348 12,394 12 11
NJ........................ 2406 13 LINDEN...................... 241,488 23,140 23 21
NJ........................ 2406 2 LINDEN...................... 413,906 40,977 39 37
NJ........................ 2408 1 MERCER...................... 4,742,300 501,406 444 454
NJ........................ 2408 2 MERCER...................... 5,329,094 588,850 499 534
NJ........................ n114 CT__NUG MOBIL NUG................ 472,302 42,550 44 39
NJ........................ 7140 CC NA 2--7140.................. 2,803,715 329,849 262 299
NJ........................ n115 GT__NUG PCLP NUG................. 191,525 14,509 18 13
NJ........................ 2390 07 SAYREVILLE.................. 475,112 40,990 44 37
NJ........................ 2390 08 SAYREVILLE.................. 566,046 47,257 53 43
NJ........................ 2411 1 SEWAREN..................... 356,963 32,179 33 29
NJ........................ 2411 2 SEWAREN..................... 346,637 29,119 32 26
NJ........................ 2411 3 SEWAREN..................... 663,913 61,857 62 56
NJ........................ 2411 4 SEWAREN..................... 972,633 94,165 91 85
NJ........................ n116 GT__1 SMECO....................... 138,720 10,509 13 10
NJ........................ 54807 GT__NUG VINELAND VCLP NUG........ 76,754 5,815 7 5
NJ........................ 2385 04 WERNER...................... 165,304 15,595 15 14
NJ........................ ........... 1 ............................ 5,479,965 644,702 513 584
NY........................ 2503 114 59TH STREET................. 753,380 60,415 57 45
NY........................ 2503 115 59TH STREET................. 611,825 49,064 46 37
NY........................ 2503 GT1 59TH STREET................. 9,250 649 1 0
NY........................ 2504 120 74TH STREET................. 649,914 63,344 49 48
NY........................ 2504 121 74TH STREET................. 1,092,255 106,458 82 80
NY........................ 2504 122 74TH STREET................. 1,094,077 106,635 82 80
NY........................ 2504 GT1 74TH STREET................. 50 4 0 0
NY........................ 2504 GT2 74TH STREET................. 50 4 0 0
[[Page 56370]]
NY........................ 2539 1 ALBANY...................... 873,788 84,018 66 63
NY........................ 2539 2 ALBANY...................... 1,226,877 117,969 92 89
NY........................ 2539 3 ALBANY...................... 1,440,506 138,510 109 104
NY........................ 2539 4 ALBANY...................... 733,021 70,483 55 53
NY........................ n120 1 AMERICAN BRASS.............. 1,400,238 126,148 105 95
NY........................ n121 1 ANITEC...................... 752,975 52,840 57 40
NY........................ 2490 20 ARTHUR KILL................. 7,458,261 803,952 562 604
NY........................ 2490 30 ARTHUR KILL................. 5,212,390 582,325 393 438
NY........................ 2490 GT1 ARTHUR KILL................. 12,450 874 1 1
NY........................ 8906 40 ASTORIA..................... 8,441,166 887,050 636 667
NY........................ 8906 50 ASTORIA..................... 8,377,051 830,809 631 624
NY........................ 8906 GT1 ASTORIA..................... 29,250 2,053 2 2
NY........................ 8906 GT10 ASTORIA..................... 20,800 1,460 2 1
NY........................ 8906 GT11 ASTORIA..................... 20,800 1,460 2 1
NY........................ 8906 GT12 ASTORIA..................... 20,750 1,456 2 1
NY........................ 8906 GT13 ASTORIA..................... 20,750 1,456 2 1
NY........................ 8906 GT2-1 ASTORIA..................... 138,200 9,698 10 7
NY........................ 8906 GT2-2 ASTORIA..................... 138,200 9,698 10 7
NY........................ 8906 GT2-3 ASTORIA..................... 138,200 9,698 10 7
NY........................ 8906 GT2-4 ASTORIA..................... 138,150 9,695 10 7
NY........................ 8906 GT3-1 ASTORIA..................... 138,150 9,695 10 7
NY........................ 8906 GT3-2 ASTORIA..................... 138,150 9,695 10 7
NY........................ 8906 GT3-3 ASTORIA..................... 138,150 9,695 10 7
NY........................ 8906 GT3-4 ASTORIA..................... 138,150 9,695 10 7
NY........................ 8906 GT4-1 ASTORIA..................... 138,150 9,695 10 7
NY........................ 8906 GT4-2 ASTORIA..................... 138,150 9,695 10 7
NY........................ 8906 GT4-3 ASTORIA..................... 138,150 9,695 10 7
NY........................ 8906 GT4-4 ASTORIA..................... 138,150 9,695 10 7
NY........................ 8906 GT5 ASTORIA..................... 20,850 1,463 2 1
NY........................ 8906 GT7 ASTORIA..................... 20,850 1,463 2 1
NY........................ 8906 GT8 ASTORIA..................... 20,850 1,463 2 1
NY........................ 8906 GT9 ASTORIA..................... 20,850 1,463 2 1
NY........................ 2625 1 BOWLINE POINT............... 11,471,865 1,188,179 864 893
NY........................ 2625 2 BOWLINE POINT............... 5,071,722 502,101 382 377
NY........................ 25496 3 C R HUNTLEY................. 1,720,724 165,454 130 124
NY........................ 25496 4 C R HUNTLEY................. 1,980,448 190,428 149 143
NY........................ 25496 5 C R HUNTLEY................. 2,127,327 204,551 160 154
NY........................ 25496 6 C R HUNTLEY................. 2,109,123 202,800 159 152
NY........................ 25496 7 C R HUNTLEY................. 6,327,954 608,457 477 457
NY........................ 25496 8 C R HUNTLEY................. 6,424,113 617,703 484 464
NY........................ 10190 1 CETI FORT ORANGE............ 1,359,587 122,485 102 92
NY........................ 2491 001 CHARLES POLETTI............. 13,671,196 1,393,882 1,030 1,047
NY........................ 2480 1 DANSKAMMER.................. 386,587 36,471 29 27
NY........................ 2480 2 DANSKAMMER.................. 662,648 62,514 50 47
NY........................ 2480 3 DANSKAMMER.................. 3,748,001 360,385 282 271
NY........................ 2480 4 DANSKAMMER.................. 5,975,388 574,557 450 432
NY........................ 2554 1 DUNKIRK..................... 3,158,348 303,687 238 228
NY........................ 2554 2 DUNKIRK..................... 2,827,332 271,859 213 204
NY........................ 2554 3 DUNKIRK..................... 4,429,898 425,952 334 320
NY........................ 2554 4 DUNKIRK..................... 5,327,881 512,296 401 385
NY........................ 2511 10 E F BARRETT................. 4,766,731 458,340 359 344
NY........................ 2511 20 E F BARRETT................. 4,804,972 462,017 362 347
NY........................ 2493 50 EAST RIVER.................. 2,946,262 277,949 222 209
NY........................ 2493 60 EAST RIVER.................. 3,398,132 295,130 256 222
NY........................ 2493 70 EAST RIVER.................. 1,571,481 157,970 118 119
NY........................ n130 1 ENRGY INIT-ONDGA............ 1,293,731 116,552 97 88
NY........................ 2513 40 FAR ROCKAWAY................ 2,213,857 208,854 167 157
NY........................ 10464 1 FORT DRUM................... 1,333,783 125,829 100 95
NY........................ n132 1 GAS ALTERNATIVES............ 1,160,279 104,530 87 79
NY........................ 2514 40 GLENWOOD.................... 2,406,229 227,003 181 171
NY........................ 2514 50 GLENWOOD.................... 1,862,067 175,667 140 132
NY........................ 2526 13 GOUDEY...................... 2,958,418 304,615 223 229
NY........................ ........... GT1-1 GOWANUS..................... 35,825 2,514 3 2
NY........................ ........... GT1-2 GOWANUS..................... 35,825 2,514 3 2
NY........................ ........... GT1-3 GOWANUS..................... 35,825 2,514 3 2
NY........................ ........... GT1-4 GOWANUS..................... 35,825 2,514 3 2
NY........................ ........... GT1-5 GOWANUS..................... 35,825 2,514 3 2
NY........................ ........... GT1-6 GOWANUS..................... 35,825 2,514 3 2
NY........................ ........... GT1-7 GOWANUS..................... 35,825 2,514 3 2
NY........................ ........... GT1-8 GOWANUS..................... 35,825 2,514 3 2
NY........................ ........... GT2-1 GOWANUS..................... 35,875 2,518 3 2
NY........................ ........... GT2-2 GOWANUS..................... 35,875 2,518 3 2
NY........................ ........... GT2-3 GOWANUS..................... 35,825 2,514 3 2
NY........................ ........... GT2-4 GOWANUS..................... 35,875 2,518 3 2
NY........................ ........... GT2-5 GOWANUS..................... 35,875 2,518 3 2
NY........................ ........... GT2-6 GOWANUS..................... 35,875 2,518 3 2
[[Page 56371]]
NY........................ ........... GT2-7 GOWANUS..................... 35,875 2,518 3 2
NY........................ ........... GT2-8 GOWANUS..................... 35,875 2,518 3 2
NY........................ ........... GT3-1 GOWANUS..................... 35,825 2,514 3 2
NY........................ ........... GT3-2 GOWANUS..................... 35,825 2,514 3 2
NY........................ ........... GT3-3 GOWANUS..................... 35,825 2,514 3 2
NY........................ ........... GT3-4 GOWANUS..................... 35,825 2,514 3 2
NY........................ ........... GT3-5 GOWANUS..................... 35,825 2,514 3 2
NY........................ ........... GT3-6 GOWANUS..................... 35,825 2,514 3 2
NY........................ ........... GT3-7 GOWANUS..................... 35,825 2,514 3 2
NY........................ ........... GT3-8 GOWANUS..................... 35,825 2,514 3 2
NY........................ ........... GT4-1 GOWANUS..................... 35,825 2,514 3 2
NY........................ ........... GT4-2 GOWANUS..................... 35,825 2,514 3 2
NY........................ ........... GT4-3 GOWANUS..................... 35,825 2,514 3 2
NY........................ ........... GT4-4 GOWANUS..................... 35,825 2,514 3 2
NY........................ ........... GT4-5 GOWANUS..................... 35,825 2,514 3 2
NY........................ ........... GT4-6 GOWANUS..................... 35,825 2,514 3 2
NY........................ ........... GT4-7 GOWANUS..................... 35,825 2,514 3 2
NY........................ ........... GT4-8 GOWANUS..................... 35,825 2,514 3 2
NY........................ 2527 4 GREENIDGE................... 97,546 9,379 7 7
NY........................ 2527 5 GREENIDGE................... 91,780 8,825 7 7
NY........................ 2527 6 GREENIDGE................... 2,929,270 305,450 221 230
NY........................ 2529 3 HICKLING.................... 41,894 71,336 56 54
NY........................ 2529 4 HICKLING.................... 706,180 67,902 53 51
NY........................ 2496 100 HUDSON AVENUE............... 2,443,411 230,511 184 173
NY........................ 2496 71 HUDSON AVENUE............... 375,025 26,318 28 20
NY........................ 2496 72 HUDSON AVENUE............... 375,025 26,318 28 20
NY........................ 2496 81 HUDSON AVENUE............... 375,025 26,318 28 20
NY........................ 2496 82 HUDSON AVENUE............... 375,025 26,318 28 20
NY........................ 2496 GT1 HUDSON AVENUE............... 12,700 891 1 1
NY........................ 2496 GT2 HUDSON AVENUE............... 12,800 898 1 1
NY........................ 2496 GT3 HUDSON AVENUE............... 12,700 891 1 1
NY........................ 54076 1 INDECK--OLEAN............... 885,587 79,783 67 60
NY........................ 50450 1 INDECK--OSWEGO.............. 1,122,189 101,098 85 76
NY........................ 50451 6 INDECK/YERKES............... 749,551 67,527 56 51
NY........................ 50459 1 INDECK-ILION................ 546,152 49,203 41 37
NY........................ 50449 CT__SPR INDECK-SILVER SPR........... 1,096,720 98,804 83 74
NY........................ 50449 CW__SPR INDECK-SILVER SPR........... 200,548 18,067 15 14
NY........................ ........... GT1 INDIAN POINT................ 21,100 1,481 2 1
NY........................ ........... GT2 INDIAN POINT................ 21,100 1,481 2 1
NY........................ ........... GT3 INDIAN POINT................ 27,150 1,905 2 1
NY........................ 2531 1 JENNISON.................... 243,674 23,430 18 18
NY........................ 2531 2 JENNISON.................... 250,674 24,103 19 18
NY........................ 2531 3 JENNISON.................... 346,396 33,307 26 25
NY........................ 2531 4 JENNISON.................... 363,717 34,973 27 26
NY........................ n14 3CC__IRK JMC-SELKIRK................. 1,224,755 110,338 92 83
NY........................ 10620 1 KAMINE-CARTHAGE............. 928,270 83,628 70 63
NY........................ n145 1 KAMINE-GOUVNR............... 307,042 27,661 23 21
NY........................ 10618 1 KAMINE-S GLENS FL........... 920,156 82,897 69 62
NY........................ 6082 1 KINTIGH..................... 19,171,661 2,086,598 1,444 1,568
NY........................ n147 1 L.C.P. CHEMICAL............. 554,080 49,917 42 38
NY........................ 54041 CT__PR LOCKPORT COGEN PR........... 1,595,458 187,701 120 141
NY........................ 54041 CW__PR LOCKPORT COGEN PR........... 1,228,525 144,532 93 109
NY........................ 2629 3 LOVETT...................... 1,042,213 108,169 79 81
NY........................ 2629 4 LOVETT...................... 5,081,891 521,808 383 392
NY........................ 2629 5 LOVETT...................... 5,821,325 536,725 439 403
NY........................ 54592 1 MASSENA ENRG FAC............ 1,820,093 214,129 137 161
NY........................ 2535 1 MILLIKEN.................... 4,379,423 458,290 330 344
NY........................ 2535 2 MILLIKEN.................... 4,980,801 526,734 375 396
NY........................ n155 1 MRA CANTON.................. 965,559 86,987 73 65
NY........................ ........... GT1-1 NARROWS..................... 104,875 7,360 8 6
NY........................ ........... GT1-2 NARROWS..................... 104,875 7,360 8 6
NY........................ ........... GT1-3 NARROWS..................... 104,875 7,360 8 6
NY........................ ........... GT1-4 NARROWS..................... 104,925 7,363 8 6
NY........................ ........... GT1-5 NARROWS..................... 104,925 7,363 8 6
NY........................ ........... GT1-6 NARROWS..................... 104,925 7,363 8 6
NY........................ ........... GT1-7 NARROWS..................... 104,925 7,363 8 6
NY........................ ........... GT1-8 NARROWS..................... 104,925 7,363 8 6
NY........................ ........... GT2-1 NARROWS..................... 104,925 7,363 8 6
NY........................ ........... GT2-2 NARROWS..................... 104,925 7,363 8 6
NY........................ ........... GT2-3 NARROWS..................... 104,925 7,363 8 6
NY........................ ........... GT2-4 NARROWS..................... 104,925 7,363 8 6
NY........................ ........... GT2-5 NARROWS..................... 104,925 7,363 8 6
NY........................ ........... GT2-6 NARROWS..................... 104,925 7,363 8 6
NY........................ ........... GT2-7 NARROWS..................... 104,925 7,363 8 6
NY........................ ........... GT2-8 NARROWS..................... 104,925 7,363 8 6
NY........................ n156 1 NESTLES..................... 1,061,226 95,606 80 72
[[Page 56372]]
NY........................ 2516 1 NORTHPORT................... 4,203,823 396,587 317 298
NY........................ 2516 2 NORTHPORT................... 8,438,205 796,057 636 598
NY........................ 2516 3 NORTHPORT................... 4,214,290 397,575 317 299
NY........................ 2516 4 NORTHPORT................... 9,740,685 918,933 734 691
NY........................ 2594 3 OSWEGO...................... 14,034,179 1,403,418 1,057 1,055
NY........................ 2594 6 OSWEGO...................... 2,119,991 211,999 160 159
NY........................ 54131 1 OXBOW/OCCIDENTAL............ 975,327 87,867 73 66
NY........................ 2517 3 PORT JEFFERSON.............. 3,801,379 365,517 286 275
NY........................ 2517 4 PORT JEFFERSON.............. 3,522,971 338,747 265 255
NY........................ 2500 10 RAVENSWOOD.................. 4,996,240 507,696 376 382
NY........................ 2500 20 RAVENSWOOD.................. 6,076,960 642,521 458 483
NY........................ 2500 30 RAVENSWOOD.................. 18,214,290 1,965,076 1,372 1,477
NY........................ 2500 A1 RAVENSWOOD.................. 184,113 12,920 14 10
NY........................ 2500 A2 RAVENSWOOD.................. 184,113 12,920 14 10
NY........................ 2500 A3 RAVENSWOOD.................. 184,113 12,920 14 10
NY........................ 2500 A4 RAVENSWOOD.................. 184,113 12,920 14 10
NY........................ 2500 GT1 RAVENSWOOD.................. 50 4 0 0
NY........................ 2500 GT10 RAVENSWOOD.................. 24,450 1,716 2 1
NY........................ 2500 GT11 RAVENSWOOD.................. 24,450 1,716 2 1
NY........................ 2500 GT2-1 RAVENSWOOD.................. 49,450 3,470 4 3
NY........................ 2500 GT2-2 RAVENSWOOD.................. 49,450 3,470 4 3
NY........................ 2500 GT2-3 RAVENSWOOD.................. 49,450 3,470 4 3
NY........................ 2500 GT2-4 RAVENSWOOD.................. 49,450 3,470 4 3
NY........................ 2500 GT3-1 RAVENSWOOD.................. 49,425 3,468 4 3
NY........................ 2500 GT3-2 RAVENSWOOD.................. 49,425 3,468 4 3
NY........................ 2500 GT3-3 RAVENSWOOD.................. 49,425 3,468 4 3
NY........................ 2500 GT3-4 RAVENSWOOD.................. 49,425 3,468 4 3
NY........................ 2500 GT4 RAVENSWOOD.................. 10,400 730 1 1
NY........................ 2500 GT5 RAVENSWOOD.................. 10,400 730 1 1
NY........................ 2500 GT6 RAVENSWOOD.................. 12,650 888 1 1
NY........................ 2500 GT7 RAVENSWOOD.................. 12,650 888 1 1
NY........................ 2500 GT8 RAVENSWOOD.................. 24,500 1,719 2 1
NY........................ 2500 GT9 RAVENSWOOD.................. 24,450 1,716 2 1
NY........................ n163 CC__PRO RENNSLR COGEN PRO........... 768,893 69,270 58 52
NY........................ 7314 NA1 RICHARD M FLYNN............. 3,984,856 468,807 300 352
NY........................ 7314 NA2 RICHARD M FLYNN............. 416,190 37,495 31 28
NY........................ 2640 12 ROCHESTER 3................. 1,829,750 194,571 138 146
NY........................ 2642 1 ROCHESTER 7................. 1,068,791 102,768 81 77
NY........................ 2642 2 ROCHESTER 7................. 1,565,479 150,166 118 113
NY........................ 2642 3 ROCHESTER 7................. 1,706,369 165,186 129 124
NY........................ 2642 4 ROCHESTER 7................. 2,105,925 224,728 159 169
NY........................ 8006 2 ROSETON..................... 8,971,513 897,151 676 674
NY........................ 50651 1 SALT CITY ENERGY............ 2,992,250 282,288 225 212
NY........................ 54574 1 SARANAC ENERGY CO........... 2,702,186 317,904 204 239
NY........................ 54574 2 SARANAC ENERGY CO........... 2,200,892 258,928 166 195
NY........................ 10725 2 SELKIRK..................... 2,527,299 297,329 190 223
NY........................ 10725 3 SELKIRK..................... 2,350,443 276,523 177 208
NY........................ 54593 1 SENECA PWR (OATKA).......... 1,238,728 111,597 93 84
NY........................ n170 1 SITHE GT 1.................. 4,163,470 489,820 314 368
NY........................ n171 2 SITHE GT 2.................. 4,163,470 489,820 314 368
NY........................ n172 1 SITHE STM 1................. 4,351,465 511,937 328 385
NY........................ n173 2 SITHE STM 2................. 4,351,465 511,937 328 385
NY........................ 50744 1 STERLING POWR LTD........... 876,658 66,413 66 50
NY........................ 50292 1A TBG-GRUMMAN................. 638,783 57,548 48 43
NY........................ 52056 4 TRIGEN-NDEC................. 1,038,844 98,004 78 74
NY........................ 50202 1 UDG/NIAGARA................. 1,432,269 135,120 108 102
NY........................ n182 CT__V.) US GEN (OLD RIV.)........... 1,572,572 141,673 118 106
NY........................ 7146 1 WADING RIVER................ 148,605 11,258 11 8
NY........................ 7146 2 WADING RIVER................ 148,605 11,258 11 8
NY........................ 7146 3 WADING RIVER................ 148,605 11,258 11 8
NY........................ 2502 51 WATERSIDE................... 47,565 4,487 4 3
NY........................ 2502 52 WATERSIDE................... 48,589 4,584 4 3
NY........................ 2502 61 WATERSIDE................... 1,173,263 110,685 88 83
NY........................ 2502 62 WATERSIDE................... 1,248,953 117,826 94 89
NY........................ 2502 80 WATERSIDE................... 3,482,508 328,538 262 247
NY........................ 2502 90 WATERSIDE................... 3,482,508 328,538 262 247
NY........................ 2502 GT1 WATERSIDE................... 0 0 0 0
NY........................ 50405 CT__SSE YORK WARBASSE............... 213,063 19,195 16 14
NY........................ 50405 CW__SSE YORK-WARBASSE............... 37,622 3,389 3 3
OH........................ 2835 10 ASHTABULA................... 1,098,131 85,718 79 59
OH........................ 2835 11 ASHTABULA................... 1,176,319 91,821 85 64
OH........................ 2835 7 ASHTABULA................... 4,550,476 470,236 329 325
OH........................ 2835 8 ASHTABULA................... 1,018,961 79,538 74 55
OH........................ 2835 9 ASHTABULA................... 960,698 74,990 70 52
OH........................ 2836 10 AVON LAKE................... 2,038,597 177,563 148 123
OH........................ 2836 12 AVON LAKE................... 15,236,399 1,676,540 1,103 1,160
[[Page 56373]]
OH........................ 2836 9 AVON LAKE................... 594,325 50,508 43 35
OH........................ 2878 1 BAY SHORE................... 3,043,524 328,887 220 228
OH........................ 2878 2 BAY SHORE................... 3,293,657 348,240 238 241
OH........................ 2878 3 BAY SHORE................... 3,102,716 335,465 225 232
OH........................ 2878 4 BAY SHORE................... 4,399,348 483,339 318 334
OH........................ 2828 1 CARDINAL.................... 14,226,732 1,607,540 1,030 1,112
OH........................ 2828 2 CARDINAL.................... 15,856,794 1,785,072 1,147 1,235
OH........................ 2828 3 CARDINAL.................... 15,180,469 1,564,191 1,099 1,082
OH........................ 2840 1 CONESVILLE.................. 2,771,211 263,473 201 182
OH........................ 2840 2 CONESVILLE.................. 2,969,788 290,671 215 201
OH........................ 2840 3 CONESVILLE.................. 2,549,626 247,081 185 171
OH........................ 2840 4 CONESVILLE.................. 14,758,742 1,565,250 1,068 1,083
OH........................ 2840 5 CONESVILLE.................. 8,165,942 810,676 591 561
OH........................ 2840 6 CONESVILLE.................. 10,207,769 987,307 739 683
OH........................ 1 DICKS CREEK................. 103,267 7,247 7 5
OH........................ 2837 1 EASTLAKE.................... 2,765,418 276,791 200 191
OH........................ 2837 2 EASTLAKE.................... 3,040,161 314,651 220 218
OH........................ 2837 3 EASTLAKE.................... 3,168,531 333,109 229 230
OH........................ 2837 4 EASTLAKE.................... 5,169,221 547,355 374 379
OH........................ 2837 5 EASTLAKE.................... 12,045,077 1,346,119 872 931
OH........................ 2857 13 EDGEWATER................... 489,049 46,589 35 32
OH........................ 2847 GT3 FRANK M TAIT................ 161,909 12,266 12 8
OH........................ 8102 1 GEN J M GAVIN............... 40,188,042 4,171,047 2,908 2,885
OH........................ 8102 2 GEN J M GAVIN............... 41,834,670 4,421,802 3,027 3,059
OH........................ 2917 9 HAMILTON.................... 1,207,309 97,797 87 68
OH........................ 2850 1 J M STUART.................. 14,907,495 1,589,116 1,079 1,099
OH........................ 2850 2 J M STUART.................. 17,977,541 1,962,185 1,301 1,357
OH........................ 2850 3 J M STUART.................. 15,142,093 1,616,018 1,096 1,118
OH........................ 2850 4 J M STUART.................. 15,822,987 1,703,411 1,145 1,178
OH........................ 6031 2 KILLEN STATION.............. 23,914,733 2,561,287 1,731 1,772
OH........................ 2876 1 KYGER CREEK................. 6,892,031 755,374 499 523
OH........................ 2876 2 KYGER CREEK................. 6,891,443 745,101 499 515
OH........................ 2876 3 KYGER CREEK................. 7,001,472 750,104 507 519
OH........................ 2876 4 KYGER CREEK................. 6,391,704 681,782 463 472
OH........................ 2876 5 KYGER CREEK................. 6,661,287 717,811 482 497
OH........................ 2838 18 LAKE SHORE.................. 2,044,475 216,989 148 150
OH........................ 10244 1 MEAD-FINE PAPER DIVISION.... 3,264,035 247,275 236 171
OH........................ 2832 5-1 MIAMI FORT.................. 238,988 22,980 17 16
OH........................ 2832 5-2 MIAMI FORT.................. 238,988 22,980 17 16
OH........................ 2832 6 MIAMI FORT.................. 4,348,442 461,863 315 320
OH........................ 2832 7 MIAMI FORT.................. 15,289,678 1,545,349 1,106 1,069
OH........................ 2832 8 MIAMI FORT.................. 14,621,880 1,508,810 1,058 1,044
OH........................ 2832 CT2 MIAMI FORT.................. 19,021 1,441 1 1
OH........................ 2872 1 MUSKINGUM RIVER............. 3,945,004 417,549 285 289
OH........................ 2872 2 MUSKINGUM RIVER............. 4,618,739 491,198 334 340
OH........................ 2872 3 MUSKINGUM RIVER............. 4,491,616 466,225 325 323
OH........................ 2872 4 MUSKINGUM RIVER............. 4,911,646 537,379 355 372
OH........................ 2872 5 MUSKINGUM RIVER............. 16,181,850 1,783,517 1,171 1,234
OH........................ 2861 1 NILES....................... 3,039,955 293,772 220 203
OH........................ 2861 2 NILES....................... 1,890,626 184,631 137 128
OH........................ 2848 H-1 O H HUTCHINGS............... 274,817 22,229 20 15
OH........................ 2848 H-2 O H HUTCHINGS............... 349,295 28,472 25 20
OH........................ 2848 H-3 O H HUTCHINGS............... 794,644 77,731 58 54
OH........................ 2848 H-4 O H HUTCHINGS............... 782,165 76,160 57 53
OH........................ 2848 H-5 O H HUTCHINGS............... 810,661 80,735 59 56
OH........................ 2848 H-6 O H HUTCHINGS............... 833,389 80,653 60 56
OH........................ 2935 13 ORRVILLE.................... 864,346 62,103 63 43
OH........................ 2843 9 PICWAY...................... 2,044,023 184,495 148 128
OH........................ 2864 1 R E BURGER.................. 167,575 16,113 12 11
OH........................ 2864 2 R E BURGER.................. 142,969 13,747 10 10
OH........................ 2864 3 R E BURGER.................. 122,673 11,795 9 8
OH........................ 2864 4 R E BURGER.................. 50,113 4,819 4 3
OH........................ 2864 5 R E BURGER.................. 202,074 19,430 15 13
OH........................ 2864 6 R E BURGER.................. 193,661 18,621 14 13
OH........................ 2864 7 R E BURGER.................. 4,456,156 418,890 322 290
OH........................ 2864 8 R E BURGER.................. 4,017,193 381,102 291 264
OH........................ 7286 1 RICHARD GORSUCH............. 2,135,351 192,652 155 133
OH........................ 7286 2 RICHARD GORSUCH............. 1,854,152 178,284 134 123
OH........................ 7286 3 RICHARD GORSUCH............. 2,050,742 185,235 148 128
OH........................ 7286 4 RICHARD GORSUCH............. 2,045,416 196,675 148 136
OH........................ 2866 1 W H SAMMIS.................. 5,405,594 563,611 391 390
OH........................ 2866 2 W H SAMMIS.................. 5,662,986 567,206 410 392
OH........................ 2866 3 W H SAMMIS.................. 5,855,268 619,343 424 428
OH........................ 2866 4 W H SAMMIS.................. 5,314,213 537,386 385 372
OH........................ 2866 5 W H SAMMIS.................. 9,236,018 962,286 668 666
OH........................ 2866 6 W H SAMMIS.................. 17,880,061 1,901,325 1,294 1,315
[[Page 56374]]
OH........................ 2866 7 W H SAMMIS.................. 16,613,419 1,749,333 1,202 1,210
OH........................ 6019 1 W H ZIMMER.................. 42,732,125 4,487,726 3,092 3,105
OH........................ 2830 1 WALTER C BECKJORD........... 1,981,394 193,118 143 134
OH........................ 2830 2 WALTER C BECKJORD........... 2,504,459 255,401 181 177
OH........................ 2830 4 WALTER C BECKJORD........... 4,487,860 483,085 325 334
OH........................ 2830 5 WALTER C BECKJORD........... 6,320,856 656,099 457 454
OH........................ 2830 6 WALTER C BECKJORD........... 12,195,684 1,259,885 883 872
OH........................ 2830 CT1 WALTER C BECKJORD........... 48,631 3,413 4 2
OH........................ 2830 CT2 WALTER C BECKJORD........... 48,892 3,431 4 2
OH........................ 2830 CT3 WALTER C BECKJORD........... 52,763 3,703 4 3
OH........................ 2830 CT4 WALTER C BECKJORD........... 34,330 2,409 2 2
OH........................ 7158 --GT1 WOODSDALE................... 356,991 28,457 26 20
OH........................ 7158 --GT2 WOODSDALE................... 350,509 27,940 25 19
OH........................ 7158 --GT3 WOODSDALE................... 388,436 30,963 28 21
OH........................ 7158 --GT4 WOODSDALE................... 367,016 29,256 27 20
OH........................ 7158 --GT5 WOODSDALE................... 404,361 32,233 29 22
OH........................ 7158 --GT6 WOODSDALE................... 395,892 31,558 29 22
PA........................ 10676 ST__ley AES BEAVER VALLEY........... 3,421,790 322,810 274 253
PA........................ 50279 1 ARCHBALD POWER.............. 1,408,480 98,841 113 78
PA........................ 3178 1 ARMSTRONG................... 4,811,406 473,937 386 372
PA........................ 3178 2 ARMSTRONG................... 5,037,239 536,276 404 421
PA........................ 6094 1 BRUCE MANSFIELD............. 21,390,698 2,166,585 1,716 1,700
PA........................ 6094 2 BRUCE MANSFIELD............. 21,064,812 2,148,813 1,690 1,686
PA........................ 6094 3 BRUCE MANSFIELD............. 21,549,874 2,305,292 1,728 1,808
PA........................ 3140 1 BRUNNER ISLAND.............. 7,419,682 794,994 595 624
PA........................ 3140 2 BRUNNER ISLAND.............. 9,670,357 1,068,784 776 838
PA........................ 3140 3 BRUNNER ISLAND.............. 20,738,335 2,283,455 1,663 1,791
PA........................ 10641 1 CAMBRIA COGEN............... 1,841,698 173,745 148 136
PA........................ 10641 2 CAMBRIA COGEN............... 1,883,698 177,707 151 139
PA........................ 8226 1 CHESWICK.................... 15,086,514 1,533,962 1,210 1,203
PA........................ 3118 1 CONEMAUGH................... 29,200,485 3,177,419 2,342 2,492
PA........................ 3118 2 CONEMAUGH................... 24,102,490 2,622,687 1,933 2,057
PA........................ 10870 CW__NUG CONTINENTAL COGEN NUG.... 882,161 103,784 71 81
PA........................ 3159 1 CROMBY...................... 4,546,839 439,223 365 345
PA........................ 3159 2 CROMBY...................... 2,065,179 209,302 166 164
PA........................ 3160 71 DELAWARE.................... 711,493 70,313 57 55
PA........................ 3160 81 DELAWARE.................... 753,207 64,598 60 51
PA........................ 10603 1 EBENSBURG POWER............. 2,195,697 211,125 176 166
PA........................ 3161 1 EDDYSTONE................... 7,618,327 758,798 611 595
PA........................ 3161 2 EDDYSTONE................... 8,533,347 859,783 684 674
PA........................ 3161 3 EDDYSTONE................... 1,611,083 148,173 129 116
PA........................ 3161 4 EDDYSTONE................... 2,093,154 189,804 168 149
PA........................ 3098 1 ELRAMA...................... 2,821,678 233,776 226 183
PA........................ 3098 2 ELRAMA...................... 2,355,589 191,247 189 150
PA........................ 3098 3 ELRAMA...................... 2,802,309 257,992 225 202
PA........................ 3098 4 ELRAMA...................... 5,460,730 520,764 438 408
PA........................ 10343 AB__NUG FOSTER WHEELER MT. CARMEL... 984,307 92,859 79 73
PA........................ 01011 AB__NUG GILBERTON POWER NUG...... 2,938,728 277,238 236 217
PA........................ 3110 1--3 GPT GENCO HUNTERSTOWN....... 0 0 0 0
PA........................ 3199 1--2 GPU GENCO BENTON............ 0 0 0 0
PA........................ 3109 1 GPU GENCO HAMILTON.......... 0 0 0 0
PA........................ 3111 1--2 GPU GENCO MOUNTAIN.......... 0 0 0 0
PA........................ 3112 1 GPU GENCO ORTANNA........... 0 0 0 0
PA........................ 3114 1 GPU GENCO SHAWNEE........... 0 0 0 0
PA........................ 3120 1 GPU GENCO TIOGA............. 0 0 0 0
PA........................ 3116 1--2 GPU GENCO TOLNA............. 0 0 0 0
PA........................ 3134 1 GPU GENCO WAYNE............. 0 0 0 0
PA........................ 54785 1--3 GRAYS FERRY PROJECT......... 0 0 0 0
PA........................ 3179 1 HATFIELD'S FERRY............ 15,310,890 1,600,888 1,228 1,256
PA........................ 3179 2 HATFIELD'S FERRY............ 19,368,646 2,104,144 1,553 1,651
PA........................ 3179 3 HATFIELD'S FERRY............ 14,202,486 1,547,617 1,139 1,214
PA........................ 3145 17 HOLTWOOD.................... 3,106,258 246,665 249 193
PA........................ 3122 1 HOMER CITY.................. 19,827,390 2,093,927 1,590 1,643
PA........................ 3122 2 HOMER CITY.................. 20,699,247 2,187,156 1,660 1,716
PA........................ 3122 3 HOMER CITY.................. 18,602,194 1,901,482 1,492 1,492
PA........................ 3176 6 HUNLOCK PWR STATION......... 1,764,784 133,980 142 105
PA........................ 3136 1 KEYSTONE.................... 28,703,322 3,021,402 2,302 2,370
PA........................ 3136 2 KEYSTONE.................... 28,430,610 2,992,696 2,280 2,348
PA........................ 3157 10 KIMBERLY-CLARK.............. 0 0 0 0
PA........................ 3148 1 MARTINS CREEK............... 4,229,014 384,211 339 301
PA........................ 3148 2 MARTINS CREEK............... 3,949,723 360,804 317 283
PA........................ 3148 3 MARTINS CREEK............... 3,869,537 408,740 310 321
PA........................ 3148 4 MARTINS CREEK............... 4,010,953 425,475 322 334
PA........................ 52149 1 MERCK SHARP & DOHME......... 0 0 0 0
PA........................ 3181 1 MITCHELL.................... 75,203 7,095 6 6
PA........................ 3181 3 MITCHELL.................... 45,707 4,312 4 3
[[Page 56375]]
PA........................ 3181 33 MITCHELL.................... 5,833,720 592,436 468 465
PA........................ 3149 1 MONTOUR..................... 18,421,287 2,017,666 1,477 1,583
PA........................ 3149 2 MONTOUR..................... 21,572,636 2,426,345 1,730 1,903
PA........................ 3138 3 NEW CASTLE.................. 2,045,707 197,177 164 155
PA........................ 3138 4 NEW CASTLE.................. 2,265,637 211,485 182 166
PA........................ 3138 5 NEW CASTLE.................. 3,307,970 318,105 265 250
PA........................ 54571 CC__AB) NORCON(FALC SEAB)........... 1,087,345 97,959 87 77
PA........................ 50888 1 NORTHAMPTION GENERATING..... 2,906,127 274,163 233 215
PA........................ 50039 ............................. NORTHEASTERN POWER.......... 2,530,021 238,681 203 187
PA........................ 50776 1 PANTHER CREEK............... 1,158,239 109,268 93 86
PA........................ 50776 2 PANTHER CREEK............... 1,163,341 109,749 93 86
PA........................ 880008 1--2 PECO ENERGY................. 0 0 0 0
PA........................ 8012 11 PECO ENERGY CROYDEN......... 0 0 0 0
PA........................ 8012 12 PECO ENERGY CROYDEN......... 0 0 0 0
PA........................ 8012 21 PECO ENERGY CROYDEN......... 0 0 0 0
PA........................ 8012 22 PECO ENERGY CROYDEN......... 0 0 0 0
PA........................ 8012 31 PECO ENERGY CROYDEN......... 0 0 0 0
PA........................ 8012 32 PECO ENERGY CROYDEN......... 0 0 0 0
PA........................ 8012 41 PECO ENERGY CROYDEN......... 0 0 0 0
PA........................ 8012 42 PECO ENERGY CROYDEN......... 0 0 0 0
PA........................ 50731 3 PECO ENERGY FAIRLESS HILLS.. 0 0 0 0
PA........................ 3168 91 PECO ENERGY RICHMOND........ 0 0 0 0
PA........................ 3168 92 PECO ENERGY RICHMOND........ 0 0 0 0
PA........................ 3170 3--6 PECO ENERGY SOUTHWARK....... 0 0 0 0
PA........................ n218 CC__PER PENNTECH PAPER.............. 617,031 55,588 49 44
PA........................ 54144 1 PINEY CREEK................. 0 0 0 0
PA........................ 3113 1 PORTLAND.................... 3,585,481 337,870 288 265
PA........................ 3113 2 PORTLAND.................... 4,573,152 441,254 367 346
PA........................ 3113 4 PORTLAND.................... 1,570,979 184,821 126 145
PA........................ 3113 --5 PORTLAND.................... 150,505 11,402 12 9
PA........................ 3139 1--4 PP&L ALLENTOWN.............. 0 0 0 0
PA........................ 3142 1--2 PP&L FISHBACK............... 0 0 0 0
PA........................ 3143 1--4 PP&L HARRISBURG............. 0 0 0 0
PA........................ 3144 1--2 PP&L HARWOOD................ 0 0 0 0
PA........................ 3146 1--2 PP&L JENKINS................ 0 0 0 0
PA........................ 3154 1--2 PP&L WEST SHORE............. 0 0 0 0
PA........................ 3155 1--2 PP&L WILLIAMSPORT........... 0 0 0 0
PA........................ 3169 1 SCHUYLKILL.................. 1,025,090 97,721 82 77
PA........................ 880010 1 SCHUYLKILL ENERGY RESOURCES. 3,891,284 367,102 312 288
PA........................ 50607 AB__NUG SCHUYLKILL STATION (TURBI... 9,441,744 890,731 757 699
PA........................ 50974 1 SCRUBGRASS GENERATING PLANT. 2,730,403 257,585 219 202
PA........................ 50974 2 SCRUBGRASS GENERATING PLANT. 1,630,792 156,807 131 123
PA........................ 3130 12 SEWARD...................... 859,296 82,625 69 65
PA........................ 3130 14 SEWARD...................... 976,355 93,880 78 74
PA........................ 3130 15 SEWARD...................... 4,658,271 467,416 374 367
PA........................ 3131 1 SHAWVILLE................... 3,979,027 379,896 319 298
PA........................ 3131 2 SHAWVILLE................... 3,819,973 364,432 306 286
PA........................ 3131 3 SHAWVILLE................... 4,979,445 499,042 399 391
PA........................ 3131 4 SHAWVILLE................... 5,056,822 506,797 406 398
PA........................ 880013 1--6 SOLAR TURBINES.............. 0 0 0 0
PA........................ 3152 3 SUNBURY..................... 3,548,941 303,692 285 238
PA........................ 3152 4 SUNBURY..................... 3,884,437 372,394 312 292
PA........................ 3115 1 TITUS....................... 1,942,834 189,176 156 148
PA........................ 3115 2 TITUS....................... 2,007,778 193,018 161 151
PA........................ 3115 3 TITUS....................... 1,918,450 182,866 154 143
PA........................ 88000 6 1--4 TRIGEN ENERGY SANSOM........ 0 0 0 0
PA........................ ........... 1 VIKING ENERGY NORTHUMBERLAND 0 0 0 0
PA........................ 3132 1 WARREN...................... 576,001 55,385 46 43
PA........................ 3132 2 WARREN...................... 385,366 37,054 31 29
PA........................ 3132 3 WARREN...................... 543,134 44,208 44 35
PA........................ 3132 4 WARREN...................... 564,080 54,238 45 43
PA........................ 50867 1--2 WASHINGTON POWER COMPANY.... 0 0 0 0
PA........................ 50611 AB__NUG WESTWOOD ENERGY PROPERTIE... 12,527,355 879,113 1,005 690
PA........................ 50879 AB__NUG WHEELABRATOR FRACKVILLE E... 2,058,812 144,478 165 113
RI........................ ........... 1 JEPSON...................... 1,282 90 0 0
RI........................ ........... 2 JEPSON...................... 1,249 88 0 0
RI........................ ........... 3 JEPSON...................... 1,042 73 0 0
RI........................ ........... 4 JEPSON...................... 1,281 90 0 0
RI........................ 3236 10 MANCHESTER STREET........... 4,223,753 398,467 136 120
RI........................ 3236 11 MANCHESTER STREET........... 4,020,769 379,318 130 114
RI........................ 3236 9 MANCHESTER STREET........... 3,739,441 352,777 121 106
RI........................ 51030 CC__(*) OCEAN STATE 1 (*)........... 9,189,307 1,081,095 297 326
RI........................ 54324 CC__(*) OCEAN STATE 2 (*)........... 9,189,307 1,081,095 297 326
RI........................ 54056 CC__(*) PAWTUCKET POWER (*)......... 2,433,886 219,269 79 66
TN........................ 3393 1 ALLEN....................... 6,894,770 713,301 578 584
TN........................ 3393 2 ALLEN....................... 7,326,410 757,957 614 621
[[Page 56376]]
TN........................ 3393 3 ALLEN....................... 7,556,678 781,779 633 641
TN........................ 3396 1 BULL RUN.................... 21,275,985 2,389,755 1,783 1,958
TN........................ 3399 1 CUMBERLAND.................. 51,385,046 5,284,353 4,307 4,330
TN........................ 3399 2 CUMBERLAND.................. 55,332,549 5,690,307 4,637 4,662
TN........................ 3403 1 GALLATIN.................... 6,970,897 734,707 584 602
TN........................ 3403 2 GALLATIN.................... 6,860,771 723,100 575 592
TN........................ 3403 3 GALLATIN.................... 6,984,817 728,192 585 597
TN........................ 3403 4 GALLATIN.................... 7,834,299 816,753 657 669
TN........................ 3405 1 JOHN SEVIER................. 5,853,636 615,266 491 504
TN........................ 3405 2 JOHN SEVIER................. 5,858,042 615,729 491 504
TN........................ 3405 3 JOHN SEVIER................. 6,184,144 650,005 518 533
TN........................ 3405 4 JOHN SEVIER................. 6,114,293 642,663 512 527
TN........................ 3406 1 JOHNSONVILLE................ 3,724,159 323,840 312 265
TN........................ 3406 10 JOHNSONVILLE................ 3,681,387 351,412 309 288
TN........................ 3406 2 JOHNSONVILLE................ 3,749,100 326,009 314 267
TN........................ 3406 3 JOHNSONVILLE................ 3,666,648 318,839 307 261
TN........................ 3406 4 JOHNSONVILLE................ 3,679,462 319,953 308 262
TN........................ 3406 5 JOHNSONVILLE................ 3,640,648 322,753 305 264
TN........................ 3406 6 JOHNSONVILLE................ 3,719,286 329,724 312 270
TN........................ 3406 7 JOHNSONVILLE................ 4,680,922 446,823 392 366
TN........................ 3406 8 JOHNSONVILLE................ 4,133,749 394,592 346 323
TN........................ 3406 9 JOHNSONVILLE................ 4,006,336 382,430 336 313
TN........................ 3407 1 KINGSTON.................... 4,432,856 448,715 372 368
TN........................ 3407 2 KINGSTON.................... 4,515,371 457,068 378 374
TN........................ 3407 3 KINGSTON.................... 4,047,180 409,675 339 336
TN........................ 3407 4 KINGSTON.................... 4,494,642 454,969 377 373
TN........................ 3407 5 KINGSTON.................... 6,137,914 632,449 514 518
TN........................ 3407 6 KINGSTON.................... 5,842,656 602,025 490 493
TN........................ 3407 7 KINGSTON.................... 5,678,568 585,118 476 479
TN........................ 3407 8 KINGSTON.................... 5,801,972 597,833 486 490
TN........................ 3407 9 KINGSTON.................... 5,689,108 586,204 477 480
VA........................ 3796 3 BREMO BLUFF................. 1,756,163 158,241 163 143
VA........................ 3796 4 BREMO BLUFF................. 4,959,806 506,568 459 457
VA........................ 3803 1 CHESAPEAK................... 3,461,324 334,137 320 302
VA........................ 3803 2 CHESAPEAK................... 3,444,719 343,407 319 310
VA........................ 3803 3 CHESAPEAK................... 4,744,776 499,555 439 451
VA........................ 3803 4 CHESAPEAK................... 7,270,201 775,488 673 700
VA........................ 10017 ST--rp. CHESAPEAK CORP.............. 751,025 70,851 70 64
VA........................ 3797 3 CHESTERFIELD................ 2,394,580 216,000 222 195
VA........................ 3797 4 CHESTERFIELD................ 4,636,999 497,799 429 449
VA........................ 3797 5 CHESTERFIELD................ 9,875,438 1,104,759 914 997
VA........................ 3797 6 CHESTERFIELD................ 17,283,476 1,781,985 1,600 1,608
VA........................ 3797 --8 CHESTERFIELD................ 1,701,065 153,249 157 138
VA........................ 3775 1 CLINCH RIVER................ 6,480,271 723,406 600 653
VA........................ 3775 2 CLINCH RIVER................ 6,272,239 678,300 581 612
VA........................ 3775 3 CLINCH RIVER................ 7,143,953 798,564 661 721
VA........................ 7213 1 CLOVER...................... 9,235,814 888,059 855 801
VA........................ 10377 ST__ell COGENTRIX--HOPEWELL......... 2,275,948 214,712 211 194
VA........................ 10071 ST__uth COGENTRIX--PORTSMOUTH....... 2,617,290 246,914 242 223
VA........................ 54081 ST__d 1 COGENTRIX RICHMOND 1........ 2,628,680 247,989 243 224
VA........................ 54081 ST__d 2 COGENTRIX RICHMOND 2........ 2,127,966 200,752 197 181
VA........................ 52087 GT__LP COMMONWEALTH ATLANTIC LP.... 450,631 34,139 42 31
VA........................ 7212 --1 DARBYTOWN................... 115,229 8,729 11 8
VA........................ 7212 --2 DARBYTOWN................... 115,229 8,729 11 8
VA........................ 7212 --3 DARBYTOWN................... 115,229 8,729 11 8
VA........................ 7212 --4 DARBYTOWN................... 115,229 8,729 11 8
VA........................ 52019 CA__#1 DOSEWELL #1................. 594,931 69,992 55 63
VA........................ 52019 CT__#1 DOSEWELL #1................. 1,207,760 142,089 112 128
VA........................ 52019 CA__#2 DOSEWELL #2................. 594,931 69,992 55 63
VA........................ 52019 CT__#2 DOSEWELL #2................. 1,207,760 142,089 112 128
VA........................ 3776 51 GLEN LYN.................... 1,298,222 124,829 120 113
VA........................ 3776 52 GLEN LYN.................... 1,188,728 114,301 110 103
VA........................ 3776 6 GLEN LYN.................... 5,646,574 626,075 523 565
VA........................ 54844 CA__e 1 GORDONSVILLE 1.............. 211,614 24,896 20 22
VA........................ 54844 CT__e 1 GORDONSVILLE 1.............. 429,231 50,498 40 46
VA........................ 54844 CA__e 2 GORDONSVILLE 2.............. 214,004 25,177 20 23
VA........................ 54844 CT__e 2 GORDONSVILLE 2.............. 434,011 51,060 40 46
VA........................ 7032 --3 GRAVEL NECK................. 116,841 8,852 11 8
VA........................ 7032 4 GRAVEL NECK................. 116,841 8,852 11 8
VA........................ 7032 5 GRAVEL NECK................. 116,841 8,852 11 8
VA........................ 7032 6 GRAVEL NECK1................ 116,841 8,852 11 8
VA........................ 10633 CT__nc. HOPEWELL COGEN, INC......... 1,310,927 154,227 121 139
VA........................ 10633 CW__nc. HOPEWELL COGEN, INC......... 675,419 79,461 63 72
VA........................ 10773 ST__sta LG&E-WESTMLD ALTAVISTA...... 1,427,003 134,623 132 121
VA........................ 10771 ST__ell LG&E-WESTMLD HOPEWELL....... 1,427,003 134,623 132 121
VA........................ 10774 ST__ton LG&E-WESTMLD SOUTHAMPTON.... 1,427,003 134,623 132 121
[[Page 56377]]
VA........................ 52007 STurg MECKLENBURG................. 3,004,193 283,414 278 256
VA........................ 3804 3 POSSUM POINT................ 2,489,785 231,242 231 209
VA........................ 3804 4 POSSUM POINT................ 6,778,888 735,716 628 664
VA........................ 3788 1 POTOMAC RIVER............... 1,780,998 149,450 165 135
VA........................ 3788 2 POTOMAC RIVER............... 1,608,529 136,247 149 123
VA........................ 3788 3 POTOMAC RIVER............... 2,711,245 278,619 251 251
VA........................ 3788 4 POTOMAC RIVER............... 10,902,795 1,135,590 1,009 1,025
VA........................ 3788 5 POTOMAC RIVER............... 10,567,982 1,095,468 978 989
VA........................ 50813 ST__ner STONE CONTAINER............. 873,930 82,446 81 74
VA........................ 3809 1 YORKTOWN.................... 7,206,933 734,577 667 663
VA........................ 3809 2 YORKTOWN.................... 7,241,953 702,966 670 634
VA........................ 3809 3 YORKTOWN.................... 3,676,409 370,905 340 335
VA........................ ........... 1 ............................ 4,214,872 397,629 390 359
WV........................ 3942 1 ALBRIGHT.................... 705,441 58,973 46 36
WV........................ 3942 2 ALBRIGHT.................... 703,469 59,090 46 36
WV........................ 3942 3 ALBRIGHT.................... 3,366,883 325,240 221 200
WV........................ 3943 1 FORT MARTIN................. 13,735,054 1,559,384 901 960
WV........................ 3943 2 FORT MARTIN................. 13,544,284 1,466,466 889 903
WV........................ 10151 ST__own GRANT TOWN.................. 2,430,507 229,293 159 141
WV........................ 3944 1 HARRISON.................... 21,606,702 2,294,436 1,418 1,413
WV........................ 3944 2 HARRISON.................... 21,825,171 2,294,971 1,432 1,413
WV........................ 3944 3 HARRISON.................... 22,529,228 2,377,002 1,478 1,463
WV........................ 3935 1 JOHN E AMOS................. 18,733,385 2,087,285 1,229 1,285
WV........................ 3935 2 JOHN E AMOS................. 18,693,941 2,089,409 1,227 1,286
WV........................ 3935 3 JOHN E AMOS................. 24,715,234 2,677,997 1,622 1,649
WV........................ 3947 1 KAMMER...................... 5,775,301 632,702 379 390
WV........................ 3947 2 KAMMER...................... 6,520,529 709,833 428 437
WV........................ 3947 3 KAMMER...................... 6,977,907 759,376 458 468
WV........................ 3936 1 KANAWHA RIVER............... 4,385,010 479,131 288 295
WV........................ 3936 2 KANAWHA RIVER............... 3,915,227 419,414 257 258
WV........................ 3948 1 MITCHELL.................... 20,089,496 2,155,757 1,318 1,327
WV........................ 3948 2 MITCHELL.................... 17,971,393 1,950,233 1,179 1,201
WV........................ 6264 1 MOUNTAINEER (1301).......... 29,445,137 3,169,552 1,932 1,951
WV........................ 3954 1 MT STORM.................... 19,946,826 2,157,580 1,309 1,328
WV........................ 3954 2 MT STORM.................... 17,300,820 1,859,503 1,135 1,145
WV........................ 3954 3 MT STORM.................... 17,911,570 1,827,152 1,175 1,125
WV........................ 7537 1A NORTH BRANCH................ 1,606,967 112,770 105 69
WV........................ 7357 1B NORTH BRANCH................ 1,653,848 116,060 109 71
WV........................ 3938 11 PHIL SPORN.................. 3,332,224 356,045 219 219
WV........................ 3938 21 PHIL SPORN.................. 3,312,719 350,849 217 216
WV........................ 3938 31 PHIL SPORN.................. 3,501,732 367,597 230 226
WV........................ 3938 41 PHIL SPORN.................. 3,491,270 370,741 229 228
WV........................ 3938 51 PHIL SPORN.................. 10,028,012 1,123,713 658 692
WV........................ 6004 1 PLEASANTS................... 20,225,588 2,064,889 1,327 1,271
WV........................ 6004 2 PLEASANTS................... 17,354,353 1,780,299 1,139 1,096
WV........................ 3945 7 RIVESVILLE.................. 288,741 27,764 19 17
WV........................ 3945 8 RIVESVILLE.................. 741,331 63,743 49 39
WV........................ 3946 1 WILLOW ISLAND............... 905,250 82,161 59 51
WV........................ 3946 2 WILLOW ISLAND............... 3,490,911 340,245 229 209
--------------------------------------------------------------------------------------------------------------------------------------------------------
Table A.2.--Allocations to Non-EGUs by mmBtu
------------------------------------------------------------------------
Unit
State Plant Point ID Unit 1995, allocations
Summer HI by HI
------------------------------------------------------------------------
AL............. MEAD COATED 004 1,118,921 138
BOARD INC.
AL............. GULF STATES 003 154,732 19
PAPER
CORPORATION.
AL............. TRANSCONTINENTAL 018 48,682 6
GAS PIPELINE
CORPORATION.
AL............. INTERNATIONAL 011 1,143,170 141
PAPER SIEBERT
STATION.
AL............. MOBILE ENERGY 001 326,785 40
SERVICES
COMPANY.
AL............. COURTAULDS 011 60,045 7
FIBERS INC.
AL............. COURTAULDS 013 382,789 47
FIBERS INC.
AL............. AMOCO CHEMICALS. 024 396,068 49
AL............. AMOCO CHEMICALS. 026 106,811 13
AL............. SOLUTIA, INC.-- 013 795,511 98
DECATUR PLANT.
AL............. SOLUTIA, INC.-- 014 786,934 97
DECATUR PLANT.
AL............. SOLUTIA, INC.-- 015 747,265 92
DECATUR PLANT.
AL............. GENERAL ELECTRIC 005 186,487 23
CO.
AL............. CERESTAR USA 020 683,593 84
DECATUR INC.
AL............. GULF STATES 006 764,955 94
PAPER
CORPORATION.
AL............. U. S. ALLIANCE 007 649,512 80
COOSA PINES
CORPORATION.
AL............. U. S. ALLIANCE 008 649,512 80
COOSA PINES
CORPORATION.
AL............. U. S. ALLIANCE 009 649,512 80
COOSA PINES
CORPORATION.
AL............. U. S. ALLIANCE 010 649,512 80
COOSA PINES
CORPORATION.
AL............. EMPIRE COKE CO.. 001 108,543 13
[[Page 56378]]
AL............. CIBA SPECIALTY 010 153,000 19
CHEMICALS
CORPORATION.
AL............. CIBA SPECIALTY 011 36,951 5
CHEMICALS
CORPORATION.
AL............. OLIN CHEMICAL 003 606,282 75
CORPORATION.
AL............. MACMILLAN 002 1,779,840 219
BLOEDEL
PACKAGING INC.
AL............. MACMILLAN 005 404,136 50
BLOEDEL
PACKAGING INC.
AL............. CELANESE 006 379,902 47
CORPORATION.
AL............. SOLUTIA, INC.-- 016 471,731 58
DECATUR PLANT.
AL............. GULF STATES 047 184,755 23
STEEL INC.
AL............. DEGUSSA 004 410,502 51
CORPORATION.
AL............. AMOCO CHEMICALS. 010 535,211 66
AL............. AMOCO CHEMICALS. 015 389,140 48
AL............. AMOCO CHEMICALS. 019 339,487 42
AL............. AMOCO CHEMICALS. 022 312,351 38
AL............. AMOCO CHEMICALS. 023 254,615 31
AL............. TVA COLBERT..... 008 195,178 24
AL............. TVA COLBERT..... 009 195,178 24
AL............. LAROCHE 002 220,551 27
INDUSTRIES INC.
AL............. INTERNATIONAL 010 525,974 65
PAPER CO.
RIVERDALE MILL.
AL............. INTERNATIONAL 010 1,143,170 141
PAPER SIEBERT
STATION.
AL............. GULF STATES 046 184,755 23
STEEL INC.
AL............. CHAMPION 016 498,838 61
INTERNATIONAL
COURTLAND RD29.
AL............. TVA COLBERT..... 007 195,178 24
AL............. CHAMPION 015 2,140,980 263
INTERNATIONAL
COURTLAND RD29.
AL............. CHAMPION 007 663,276 82
INTERNATIONAL
COURTLAND RD29.
AL............. JEFFERSON 008 424,359 52
SMURFIT.
AL............. AMERICAN CAST 041 97,574 12
IRON PIPE
COMPANY.
AL............. GULF STATES 049 368,932 45
STEEL INC.
AL............. TVA COLBERT..... 006 195,178 24
AL............. TVA COLBERT..... 005 195,178 24
AL............. TVA COLBERT..... 003 195,178 24
AL............. TVA COLBERT..... 002 195,178 24
AL............. FORT JAMES- 029 316,970 39
PENNINGTON,
INC..
AL............. FORT JAMES- 027 783,476 96
PENNINGTON,
INC..
AL............. MEAD 001 435,843 54
CONTAINERBOARD.
CT............. PFIZER INC-- 010 480,420 24
CHEMICALS.
CT............. FEDERAL PAPER 003 721,140 36
BOARD CO.
CT............. PFIZER INC-- 012 604,860 30
CHEMICALS.
CT............. PFIZER INC-- 009 332,520 17
CHEMICALS.
CT............. SIMKINS 673 193,917 10
INDUSTRIES INC.
CT............. DEXTER NONWOVENS P29 1,788,060 89
DIV.
CT............. PRATT & WHITNEY 168 18,360 1
AIRC.
CT............. PRATT & WHITNEY 167 25,500 1
AIRC.
CT............. PRATT & WHITNEY 166 47,940 2
AIRC.
CT............. PFIZER INC-- P01 478,380 24
CHEMICALS.
CT............. PRATT & WHITNEY 164 85,680 4
AIRC.
CT............. CAPITOL DISTRICT P64 264,111 13
ENERGY CENTER.
CT............. PRATT & WHITNEY 163 5,100 0
AIRC.
CT............. PRATT & WHITNEY. 039 353,274 18
DC............. GSA WEST HEATING 001 18,360 1
PLANT.
DC............. GSA--CENTRAL 003 4,348 0
HEATING.
DC............. GSA--WEST 005 182,517 9
HEATING.
DC............. GSA--WEST 003 162,886 8
HEATING.
DC............. GSA WEST HEATING 002 3,060 0
PLANT.
DE............. DUPONT SEAFORD.. 002 931,055 61
DE............. DUPONT SEAFORD.. 001 826,012 54
DE............. CHRYSLER MOTORS. 003 257,164 17
DE............. STANDARD 001 372,919 24
CHLORINE OF
DELAWARE.
DE............. KRAFT GENERAL 001 695,930 45
FOODS.
DE............. DUPONT SEAFORD.. 003 393,082 26
IL............. INDIAN REFINING 7211029701 587,751 69
LIMITED 7
PARTNERSHIP.
IL............. ZEXEL ILINOIS, 7512015500 382,086 45
INC.--DECATUR 2
FACTORY.
IL............. GRANITE CITY 7303111904 381,057 45
STEEL COMPANY. 1
IL............. AMOCO PETROLEUM 7302008303 122,977 14
ADDITIVES CO. 6
IL............. JEFFERSON 7212042600 170,544 20
SMURFIT 1
CORPORATION.
IL............. A E STALEY 7302008412 918,510 107
MANUFACTURING 9
CO.
IL............. GRANITE CITY 7303111904 163,392 19
STEEL COMPANY. 2
IL............. ZEXEL ILINOIS, 7512015500 127,596 15
INC.--DECATUR 1
FACTORY.
IL............. ARCHER DANIELS 8506003008 1,202,940 141
MIDLAND CO EAST 1
PLANT.
IL............. CENTRAL ILLINOIS 7911000101 123,227 14
PUBLIC SERVICE. 4
IL............. ARCHER DANIELS 7612004807 862,589 101
MIDLAND CO EAST 1
PLANT.
[[Page 56379]]
IL............. CATERPILLAR--EAS 7305053101 452,649 53
T PEORIA PLANT. 9
IL............. INDIAN REFINING 7211029701 587,751 69
LIMITED 6
PARTNERSHIP.
IL............. INDIAN REFINING 7211029701 587,751 69
LIMITED 5
PARTNERSHIP.
IL............. GREAT LAKES 7808007101 331,981 39
NAVAL STATION. 1
IL............. GATES RUBBER 7211101100 119,513 14
CO.--GALESBURG 2
HOSE PLANT.
IL............. ARCHER DANIELS 7612004807 862,589 101
MIDLAND CO EAST 2
PLANT.
IL............. NORTHWESTERN 7302082102 172,053 20
STEEL & WIRE 1
CO..
IL............. GATES RUBBER 7211101100 119,513 14
CO.--GALESBURG 1
HOSE PLANT.
IL............. CLIFFORD--JACOBS 7302156500 228,634 27
FORGING CO.. 1
IL............. PEOPLES GAS 7505001900 346,415 41
LIGHT & COKE CO. 6
IL............. MOBIL JOLIET 8601000904 269,836 32
REFINING CORP. 3
IL............. MOBIL JOLIET 7211057702 207,849 24
REFINING CORP. 5
IL............. MOBIL JOLIET 7211057602 141,453 17
REFINING CORP. 1
IL............. IOWA--ILL. GAS & 7301026900 1,096,036 128
ELECTRIC CO.-- 1
MOLINE GEN. STA.
IL............. UNO-VEN COMPANY. 7211024000 430,709 50
7
IL............. KRAFT FOOD 7210092100 62,027 7
INGREDIENTS 3
CORP.
IL............. NORTHWESTERN 7302081901 958,524 112
STEEL & WIRE CO. 4
IL............. NORTHWESTERN 7302081901 215,027 25
STEEL & WIRE CO. 3
IL............. LAUHOFF GRAIN 7212126209 165,702 19
COMPANY. 1
IL............. PEKIN ENERGY 7302008701 769,080 90
COMPANY. 9
IL............. IOWA--ILL. GAS & 7301026900 1,096,036 128
ELECTRIC CO.-- 2
MOLINE GEN. STA.
IL............. SHEREX CHEMICAL 7303213100 312,522 37
COMPANY. 1
IL............. ARCHER DANIELS 8601005602 125,864 15
MIDLAND CORN 4
SWEETENERS.
IL............. UNO-VEN COMPANY. 7211025303 391,449 46
7
IL............. GENERAL ELECTRIC/ 7303110000 417,430 49
HOT POINT-- 3
RANGE DIVISIO.
IL............. CHICAGO WATER 7511006600 193,415 23
DEPT--SPRINGFIE 2
LD STATION.
IL............. MENTAL HEALTH 7508001800 117,781 14
DEPT--CHICAGO-R 1
EAD CENTER.
IL............. COM ED--FISK 7303081801 72,327 8
STATION. 3
IL............. COM ED--FISK 7303081801 52,855 6
STATION. 2
IL............. U S STEEL--SOUTH 8201004401 849,872 99
WORKS. 4
IL............. U S STEEL--SOUTH 8201004401 872,389 102
WORKS. 3
IL............. GENERAL MILLS 7303098807 149,536 17
INC. 0
IL............. GENERAL ELECTRIC/ 7303110000 128,751 15
HOT POINT-- 6
RANGE DIVISIO.
IL............. CPC 7302014604 760,959 89
INTERNATIONAL 3
INC.
IL............. CPC 8805006611 139,143 16
INTERNATIONAL 8
INC.
IL............. CPC 7302014704 760,959 89
INTERNATIONAL 6
INC.
IL............. CPC 7302014704 819,060 96
INTERNATIONAL 5
INC.
IL............. CATERPILLAR 7302118200 245,955 29
TRACTOR CO 9
AURORA PLANT.
IL............. CPC 7302014604 819,060 96
INTERNATIONAL 2
INC.
IL............. CPC 7302014604 819,060 96
INTERNATIONAL 1
INC.
[[Page 56380]]
IL............. CLIFFORD-JACOBS 7302156500 256,378 30
FORGING CO. 3
IL............. METROPOLITAN 8501007300 375,283 44
W.R.D. OF 7
GREATER CHICAGO.
IL............. QUANTUM--USI 7210001601 169,166 20
DIVISION. 7
IL............. WM WRIGLEY JR 7211074600 119,513 14
CO--CHICAGO 4
PLANT.
IL............. AUSTIN WESTERN 7405009800 363,736 43
DIVISION. 2
IL............. QUANTUM--USI 7210001601 149,536 17
DIVISION. 6
IL............. QUANTUM--USI 7210001601 199,189 23
DIVISION. 4
IL............. QUANTUM--USI 7210001601 397,223 46
DIVISION. 3
IL............. NALCO CHEMICAL 8501003300 171,777 20
COMPANY--CORP 4
RES CENTER.
IL............. QUANTUM--USI 7212120711 654,458 77
DIVISION. 2
IL............. AMOCO CHEMICALS 7210022200 188,219 22
CORP--WILLOW 2
SPRINGS PL.
IL............. QUANTUM--USI 7212120711 654,458 77
DIVISION. 0
IL............. QUANTUM--USI 7212120710 654,458 77
DIVISION. 9
IL............. QUANTUM--USI 7212120710 615,960 72
DIVISION. 8
IL............. MARATHON OIL CO 7211129105 271,265 32
ILLINOIS 6
REFINING DIV.
IL............. MARATHON OIL CO 7211129105 271,265 32
ILLINOIS 5
REFINING DIV.
IL............. K-FIVE SOUTH 8610004500 62,027 7
PLANT. 2
IL............. NATURAL GAS 7302022100 703,800 82
PIPELINE CO OF 4
AMERICA.
IL............. QUANTUM--USI 7212120711 654,458 77
DIVISION. 1
IN............. LTV STEEL 023 577,936 104
COMPANY.
IN............. LTV STEEL 024 1,178,381 213
COMPANY.
IN............. LTV STEEL 022 611,423 110
COMPANY.
IN............. IPALCO--PERRY K. 001 949,685 171
IN............. INLAND STEEL 320 2,437,729 440
COMPANY.
IN............. IPALCO--PERRY K. 002 959,398 173
IN............. GMC-DELPHI 002 16,166 3
INTERIOR AND
LIGHTING
SYSTEMS.
IN............. LTV STEEL 021 531,747 96
COMPANY.
IN............. INLAND STEEL 330 2,245,925 405
COMPANY.
IN............. INLAND STEEL 321 3,811,376 688
COMPANY.
IN............. INLAND STEEL 285 311,774 56
COMPANY.
IN............. IPALCO--PERRY K. 003 506,874 91
IN............. A.E. STALEY MAN. 040 1,412,496 255
CO. SOUTH PLANT.
IN............. INLAND STEEL 322 9,116,363 1,645
COMPANY.
IN............. IPALCO--PERRY K. 004 629,974 114
IN............. INDIANA GIRLS 003 2,031,840 367
SCHOOL.
IN............ GENERAL ELECTRIC 001 7,506 1
CO.
IN............ PANHANDLE 016 6,282,041 1,133
EASTERN
PIPELINE CO.
IN............ NATIONAL STEEL 001 719,591 130
CORP.
IN............ NATIONAL STEEL 003 124,132 22
CORP.
IN............ NATIONAL STEEL 004 370,664 67
CORP.
IN............ INLAND STEEL 284 315,815 57
COMPANY.
IN............ NEW ENERGY 003 8,648,738 1,560
COMPANY OF
INDIANA.
IN............ PFIZER INC...... 004 503,457 91
IN............ WESTON PAPER & 002 325,584 59
MFG.
IN............ APPLIED 005 23,672 4
EXTRUSION
TECHNOLOGIES,
INC..
IN............ JEFFERSON 001 643,824 116
SMURFIT
CORPORATION.
IN............ PRAXAIR, INC.... 002 44,457 8
IN............ E.W.I. INC...... 001 18,475 3
IN............ U S STEEL CO 108 360,272 65
GARY WORKS.
IN............ ALLISON 008 2,623 0
TRANSMISSION
DIV PLANT 3.
IN............ FRITO-LAY, INC.. 001 12,702 2
IN............ JOSEPH SEAGRAM & 009 700,650 126
SONS.
IN............ SUPERIOR 002 163,392 29
LAMINATING,
INC..
IN............ KIEFFER PAPER 001 38,683 7
MILLS INC..
IN............ AMOCO OIL 001 5,430,169 980
COMPANY,
WHITING
REFINERY.
IN............ AMOCO OIL 002 153,577 28
COMPANY,
WHITING
REFINERY.
IN............ U S STEEL CO 014 6,928 1
GARY WORKS.
IN............ U S STEEL CO 028 122,400 22
GARY WORKS.
IN............ U S STEEL CO 105 133,947 24
GARY WORKS.
[[Page 56381]]
IN............. U S STEEL CO 301 393,181 71
GARY WORKS.
IN............. U S STEEL CO 405 103,925 19
GARY WORKS.
IN............. U S STEEL CO 701 950,909 172
GARY WORKS.
IN............. U S STEEL CO 714 405,306 73
GARY WORKS.
IN............. INLAND STEEL 254 217,664 39
COMPANY.
IN............. INLAND STEEL 282 297,917 54
COMPANY.
IN............. INLAND STEEL 281 289,834 52
COMPANY.
IN............. U S STEEL CO 104 138,566 25
GARY WORKS.
IN............. INLAND STEEL 256 217,664 39
COMPANY.
IN............. U S STEEL CO 718 101,038 18
GARY WORKS.
IN............. INLAND STEEL 252 217,664 39
COMPANY.
IN............. INLAND STEEL 217 1,013,264 183
COMPANY.
IN............. U S STEEL CO 720 660,762 119
GARY WORKS.
IN............. AMERICAN MAIZE 007 944,559 170
PRODUCTS
COMPANY.
IN............. COLGATE- 003 101,636 18
PALMOLIVE.
IN............. U S STEEL CO 726 301,958 54
GARY WORKS.
IN............. INLAND STEEL 283 297,917 54
COMPANY.
IN............. INLAND STEEL 206 203,808 37
COMPANY.
IN............. INLAND STEEL 280 289,834 52
COMPANY.
KY............. GENERAL TIRE INC 001 395,491 35
KY............. WILLAMETTE 009 320,706 28
INDUSTRIES INC.
KY............. ROHM & HAAS 001 3,253,549 286
KENTUCKY INC.
KY............. G E APPLIANCES 001 1,072,019 94
BOILER PLANT.
KY............. B F GOODRICH CO. 007 898,370 79
KY............. B F GOODRICH CO. 018 344,106 30
KY............. AIR PRODUCTS & 0AB 976,162 86
CHEMICALS.
KY............. E I DUPONT INC.. 001 3,177,045 280
KY............. AGE 011 196,879 17
INTERNATIONAL,
INC.
KY............. AIR PRODUCTS & 0AA 831,963 73
CHEMICALS.
KY............. ARMCO STEEL CORP 0G5 329,901 29
KY............. OWENSBORO GRAIN 032 797,119 70
COMPANY.
KY............. PROTEIN 001 559,368 49
TECHNOLOGIES
INT.
KY............. ARMCO STEEL CORP 0G4 329,901 29
KY............. ARMCO STEEL CORP 0G6 329,901 29
KY............. ARMCO INC....... 020 200,390 18
KY............. ARMCO INC....... 021 200,390 18
KY............. ASHLAND OIL INC. 067 801,951 71
KY............. ARMCO INC....... 022 200,390 18
KY............. TEXAS GAS 003 618,954 54
TRANSMISSION.
KY............. DOW CORNING CORP 059 2,292,113 202
KY............. ARMCO STEEL CORP 0G3 329,901 29
MA............. BAY STATE 002 1,542,240 64
STERLING.
MA............. TRIGEN-BOSTON 001 678,388 28
ENERGY.
MA............. NATICK 002 279,072 12
PAPERBOARD.
MA............. MEDICAL 005 155,448 6
AREATOTALENG.
MA............. MEDICAL 004 168,912 7
AREATOTALENG.
MA............. TRIGEN-BOSTON 002 558,873 23
ENERGY.
MA............. WELLESLEY 001 58,416 2
COLLEGE.
MA............. BAKER 004 117,749 5
COMMODITIES.
MA............. G E AIRCRAFT 003 412,488 17
ENGINES.
MA............. TRIGEN-BOSTON 004 678,388 28
ENERGY.
MA............. G E AIRCRAFT 007 630,125 26
ENGINES.
MD............. CHESAPEAKE 002 402,696 45
PAPERBOARD
COMPANY.
MD............. NAVAL SURFACE 005 603,947 68
WARFARE CNTR-
INDIAN HD.
MD............. NAVAL SURFACE 004 603,947 68
WARFARE CNTR-
INDIAN HD.
MD............. BETHLEHEM STEEL. 009 904,230 102
MD............. BETHLEHEM STEEL. 008 904,230 102
MD............. WESTVACO........ 002 1,701,768 192
MD............. WESTVACO........ 001 1,647,393 185
MI............. STEELCASE INC... 0033 448,750 50
MI............. WILLIAM BEAUMONT 0010 0 0
HOSPITAL.
MI............. GENERAL MOTORS 0510 46,245 5
CORP.
MI............. GENERAL MOTORS 0506 265,585 30
CORP.
MI............. S D WARREN CO... 0011 403,240 45
MI............. S D WARREN CO... 0003 142,030 16
MI............. WILLIAM BEAUMONT 0011 0 0
HOSPITAL.
MI............. DOW CHEMICAL USA 0084 192,838 21
MI............. NATIONAL STEEL 0205 241,913 27
CORP.
MI............. DOW CHEMICAL USA 0401 60,045 7
MI............. STONE CONTAINER 0001 1,386,384 154
CORP.
MI............. THE REGENTS OF 0001 402,996 45
THE UNIVERSITY
OF MICHIGA.
MI............. THE REGENTS OF 0002 374,706 42
THE UNIVERSITY
OF MICHIGA.
MI............. NATIONAL STEEL 0202 165,702 18
CORP.
MI............. DSC LTD......... 0006 261,543 29
MI............. ROUGE STEEL CO.. 0219 536,366 60
MI............. ROUGE STEEL CO.. 0218 302,536 34
MI............. DETROIT EDISON 0003 316,392 35
CO.
MI............. GEORGIA PACIFIC 0005 1,164,554 130
CORP.
MI............. NATIONAL STEEL 0201 213,623 24
CORP.
MI............. CHAMPION 0002 92,198 10
INTERNATIONAL
CORP.
[[Page 56382]]
MI............. GEORGIA PACIFIC 0004 83,717 9
CORP.
MI............. MARATHON OIL 0001 320,543 36
COMPANY.
MI............. MENASHA CORP.... 0024 754,568 84
MI............. MENASHA CORP.... 0025 729,532 81
MI............. ROCK TENN 0001 275,413 31
COMPANY.
MI............. ROCK TENN 0002 275,413 31
COMPANY.
MI............. MEAD PAPER CO... 0310 1,927,800 214
MI............. MEAD PAPER CO... 0340 1,680,893 187
MI............. CHAMPION 0015 54,272 6
INTERNATIONAL
CORP.
MI............. GENERAL MOTORS 0501 747,102 83
CORP.
MI............. MICHIGAN STATE 0054 1,203,801 134
UNIVERSITY.
MI............. JAMES RIVER 0003 957,583 107
PAPER CO INC.
MI............. GREAT LAKES GAS 0005 854,018 95
TRANSMISSION.
MI............. MEAD PAPER CO... 0320 949,177 106
MI............. MICHIGAN STATE 0055 803,812 89
UNIVERSITY.
MI............. GENERAL MOTORS 0502 558,883 62
CORP.
MI............. MICHIGAN STATE 0053 1,211,151 135
UNIVERSITY.
MI............. GREAT LAKES GAS 0001 1,201,050 134
TRANSMISSION.
MI............. GREAT LAKES GAS 0003 943,732 105
TRANSMISSION
LTD.
MI............. GENERAL MOTORS 0507 231,521 26
CORP.
MI............. MICHIGAN STATE 0056 1,508,240 168
UNIVERSITY.
MO............. THE DOE RUN 002 454,182 58
COMPANY--SMELTI
NG.
MO............. SCHUYLKILL 001 59,317 8
METALS
CORPORATION.
MO............. ANHEUSER BUSCH, 003 46,189 6
INC., ST.LOUIS.
MO............. CHRYSLER CORP. 015 88,944 11
NORTH PLANT.
MO............. MONSANTO COMPANY 001 577 0
MO............. FORD MOTOR CO... 018 82,562 11
MO............. BLUE RIVER 003 1,732 0
TREATMENT PLANT.
MO............. DOE RUN COMPANY. 017 0 0
MO............. ASARCO.......... 001 28,916 4
MO............. CONTINENTAL 007 2,309 0
BAKING COMPANY.
MO............. ASARCO.......... 019 215,453 28
NC............. INTERNATIONAL 004 304,251 40
PAPER:
REIGELWOOD.
NC............. R.J. REYNOLDS 004 1,230,528 164
TOBACCO CO.--
0745.
NC............. R.J. REYNOLDS 003 1,230,528 164
TOBACCO CO.--
0745.
NC............. R.J. REYNOLDS 002 1,230,528 164
TOBACCO CO.--
0745.
NC............. R.J. REYNOLDS 001 1,230,528 164
TOBACCO CO.--
0745.
NC............. R.J. REYNOLDS 004 394,888 53
TOBACCO--0405.
NC............. R.J. REYNOLDS 003 394,888 53
TOBACCO--0405.
NC............. R.J. REYNOLDS 002 394,888 53
TOBACCO--0405.
NC............. WEYERHAUSER 005 1,699,090 226
COMPANY, NEW
BERN MILL.
NC............. INTERNATIONAL 003 334,736 45
PAPER:
REIGELWOOD.
NC............. FIELDCREST- 001 745,416 99
CANNON PLT 1,
KANNAPOLIS.
NC............. CHAMPION INT 003 1,952,688 260
CORP.
NC............. FMC CORP-LITHIUM 030 631,584 84
DIV. HWY 161.
NC............. R.J. REYNOLDS 001 395,544 53
TOBACCO--0405.
NC............. CHAMPION 001 1,260,555 168
INTERNATIONAL
CORP. ROANOKE
RAP.
NC............. CHAMPION INT 002 860,880 115
CORP.
NC............. CHAMPION INT 001 955,128 127
CORP.
NC............. CHAMPION INT 004 1,713,192 228
CORP.
NC............. WEYERHAEUSER 001 2,458,162 327
PAPER CO.
PLYMOUTH.
NC............. WEYERHAEUSER 007 1,888,305 251
PAPER CO.
PLYMOUTH.
NC............. P. H. GLATFELTER 006 1,753,584 233
CO.--ECUSTA.
NC............. CONE MILLS CORP- 004 342,210 46
WHITE OAK PLANT.
NJ............. CHEVRON U.S.A., 43 496,897 28
INC..
NJ............. DUPONT DE 10 750,245 42
NEMOURS, E.I.,
& CO..
NJ............. HOFFMAN LAROCHE 7 102,729 6
INC. C/O ENVIR.
NJ............. INTERNATIONAL 1 199,993 11
VEILING
CORPORAT.
NJ............. OWENS-BROCKWAY 1 1,116,375 62
GLASS CONTAINER.
NJ............. NESTLE CO., 7 120,697 7
INC., THE.
NJ............. NESTLE CO., 6 120,697 7
INC., THE.
NJ............. DEGUSSA 9 146,443 8
CORPORATION-
METZ DIVIS.
NJ............. NEW JERSEY STEEL 1 169,934 9
CORPORATION.
NJ............. DUPONT DE 7 220,757 12
NEMOURS, E.I.,
& CO..
NJ............. FORD MOTOR 13 1,551,857 86
COMPANY.
NJ............. MERCK & CO., 2 532,593 30
INC..
NJ............. CHEVRON U.S.A., 1 149,721 8
INC..
NJ............. HERCULES 2 325,380 18
INCORPORATED.
NJ............. HERCULES 1 333,540 19
INCORPORATED.
NJ............. STONY BROOK 2 441,660 25
REGIONAL
SEWERAGE.
NJ............. BALL-INCON GLASS 1 456,814 25
PACKAGING COR.
NJ............. PSE & G CO. ATTN 6 3,963,652 220
ENVIRONMETAL.
NJ............. STONY BROOK 1 441,660 25
REGIONAL
SEWERAGE.
NJ............. GARDEN STATE 2 304,980 17
PAPER CO., INC..
NJ............. PSE & G CO. ATTN 1 5,505,816 306
ENVIRONMETAL.
NJ............. PSE & G CO. ATTN 2 5,458,897 303
ENVIRONMETAL.
NJ............. PSE & G CO. ATTN 3 4,606,176 256
ENVIRONMETAL.
NJ............. PSE & G CO. ATTN 4 2,946,636 164
ENVIRONMETAL.
NJ............. EXXON 7 199,993 11
CORPORATION.
NJ............. MERCK & CO., 6 902,273 50
INC..
[[Page 56383]]
NJ............. EXXON 14 887,400 49
CORPORATION.
NJ............. MERCK & CO., 5 775,912 43
INC..
NJ............. HOFFMAN LAROCHE 34 396,707 22
INC..
NJ............. MERCK & CO., 4 651,642 36
INC..
NJ............. MERCK & CO., 3 487,689 27
INC..
NJ............. MERCK & CO., 1 576,469 32
INC..
NJ............. EXXON 15 130,050 7
CORPORATION.
NJ............. PSE & G CO. ATTN 5 2,946,636 164
ENVIRONMETAL.
NJ............. GARDEN STATE 1 701,369 39
PAPER CO., INC..
NJ............. HOMASCTE COMPANY 2 2,673,335 149
NJ............. DUPONT DE 9 2,569,307 143
NEMOURS, E.I.,
& CO..
NJ............. GARDEN STATE 4 766,675 43
PAPER CO., INC..
NJ............. ANHEUSER-BUSCH 2 324,360 18
INCORPORATED.
NJ............. GEORGIA-PACIFIC 1 148,629 8
CORPORATION.
NJ............. COASTAL EAGLE 38 102,729 6
POINT OIL
COMPAN.
NJ............. GARDEN STATE 3 287,640 16
PAPER CO., INC..
NJ............. COASTAL EAGLE 123 331,136 18
POINT OIL
COMPAN.
NJ............. SCOTT PAPER 4 846,536 47
COMPANY.
NJ............. SCOTT PAPER 3 644,590 36
COMPANY.
NJ............. SCOTT PAPER 2 759,028 42
COMPANY.
NJ............. MARINA 3 1,208,661 67
ASSOCIATES.
NJ............. MARINA 2 2,143,093 119
ASSOCIATES.
NJ............. MARINA 1 2,143,093 119
ASSOCIATES.
NJ............. MALT PRODUCTS 1 242,614 13
CORPORATION.
NJ............. PETROLEUM 20 1,536,557 85
RECYCLING, INC..
NJ............. HOMASCTE COMPANY 1 2,486,646 138
NJ............. KAMINE MILFORD 1 775,710 43
LIMITED PARTNER.
NJ............. COGEN 2 365,670 20
TECHNOLOGIES--N
EW JERSE.
NJ............. COGEN 1 362,610 20
TECHNOLOGIES--N
EW JERSE.
NJ............. DUPONT DE 10 2,569,307 143
NEMOURS, E.I.,
& CO..
NJ............. BEST FOODS CPC 3 251,555 14
INTERNATIONAL I.
NJ............. COASTAL EAGLE 39 102,729 6
POINT OIL
COMPAN.
NJ............. MOBIL OIL 6 953,835 53
CORPORATION.
NJ............. MOBIL OIL 5 143,149 8
CORPORATION.
NJ............. MOBIL OIL 4 445,797 25
CORPORATION.
NJ............. MOBIL OIL 3 492,776 27
CORPORATION.
NJ............. MOBIL OIL 270 127,709 7
CORPORATION.
NJ............. MOBIL OIL 2 492,776 27
CORPORATION.
NJ............. MOBIL OIL 1 492,776 27
CORPORATION.
NJ............. COASTAL EAGLE 64 343,157 19
POINT OIL
COMPAN.
NJ............. COASTAL EAGLE 40 102,729 6
POINT OIL
COMPAN.
NY............. GEORGIA PACIFIC 001 231,568 27
CORP PLATTS.
NY............. GENERAL ELECTRIC 00C 405,181 47
NY............. GENERAL ELECTRIC 02Z 393,942 46
NY............. CAMPUS PWR PLANT 006 289,170 33
OGS.
NY............. KODAK PARK DIV 001 1,280,644 148
ROCHES.
NY............. HOLBROOK 001 64,121 7
GENERATING STA.
NY............. HOLBROOK 008 64,121 7
GENERATING STA.
NY............. HOLBROOK 007 64,121 7
GENERATING STA.
NY............. HOLBROOK 006 64,121 7
GENERATING STA.
NY............. HOLBROOK 005 64,121 7
GENERATING STA.
NY............. HOLBROOK 004 64,121 7
GENERATING STA.
NY............. LEDERLE 04Y 265,593 31
LABORATORIES.
NY............. HOLBROOK 002 64,121 7
GENERATING STA.
NY............. HOLBROOK 00B 29,835 3
GENERATING STA.
NY............. AKZO SALT-- 00F 320,027 37
WATKINS GLEN
REFIN..
NY............. HUDSON RIVER 007 2,361,664 273
MILL.
NY............. SILICONE 0ZZ 240,744 28
PRODUCTS
DIVISION.
NY............. SILICONE 02F 458,291 53
PRODUCTS
DIVISION.
NY............. PAPYRUS NEWTON 001 297,730 34
FALLS, INC.
NY............. ALCOA MASSENA 002 148,958 17
OPERATIONS.
NY............. HOLBROOK 003 64,121 7
GENERATING STA.
NY............. HOLBROOK 00J 29,835 3
GENERATING STA.
NY............. INDECK-YERKES 004 1,622,421 188
ENERGY SERVICES
TONAWAND.
NY............. IONDECK SILVER 004 305,561 35
SPRINGS ENERGY.
NY............. IONDECK SILVER 001 1,092,372 126
SPRINGS ENERGY.
NY............. MORTON SALT 00E 209,984 24
COMPANY.
NY............. REFINED SUGARS, 00K 174,420 20
INC.
NY............. SCOTT PAPER CO.. 001 69,283 8
NY............. HOLBROOK 009 64,121 7
GENERATING STA.
NY............. HOLBROOK 00K 29,835 3
GENERATING STA.
NY............. HOLBROOK 00A 64,121 7
GENERATING STA.
NY............. HOLBROOK 00I 29,835 3
GENERATING STA.
NY............. HOLBROOK 00G 29,835 3
GENERATING STA.
NY............. HOLBROOK 00E 29,835 3
GENERATING STA.
NY............. HOLBROOK 00D 29,835 3
GENERATING STA.
NY............. HOLBROOK 00C 29,835 3
GENERATING STA.
NY............. HOLBROOK 00F 29,835 3
GENERATING STA.
NY............. FINCH PRUYN & CO 006 462,437 53
NY............. TICONDEROGA MILL 016 1,818,536 210
TICOND.
[[Page 56384]]
NY............. KODAK PARK DIV 004 4,956,513 573
ROCHES.
NY............. KODAK PARK DIV 003 3,716,404 430
ROCHES.
NY............. KODAK PARK DIV 002 3,510,348 406
ROCHES.
NY............. ................ 002 104,229 12
NY............. BURROWS PAPER 001 344,043 40
CORP LYONSD.
NY............. EAST 60TH STREET 001 644,130 74
NY............. CHAMPION 008 1,000,960 116
INTERNATIONAL
CORP DEFERI.
NY............. ................ 0ZZ 305,235 35
NY............. CHEVY MOTOR PLT 0ZZ 604,888 70
TONAWA.
NY............. GENERAL MILLS 06V 700,740 81
INC BUFFAL.
NY............. BSC BAR PRODUCTS 00E 153,000 18
DIV. LACKAW.
NY............. BETHENERGY LACK 018 338,130 39
COKE LA.
NY............. LEDERLE 032 265,593 31
LABORATORIES.
NY............. HOLBROOK 00H 29,835 3
GENERATING STA.
NY............. ................ 0ZZ 800,101 93
NY............. NESTLE FOODS 001 65,105 8
CORP..
NY............. BASF-WYANDOTTE 0ZZ 150,691 17
CORP.
NY............. R. P. I......... 003 276,021 32
NY............. CHAMPION 007 1,133,560 131
INTERNATIONAL
CORP DEFERI.
NY............. OCCIDENTAL 006 2,448 0
CHEMICAL CORP
(HOOKER CHEM.
NY............. RAVENSWOOD--A--H 002 417,384 48
OUSE.
NY............. RAVENSWOOD--A--H 001 417,384 48
OUSE.
NY............. MILLER EASTERN 00L 298,781 35
BREWERY.
NY............. A-B INC 002 175,196 20
BALDWINSVILLE
BREWERY LYSAND.
NY............. HOOKER EFW PLANT 0D1 690,409 80
NIAGARA.
NY............. BRISTOL-MYERS 022 114,079 13
COMPANY DEWITT.
NY............. OCCIDENTAL 007 27,061 3
CHEMICAL CORP
(HOOKER CHEM.
NY............. ROME MFG CO DIV 002 299,384 35
ROME.
NY............. A-B INC 001 175,196 20
BALDWINSVILLE
BREWERY LYSAND.
NY............. HOOKER EFW PLANT 00C 4,896 1
NIAGARA.
NY............. OSWEGO ENERGY 001 172,982 20
CENTER.
NY............. HOOKER EFW PLANT 00D 965,861 112
NIAGARA.
OH............. JEFFERSON B004 788,542 89
SMURFIT (FRMLY
CONTAINER CORP).
OH............. PORTSMOUTH B001 591,272 67
GASEOUS
DIFFUSION PLANT.
OH............. PORTSMOUTH B002 591,272 67
GASEOUS
DIFFUSION PLANT.
OH............. PORTSMOUTH B003 591,272 67
GASEOUS
DIFFUSION PLANT.
OH............. GREAT LAKES B004 172,630 20
SUGAR COMPANY.
OH............. MIAMI PAPER B001 644,232 73
CORPORATION.
OH............. GIBSONBURG B001 4,265,918 484
CANNING CO.,
INC..
OH............. USS/KOBE STEEL B001 957,838 109
CO.--LORAIN
WORKS.
OH............. MEAD CORPORATION B002 1,778,323 202
OH............. MEAD CORPORATION B003 2,144,090 243
OH............. MEAD CORPORATION B001 1,579,838 179
OH............. APPLETON PAPERS B003 716,174 81
INC..
OH............. APPLETON PAPERS B002 541,955 61
INC..
OH............. CARGILL,INC..... B004 834,821 95
OH............. USS/KOBE STEEL B013 771,928 88
CO.--LORAIN
WORKS.
OH............. USS/KOBE STEEL B009 574,472 65
CO.--LORAIN
WORKS.
OH............. USS/KOBE STEEL B005 143,185 16
CO.--LORAIN
WORKS.
OH............. ARISTECH B004 261,312 30
CHEMICAL
CORPORATION.
OH............. GEORGIA PACIFIC B004 553,860 63
ROOFING FELT
PLANT.
OH............. SOUTH POINT B007 862,912 98
ETHANOL.
OH............. SOUTH POINT B004 862,912 98
ETHANOL.
OH............. USS/KOBE STEEL B007 379,902 43
CO.--LORAIN
WORKS.
OH............. TIMKEN COMPANY B003 402,996 46
CANTON PLANT NO
5.
OH............. ARMCO STEEL B005 898,729 102
COMPANY, L.P..
OH............. SOUTH POINT B003 862,912 98
ETHANOL.
OH............. LOF CO ROSSFORD B003 273,700 31
PLANT 6.
OH............. SHELL CHEMICAL B007 313,620 36
CO.
OH............. SHELL CHEMICAL B005 313,620 36
CO.
OH............. FRANKLIN B001 1,138,897 129
BOXBOARD
CORPORATION.
OH............. W C I STEEL, B001 1,323,261 150
INC..
OH............. GOODYEAR TIRE & B002 751,128 85
RUBBER CO THE
PLANT 11.
OH............. W C I STEEL, B004 260,389 30
INC..
OH............. TIMKEN COMPANY X001 640,291 73
CANTON PLANT NO
5.
OH............. ARISTECH B005 384,754 44
CHEMICAL
CORPORATION.
OH............. TIMKEN COMPANY, P014 285,215 32
THE.
OH............. TIMKEN COMPANY, P013 285,215 32
THE.
OH............. TIMKEN COMPANY X002 169,166 19
GAMBRINUS PLANT.
OH............. TIMKEN COMPANY X001 802,528 91
GAMBRINUS PLANT.
OH............. ASHLAND B029 167,434 19
PETROLEUM
COMPANY.
OH............. CANTON DROP X001 649,528 74
FORGING & MFG
CO.
OH............. ARISTECH B010 530,775 60
CHEMICAL
CORPORATION.
OH............. ARISTECH B009 503,485 57
CHEMICAL
CORPORATION.
OH............. ARISTECH B006 385,401 44
CHEMICAL
CORPORATION.
OH............. GOODYEAR TIRE & B001 826,200 94
RUBBER CO THE
PLANT 11.
OH............. ARMCO STEEL P010 1,035,705 118
COMPANY L.P..
OH............. ARMCO STEEL B004 838,287 95
COMPANY, L.P..
OH............. ARMCO STEEL B003 838,287 95
COMPANY, L.P..
OH............. ARMCO STEEL 860,643 98
COMPANY, L.P.01.
[[Page 56385]]
OH............. ARMCO STEEL P009 1,035,705 118
COMPANY L.P..
OH............. ARMCO STEEL B010 511,020 58
COMPANY L.P..
OH............. ARMCO STEEL B009 511,020 58
COMPANY L.P..
OH............. ARMCO STEEL B008 818,504 93
COMPANY L.P..
OH............. ARMCO STEEL B007 818,504 93
COMPANY L.P..
OH............. BP CHEMICALS, B003 3,729,736 423
INC..
OH............. BP CHEMICALS, B002 532,325 60
INC..
OH............. BP CHEMICALS, B001 599,876 68
INC..
OH............. BP OIL COMPANY-- P010 1,224,000 139
LIMA REFINERY.
OH............. GENERAL ELECTRIC B004 166,309 19
CO.
OH............. PROCTER & GAMBLE B021 932,754 106
CO.
OH............. WHEELING B004 125,864 14
PITTSBURGH
STEEL
STEUBENVILLE S.
OH............. ARMCO STEEL P012 1,035,705 118
COMPANY L.P..
OH............. PROCTER & GAMBLE B022 5,348,925 607
CO.
OH............. HENKEL CORP.-- B027 3,846,420 436
EMERY GROUP.
OH............. HENKEL CORP.-- B015 681,360 77
EMERY GROUP.
OH............. HENKEL CORP.-- B014 317,220 36
EMERY GROUP.
OH............. ANHEUSER-BUSCH X001 302,149 34
COLUMBUS
BREWERY.
OH............. FAIRFIELD B003 192,697 22
RECYCLED PAPER,
INC..
OH............. GENERAL ELECTRIC B002 1,240,166 141
CO.
OH............. LTV STEEL B905 87,181 10
COMPANY, INC..
OH............. LTV STEEL B009 707,842 80
COMPANY, INC..
OH............. LTV STEEL B005 473,434 54
COMPANY, INC..
OH............. LTV STEEL B007 527,014 60
COMPANY, INC..
OH............. LTV STEEL B004 632,208 72
COMPANY, INC..
OH............. LTV STEEL B010 192,838 22
COMPANY, INC..
OH............. LTV STEEL B001 575,218 65
COMPANY, INC..
OH............. LTV STEEL B002 931,161 106
COMPANY, INC..
OH............. LTV STEEL B003 437,625 50
COMPANY, INC..
OH............. LTV STEEL B004 1,008,422 114
COMPANY, INC..
OH............. LTV STEEL B005 259,811 29
COMPANY, INC..
OH............. LTV STEEL B006 202,653 23
COMPANY, INC..
PA............. INTERNATIONAL 040 662,852 68
PAPER CO..
PA............. ALLIED CHEMICAL 052 844,191 87
CORP.
PA............. TEXAS EASTERN 032 753,026 77
GAS PIPELINE CO.
PA............. GENERAL ELECTRIC 035 627,589 65
CO..
PA............. MERCK SHARP & 039 532,174 55
DOHME.
PA............. BETHLEHEM STEEL 041 639,151 66
CORP..
PA............. BETHLEHEM STEEL 042 835,995 86
CORP..
PA............. BETHLEHEM STEEL 067 1,333,002 137
CORP..
PA............. BETHLEHEM STEEL 147 3,110,558 320
CORP..
PA............. GENERAL ELECTRIC 032 1,000,620 103
CO..
PA............. SUN REFINING AND 006 450,087 46
MARKETING 1 O.
PA............. SUN REFINING AND 007 740,245 76
MARKETING 1 O.
PA............. SUN REFINING AND 038 549,423 57
MARKETING 1 O.
PA............. SUN REFINING AND 039 549,423 57
MARKETING 1 O.
PA............. PROCTER & GAMBLE 932 5,618,055 578
PAPER PRODUCTS
CO..
PA............. ALLIED CHEMICAL 051 175,625 18
CORP.
PA............. JEFFERSON 001 724,340 75
SMURFIT (FRMLY
CONTAINER CORP).
PA............. MONESSEN INC.... 031 252,039 26
PA............. PROCTER & GAMBLE 035 2,522,800 259
PAPER PRODUCTS
CO..
PA............. INTERNATIONAL 037 1,029,159 106
PAPER CO..
PA............. ALLIED CHEMICAL 050 100,620 10
CORP.
PA............. LTV STEEL 17 114,361 12
COMPANY--PITTSB
URGH WORKS.
PA............. GLATFELTER, P. 031 1,030,727 106
H. CO..
PA............. LTV STEEL 15 114,361 12
COMPANY--PITTSB
URGH WORKS.
PA............. LTV STEEL 19 157,590 16
COMPANY--PITTSB
URGH WORKS.
PA............. LTV STEEL 21 95,486 10
COMPANY--PITTSB
URGH WORKS.
PA............. SHENANGO IRON & 06 168,766 17
COKE WORKS.
PA............. SHENANGO IRON & 09 137,678 14
COKE WORKS.
PA............. BMG ASPHALT CO.. 101 30,943 3
PA............. ZINC CORPORATION 034 1,498,461 154
OF AMERICA.
PA............. ZINC CORPORATION 035 1,759,488 181
OF AMERICA.
PA............. UNITED STATES 043 999,098 103
STEEL CORP.,
THE.
PA............. BP OIL, INC..... 033 1,234,200 127
PA............. PENNTECH PAPERS, 041 1,063,116 109
INC..
PA............. UNITED STATES 045 1,172,194 121
STEEL CORP.,
THE.
PA............. PENNTECH PAPERS, 040 978,703 101
INC..
PA............. SUN REFINING & 090 2,212,658 228
MARKETING CO..
PA............. SCOTT PAPER CO.. 035 2,173,948 224
PA............. SCOTT PAPER CO.. 034 858,330 88
PA............. INTERNATIONAL 034 1,099,800 113
PAPER COMPANY.
PA............. INTERNATIONAL 033 1,100,520 113
PAPER COMPANY.
PA............. BETHLEHEM STEEL 132 981,509 101
CORP..
PA............. UNITED STATES 046 982,367 101
STEEL CORP.,
THE.
TN............. EASTMAN, TENN. 002 540,192 64
CO.
TN............. EASTMAN, TENN. 001 540,192 64
CO.
TN............. KRAFT FOOD 003 621,815 74
INGREDIENTS
CORP.
TN............. HUMKO-DIV WITCO 010 453,804 54
CHEM.
TN............. HUMKO-DIV WITCO 009 468,815 55
CHEM.
[[Page 56386]]
TN............. ARCADIAN 007 1,274,808 151
CORPORATION.
TN............. E.I. DUPONT DE 011 3,364,846 398
NEMOURS &
INTERMEDIATES.
TN............. E.I. DUPONT DE 016 612,000 72
NEMOURS &
INTERMEDIATES.
TN............. E.I. DUPONT DE 013 1,453,211 172
NEMOURS &
INTERMEDIATES.
TN............. EASTMAN, TENN. 003 618,528 73
CO.
TN............. TEXAS EASTERN 001 1,373,523 162
GAS PIPELINE
GLADEVILLE.
TN............. E.I. DUPONT DE 015 1,019,615 121
NEMOURS &
INTERMEDIATES.
TN............. EASTMAN, TENN. 004 618,528 73
CO.
TN............. EASTMAN, TENN. 005 673,200 80
CO.
TN............. EASTMAN, TENN. 006 673,200 80
CO.
TN............. EASTMAN, TENN. 013 881,816 104
CO.
TN............. EASTMAN, TENN. 014 881,816 104
CO.
TN............. EASTMAN, TENN. 015 2,913,528 345
CO.
TN............. EASTMAN, TENN. 016 2,913,528 345
CO.
TN............. EASTMAN, TENN. 017 2,913,528 345
CO.
TN............. EASTMAN, TENN. 019 2,913,528 345
CO.
TN............. TENN EASTMAN CO 037 3,607,944 427
PO BOX 511
KINGSPOR.
TN............. E.I. DUPONT DE 010 3,849,249 455
NEMOURS &
INTERMEDIATES.
TN............. MEAD CORP....... 009 1,916,449 227
TN............. EASTMAN, TENN. 018 2,913,528 345
CO.
TN............. E I DUPONT DE 0P3 328,104 39
NEMOURS & CO
INC.
TN............. PROCTER & GAMBLE 003 2,345,808 277
CELLULOSE
COMPANY, THE.
TN............. TN EASTMAN INC.. 059 786,362 93
TN............. ARNOLD 006 10,751 1
ENGINEERING DEV
CTR.
TN............. E I DUPONT DE 0P2 1,000,824 118
NEMOURS & CO
INC.
TN............. BASF FIBERS HWY 008 869,725 103
160 LOWLAND.
TN............. BASF FIBERS HWY 009 869,725 103
160 LOWLAND.
TN............. CENTRAL SOYA.... 042 1,051,978 124
TN............. E I DUPONT...... 001 325,022 38
TN............. E I DUPONT...... 003 463,154 55
TN............. VELSICOL 018 342,389 40
CHEMICAL.
TN............. PACKAGING 017 224,205 27
CORPORATION OF
AMERICA.
TN............. PACKAGING 018 3,522,121 416
CORPORATION OF
AMERICA.
TN............. CARGILL 003 1,487,976 176
CORNSTARCH.
TN............. E I DUPONT DE 0P1 403,704 48
NEMOURS & CO
INC.
TN............. TENNECO GAS/ 001 481,255 57
ENVIRONMENTAL
DEPARTMENT.
TN............. PROCTER & GAMBLE 002 2,462,434 291
CELLULOSE
COMPANY, THE.
TN............. PROCTER & GAMBLE 001 617,774 73
CELLULOSE
COMPANY, THE.
TN............. CARGILL 002 1,280,108 151
CORNSTARCH.
TN............. BRIDGESTONE 001 363,659 43
(U.S.A.), INC.
TN............. US DEPARTMENT OF 003 58,562 7
ENERGY (ORNL).
TN............. GOODYEAR TIRE & 004 1,095,940 130
RUBB.
TN............. BOWATERS PAPER 012 1,087,729 129
CO.
TN............. BOWATERS PAPER 011 1,086,881 129
CO.
TN............. A.E. STALEY 035 1,189,514 141
MANUFACTURING
COMPANY.
TN............. A.E. STALEY 034 1,189,514 141
MANUFACTURING
COMPANY.
VA............. BEAR ISLAND 001 2,206,643 201
PAPER CO.
VA............. JAMES RIVER 002 3,761,847 342
COGENERATION
(COGE.
VA............. SMITHFIELD 001 96,591 9
PACKING.
VA............. DUPONT DE 004 285,120 26
NEMOURS E I &
CO.
VA............. DUPONT DE 005 406,080 37
NEMOURS E I &
CO.
VA............. UNION CAMP CORP/ 003 1,703,400 155
FINE PAPER DIV.
VA............. UNION CAMP CORP/ 005 384,182 35
FINE PAPER DIV.
VA............. UNION CAMP CORP/ 017 632,549 58
FINE PAPER DIV.
VA............. DUPONT DE 001 360,720 33
NEMOURS E I &
CO.
VA............. CHESAPEAKE PAPER 003 1,950,681 178
PDTS CO.
VA............. CHESAPEAKE PAPER 004 487,946 44
PDTS CO.
VA............. STONE CONTAINER 004 5,141,951 468
CORP.
VA............. ALLIED-SIGNAL 002 5,140,799 468
INC.
VA............. ALLIED-SIGNAL 016 7,509,947 684
INC.
VA............. JAMES RIVER 001 3,761,847 342
COGENERATION
(COGE.
VA............. HOECHST CELANESE 007 911,520 83
CORP.
VA............. UNION CAMP CORP/ 004 2,379,652 217
FINE PAPER DIV.
VA............. ALLIED-SIGNAL 017 595,170 54
INC.
VA............. WESTVACO CORP... 002 1,076,877 98
VA............. UNION CAMP CORP/ 016 380,432 35
FINE PAPER DIV.
VA............. HOECHST CELANESE 006 877,200 80
CORP.
VA............. WESTVACO CORP... 001 1,413,167 129
VA............. WESTVACO CORP... 003 1,545,951 141
VA............. WESTVACO CORP... 004 2,616,233 238
VA............. DUPONT, EI 001 401,760 37
DENEMOURS & CO.
VA............. DUPONT, EI 002 532,691 48
DENEMOURS & CO.
VA............. DUPONT, EI 003 373,553 34
DENEMOURS & CO.
VA............. GEORGIA-PACIFIC. 002 673,368 61
VA............. E I DUPONT DE 004 1,344,182 122
NEMOURS & CO.
VA............. HOECHST CELANESE 003 885,360 81
CORP.
VA............. E I DUPONT DE 006 1,281,074 117
NEMOURS & CO.
VA............. E I DUPONT DE 007 978,350 89
NEMOURS & CO.
VA............. HOECHST CELANESE 005 656,880 60
CORP.
VA............. E I DUPONT DE 008 1,272,956 116
NEMOURS & CO.
[[Page 56387]]
VA............. HOECHST CELANESE 002 612,000 56
CORP.
VA............. E I DUPONT DE 005 1,202,326 109
NEMOURS & CO.
VA............. HOECHST CELANESE 004 226,800 21
CORP.
WV............. ELKEM METALS 016 435,240 58
COMPANY--ALLOY
P.
WV............. DU PONT--BELLE.. 0ZD 844,340 113
WV............. BASF CORPORATION 003 312,814 42
HUNTINGTON WO.
WV............. WEIRTON STEEL 030 1,209,426 161
CORPORATION.
WV............. WEIRTON STEEL 088 500,915 67
CORPORATION.
WV............. WEIRTON STEEL 089 305,643 41
CORPORATION.
WV............. WEIRTON STEEL 090 585,781 78
CORPORATION.
WV............. WEIRTON STEEL 091 580,467 77
CORPORATION.
WV............. WEIRTON STEEL 092 721,698 96
CORPORATION.
WV............. WEIRTON STEEL 093 702,068 94
CORPORATION.
WV............. QUAKER STATE 001 693,049 92
REFINING CORP.
--.
WV............. QUAKER STATE 002 709,589 95
REFINING CORP.
--.
WV............. QUAKER STATE 004 743,213 99
REFINING CORP.
--.
WV............. DU PONT--BELLE.. 0ZA 1,046,722 140
WV............. WEIRTON STEEL 087 413,954 55
CORPORATION.
WV............. DU PONT--BELLE.. 0ZC 380,180 51
WV............. DU PONT 0P6 803,015 107
WASHINGTON
WORKS.
WV............. DU PONT--BELLE.. 0ZE 1,079,138 144
WV............. FMC CORPORATION-- 003 4,423,563 590
STEAM PLANT.
WV............. UNION CARBIDE-- 0B1 737,843 98
SOUTH CHARLEST.
WV............. PPG INDUSTRIES, 001 1,402,296 187
INC.
WV............. PPG INDUSTRIES, 002 824,976 110
INC.
WV............. PPG INDUSTRIES, 003 2,445,280 326
INC.
WV............. BAYER 022 206,694 28
CORPORATION.
WV............. COLUMBIAN 032 296,762 40
CHEMICALS CO.
WV............. CYTEC INDUSTRIES OWA 362,304 48
WV............. CYTEC INDUSTRIES OWB 362,304 48
WV............. DU PONT OP4 351,654 47
WASHINGTON
WORKS.
WV............. DU PONT OP5 608,426 81
WASHINGTON
WORKS.
WV............. DU PONT--BELLE.. OZB 898,968 120
------------------------------------------------------------------------
Appendix B to Part 97--NOx Allowance Allocation Tables
for Affected Sources Under Section 110 of the Act in Georgia, South
Carolina, and Wisconsin
Table B.1.--Allocations to Fossil Fuel-Fired EGUs by mmBtu and MWh
----------------------------------------------------------------------------------------------------------------
Unit Unit
average of average of
two highest two Highest Unit Unit
State Plant ID Point ID Plant of 1995, of 1995, allocations allocation
1996, or 1996, or by HI s by MWh
1997 summer 1997 summer
HI MWh
----------------------------------------------------------------------------------------------------------------
GA............ 699 1 ARKWRIGHT...... 576,855 55,467 45 42
GA............ 699 2 ARKWRIGHT...... 586,172 56,363 46 43
GA............ 699 3 ARKWRIGHT...... 699,177 67,229 55 51
GA............ 699 4 ARKWRIGHT...... 629,120 60,492 49 46
GA............ 700 A2 ATKINSON....... 906,420 85,511 71 65
GA............ 700 A3 ATKINSON....... 817,568 62,880 64 48
GA............ 700 A4 ATKINSON....... 754,261 58,199 59 44
GA............ 703 1BLR BOWEN.......... 21,604,980 2,244,673 1,696 1,713
GA............ 703 2BLR BOWEN.......... 22,900,012 2,406,980 1,798 1,837
GA............ 703 3BLR BOWEN.......... 28,660,178 3,033,144 2,250 2,314
GA............ 703 4BLR BOWEN.......... 26,354,043 2,794,110 2,069 2,132
GA............ 708 1 HAMMOND........ 2,110,931 210,861 166 161
GA............ 708 2 HAMMOND........ 2,040,405 191,336 160 146
GA............ 708 3 HAMMOND........ 2,025,655 192,480 159 147
GA............ 708 4 HAMMOND........ 10,921,707 1,088,470 858 831
GA............ 709 1 HARLLEE BRANCH. 6,718,809 684,684 528 522
GA............ 709 2 HARLLEE BRANCH. 8,055,215 830,949 632 634
GA............ 709 3 HARLLEE BRANCH. 13,120,649 1,392,407 1,030 1,062
GA............ 709 4 HARLLEE BRANCH. 13,892,588 1,492,864 1,091 1,139
GA............ 54538 MAG1 HARTWELL ENERGY 22,233 2,616 2 2
FACILITY.
GA............ 54538 MAG2 HARTWELL ENERGY 26,322 3,097 2 2
FACILITY.
GA............ 710 MB1 JACK MCDONOUGH. 6,978,996 702,254 548 536
GA............ 710 MB2 JACK MCDONOUGH. 7,807,471 791,913 613 604
GA............ 733 1 KRAFT.......... 1,099,803 97,856 86 75
GA............ 733 2 KRAFT.......... 981,804 89,917 77 69
GA............ 733 3 KRAFT.......... 1,950,273 184,023 153 140
GA............ 733 4 KRAFT.......... 664,593 65,769 52 50
GA............ 6124 1 MCINTOSH....... 4,024,081 410,746 316 313
GA............ 6124 --CT3 MCINTOSH....... 345,688 26,942 27 21
GA............ 6124 --CT4 MCINTOSH....... 325,133 25,340 26 19
GA............ 6124 --CT5 MCINTOSH....... 341,543 26,619 27 20
GA............ 6124 --CT6 MCINTOSH....... 340,759 26,557 27 20
GA............ 6124 --CT7 MCINTOSH....... 315,416 32,195 25 25
[[Page 56388]]
GA............ 6124 --CT8 MCINTOSH....... 328,841 33,565 26 26
GA............ 715 1 MCMANUS........ 589,903 55,651 46 42
GA............ 715 2 MCMANUS........ 954,370 94,027 75 72
GA............ 727 3 MITCHELL....... 3,043,908 306,784 239 234
GA............ 734 12 RIVERSIDE...... 193,852 17,000 15 13
GA............ 7348 CT1 ROBINS......... 268,614 31,602 21 24
GA............ 7348 CT2 ROBINS......... 292,814 34,449 23 26
GA............ 6257 1 SCHERER........ 23,234,939 2,383,804 1,824 1,819
GA............ 6257 2 SCHERER........ 24,621,510 2,553,039 1,933 1,948
GA............ 6257 3 SCHERER........ 25,671,808 2,581,378 2,016 1,970
GA............ 6257 4 SCHERER........ 29,025,526 2,918,605 2,279 2,227
GA............ 6052 1 WANSLEY........ 21,381,911 2,300,367 1,679 1,755
GA............ 6052 2 WANSLEY........ 21,242,550 2,283,163 1,668 1,742
GA............ 6052 --5A WANSLEY........ 100,644 7,625 8 6
GA............ 728 Y1BR YATES.......... 1,867,410 161,164 147 123
GA............ 728 Y2BR YATES.......... 2,067,213 182,165 162 139
GA............ 728 Y3BR YATES.......... 1,867,344 156,630 147 120
GA............ 728 Y4BR YATES.......... 2,626,026 261,739 206 200
GA............ 728 Y5BR YATES.......... 2,296,410 221,000 180 169
GA............ 728 Y6BR YATES.......... 6,632,004 659,048 521 503
GA............ 728 Y7BR YATES.......... 6,805,284 689,632 534 526
SC............ 3280 CAN1 CANADYS STEAM.. 2,869,700 284,129 282 276
SC............ 3280 CAN2 CANADYS STEAM.. 3,511,752 347,698 345 338
SC............ 3280 CAN3 CANADYS STEAM.. 4,088,313 400,815 401 389
SC............ 7210 COP1 COPE........... 10,227,161 983,381 1,004 955
SC............ 130 1 CROSS.......... 15,587,385 1,640,777 1,530 1,594
SC............ 130 2 CROSS.......... 14,641,271 1,534,724 1,437 1,491
SC............ 3317 1 DOLPHUS M 1,668,846 160,899 164 156
GRAINGER.
SC............ 3317 2 DOLPHUS M 1,453,280 140,549 143 137
GRAINGER.
SC............ 3251 1 H B ROBINSON... 4,576,700 469,984 449 457
SC............ 3285 --4 HAGOOD......... 195,876 15,853 19 15
SC............ 3318 --3 HILTON HEAD.... 96,373 7,301 9 7
SC............ 3319 1 JEFFERIES...... 87,283 8,234 9 8
SC............ 3319 2 JEFFERIES...... 95,610 9,020 9 9
SC............ 3319 3 JEFFERIES...... 3,609,158 356,460 354 346
SC............ 3319 4 JEFFERIES...... 3,821,882 385,309 375 374
SC............ 3287 MCM1 MCMEEKIN....... 4,125,180 438,849 405 426
SC............ 3287 MCM2 MCMEEKIN....... 3,928,408 417,916 386 406
SC............ 50806 ST__NER STONE CONTAINER 1,347,859 127,157 132 124
SC............ 3295 URQ1 URQUHART....... 2,118,629 207,709 208 202
SC............ 3295 URQ2 URQUHART....... 2,190,221 214,728 215 209
SC............ 3295 URQ3 URQUHART....... 3,017,055 307,863 296 299
SC............ 3264 1 W S LEE........ 1,529,058 130,232 150 127
SC............ 3264 2 W S LEE........ 1,653,216 148,138 162 144
SC............ 3264 3 W S LEE........ 2,934,022 293,402 288 285
SC............ 3264 --4 W S LEE........ 50,719 3,559 5 3
SC............ 3297 WAT1 WATEREE........ 8,329,168 849,915 818 826
SC............ 3297 WAT2 WATEREE........ 10,033,636 1,023,840 985 995
SC............ 3298 WIL1 WILLIAMS....... 20,429,832 2,084,677 2,006 2,025
SC............ 6249 1 WINYAH......... 7,076,385 728,773 695 708
SC............ 6249 2 WINYAH......... 7,783,646 780,472 764 758
SC............ 6249 3 WINYAH......... 6,588,503 620,913 647 603
SC............ 6249 4 WINYAH......... 7,930,443 802,758 779 780
WI............ 4140 B4 ALMA........... 906,033 82,667 68 64
WI............ 4140 B5 ALMA........... 1,322,085 127,590 99 99
WI............ ........... 2 ARCADIA 359 25 0 0
MUNICIPAL
ELECTRIC.
WI............ ........... 3 ARCADIA 181 13 0 0
MUNICIPAL
ELECTRIC.
WI............ ........... 4 ARCADIA 78 5 0 0
MUNICIPAL
ELECTRIC.
WI............ ........... 5 ARCADIA 4,411 310 0 0
MUNICIPAL
ELECTRIC.
WI............ ........... CT1 BEACH.......... 8,810 618 1 0
WI............ 3992 8 BLOUNT STREET.. 746,085 61,609 56 48
WI............ 3992 9 BLOUNT STREET.. 883,198 72,931 66 56
WI............ 8023 1 COLUMBIA....... 17,697,465 1,721,376 1,328 1,333
WI............ 8023 2 COLUMBIA....... 19,254,893 1,881,831 1,445 1,458
WI............ 7159 --1 CONCORD........ 234,673 19,126 18 15
WI............ 7159 --2 CONCORD........ 252,008 20,539 19 16
WI............ 7159 --3 CONCORD........ 222,583 16,862 17 13
WI............ 7159 --4 CONCORD........ 217,995 16,515 16 13
WI............ ........... .............. CUMBERLAND 193 14 0 0
MUNICIPAL
UTILITY.
WI............ ........... .............. CUMBERLAND 280 20 0 0
MUNICIPAL
UTILITY.
WI............ ........... .............. CUMBERLAND 374 26 0 0
MUNICIPAL
UTILITY.
WI............ ........... .............. CUMBERLAND 584 41 0 0
MUNICIPAL
UTILITY.
WI............ ........... 1 DANBURY........ 65 5 0 0
WI............ ........... 2 DANBURY........ 73 5 0 0
WI............ ........... 3 DANBURY........ 158 11 0 0
WI............ 4050 3 EDGEWATER...... 1,632,111 139,963 122 108
[[Page 56389]]
WI............ 4050 4 EDGEWATER...... 8,821,558 917,097 662 710
WI............ 4050 5 EDGEWATER...... 12,812,254 1,206,427 961 935
WI............ ........... 1 FITCHBURG...... 93,659 6,573 7 5
WI............ ........... 2 FITCHBURG...... 90,110 6,323 7 5
WI............ ........... CT1 FLAMBEAU....... 78,623 5,517 6 4
WI............ ........... 2 FREDERIC....... 20 1 0 0
WI............ ........... 3 FREDERIC....... 19 1 0 0
WI............ ........... 4 FREDERIC....... 144 10 0 0
WI............ ........... 5 FREDERIC....... 103 7 0 0
WI............ ........... 6 FREDERIC....... 705 49 0 0
WI............ ........... 7 FREDERIC....... 871 61 0 0
WI............ ........... CT1 FRENCH ISLAND.. 56,592 4,287 4 3
WI............ ........... CT2 FRENCH ISLAND.. 20,835 1,578 2 1
WI............ 4143 1 GENOA.......... 9,095,142 1,001,668 682 776
WI............ 6253 --1 GERMANTOWN..... 107,413 8,137 8 6
WI............ 6253 --2 GERMANTOWN..... 107,413 8,137 8 6
WI............ 6253 --3 GERMANTOWN..... 107,413 8,137 8 6
WI............ 6253 --4 GERMANTOWN..... 107,413 8,137 8 6
WI............ 4271 B1 J P MADGETT.... 9,339,971 841,818 701 652
WI............ ........... CT1 MANITOWOC...... 21,524 1,510 2 1
WI............ ........... 31 MARINETTE...... 76,764 5,387 6 4
WI............ ........... 32 MARINETTE...... 22,262 1,562 2 1
WI............ ........... 33 MARINETTE...... 383,016 29,016 29 22
WI............ 54851 GT__MSD MMSD........... 22,263 1,562 2 1
WI............ 4054 1 NELSON DEWEY... 2,969,241 276,363 223 214
WI............ 4054 2 NELSON DEWEY... 3,141,352 301,995 236 234
WI............ ........... 1 NINE SPRINGS... 16,452 1,155 1 1
WI............ ........... .............. Northwestern 37 3 0 0
Wisconsin
Electric Com.
WI............ ........... .............. Northwestern 50 4 0 0
Wisconsin
Electric Com.
WI............ ........... .............. Northwestern 391 27 0 0
Wisconsin
Electric Com.
WI............ ........... .............. Northwestern 1,127 79 0 0
Wisconsin
Electric Com.
WI............ 7270 **1 PARIS.......... 382,238 28,957 29 22
WI............ 7270 **2 PARIS.......... 487,654 36,943 37 29
WI............ 7270 **3 PARIS.......... 524,161 39,709 39 31
WI............ 7270 **4 PARIS.......... 386,103 29,250 29 23
WI............ 6170 1 PLEASANT 23,012,814 2,129,633 1,727 1,650
PRAIRIE.
WI............ 6170 2 PLEASANT 21,265,904 1,967,972 1,596 1,524
PRAIRIE.
WI............ ........... AUX1 PLEASANT 18,405 1,736 1 1
PRAIRIE.
WI............ ........... AUX2 PLEASANT 10,617 1,002 1 1
PRAIRIE.
WI............ 4040 1 PORT WASHINGTON 1,295,715 124,588 97 97
WI............ 4040 2 PORT WASHINGTON 1,613,882 155,660 121 121
WI............ 4040 3 PORT WASHINGTON 1,719,476 167,362 129 130
WI............ 4040 4 PORT WASHINGTON 1,439,805 140,141 108 109
WI............ 4072 4 PULLIAM........ 395,870 38,064 30 29
WI............ 4072 5 PULLIAM........ 1,150,234 94,904 86 74
WI............ 4072 6 PULLIAM........ 1,994,261 167,726 150 130
WI............ 4072 7 PULLIAM........ 2,684,757 258,722 201 200
WI............ 4072 8 PULLIAM........ 4,610,833 453,020 346 351
WI............ ........... 3 RIVER FALLS 36 3 0 0
MUNICIPAL
UTILITY.
WI............ ........... 5 RIVER FALLS 2,527 177 0 0
MUNICIPAL
UTILITY.
WI............ ........... 7 RIVER FALLS 11,357 797 1 1
MUNICIPAL
UTILITY.
WI............ 4057 1 ROCK RIVER..... 1,999,193 168,666 150 131
WI............ 4057 2 ROCK RIVER..... 2,050,594 170,174 154 132
WI............ ........... 3 ROCK RIVER..... 29,868 2,096 2 2
WI............ ........... 4 ROCK RIVER..... 15,112 1,060 1 1
WI............ ........... 5 ROCK RIVER..... 166,306 12,599 12 10
WI............ ........... 6 ROCK RIVER..... 70,005 5,303 5 4
WI............ ........... 30 SHEEPSKIN...... 124,716 8,752 9 7
WI............ 7203 **CT1 SOUTH FOND DU 262,538 19,889 20 15
LAC.
WI............ 7203 **CT2 SOUTH FOND DU 275,481 18,992 21 15
LAC.
WI............ 7203 **CT3 SOUTH FOND DU 260,349 18,555 20 14
LAC.
WI............ 4041 5 SOUTH OAK CREEK 5,906,838 667,439 443 517
WI............ 4041 6 SOUTH OAK CREEK 6,206,014 701,244 466 543
WI............ 4041 7 SOUTH OAK CREEK 8,697,896 978,611 653 758
WI............ 4041 8 SOUTH OAK CREEK 8,278,088 921,016 621 713
WI............ ........... 1 SYCAMORE....... 33,342 2,340 3 2
WI............ ........... 2 SYCAMORE....... 73,840 5,182 6 4
WI............ 4042 1 VALLEY......... 1,387,542 119,133 104 92
WI............ 4042 2 VALLEY......... 1,420,141 121,932 107 94
WI............ 4042 3 VALLEY......... 1,856,188 158,014 139 122
WI............ 4042 4 VALLEY......... 1,745,618 148,601 131 115
WI............ ........... CT1 WASHINGTON 75 5 0 0
ISLAND
ELECTRIC
COOPERAT.
WI............ ........... CT2 WASHINGTON 46 3 0 0
ISLAND
ELECTRIC
COOPERAT.
WI............ ........... CT3 WASHINGTON 3 0 0 0
ISLAND
ELECTRIC
COOPERAT.
WI............ ........... CT4 WASHINGTON 94 7 0 0
ISLAND
ELECTRIC
COOPERAT.
WI............ ........... CT5 WASHINGTON 153 11 0 0
ISLAND
ELECTRIC
COOPERAT.
[[Page 56390]]
WI............ ........... CT6 WASHINGTON 270 19 0 0
ISLAND
ELECTRIC
COOPERAT.
WI............ 4076 --33 WEST MARINETTE. 227,932 18,531 17 14
WI............ 4078 1 WESTON......... 1,706,613 143,124 128 111
WI............ 4078 2 WESTON......... 2,947,494 274,594 221 213
WI............ 4078 3 WESTON......... 12,197,388 1,197,819 915 928
WI............ ........... 1 WHEATON........ 52,813 4,001 4 3
WI............ ........... 2 WHEATON........ 58,350 4,420 4 3
WI............ ........... 3 WHEATON........ 48,564 3,679 4 3
WI............ ........... 4 WHEATON........ 40,981 3,105 3 2
WI............ ........... 5 WHEATON........ 23,635 1,791 2 1
WI............ ........... 6 WHEATON........ 17,227 1,305 1 1
----------------------------------------------------------------------------------------------------------------
Table B.2.--Allocations to Non-EGUs by mmBtu
------------------------------------------------------------------------
Unit
State Plant Point ID Unit 1995 allocations
summer HI by HI
------------------------------------------------------------------------
GA............. MERCK & CO INC.. 004 1,137,138 134
GA............. FEDERAL PAPER 007 2,551,114 300
BOARD CO INC.
GA............. DSM CHEMICALS 001 1,137,974 134
NORTH AMERICA
INC.
GA............. PACKAGING CORP 015 1,239,138 146
OF AMERICA.
GA............. INTERSTATE PAPER 006 771,395 91
CORP.
GA............. CARGILL......... 001 461,546 54
GA............. BLUE............ 001 25,892 3
GA............. INLAND-ROME..... 001 986,136 116
GA............. GILMAN PAPER CO 003 1,715,895 202
ST MARYS KRAFT
BAG.
GA............. AUSTELL......... 001 1,507,475 177
GA............. FEDERAL PAPER 008 3,189,139 375
BOARD CO INC.
GA............. GILMAN PAPER CO 016 2,130,015 250
ST MARYS KRAFT
BAG.
GA............. UNION CAMP CORP. 018 1,404 0
GA............. UNION CAMP CORP. 019 1,749,095 206
GA............. UNION CAMP CORP. 020 3,300,620 388
GA............. UNION CAMP CORP. 021 4,611,960 542
GA............. SAVANNAH SUGAR 017 370,056 44
REFINERY.
SC............. SPRINGS 004 93,432 13
IND:GRACE.
SC............. HOECHST/ 005 1,284,708 175
CEL:ROCKHILL.
SC............. GOODYEAR:SPARTAN 001 5,196 1
BURG.
SC............. CAROLINA EASTMAN 005 823,637 112
CO.
SC............. CAROLINA EASTMAN 006 348,861 48
CO.
SC............. GASTON COPPER 006 151,636 21
RECYCL.
SC............. WILLAMETTE:BNVL 005 552,532 75
PULP.
SC............. UNION 001 2,637,388 360
CAMP:EASTOVER.
SC............. CAROLINA EASTMAN 004 1,224,571 167
CO.
SC............. TRANDCENTNTL 005 16,691 2
PIPELINE.
SC............. BOWATER CAROLINA 001 66,597 9
CO.
SC............. HOECHST/ 001 858,080 117
CEL:ROCKHILL.
SC............. HOECHST/ 002 858,080 117
CEL:ROCKHILL.
SC............. HOECHST/ 004 1,284,708 175
CEL:ROCKHILL.
SC............. HOECHST/ 006 1,352,714 185
CEL:ROCKHILL.
SC............. DUPONT,EI:MAY 015 1,058,715 145
PLANT.
SC............. SPRINGS 003 962,472 131
IND:GRACE.
SC............. HOECHST/ 003 858,080 117
CEL:ROCKHILL.
SC............. WESTVACO:KRAFT 007 1,534,180 210
DIV.
SC............. CAROLINA EASTMAN 003 1,174,931 160
CO.
SC............. DUPONT, EI:MAY 014 1,110,177 152
PLANT.
SC............. SAVANNAH R 001 322,804 44
PL:AREA D.
SC............. SAVANNAH R 002 1,160,658 159
PL:AREA D.
SC............. SAVANNAH R 003 270,000 37
PL:AREA D.
SC............. WESTVACO:KRAFT 003 604,557 83
DIV.
SC............. SONOCO:HARTSVILL 003 992,068 135
E.
SC............. SONOCO:HARTSVILL 004 1,245,367 170
E.
SC............. STONE 002 699,348 96
CONT:FLORENCE.
SC............. US AIRFORCE:MRTL 007 1,246 0
BCH.
SC............. STONE 010 4,460,897 609
CONT:FLORENCE.
SC............. US FINISHING.... 004 12,125 2
SC............. US FINISHING.... 005 6,928 1
SC............. US FINISHING.... 006 1,155 0
SC............. CAROTELL PAPER 004 17,136 2
BOARD.
SC............. US AIRFORCE:MRTL 005 2,476 0
BCH.
SC............. STONE 004 1,736,541 237
CONT:FLORENCE.
SC............. SAVANNAH R 004 501,768 69
PL:AREA D.
WI............. LADISH MALTING B28 79,675 12
CO.
WI............. TENNECO B30 8,660 1
PACKAGING INC.
WI............. A.A. LAUN B21 0 0
FURNITURE CO.
WI............. MILLER BREWING B20 465,928 71
COMPANY
MILWAUKEE PLANT.
[[Page 56391]]
WI............. PROCTER & GAMBLE B06 193,276 30
PAPER PRODUCTS
COMPANY.
WI............. WIS DOA / UW- B20 32,909 5
MILWAUKEE POWER
PLANT.
WI............. ST. JOSEPH'S T07 577 0
HOSPITAL.
WI............. WAUSAU PAPER B25 65,242 10
MILLS COMPANY.
WI............. WIS DOA / UW B25 256,925 39
MADISON--CHARTE
R ST.
WI............. WIS DOA / UW B21 608,077 93
MADISON--CHARTE
R ST.
WI............. FORT HOWARD B26 1,448,966 222
CORPORATION.
WI............. PROCTER & GAMBLE B05 80,349 12
PAPER PRODUCTS
COMPANY.
WI............. PROCTER & GAMBLE B07 116,626 18
PAPER PRODUCTS
COMPANY.
WI............. JAMES RIVER B01 419,007 64
CORPORATION--GR
EEN BAY MILL.
WI............. ST. JOSEPH'S T08 577 0
HOSPITAL.
WI............. ANDIS COMPANY... B10 577 0
WI............. FORT HOWARD B29 1,785,381 273
CORPORATION.
WI............. FORT HOWARD B27 2,670,322 409
CORPORATION.
WI............. GREAT LAKES GAS P01 716,318 110
TRANSMISSION-
COMP STATIO.
WI............. ANDIS COMPANY... B11 0 0
WI............. BURNETT MEDICAL B22 1,155 0
CENTER.
WI............. CONSOLIDATED B24 70,438 11
PAPERS INC-
KRAFT DIV.
WI............. CONSOLIDATED B21 1,286,371 197
PAPERS INC-
KRAFT DIV.
WI............. NEKOOSA PAPERS B24 848,238 130
INC NEKOOSA
MILL.
WI............. CONSOLIDATED B20 1,566,432 240
PAPERS INC-
KRAFT DIV.
WI............. CONSOL PAPERS B24 1,538,813 236
INC BIRON DIV.
WI............. FLAMBEAU PAPER I50 9,815 2
CORP.
WI............. DELUXE CHECK B20 1,732 0
PRINTERS.
WI............. HYDRO-PLATERS, B01 0 0
INC.
WI............. BLOUNT INC. B20 1,155 0
FORESTY &
INDUSTRIAL
EQUIP D.
WI............. APPLETON PAPERS B23 1,453,493 223
INC LOCKS MILL.
WI............. APPLETON PAPERS B05 35,796 5
INC LOCKS MILL.
WI............. THILMANY PULP & B11 1,460,691 224
PAPER COMPANY.
WI............. RHINELANDER B26 1,370,808 210
PAPER CO.
WI............. QUAD/GRAPHICS, B02 577 0
INC.
WI............. QUAD/GRAPHICS, B01 577 0
INC.
WI............. PRINTWORKS INC.. P33 577 0
WI............. CONSOL PAPERS B23 1,274,336 195
INC BIRON DIV.
------------------------------------------------------------------------
Appendix C to Part 97-State-by-State Maximum Summer NOX
Emission Levels and Allocation Aggregates
----------------------------------------------------------------------------------------------------------------
EGU Non-EGU
EGU maximum allocations Non-EGU allocations
State summer NOx (95% of maximum (95% of
Tons maximum summer NOx maximum
summer) tons summer)
----------------------------------------------------------------------------------------------------------------
AL.......................................................... 28,884 27,440 3,347 3,179
CT.......................................................... 2,545 2,418 283 269
DC.......................................................... 207 196 18 17
DE.......................................................... 3,489 3,315 238 226
GA.......................................................... 30,061 28,558 3,328 3,161
IL.......................................................... 30,165 28,657 3,600 3,420
IN.......................................................... 46,627 44,296 11,325 10,758
KY.......................................................... 36,315 34,499 1,709 1,624
MA.......................................................... 14,619 13,888 232 220
MD.......................................................... 14,788 14,048 802 762
MI.......................................................... 26,344 25,027 2,844 2,702
MO.......................................................... 23,171 22,012 132 126
NC.......................................................... 29,967 28,468 3,277 3,113
NJ.......................................................... 7,898 7,503 3,882 3,688
NY.......................................................... 29,391 27,921 4,409 4,189
OH.......................................................... 45,776 43,487 8,693 8,258
PA.......................................................... 48,038 45,636 4,657 4,424
RI.......................................................... 1,115 1,059 0 0
SC.......................................................... 16,286 15,472 4,355 4,137
TN.......................................................... 25,386 24,117 8,085 7,681
VA.......................................................... 18,009 17,109 5,372 5,104
WI.......................................................... 16,751 15,913 3,204 3,043
WV.......................................................... 26,439 25,117 3,509 3,334
---------------------------------------------------
Total................................................. 522,271 496,157 77,300 73,436
----------------------------------------------------------------------------------------------------------------
[FR Doc. 98-26292 Filed 10-20-98; 8:45 am]
BILLING CODE 6560-50-P
