[Federal Register Volume 63, Number 90 (Monday, May 11, 1998)]
[Proposed Rules]
[Pages 25902-25994]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 98-11873]
[[Page 25901]]
_______________________________________________________________________
Part II
Environmental Protection Agency
_______________________________________________________________________
40 CFR Parts 51, 76, and 96
Supplemental Notice for the Finding of Significant Contribution and
Rulemaking for Certain States in the Ozone Transport Assessment Group
Region for Purposes of Reducing Regional Transport of Ozone; Proposed
Rule
Federal Register / Vol. 63, No. 90 / Monday, May 11, 1998 / Proposed
Rules
[[Page 25902]]
ENVIRONMENTAL PROTECTION AGENCY
40 CFR Parts 51, 76, and 96
[FRL-6008-6]
RIN 2060-AH10
Supplemental Notice for the Finding of Significant Contribution
and Rulemaking for Certain States in the Ozone Transport Assessment
Group Region for Purposes of Reducing Regional Transport of Ozone
AGENCY: Environmental Protection Agency (EPA).
ACTION: Supplemental Notice of Proposed Rulemaking (SNPR).
-----------------------------------------------------------------------
SUMMARY: In accordance with the Clean Air Act (CAA), today's action is
a SNPR to EPA's November 7, 1997 notice of proposed rulemaking (NPR).
This action augments EPA's proposal to require certain States to submit
State implementation plan (SIP) measures to ensure that emissions
reductions are achieved as needed to mitigate transport of ozone (smog)
pollution and one of its main precursors--emissions of oxides of
nitrogen (NOX)--across State boundaries in the eastern half
of the United States.
Ozone 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.
Today's action includes proposed rule language for the November 7,
1997 NPR for the 23 jurisdictions, revised statewide emissions budgets
and cost analysis, proposed State reporting requirements and SIP
approvability criteria, a proposed model cap-and-trade rule, a
discussion of the interaction between this proposal and the title IV
NOX rule, and air quality analyses of the proposed statewide
emissions budgets.
The EPA intends to finalize today's action and the November 7, 1997
NPR simultaneously in the September 1998 timeframe.
DATES: The EPA is establishing a 45-day comment period, ending on June
25, 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). A public hearing will be held on May 29,
1998, beginning at 9:00 am. Please refer to SUPPLEMENTARY INFORMATION
for details.
ADDRESSES: Comments may be submitted to the Air and Radiation Docket
and Information Center (6101), Attention: Docket No. A-96-56, US
Environmental Protection Agency, 401 M Street SW, room M-1500,
Washington, DC 20460, telephone (202) 260-7548, between 8:00 a.m. and
4:00 p.m., Monday through Friday, excluding legal holidays. A
reasonable fee may be charged for copying. 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. A courtesy copy
of comments to David Cole 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) 541-5565, Fax
(919) 541-0824. An electronic copy would also be helpful to
[email protected]. The address for sending overnight packages is US
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 at 401 M Street SW, Washington, DC, 20460.
FOR FURTHER INFORMATION CONTACT: General questions concerning today's
action should be addressed to Kimber Smith Scavo, Office of Air Quality
Planning and Standards, Air Quality Strategies and Standards Division,
MD-15, Research Triangle Park, NC 27711, telephone (919) 541-3354.
Please refer to SUPPLEMENTARY INFORMATION below for a list of contacts
for specific subjects described in today's action.
SUPPLEMENTARY INFORMATION:
Reopening of November 7, 1997 NPR Comment Period and Technical
Analyses
The Agency will ensure that all comments and technical analyses
received on the November 7, 1997 NPR (62 FR 60318) and this SNPR are
made publicly available in the docket to this rulemaking. The EPA will
accept comments on all issues raised in today's SNPR, as well as
comments concerning the implications that any such issues may have for
issues raised in the November 7, 1997 NPR. In addition, on April 9,
1998 (63 FR 17349), EPA published a notice in the Federal Register that
discussed additional items related to the November 7, 1998 NPR for
which the Agency is reopening the comment period. Therefore, the
comment period for the November 7, 1997 NPR is reopened until June 25,
1998 for the items specified in the April 9, 1998 notice.
Public Hearing
The EPA will conduct a public hearing on today's proposal on May
29, 1998 beginning at 9:00 a.m. The public hearing will be held at the
EPA Auditorium at 401 M Street SW., Washington, DC 20460. The metro
stop is Waterfront which is on the green line. Persons planning to
present oral testimony at the hearing should notify JoAnn Allman,
Office of Air Quality Planning and Standards, Air Quality Strategies
and Standards Division, MD-15, Research Triangle Park, NC 27711,
telephone (919) 541-1815 no later than May 22, 1998. Oral testimony
will be limited to 5 minutes each. Any member of the public may file a
written statement before, during, or by the close of the comment period
after the hearing. For written statements concerning the proposed
amended 40 CFR Part 76, the hearing record will be kept open for 30
days after the hearing date, under section 307(d)(5)(iv) of the CAA to
provide an opportunity for submission of rebuttal and supplementary
information. Written statements (duplicate copies preferred) should be
submitted to the docket at the above address. A hearing schedule
including a list of speakers will be posted on EPA's SIP call webpage
at http://www.epa.gov/ttn/oarpg/otagsip.html prior to the hearing.
Following the hearing, a verbatim transcript of the hearing and
written statements will be made available for copying during normal
working hours at the Air and Radiation Docket Information Center at the
above address. The Agency does not plan to schedule any additional
hearings on the proposed rule.
Electronic Availability
The official record for this rulemaking, as well as the public
version, has been established under docket number A-96-56 (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.
[[Page 25903]]
Electronic comments can be sent directly to EPA at: A-and-R-
D[email protected]. 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 6.1 (or 5.1) file format or ASCII file format. All
comments and data in electronic form must be identified by the docket
number A-96-56. Electronic comments on this proposed rule may be filed
online at many Federal Depository Libraries.
Availability of Related Information
Documents related to the Ozone Transport Assessment Group (OTAG)
are 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. The October 10, 1997
signature version of the proposed SIP call, the November 7, 1997
Federal Register version, and associated documents are located at
http://epa.gov/ttn/oarpg/otagsip.html. Information related to Section
VII, Air Quality Assessment of the Statewide Emissions Budgets can be
obtained in electronic form from the following EPA website: http://
www.epa.gov/scram001/regmodcenter/t28.htm.
For Additional Information
For technical questions related to the air quality analyses, please
contact Norm Possiel; Office of Air Quality Planning and Standards,
Emissions, Monitoring, and Analysis Division; MD-14, Research Triangle
Park, NC 27711, telephone (919) 541-5692. 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
concerning the statewide emissions budget revisions, please contact
Laurel Schultz; Office of Air Quality Planning and Standards;
Emissions, Monitoring, and Analysis Division; MD-14, Research Triangle
Park, NC 27711, telephone (919) 541-5511. For questions concerning SIP
reporting requirements, please contact Bill Johnson, Office of Air
Quality Planning and Standards, Air Quality Strategies and Standards
Division, MD-15, Research Triangle Park, NC 27711, telephone (919) 541-
5245. For questions concerning the model cap-and-trade rule, please
contact Rob Lacount, Office of Atmospheric Programs, Acid Rain
Division, MC-6204J, 401 M Street SW, Washington, DC 20460, telephone
(202) 564-9122. For questions concerning the regulatory cost analysis
of 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
concerning the regulatory cost analysis of 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 November 7, 1997 NPR
B. Updates With 1994-96 Air Quality Data for the Findings of
Significant Contribution
II. Proposed Rule for the 23 Jurisdictions
III. Emissions Budgets Analyses
A. Explanation of Revised Budgets
1. Electricity Generating Units
a. Addition of Sources
b. Growth Factors
c. Revised Budget Component
d. Alternative Approach to Calculating the Component of the
Budget for Electricity Generation
2. Non-Electricity Generating Point Sources
a. Addition of Sources
b. Application of Controls
c. Revised Budget Component
d. Options for Calculating the Budgets
3. Revised State Budgets
B. Revised Cost Analyses
1. Electricity Generating Sources
2. Non-Electricity Generating Point Sources
3. Cost Analysis Results
IV. SIP Criteria and Emissions Reporting Requirements
A. SIP Criteria
1. Introduction
2. Completeness Determination
3. Approvability Criteria
a. Additional Control Strategy Approvability Criteria
i. Introduction
ii. General Recommendations
iii. New Proposed Approval Criteria
b. Emissions Inventory Preparation Guidance and Control
Strategies Guidance
c. Growth Estimates
d. Emissions Growth and Projection Guidance
B. Emissions Reporting Requirements
1. Use of Inventory Data
2. Legal Authority
3. Background for Reporting Requirements
4. Proposal
5. Annual Reporting
a. Point Sources
b. Area Sources
c. Mobile Sources
6. Reporting Every Third Year (3-year cycle reporting)
7. 2007 Report
8. Ozone Season Reporting
9. Data Reporting Procedures
10. Reporting Schedule
11. Confidential Data
12. Data Elements to be Reported
V. NOX Budget Trading Program
A. Program Summary
1. Purpose of the NOX Budget Trading Program
2. Emissions Reductions Required by the Proposed Transport
Rulemaking
3. Benefits of Participating in the NOX Budget
Trading Program
4. EPA's Proposal
B. Evolution of the NOX Budget Trading Program
1. OTC's NOX Budget Program
2. OTAG Process
3. EPA Model Trading Program Workshops
4. RECLAIM Program
C. NOX Budget Trading Program
1. General Provisions
a. Purpose
b. Definitions, Measurements, Abbreviations and Acronyms
c. Applicability
i. Monitoring
ii. Responsible Party
iii. Inclusion of Additional Source Categories
iv. Individual Opt-Ins
v. Additional Options for Applicability
vi. Area and Mobile Sources
d. Retired Unit Exemption
e. Standard Requirements
f. Computation of Time
2. NOX Authorized Account Representative (AAR)
3. Permits
a. General Requirements
b. Title V/Non-title V Permits
c. NOX Budget Permit Application Deadlines
d. NOX Budget Trading Program Permit Application
e. NOX Budget Permit Issuance
f. NOX Budget Permit Revisions
4. Compliance Certification
5. NOX Allowance Allocations
a. Development of State Trading Program Budget
b. Timing Requirements
c. Options for NOX Allowance Allocation
Recommendation
i. Basis for Developing an Allocation Recommendation
ii. Options for an Allocation Recommendation
iii. Framework for an Allocation Recommendation
6. NOX Allowance Tracking System
a. Compliance Accounts
b. Overdraft Accounts
c. Compliance
d. General Accounts
7. Banking
a. General Discussion
i. Banking After the Start of the Program
ii. Banking Prior to the Start of the Program
iii. Management of Banking
b. Options
i. Option 1: No Banking
ii. Option 2: Banking After Program Start Only
[[Page 25904]]
iii. Option 3: Early-Reduction Credits
iv. Option 4: Phased-In Program
8. Allowance Transfers
9. Emissions Monitoring and Reporting
a. Requirements for Point Sources
b. Output Information
10. Opt-Ins
a. Applicability for Opt-In Units
b. Allowance Allocations for Opt-In Units
c. Units Sharing Stacks or Fuel Pipe Headers with NOX
Budget Units
d. Withdrawal and Termination of Opt-In Units
11. Program Audits
12. Administration of Program
D. SIP Approvability
E. OTC Integration
1. Applicability
a. State Applicability
b. Source Applicability
2. Allocations
3. Emissions Banking
4. Emissions Monitoring and Reporting
5. Permitting
F. New Source Review
G. End Use Energy Efficiency and Renewable Energy
1. Background
2. Energy Efficiency and Renewables Set-Aside Options
VI. Interaction with Title IV NOX Rule
VII. Air Quality Assessment of the Statewide Emissions Budgets
Analyses
A. Background Information
B. Emissions Scenarios
1. Development of Emissions Inputs
a. Electric Generation Sources
b. Non-Electric Generation Point Sources
c. Mobile and Area Sources
2. Emissions Summaries
C. Analysis of Modeling Results
1. Technical Procedures
a. State-Level Analysis
i. Selection of Grid Cells for Analysis
ii. Procedures for Calculating State-Level Metrics
b. OTAG Standard Table of Metrics
D. Analysis Results and Findings
1. Introduction
a. Impacts on 1-Hour Ozone Concentrations
i. State-Level Analyses--1-Hour Concentrations
ii. Ozone Problem Area Analyses--1-Hour Concentrations
b. Impacts on 8-Hour Ozone Concentrations
i. State-Level Analyses--8-Hour Concentrations
ii. Ozone Problem Area Analyses--8-Hour Concentrations
2. Summary and Conclusions
E. Alternative Approaches
VIII. Impact on Small Entities
IX. Unfunded Mandates Reform Act
X. Paperwork Reduction Act
XI. Judicial Review
I. Background
A. Summary of November 7, 1997 NPR
The EPA's November 7, 1997 proposal 1 (hereafter
referred to as the ``proposed SIP call'' or ``SIP call'') proposed to
find that the transport of ozone and ozone precursors from 22 States
and the District of Columbia (23 jurisdictions) significantly
contributes to nonattainment of the ozone national ambient air quality
standards (NAAQS), or interferes with maintenance of the NAAQS, in
downwind States. The proposed SIP call explained the basis for
determining significant contribution or interference with maintenance
for the 23 jurisdictions. Further, the SIP call proposed the
appropriate levels of NOX emissions that each of the 23
jurisdictions would be required to achieve. The EPA also conducted a
regulatory cost analysis which is available in the docket to this
rulemaking (docket number II-B-01) as a technical support document
(TSD) to the proposed SIP call. A detailed explanation of how EPA
established the budgets is also available as a TSD to the proposal
(docket number III-B-02). These TSDs have been revised as explained in
Section III, Emissions Budgets Analyses.
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\1\ The EPA signed the November 7, 1997 NPR on October 10, 1997
and made it immediately available to the public on EPA's homepage at
http://www.epa.gov/ttn/oarpg/rules.html.
---------------------------------------------------------------------------
The SIP call proposed SIP requirements under CAA section 110(a)(1)
and section 110(k)(5) in order to meet the requirements of section
110(a)(2)(D), as it pertains to the ozone NAAQS, to prohibit ozone
precursor emissions from sources or activities in those States from
``contribut[ing] significantly to nonattainment in, or interfer[ing]
with maintenance by,'' a downwind State.
Based on this determination, the EPA proposed to require SIP
revisions in order to take steps toward ensuring that the necessary
regional reductions are achieved that will enable current ozone
nonattainment areas in the eastern half of the United States to prepare
attainment demonstrations and that will enable all areas to demonstrate
noninterference with maintenance of the ozone standard. This
requirement permits each State to choose for itself what measures to
adopt to meet the necessary emissions budget. Consistent with OTAG's
recommendations to achieve NOX emissions decreases primarily
from large stationary sources in a trading program, EPA encourages
States to consider electric utility and large boiler controls under a
cap-and-trade program as a cost-effective strategy. The cap-and-trade
program is described in more detail in Section V, NOX Budget
Trading Program.
B. Updates With 1994-96 Air Quality Data for the Findings of
Significant Contribution
In the proposed SIP call, EPA followed a weight of evidence
approach to determine which States cause a significant contribution to
nonattainment in downwind States. Part of the information EPA
considered in this determination included air quality modeling based on
the OTAG 2007 Base Case and OTAG ``zero-out'' subregional UAM-V
simulations. The results of the 2007 Base Case modeling were analyzed
with 1993-1995 ambient air quality measurements to identify areas which
(a) currently violate the NAAQS (based on monitoring) and (b) are
expected to continue to violate the NAAQS in the future (based on
modeling). The ``zero-out'' subregional modeling data were then used to
quantify the ``ppb'' contributions to ozone in these ``nonattainment''
areas. The resulting ``ppb'' contributions were provided in the SIP
call Tables II-10 and II-12 for the 1-hour and 8-hour NAAQS,
respectively.
The EPA stated in the SIP call that it would review more recent air
quality data and, in the event that these data alter the results of the
significant contribution assessment in any meaningful way, EPA would
make the appropriate adjustments to the findings. Since the SIP call
was published, EPA has reviewed 1996 air quality data to determine
which counties violate the 1-hour and 8-hour NAAQS based on 1994-1996
measurements. A list of the 1-hour and 8-hour violating counties based
on these data is provided in the docket. The EPA recalculated the
``ppb'' contributions to downwind nonattainment using the 1994-1996 1-
hour and 8-hour violating counties and the OTAG 2007 Base Case and
``zero-out'' subregional modeling. The resulting updated 1-hour and 8-
hour contribution tables are provided in the docket. Based upon a
review of the information in these tables, EPA finds no basis for
altering its conclusions on significant contribution.
II. Proposed Action for the 23 Jurisdictions
This SNPR includes the proposed rule language for the CFR for the
basic elements of the proposed SIP call, including the requirements
imposed on the 23 jurisdictions to submit SIP revisions, under both the
1-hour and 8-hour standard, providing for implementation of the
applicable statewide NOX emissions budget, as well as the
definition of the NOX
[[Page 25905]]
budget. The rule language is located at the end of the preamble.
III. Emissions Budgets Analyses
A. Explanation of Revised Budgets
A number of changes were made to the emissions inventory used to
calculate the budget. These changes apply to the electricity generating
and non-electricity generating point source sectors only and were made
to correct errors found subsequent to publication of the proposed SIP
call (NPR). These source sectors are discussed separately below.
Detailed information concerning the changes can be found in the revised
Budget TSD titled ``Development of Modeling Inventory and Budgets for
the Ozone Transport SIP Call'' (revised Budget TSD).
1. Electricity Generating Units
The changes that were made to the electricity generating component
of the budgets fall into two general categories: addition of sources
and changes in growth factors. Both of these changes increase the
budgets.
a. Addition of Sources. The changes that were made in the
population of the utility and non-utility owned electricity generating
units since the November 7, 1997 notice are summarized in Table III-1.
This SNPR includes 1,757 units compared to 1,180 units in the NPR. This
reflects an addition of 577 units to the State budget inventories.
These units include electricity generating sources 25 megawatts of
electrical output (MWe) or smaller and additional units not affected
under the Acid Rain Program (40 CFR part 76). Detailed information on
the sources of data for these additional units is contained in the
revised Budget TSD.
Table III-1.--Inventory Change From NPR
------------------------------------------------------------------------
NPR SNPR
Source population population
------------------------------------------------------------------------
Utility....................................... 1062 1510
Non-Utility................................... 118 247
-------------------------
Total..................................... 1180 1757
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b. Growth Factors. The EPA's ``Proposed Ozone Transport Rulemaking
Regulatory Analysis'' (September 1997, docket number III-B-01) used a
1995 forecast of future electricity demand prepared by the North
American Electric Reliability Council (NERC), with adjustments for
EPA's 1996 estimates of the electricity demand reductions that the
Climate Change Action Plan (CCAP) was projected to produce from the
year 2000 and on. Details on how EPA prepared this electricity demand
forecast can be found in EPA's ``Analyzing Electric Power Generation
under the Clean Air Act,'' (July 1996, docket number II-A-07). The EPA
used this electricity demand forecast in analyses conducted for OTAG
and the Clean Air Power Initiative (CAPI). Further, EPA also used this
forecast when establishing the State-specific growth factors used in
the NPR (referred to as the ``original'' projections).
While EPA is continuing to use the electricity generating industry
growth projections described in the NPR when establishing the budget
component for that sector, this SNPR is correcting one error in the
growth factor calculation of the NPR. The EPA corrected its estimates
of State-specific growth rates from 1996 to 2007. The estimates were
interpolated from the average annual growth of each State as forecasted
by EPA using the Integrated Planning Model (IPM) and EPA's baseline
electricity generation forecast. In developing the average annual
growth, EPA relied on unit-specific summer energy use from 2000 to 2010
as forecasted by the IPM. The average annual growth was determined
using the State-specific growth from 2000 to 2010. However, when
calculating the growth for the year 2010, EPA inadvertently omitted
information on many of the new combustion turbine and combined-cycle
units that IPM forecasts to be built by 2010. Thus new electricity-
generating capacity, expected to be built between 2000 and 2010 was not
included when estimating the industry growth between 2000 and 2010.
This error resulted in an underestimation of the expected average
annual growth for each affected State. In the revision of the budget
for the electric power industry, this error has been corrected. The
change leads to a higher electricity generating component of the
NOX budget for all affected States. The corrected growth
factors are shown in Table III-2 (referred to as the ``corrected''
projections).
Table III-2.--Corrected Electricity Generation Growth Factors
----------------------------------------------------------------------------------------------------------------
Original 96- Corrected 96- Percent
State 07 factor 07 factor increase
----------------------------------------------------------------------------------------------------------------
Alabama......................................................... 1.03 1.16 12.92
Connecticut..................................................... 0.92 1.22 32.99
District of Columbia............................................ 1.00 1.00 0.00
Delaware........................................................ 1.68 1.80 6.77
Georgia......................................................... 1.14 1.21 6.32
Illinois........................................................ 1.23 1.34 8.63
Indiana......................................................... 1.27 1.30 2.64
Kentucky........................................................ 1.20 1.28 6.41
Massachusetts................................................... 1.62 1.71 5.62
Maryland........................................................ 1.14 1.23 7.37
Michigan........................................................ 1.13 1.18 4.60
Missouri........................................................ 1.13 1.24 9.28
North Carolina.................................................. 1.10 1.26 15.04
New Jersey...................................................... 0.99 1.26 27.37
New York........................................................ 1.11 1.22 10.16
Ohio............................................................ 1.10 1.14 3.19
Pennsylvania.................................................... 1.07 1.15 7.07
Rhode Island.................................................... 0.43 0.48 11.83
South Carolina.................................................. 1.32 1.63 23.22
Tennessee....................................................... 0.92 1.25 35.78
Virginia........................................................ 1.18 1.43 20.50
Wisconsin....................................................... 1.07 1.13 6.30
West Virginia................................................... 1.02 1.05 3.26
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[[Page 25906]]
Since the NPR, EPA has also updated its electricity demand forecast
to include more up-to-date information. The information was obtained
from the same sources used in developing the forecast used in the NPR.
The EPA's more recent forecast uses the 1997 forecast of future
electricity demand prepared by NERC with adjustments for the
Administration's 1997 estimates of electricity demand reductions that
the CCAP is projected to produce from 2000 on (referred to as the
``revised'' projections). The EPA found that this revised estimate
leads to lower growth rates for the electricity generating industry
than the estimate used in the NPR analyses. However, in this SNPR, EPA
uses the corrected forecast when calculating State-specific budgets
because of the inherent uncertainty in any projection, and EPA's
willingness to provide States flexibility in achieving their budgets.
Further, when evaluating the cost effectiveness of NOX
controls, EPA considered both the corrected and revised future
electricity demand forecasts. However, for all other analyses under
this SNPR, EPA is using the corrected future electricity demand
forecast. Further, EPA solicits comment on whether to use only the
revised future electricity demand forecast for the budget and cost
effectiveness calculations.
c. Revised Budget Component. Both the 2007 electricity generating
Base Case and the electricity generating Budget component were revised
based on the changes described above. These revisions are shown in
Tables III-3 and III-4. The difference between the 2007 Base Case and
Budget emissions that were proposed and the revised Base Case and
Budget emissions is shown in Table III-3. The revised percent reduction
from the 2007 Base Case to the Budget is shown in Table III-4.
Table III-3.--Changes to Proposed Base Case and Budget Components for Electricity Generating Units
[tons NOX/season]
----------------------------------------------------------------------------------------------------------------
Proposed Revised Percent Proposed Revised Percent
State base base increase budget budget increase
----------------------------------------------------------------------------------------------------------------
Alabama................................. 81,704 85,201 4 26,946 30,644 14
Connecticut............................. 5,715 7,048 23 3,409 5,245 54
Delaware................................ 10,901 10,727 -2 4,390 4,994 14
District of Columbia.................... 385 236 -39 152 152 0
Georgia................................. 92,946 84,890 -9 30,158 32,433 8
Illinois................................ 115,053 119,756 4 31,833 36,570 15
Indiana................................. 177,888 159,917 -10 48,791 51,818 6
Kentucky................................ 128,688 130,919 2 35,820 38,775 8
Maryland................................ 35,332 37,575 6 11,364 12,971 14
Massachusetts........................... 28,284 24,998 -12 12,956 14,651 13
Michigan................................ 82,057 73,585 -10 25,402 29,458 16
Missouri................................ 92,313 81,799 -11 22,932 26,450 15
New Jersey.............................. 14,553 17,484 20 5,041 8,191 62
New York................................ 39,639 43,705 10 24,653 31,222 27
North Carolina.......................... 83,273 86,872 4 27,543 32,691 19
Ohio.................................... 185,757 167,601 -10 46,758 51,493 10
Pennsylvania............................ 125,195 120,979 -3 39,594 45,971 16
Rhode Island............................ 773 1,351 75 905 1,609 78
South Carolina.......................... 43,363 57,146 32 15,090 19,842 31
Tennessee............................... 71,994 83,844 16 19,318 26,225 36
Virginia................................ 45,719 51,113 12 16,884 20,990 24
West Virginia........................... 83,719 76,374 -9 23,306 24,045 3
Wisconsin............................... 51,004 45,538 -11 15,755 17,345 10
-----------------------------------------------------------------------
Total............................... 1,596,255 1,568,655 -2 489,000 563,784 15
----------------------------------------------------------------------------------------------------------------
Table III-4.--Revised NOX Budget Components and Percent Reduction for Electricity Generating Units
[tons/season]
----------------------------------------------------------------------------------------------------------------
Revised Percent
State Revised base budget reduction
----------------------------------------------------------------------------------------------------------------
Alabama......................................................... 85,201 30,644 64
Connecticut..................................................... 7,048 5,245 26
Delaware........................................................ 10,727 4,994 53
District of Columbia............................................ 236 152 36
Georgia......................................................... 84,890 32,433 62
Illinois........................................................ 119,756 36,570 69
Indiana......................................................... 159,917 51,818 68
Kentucky........................................................ 130,919 38,775 70
Maryland........................................................ 37,575 12,971 65
Massachusetts................................................... 24,998 14,651 41
Michigan........................................................ 73,585 29,458 60
Missouri........................................................ 81,799 26,450 68
New Jersey...................................................... 17,484 8,191 53
New York........................................................ 43,705 31,222 29
North Carolina.................................................. 86,872 32,691 62
Ohio............................................................ 167,601 51,493 69
Pennsylvania.................................................... 120,979 45,971 62
Rhode Island.................................................... 1,351 1,609 -19
[[Page 25907]]
South Carolina.................................................. 57,146 19,842 65
Tennessee....................................................... 83,844 26,225 69
Virginia........................................................ 51,113 20,990 59
West Virginia................................................... 76,374 24,045 69
Wisconsin....................................................... 45,538 17,345 62
-----------------------------------------------
Total....................................................... 1,568,655 563,784 64
----------------------------------------------------------------------------------------------------------------
d. Alternative Approach to Calculating the Component of the Budget
for Electricity Generation. In this regulatory action, the component of
each State's budget assigned to electricity generation is determined
using the State's total heat input, applicable emission rate (0.15 lb/
million British thermal units per hour (mmBtu)), and projected growth
to 2007. Consequently, for each State this budget component is based on
the amount of fossil fuel each State uses to produce electricity.
However, States use other fuel sources to generate electricity,
notably nuclear and hydro energy, as well as solar and wind energy.
Furthermore, some facilities that rely on fossil fuel sources are more
efficient, in terms of lower NOX emissions, than other
facilities. In addition, each State's use of sources to generate
electricity may change over time. For example, electricity now produced
by the combustion of fossil fuels may, in the future, be produced using
alternative sources and vice versa.
Because of the shifts in generation from one fuel source to
another, an alternative approach to determining each State's share of
the total regionwide budget component based on total heat input may be
a consideration of total electricity generation within the State. Under
this approach (referred to as ``output-based''), the electricity
generation component (i.e., 563,784 tons of NOX) of the
regionwide budget would be apportioned among the States based on total
electricity generation, not only fossil-fuel generation. Since the
total regionwide budget component would be the same as that proposed in
this notice, and assuming a multistate trading program, the
environmental effects and cost effectiveness of such an allocation
should be similar to the proposed approach.
The data used to apportion the regionwide budget component to each
State under the output-based approach would be State-specific
generation (in MWh) for the time period May 1 to September 30. One
source of such information is the Energy Information Administration's
(EIA) Form 759, where electricity generating sources report their
monthly generation. To more equitably account for shifts from State-to-
State, it may be appropriate to use the higher of summer 1995 or 1996
generation for each State in determining the output-based State budget
components, or perhaps the average of the highest two out of three
summer periods. The first approach is similar to that used in
generating the proposed budget for this sector.
This alternative approach has the effect of rewarding States that
have invested in methods of electricity generation that result in no,
or fewer, NOX emissions. At the same time, because most
electricity generation relies on fossil-fuel inputs that, in turn,
result in NOX emissions, even under this output-based
approach, the State budgets would bear a strong relationship to amount
of actual NOX emissions on a State-by-State basis.
Even so, the resulting budgets for each State would be different,
to some degree, from the budgets currently proposed. If a regionwide
trading program is ultimately used, it may be assumed that emissions
would be reallocated so that each State's budget under the alternative
approach would be the same as under the currently proposed approach. Of
course, in this case, the cost effectiveness and environmental benefit
associated with this alternative approach would be the same as that of
the currently proposed approach. It seems plausible to assume that
States subject to the NOX SIP call would opt for regionwide
trading due to the cost effectiveness of this approach.
However, in this rulemaking, EPA is not attempting to require
regionwide trading, and if the States opt not to employ such a system,
the air quality impacts of an output-based approach and its cost
effectiveness may be different from the air quality impacts under the
proposed budget. If for some States, the budget under the output-based
approach is significantly lower than that under the proposed approach,
the absence of a regionwide trading system may result in required
control levels that are not technically achievable.
Other issues that arise under the output-based approach concern the
representativeness and quality of the required data. Specifically, the
EIA data used in the output-based approach may not include all
electricity generating sources, such as Independent Power Producers
(IPPs) and Non-Utility Generators (NUGs). Additionally, some may argue
that it is inappropriate to incorporate the non-NOX-emitting
sources in the calculation of each State's electricity generation
component of the budget. In addition, the alternative budget fails to
consider the fact that nuclear-, hydro-, solar-, or wind-powered
facilities generate steam output, as well as electricity. Accordingly,
it may be logical to adjust the alternative budgets further to take
account of steam output. Further, as discussed in Section V.C.9.b,
Output Information, of this preamble, there are a number of issues
associated with measuring and using electricity- or steam-related
output data. The EPA solicits comments on all issues concerning this
alternative approach, including the appropriateness, legality,
rationale, and methodology for incorporating the output-based approach
when calculating the electricity generation component of each State's
budget.
2. Non-Electricity Generating Point Sources
Changes that were made to the non-electricity generating point
source component of the budgets fall into two categories: addition of
sources and application of controls. Addition of sources increases the
budgets, while correction in the application of controls tends to
decrease the budgets.
a. Addition of Sources. Based on the matching that was done to
identify electricity generating sources, it was determined that a
number of sources
[[Page 25908]]
that were identified in the OTAG inventory as utilities were, in fact,
not utility sources. In the budgets that were proposed on November 7,
1997, these sources were left out of the inventory when the OTAG
utility data were replaced by the acid rain data. These sources have
since been identified and added back into the budgets. A list of the
sources that were moved from the electricity generating to non-
electricity generating sector is contained in the revised Budget TSD.
b. Application of Controls. The non-electricity generating point
source budget components were calculated based on the OTAG
recommendations as follows:
70 percent control for large (> 250 mmBtu/hr) sources
(measured from uncontrolled 2007 emissions);
Reasonably Available Control Technology (RACT)-level
controls for all other NOX sources with more than 1.0 tons
per day (tpd) of NOX emissions (medium-sized sources);
Small source NOX emissions were estimated using
OTAG Base 1c scenario emission values.
For the budgets that were proposed, RACT was erroneously applied
only to those sources that were in areas required to adopt RACT. The
intent of the proposed approach was to apply RACT to all medium-sized
sources, regardless of whether they are located in an area that would
otherwise be required to apply RACT. The revised budgets reflect the
application of RACT to all medium-sized sources in the affected States.
A list of the sources that were treated as large and medium sources is
contained in the appendices to the revised Budget TSD.
c. Revised Budget Component. Both the 2007 Base Case and Budget
component for non-electricity generating point sources were revised
based on the changes described above. These revisions are shown in
Tables III-5 and III-6. The difference between the 2007 Base Case and
Budget emissions that were proposed and the revised Base Case and
Budget emissions for non-electricity generating units is shown in Table
III-5. The revised percent reduction from the 2007 Base Case to the
Budget is shown in Table III-6.
Table III-5.--Changes to Proposed Base Case and Budget Components for Non-Electricity Generating Units
[tons NOX/season]
----------------------------------------------------------------------------------------------------------------
Proposed Revised Percent Proposed Revised Percent
base base increase budget budget decrease
----------------------------------------------------------------------------------------------------------------
Alabama................................. 47,182 48,187 2 25,131 24,416 3
Connecticut............................. 4,732 5,254 11 4,475 3,103 31
Delaware................................ 5,205 5,276 1 3,206 2,271 29
District of Columbia.................... 312 311 0 312 259 17
Georgia................................. 34,012 33,939 0 20,472 14,305 30
Illinois................................ 63,642 65,351 3 39,855 40,719 -2
Indiana................................. 51,432 51,839 1 35,603 29,187 18
Kentucky................................ 18,817 19,019 1 12,258 11,996 2
Maryland................................ 6,729 10,710 59 4,825 5,852 -21
Massachusetts........................... 10,683 9,978 -7 7,590 6,207 18
Michigan................................ 57,190 61,656 8 35,317 35,957 -2
Missouri................................ 12,248 12,320 1 8,174 9,012 -10
New Jersey.............................. 32,663 22,228 -32 26,741 12,786 52
New York................................ 19,889 20,853 5 16,930 14,644 14
North Carolina.......................... 32,107 34,412 7 21,113 19,267 9
Ohio.................................... 50,946 53,329 5 32,799 30,923 6
Pennsylvania............................ 64,224 74,839 17 59,622 41,824 30
Rhode Island............................ 328 327 0 328 327 0
South Carolina.......................... 34,791 34,994 1 20,097 18,671 7
Tennessee............................... 65,051 67,774 4 32,138 34,308 -7
Virginia................................ 23,333 25,509 9 15,529 10,919 30
West Virginia........................... 41,510 42,733 3 31,377 21,066 33
Wisconsin............................... 21,209 21,263 0 12,269 11,401 7
-----------------------------------------------------------------------
Total............................... 698,233 722,101 3 466,158 399,416 14
----------------------------------------------------------------------------------------------------------------
Table III-6.--Revised NOX Budget Components and Percent Reduction for Non-Electricity Generating Units
[tons/season]
----------------------------------------------------------------------------------------------------------------
Revised Percent
Revised base budget reduction
----------------------------------------------------------------------------------------------------------------
Alabama......................................................... 48,187 24,416 49
Connecticut..................................................... 5,254 3,103 41
Delaware........................................................ 5,276 2,271 57
District of Columbia............................................ 311 259 17
Georgia......................................................... 33,939 14,305 58
Illinois........................................................ 65,351 40,719 38
Indiana......................................................... 51,839 29,187 44
Kentucky........................................................ 19,019 11,996 37
Maryland........................................................ 10,710 5,852 45
Massachusetts................................................... 9,978 6,207 38
Michigan........................................................ 61,656 35,957 42
[[Page 25909]]
Missouri........................................................ 12,320 9,012 27
New Jersey...................................................... 22,228 12,786 42
New York........................................................ 20,853 14,644 30
North Carolina.................................................. 34,412 19,267 44
Ohio............................................................ 53,329 30,923 42
Pennsylvania.................................................... 74,839 41,824 44
Rhode Island.................................................... 327 327 0
South Carolina.................................................. 34,994 18,671 47
Tennessee....................................................... 67,774 34,308 49
Virginia........................................................ 25,509 10,919 57
West Virginia................................................... 42,733 21,066 51
Wisconsin....................................................... 21,263 11,401 46
-----------------------------------------------
Total....................................................... 722,101 399,416 45
----------------------------------------------------------------------------------------------------------------
d. Options for Calculating the Budgets. In the November 7, 1997
NPR, EPA proposed budgets and developed cost effectiveness data for
non-utility boilers and gas turbines together with other non-utility
point sources. The budgets for these sources were based on the
applicable OTAG recommendation of 70 percent reduction from
uncontrolled levels at large units (greater than 250 mmBtu/hr), RACT at
medium units (other sources greater than 1 ton per day) and no controls
beyond the baseline for small sources. The revised budgets described in
Section III.A.2, Non-Electricity Generating Point Sources, of today's
action are based on the same approach. Costs were estimated for these
sources using a least cost approach for each State budget which assumed
incremental emissions reductions at the most cost-effective sources in
each State, including small, medium, and large units. In contrast,
electric generation sources were analyzed separately using an emissions
rate approach to develop the budgets and the Integrated Planning Model
(IPM) was run to estimate costs under an interstate trading program.
The November 7, 1997 NPR invited comment on the size cutoffs used in
the above analyses and also specifically invited comment on treating
large combustion sources, such as industrial boilers greater than 250
mmBtu (this level approximately corresponds to greater than 1 ton per
day), at control levels equal to that for large electric generation
sources.
In today's action, EPA is proposing to include the non-utility
boilers and gas turbines greater than 250 mmBtu/hr together with
electric generation sources as the core group of sources in the
NOX Budget Trading Program and analyze both using IPM. As a
result, EPA intends to conduct additional analyses as described below.
For the non-utility boilers and gas turbines greater than 250
mmBtu/hr, EPA intends to estimate costs using IPM and assuming a
trading program involving these sources and the electric generation
sources. The emissions budget would be calculated for these sources the
same as it was in the November 7, 1997 NPR. The EPA also solicits
comments on whether to calculate budgets for the non-utility boilers
and gas turbines through the alternative means of an emission rate
basis (e.g., 0.20 lbs/mmBtu), similar to the approach used by EPA for
electric generation sources in the November 7, 1997 NPR. The EPA
invites comment on these and other approaches for calculating the
budget component and costs for the non-utility boilers and gas turbines
greater than 250 mmBtu/hr.
Additionally, EPA intends to further analyze the point source
categories that are not part of the proposed core group of sources in
the NOX Budget Trading Program (e.g., process heaters,
stationary internal combustion engines, and cement manufacturing).
These analyses will look at applying (1) various cost-effectiveness
ceilings (e.g., maximum of $2000 per ton); (2) percentage reduction
floors (e.g., minimum of 50 percent reduction); and (3) combinations
(e.g., $2000 per ton maximum and 50 percent reduction minimum). These
analyses will cover individual source categories not in the proposed
core group of sources of the NOX Budget Trading Program as
well as all such sources in the aggregate. The EPA invites comment on
these and other approaches for calculating the budget component and
costs for this group of sources.
In the November 7, 1997 NPR, EPA noted that information on
emissions and potential control measures was generally lacking for
small sources. The EPA believes that there are several medium and large
units for which such information is also lacking. In the November 7,
1997 NPR (and in the revised budgets described in Section III.A.2, Non-
Electricity Generating Point Sources), these units were assigned a 70
percent reduction target for large and RACT for medium sized units,
consistent with the OTAG recommendation. However, since EPA cannot
identify specific control measures for these sources due to the lack of
available technical information, EPA now proposes to keep them in the
statewide budgets at baseline levels, without additional emission
reductions.
As the above analyses are completed, EPA intends to place them in
the docket.
3. Revised Statewide Budgets
The revised statewide budgets that reflect the changes to the
electricity generating and non-electricity generating point source
sectors described above are shown in Table III-7.
[[Page 25910]]
Table III-7.--Revised Statewide NOX Budgets
[tons/season]
----------------------------------------------------------------------------------------------------------------
State Base Budget Percent red.
----------------------------------------------------------------------------------------------------------------
Alabama......................................................... 241,564 155,617 36
Connecticut..................................................... 52,014 39,909 23
Delaware........................................................ 30,568 21,010 31
District of Columbia............................................ 7,978 7,000 12
Georgia......................................................... 246,243 159,013 35
Illinois........................................................ 350,154 218,679 38
Indiana......................................................... 340,084 200,345 41
Kentucky........................................................ 263,855 158,360 40
Maryland........................................................ 118,065 73,628 38
Massachusetts................................................... 103,445 73,575 29
Michigan........................................................ 283,821 199,238 30
Missouri........................................................ 185,104 116,246 37
New Jersey...................................................... 132,032 93,464 29
New York........................................................ 230,310 185,537 19
North Carolina.................................................. 234,300 153,106 35
Ohio............................................................ 391,012 236,443 40
Pennsylvania.................................................... 328,433 207,250 37
Rhode Island.................................................... 12,175 10,132 17
South Carolina.................................................. 169,572 109,267 36
Tennessee....................................................... 291,225 187,250 36
Virginia........................................................ 219,835 162,375 26
West Virginia................................................... 158,240 81,701 48
Wisconsin....................................................... 142,759 95,902 33
-----------------------------------------------
Total........................................................... 4,532,790 2,945,046 35
----------------------------------------------------------------------------------------------------------------
B. Revised Cost Analyses
The EPA has revised the cost estimates presented in the November 7,
1997 notice. As discussed in Section III.A, Explanation of Revised
Budgets, additional emissions sources were included in the emissions
budgets and several changes to the emissions inventory were made. Also,
revised unit control cost estimates for Selective Catalytic Reduction
(SCR) and Selective Non Catalytic Reduction (SNCR) were prepared for
non-electricity generating point sources. The revised costs are now
more consistent with the way estimates were developed for electricity
generating sources. Details on the revised cost analysis are presented
in ``Supplemental Ozone Transport Rulemaking Regulatory Analysis''
(Supplemental Regulatory Analysis TSD).
1. Electricity Generating Sources
The OTAG recognized the value of market-based approaches to
lowering emissions from power plants and large industrial sources. The
Agency agrees that a market-based approach with trading is preferable
as more cost effective and encourages all States covered by this
rulemaking to establish such a program. The Agency's regulatory
analysis is based on this view. As in the original proposal analysis,
analytical limitations kept EPA from estimating the costs of a single
cap-and-trade program for the electric power industry and other large
stationary sources. In this SNPR, the analysis of a cap-and-trade
program, across all States covered in the rulemaking, is limited to
sources in the electric power industry.
The analysis of the electric power industry has been expanded to
include additional electricity-generating sources (see Section III.A,
Explanation of Revised Budgets). Additionally, EPA also updated many of
the assumptions included in the Integrated Planning Model (IPM),
including more recent energy demand forecasts and more recent
information on future planned new units. These changes are discussed in
the Supplemental Regulatory Analysis TSD.
The EPA analyzed the cost of a NOX cap-and-trade program
with a summer NOX emissions cap of 563,784 tons, assuming
reductions are effective by the 2003 ozone season. Annual cost
estimates are provided for 2003 and 2007.
2. Non-Electricity Generating Point Sources
The costs for non-electricity generating point sources are
estimated using two alternative approaches. The first approach, called
the Least Cost Scenario, attempts to identify the mix of sources and
control technologies that achieve each State's non-electricity
generating budget level for point sources at the lowest possible
control cost. The sources controlled under the Least Cost Scenario may
not be the same sources that are controlled for the purpose of
establishing each State's emissions budget. The results of the Least
Cost Scenario are a proxy for State-level emissions trading programs
free of transactions costs. If it were possible to consider
transactions costs, the Least Cost Scenario would result in higher cost
estimates than are presented here. On the other hand, if the Least Cost
Scenario had been modeled assuming the States participate collectively
in a trading program for non-electricity generating sources (i.e.,
domain-wide trading as modeled in the electricity generating sector),
the resulting cost estimates would likely be lower than presented here.
The second approach, termed the Command-and-Control Scenario,
attempts to estimate the cost of controlling just those sources that
were used to establish each State's emissions budget. This method does
not take into account possible cost savings that can be realized by
more efficient regulatory schemes, such as emissions trading, and
therefore tends to overstate the cost of meeting the non-electricity
generating point source emissions budget.
The EPA has revised the cost of controls associated with non-
electricity generating sources based on information previously
developed for the revised IPM for electricity generating sources. The
new method for estimating SCR and SNCR costs for non-electricity
generating sources is now more
[[Page 25911]]
consistent with the estimates for electricity generating sources. The
annual costs for non-electricity generating sources are estimated based
on the 2007 non-electricity generating source emissions projections.
Unlike the IPM analysis for electricity generating sources, the cost
analysis framework for non-electricity generating sources did not allow
distinctions to be made between the estimated annual cost of compliance
in 2003 relative to the year 2007. As shown in Section III.B.3, Cost
Analysis Results, the electricity generating sector annual cost
estimates vary only 5 percent between 2003 and 2007. It is reasonable
to believe that non-electricity generating sector annual cost would
also not vary significantly between 2003 and 2007.
For NOX point sources, EPA estimated annual compliance
costs for achieving a total summer NOX emissions budget of
416,619 tons. This budget is slightly higher (4 percent) than the
399,416 ton budget presented in Section III.A.2, Non-Electric
Generation Point Sources, because the cost analysis for non-electricity
generating point sources was completed before all adjustments to the
proposed budgets had been finalized. If the final 399,416 ton budget
had been analyzed the cost estimates for non-electricity generating
point sources would have been only slightly higher.
3. Cost Analysis Results
Tables III-8 and III-9 show the analysis results based on the
changes to the proposed emissions budgets and cost methodology
improvements. Table III-8 shows the population of sources covered by
each element of the cost analysis and the resulting NOX
emissions levels. Table III-9 shows the estimated annual compliance
costs and average cost effectiveness.
Table III-8.--Population of Emissions Sources and NOX Emissions After
Compliance with the Ozone Transport Rulemaking
------------------------------------------------------------------------
Ozone season
Budget component Number of emissions (1,000
sources* NOX tons)
------------------------------------------------------------------------
Electricity generating sources.... 1,757 564
Non-Electricity generating
sources: Least Cost--2007........ 13,373 409
Non-Electricity generating
sources: Command-and-Control-2007 1,774 394
------------------------------------------------------------------------
* The number of electricity generating sources reflects the number of
sources in 1996 that were used to establish the summer season NOX
budget. The number of non-electricity generating sources reflects
sources controlled for the purpose of estimating costs.
Table III-9.--Incremental Annual Control Costs and Average Cost Effectiveness for Compliance with the Ozone
Transport Rulemaking
----------------------------------------------------------------------------------------------------------------
Average ozone Average annual
Annual control season cost cost
Budget component cost (million effectiveness ($/ effectiveness ($/
1990 dollars) ton) ton)
----------------------------------------------------------------------------------------------------------------
Electricity generating sources--2003................... 1,308 1,455 1,161
Electricity generating sources--2007................... 1,378 1,469 1,165
Non-Electricity generating sources: Least Cost--2007... 456 1,500 640
Non-Electricity generating Sources: Command-and-
Control--2007......................................... 1,170 3,700 2,600
----------------------------------------------------------------------------------------------------------------
Based on the Least Cost Scenario for non-electricity generating
sources, the incremental annual cost of the proposed SIP call in 2007
for both electricity and non-electricity generating sources is $1.8
billion (1990 dollars).
IV. SIP Criteria and Emissions Inventory Reporting Requirements
A. SIP Criteria
1. Introduction
The November 7, 1997 NPR explained that each State would be
required to submit a SIP demonstrating ``that each State will meet the
assigned statewide emission budget'' (62 FR 60365). It further
explained that each ``SIP revision should include the following general
elements related to the regional strategy: (1) Baseline 2007 statewide
NOX emissions inventory (which includes growth and existing
control requirements)--this would generally be the emissions inventory
that was used to calculate the required statewide budget; (2) a list
and description of control measures to meet [the] statewide budget; (3)
fully-adopted State rules for the regional transport strategy with
compliance dates providing for control between September 2002 and
September 2004, depending on the date EPA adopts in its final
rulemaking; (4) clearly documented growth factors and control
assumptions; and (5) a 2007 projected inventory that demonstrates that
the State measures along with national measures will achieve the State
budget in 2007.'' Id.
The purpose of this Section is to identify criteria for determining
completeness and approvability of a State submittal in response to the
final SIP call. The criteria are set forth in proposed regulatory
language (40 CFR 51.121). In addition, this section describes the
actions the Agency intends to take if a State fails to make a
submittal, or the Agency makes a finding of incompleteness or
disapproves the SIP.
2. Completeness Determination
Any submittal that is made with respect to the final SIP call first
will be determined to be either incomplete or complete. A finding of
completeness means that EPA will review the submittal to determine
whether it is approvable. It is not a determination that the submittal
is approvable; rather, it means the submittal is administratively and
technically sufficient for EPA to determine whether it meets the
statutory and regulatory requirements for approval. In order for any
submittal to be complete, 40 CFR 51.121 provides that the submittal
must meet the criteria described in 40 CFR, part 51, Appendix V,
``Criteria for Determining the Completeness of Plan Submissions.''
These criteria apply generally to SIP submissions and so should be
familiar to States submitting transport SIPs.
Section 1.2 of Appendix V, in accordance with section 110(k)(1) of
the
[[Page 25912]]
CAA, requires EPA to notify States within 60 days of EPA's receipt of a
submittal, but no later than 6 months after the submittal is due. If a
completeness determination is not made within 6 months after
submission, the submittal is deemed complete by operation of law. For
purposes of rules submitted in response to the SIP call, EPA intends to
make completeness determinations expeditiously. In addition, EPA
expects to make findings of failure to submit no later than the Agency
makes completeness determinations.
A finding of failure to submit or incompleteness triggers an 18-
month sanctions clock that can only be stopped by an affirmative EPA
finding that the State has made a complete submittal. The findings also
trigger the requirement that EPA promulgate a Federal implementation
plan (FIP) within 2 years of the date of the finding, if the deficiency
has not yet been corrected. The EPA intends to propose FIPs in the fall
of 1998 and move quickly to promulgate a FIP where necessary. In
addition, sanctions and FIP clocks are triggered if a State submits a
complete SIP, but EPA subsequently disapproves it, in whole or in
part.2
---------------------------------------------------------------------------
\2\ A more detailed discussion of sanctions and FIPs appeared in
the November 7, 1997 NPR at page 60368-69.
---------------------------------------------------------------------------
3. Approvability Criteria
In the November 7, 1997 NPR, EPA highlighted several general
elements that must be included in ozone transport SIP revisions.
Without these general elements, a SIP submission will not be approved.
This Section (1) identifies EPA's proposed additional approvability
criteria for control strategies that will help States meet their
NOX budgets; and (2) provides guidance to assist States in
preparing emissions inventories for purposes of identifying emissions
benefits of possible control strategies. The existing guidance
documents listed below will help States incorporate existing EPA
guidance into their SIPs. Much of the pertinent guidance is available
electronically.
Each State must start with a baseline 2007 statewide NOX
emissions inventory, including growth and existing control
requirements. The 2007 projected control inventory must demonstrate
that the State measures, along with national measures, will achieve the
State budget in 2007. The EPA has issued documents to assist States in
developing emissions inventories. Specifically, these documents
describe how to clearly define the particular control measures and
document the methods used to estimate emissions reductions from
implementation measures. A State need not define these measures in its
SIP to the extent it chooses to achieve the required reductions through
the model rule for the NOX Budget Trading Program, which is
being proposed in this notice.
a. Additional Control Strategy Approvability Criteria.
i. Introduction. The approvability criteria for transport SIP
submissions appear in proposed 40 CFR 51.121. Most of the criteria are
substantially identical to those that already apply to attainment SIPs.
For example, each submission must describe the control measures that
the State intends to employ, identify the enforcement methods for
monitoring compliance and handling violations, and demonstrate that the
State has legal authority to carry out its plan. This part of the
preamble focuses on approvability criteria that are being proposed for
the first time to ensure States meet their NOX budgets.
ii. General Recommendations. As discussed in the NPR (62 FR 60365-
66), regulatory requirements that employ a maximum mass emissions
limitation for a source or group of sources provide the greatest
certainty that a specific level of emissions will be attained and
maintained. With respect to transport of pollution, a mass emissions
limitation also provides the greatest assurance to downwind States that
air emissions from upwind States will be effectively managed over time.
Regulatory requirements designed and enforced as an emissions rate
limitation can achieve a measurable emissions reduction, but the
targeted level of emissions may or may not be reached depending on the
actual activity level of the affected source(s). Finally, regulatory
requirements designed as a specific technology or measure have the
greatest uncertainty for achieving a targeted emissions level due to
uncertainty in both the activity level of the affected source(s) and
uncertainty in the effectiveness of the technology or measure.
Based on the desire to establish regulatory requirements with the
greatest likelihood of achieving and maintaining the statewide
NOX emissions budget, EPA recommends that, to the maximum
extent practicable, all regulatory requirements be in the form of a
maximum level of emissions for a source or group of sources. The EPA
recognizes that this option may be difficult for some sources because
the available emissions control options may be limited, and the
techniques for quantifying mass emissions to ensure compliance with a
tonnage budget may not be adequate.
iii. New Proposed Approval Criteria. While mass emissions
limitations may be difficult for some sources, EPA believes that, if
the State chooses to meet the budget through control requirements for
electric generators and large industrial boilers, the State can
feasibly require these sources to quantify mass emissions through
reasonably available measurement technology. For this reason, as well
as others discussed below, EPA proposes the following additional SIP
approvability criteria which would apply if the State selected
regulatory requirements covering NOX sources serving
electric generators with a nameplate capacity greater than 25 MWe and
boilers with a maximum design heat input greater than 250 mmBtu/hr:
Regulatory requirements to meet the 2007 budget for these
sources would need to be expressed in one of three ways: (1) In terms
of mass emissions, which would limit total emissions from a source or
group of sources; (2) in terms of emissions rates that when multiplied
by the affected sources' maximum operating capacity would meet the
tonnage component of the emissions budget for this source or for these
sources; or (3) an alternative approach for expressing regulatory
requirements, provided the State demonstrates to EPA that its
alternative provides equivalent or greater assurance than options (1)
or (2) that seasonal emissions budgets will be attained and maintained.
Sources would be required to demonstrate that they have
met these applicable emissions control provisions using continuous
emissions monitors. Further, EPA is taking comment on whether sources
should be required to demonstrate that they met these requirements
using the monitoring provisions of the Acid Rain Program for monitoring
NOX mass emissions in 40 CFR part 75.
The EPA believes control approaches and monitoring for this group
\3\ of sources have advanced to the point that complying with,
tracking, and enforcing a maximum mass emissions limitation or tonnage
budget is reasonable. A variety of regulatory programs are currently in
use or under development that utilize a mass emissions limitation for
large combustion devices. These
[[Page 25913]]
regulatory systems include the EPA's Acid Rain Program for sulfur
dioxide (SO2) emissions, the South Coast Air Quality
Management District's Regional Clean Air Incentives Market for
SO2 and NOX, and the Ozone Transport Commission's
NOX Budget Program. Experience with these regulatory
programs indicates that establishing a tonnage budget for large
combustion sources is currently feasible and cost effective. These
approaches exist because there is a range of reasonable options
available for controlling emissions from these sources. In general,
large combustion sources have several effective control options for
reducing NOX emissions, including combustion modifications,
post-combustion technologies, and fuel switching. This range of options
provides flexibility for these sources or groups of sources to maintain
a tonnage budget for emissions.
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\3\ NOX sources serving electric generators with a
nameplate capacity greater than 25 MWe and boilers with a maximum
design heat input greater than 250 mmBtu/hr.
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For measuring emissions, continuous emissions monitors, currently
installed at most sources participating in these programs, provide
accurate, complete and timely accounting of emissions which enable the
administrators of these programs to easily track and enforce emissions
on a mass emissions basis. Therefore, EPA proposes that all of the
sources in this group must employ continuous emissions monitoring.
Further, EPA seeks comment on what specifications, if any, to require
for such continuous emissions monitoring systems (CEMS). More
specifically, EPA is taking comment on requiring these sources to meet
the NOX mass emissions monitoring and reporting provisions
that are contained in a proposed new subpart to the monitoring and
reporting provisions of the acid rain regulations in 40 CFR part 75.
These revisions are being proposed in a separate notice entitled ``Acid
Rain Program; Continuous Emission Monitoring Revisions'' that will be
published in the Federal Register in the near future. Electric utility
units have been meeting the current 40 CFR part 75 requirements since
at least 1995. The EPA believes that the proposed 40 CFR part 75
provisions will provide accurate monitoring of NOX mass
emissions and also provide flexibility, particularly for smaller and
infrequently operated sources. Additional information on the proposed
40 CFR part 75 requirements can be found in Section V.C.9.a,
Requirements for Point Sources. Also, EPA has prepared a memorandum for
the docket that compares the proposed provisions of 40 CFR part 75 to
other available CEMS requirements.\4\
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\4\ See Memorandum from Kevin Culligan, EPA, Acid Rain Division,
to Docket regarding ``Transport SIP Call: Potential Continuous
Emissions Monitoring Systems Requirements'' April 8, 1998, Docket
Number A-96-56, IV-B-01.
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Another reason that States choosing to control electricity
generating sources should use available means to assure that the
source's mass emissions stay within the State's projected levels is
that recent changes in the utility industry may foster substantial
shifts in electricity production from State to State for market
reasons. Given the changing market forces in the electricity generating
industry today, State measures to limit electricity generating unit
emission rates without accounting for potential utilization increases
would provide little assurance that mass emissions from these sources
would be reduced to the levels necessary to meet the proposed budgets.
For this reason, too, EPA believes that regulatory requirements for
large combustion sources to meet a State's NOX budget can
and should be expressed and enforced as mass emissions limitations or
an alternative providing equivalent assurance that the mass reductions
will occur.
Finally, while EPA has not heretofore imposed the proposed
approvability criteria on State ozone control measures, EPA believes
they are reasonable (as described above) and appropriate in the context
of this transport rulemaking. This SIP call addresses the regional
problem of emissions transport--i.e., the problem of one State's effect
on one or more other States. The EPA believes it is appropriate to take
reasonable and feasible steps to minimize the potential ``commons''
phenomenon inherent in this problem. Under the theory of the commons, a
State has less interest in controlling pollution that is produced
within its borders but primarily affects the health of non-residents,
compared to its interest in controlling pollution that has intrastate
effects. The additional approvability criteria proposed today offer
downwind States the assurance that upwind States, to the extent they
elect to control the applicable group of sources, will implement
measures that offer transparent certainty of success. Given the
availability of reasonable measures to control the applicable group of
sources in this way, and the potential for substantial shifts in
utilization in the utility sector in coming years, EPA believes it is
appropriate for this transport SIP call to propose additional SIP
approvability criteria to address the potential commons phenomenon.\5\
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\5\ Authority for the proposed additional SIP approval criteria
described above resides in sections 110(a) and 301(a) of the Clean
Air Act. Specifically, the requirement in section 110(a)(2)(A) that
SIPs include enforceable emissions limitations and other control
measures ``as may be necessary or appropriate'' to meet the Clean
Air Act, together with the requirement in section 110(a)(2)(D) that
SIPs include ``adequate provisions'' to mitigate certain transport
effects on other States, implicitly authorize EPA to impose the
additional SIP approval criteria described above to ensure that
affected States adequately mitigate their contribution to ozone
transport, given the reasons and circumstances described above.
Additionally, section 301(a) grants EPA broad authority to prescribe
such regulations as are necessary to carry out its functions under
the Clean Air Act. The proposed additional SIP approval criteria are
necessary for EPA to meet its obligation to approve only SIPs that
contain ``necessary or appropriate'' and ``adequate'' provisions for
the applicable State to mitigate its contribution to ozone
transport.
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To assist States with the development and implementation of an
emissions budget for large combustion sources, EPA is proposing the
NOX Budget Trading Program in section V of today's notice.
States may voluntarily choose to participate in the NOX
Budget Trading Program by adopting the model rule. This multistate
trading program would provide sources the flexibility and cost
effectiveness of a market based system, while meeting the additional
SIP approvability criteria for States that are proposed in this
section.
The EPA intends to approve the portion of any State's SIP
submission that adopts the model rule, provided: (1) The State has the
legal authority to adopt the model rule and implement its
responsibilities under the model rule, and (2) the SIP submission
accurately reflects the NOX reductions to be expected from
the State's adoption of the model rule. As noted above, today's action
proposes that transport SIP submissions comply with various approval
criteria that are substantially identical to existing approval criteria
for attainment SIPs. Those criteria include: (1) A demonstration by the
State that it has the legal authority to adopt and implement each of
the control measures contained in the SIP submission, and (2) a
demonstration of the expected emissions reductions to be achieved from
each new control measure. Provided a State meets these two criteria
with respect to its adoption of the model rule, then EPA intends to
approve the model rule portion of the State's SIP submission.
A State or group of States may also choose to develop, adopt, and
implement their own cap-and-trade program separate from today's
proposed NOX Budget Trading Program. In developing these
alternative programs,
[[Page 25914]]
States should follow the available guidance in the Economic Incentive
Program requirements (see 40 CFR part 51, subpart U) and EPA's
Emissions Trading Policy Statement (see 51 FR 43814, December 4, 1986)
in addition to the transport SIP approval criteria in proposed 40 CFR
51.121.
Regulatory requirements used to meet the 2007 budget for other
sources not identified in the above description may be expressed as (1)
a mass emissions limit, (2) an emissions rate, or (3) specific
technology or measure. As discussed above, EPA recognizes that it may
not be reasonable to require regulatory requirements to be expressed as
mass emissions limitations for all of these sources because of
limitations with control options and the ability to measure mass
emissions. Moreover, EPA believes that the likelihood of substantial
shifts in demand (and corresponding changes in emissions compared to
historical actuals) is lower for these other sources. Therefore, EPA
believes there is substantially less risk with respect to these sources
that past representative production rates will prove unreliable
predictors of future activity. However, EPA recommends that mass
emissions budgets also be used for these sources to the maximum extent
practicable.
The EPA solicits comments on the proposed SIP approvability
criteria for regulatory requirements that govern emissions from large
combustion sources. In addition, EPA solicits comments as to the
reasonableness of expressing regulatory requirements as mass emissions
limitations for other sources.
b. Emissions Inventory Preparation Guidance and Control Strategies
Guidance. This Section presents guidance that States should follow when
initiating the planning and development of an emissions inventory. The
documents referenced below describe control measures a State may wish
to consider for purposes of meeting a statewide NOX budget.
Most of these documents can be obtained directly by computer download
from the EPA's Clearinghouse for Inventories and Emission Factors
(CHIEF) Web Site (http://www.epa.gov/ttn/chief) or by contacting the
InfoCHIEF helpline at (919) 541-5285.
Descriptions of a number of potential data sources that can be
consulted for emission estimation methods are provided below. Site-
specific source tests are generally expected to provide a better
estimate for the tested site than average emission factors (including
factors cited in ``Compilation of Air Pollutant Emission Factors (AP-
42)'') derived from testing at similar sources. Site-specific tests
should be based on a reliable test procedure and should represent
typical operating conditions at the site before being assumed to be
superior to an average emission factor. The CEMS data for a given site
can be considered a superior form of site-specific source test data.
Material balances for NOX sources, and particularly
combustion NOX sources, are not appropriate and should not
be used.
If reliable site-specific tests or calculation methods are not
available or are not feasible to use for all sources, an emission
factor or emission model approach can be used. The EPA's Factor
Information Retrieval (FIRE) Data System provides a searchable
electronic listing of all criteria, toxic, and greenhouse gas emission
factors appearing through the latest printed AP-42 supplement for
stationary sources. The FIRE database also contains a number of non-AP-
42 factors, but only for sources where no AP-42 factor exists. In
addition, FIRE contains a reference indicating if the factor is from
AP-42 or another source, and it contains the factor quality rating if
one exists. Note that mobile source emission factors do not appear in
FIRE. The most recently finished AP-42 stationary source revisions can
only be found on the CHIEF web site (http://www.epa.gov/ttn/chief/
ap42etc.html).
If an emission factor is not available from one of the above
sources, or if the inventory preparer wants to improve the emissions
estimates for sources deemed significant, the following data sources
may be of use.
``Volume I, Introduction to the Emission Inventory
Improvement Program (EIIP)'' (EPA-454/R-97-004a)--
http://www.epa.gov/ttn/chief/eiip/techrep.htm#intro
``Volume II, Preferred and Alternative Methods for
Estimating Air Emissions from Point Sources'' (EPA-454/R-97-004b)--
http://www.epa.gov/ttn/chief/eiip/techrep.htm#pointsrc
``Volume III, Preferred and Alternative Methods for
Estimating Air Emissions from Area Sources'' (EPA-454/R-97-004c)--
http://www.epa.gov/ttn/chief/eiip/techrep.htm#areasrc
``Volume IV, Preferred and Alternative Methods for
Estimating Air Emissions from Mobile Sources'' (EPA-454/R-97-004d)--
http://www.epa.gov/ttn/chief/eiip/techrep.htm#mobsrc
``Procedures for the Preparation of Emission Inventories
for Carbon Monoxide and Precursors of Ozone, Volume I: General Guidance
for Stationary Sources'' (EPA-450/4-91-016)--
This document provides general procedures for estimating emissions
from point and area stationary sources; it may still be useful for
estimating emissions from area sources that are not yet covered in the
EIIP area source guidance document (e.g., small publicly owned
treatment works, aircraft refueling, on-site incineration, residential
heating (excluding wood fuel), barge and tank drum cleaning). It is not
available in electronic form. Paper copies are available from the
InfoCHIEF help desk (919) 541-5285.
``Procedures for the Preparation of Emission Inventories
for Carbon Monoxide and Precursors of Ozone, Volume II: Emission
Inventory Requirements for Photochemical Air Quality Simulation
Models'' (Revised) (EPA-450/R-92-026)--
This document offers technical assistance to those engaged in the
planning and development of detailed emissions inventories for use in
photochemical air quality simulation models. It includes guidance for
identifying and incorporating the additional detail required by
photochemical air quality simulation models into an existing base year
inventory. It is not available in electronic form. Paper copies are
available from the InfoCHIEF help desk (919) 541-5285.
``Procedures for Emission Inventory Preparation, Vol. IV:
Mobile Sources'' (EPA-450/4-81-026d [Revised]) (You can download a
zipped WordPerfect file of this document from the ``Emission Inventory
Guidance'' Section of the CHIEF Web Site.)
http://www.epa.gov/ttn/chief/ei__guide.html
c. Growth estimates. In order for EPA to approve a SIP for the
proposed Ozone Transport Rule, the State must clearly document growth
factors and control assumptions used in the budget calculations. To the
extent the State uses EPA growth factors and control assumptions, the
SIP need only include a statement attesting to this. If a State wants
to substitute its own growth factors or control assumptions in the
budget analysis, it must provide adequate justification for using the
alternative numbers. As stated in the November 7, 1997 NPR (62 FR
60367), EPA believes it is important that consistent emissions growth
estimates be used for the State's budget
[[Page 25915]]
demonstration and for EPA's calculation of the required statewide
emissions budget. The EPA will evaluate any revision to these growth
factors or control assumptions that is suggested during the comment
period on this rule and may recalculate the required statewide budget
to reflect the State's change. Because the revised growth estimates
will be included in EPA's budget calculation, lower growth rates could
not be considered part of a State's NOX control strategy to
attain that budget unless the change in growth is the result of clearly
identified control strategies that can be shown to provide real,
permanent, and quantifiable changes in growth. In the November 7, 1997
NPR, EPA encouraged States to request any changes to growth estimates
or control assumptions during the comment period for the proposal so
that budgets given in the final rulemaking would reflect these changes.
Guidance on how to prepare emission growth and projections is listed
below.
The EPA is currently considering an optional alternative approach
for States to use to meet the major source offset requirements under
section 173 of the Act (new source review (NSR) for nonattainment
areas).6 This approach would allow States to create an
offset ``pool'' composed of actual emissions reductions that generally
will be achieved as a result of NOX control strategies
adopted in response to the SIP call. To create an offset pool, at the
time States revise their SIPs to include statewide NOX
control measures, under certain conditions states could set aside a
subset of their emissions reductions generated from those measures for
the purpose of offsetting anticipated emissions increases of ozone
precursors from new and modified major sources that would be subject to
nonattainment NSR preconstruction permitting. (The EPA is considering
modifying the NSR regulations to consider both NOX and VOC
ozone precursors in all areas. Under such an approach, for offset
purposes, VOC emissions increases from new and modified major sources
could be offset with NOX emissions decreases where
appropriate.)
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\6\ The EPA is not now seeking comment on the optional
alternative approach of an offset pool. The approach is described
here solely for the purpose of informing States of the potential for
such an approach and its potential relationship to the growth
estimates in the SIP call rulemaking. If EPA pursues this approach,
the agency will propose it for comment in a separate Federal
Register notice and intends to take final action by the end of this
year. In particular, to the extent that the offset pool option might
elaborate upon or vary from existing Agency policy or guidance, such
differences will be addressed in the later notice.
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The EPA currently anticipates that those States subject to the
NOX SIP call will be able to take advantage of the offset
pool idea, as compliance with the SIP call will necessitate emissions
reductions that are likely to be creditable as offsets. Specifically,
because States' budgets under the SIP call account for a certain
increment of new major source growth, states may set aside that
increment in an offset pool and still comply with the budgets mandated
by the SIP call. Thus, to take full advantage of the offset pool
approach, States would need to ensure that they have projected
sufficient growth considering major new sources and major modifications
to existing major sources that will be locating in existing and new
nonattainment areas. In general, EPA believes that sufficient growth
assumptions have been built into the budget calculations to allow an
adequate margin for new source offsets. Nevertheless, before EPA
finalizes the NOX budgets, States have an opportunity to
reevaluate and adjust growth factors and control assumptions to ensure
that the final budgets accurately reflect State-specific forecasts of
major new source growth. Consequently, EPA recommends that States
covered by this rulemaking and interested in using offset pools review
their emissions growth assumptions and projections for anticipated new
and modified major sources that will become part of their 2007 baseline
emissions inventories under this rulemaking to ensure that growth
projections accurately reflect the expected new emissions that will be
required to be offset under major NSR.
d. Emissions Growth Projection Guidance.
``Procedures for Preparing Emissions Projections'' EPA-
450/4-91-019, July 1991 (Hard copy only available).
``Guidance for Growth factors, Projections, and Control
Strategies for the 15 Percent Rate-Of-Progress Plans'' EPA 452/R-93-
002, March 1993 (Hard copy only available).
B. Emissions Reporting Requirements for States
As stated in the November 7, 1997 NPR, the EPA believes it is
essential that compliance with the regional control strategy be
verified. Tracking emissions is the principal mechanism to ensure
compliance with the budget and to assure the downwind affected States
and EPA that the ozone transport problem is being mitigated. Emissions
reporting requirements for States subject to this SIP call are
discussed in this Section.
1. Use of Inventory Data
If tracking and periodic reports indicate that a State is not
implementing all of its NOX control measures beginning in
September 2002 7 or is off track to meet its statewide
budget by 2007, EPA will work with the State to determine the reasons
for noncompliance and what course of remedial action is needed. The EPA
will expect the State to submit a plan showing what steps it will take
to correct the problems. As described more fully in the NPR (62 FR
60364--60369), noncompliance with the NOX transport SIP may
lead EPA to make a finding of failure to implement the SIP and
potentially to implement sanctions, if the State does not take
corrective action within a specified time period.
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\7\ In this discussion of reporting requirements, September 2002
is presumed to be the compliance date for NOX transport
call controls. As discussed earlier, the final rule may adopt a
different date for compliance which may, in turn, affect the dates
in the final requirements for State reporting.
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The EPA will use 2007 data to assess how each State's SIP actually
performed in meeting the statewide NOX emissions budget. If
emissions exceed the required budget in any year after 2006, the
control strategies in the SIP will need to be strengthened. The EPA
will evaluate the circumstances for the budget failure and may issue a
call for States to revise their SIPs, as appropriate.
2. Legal Authority
The legal authority for the proposed State reporting requirements
described in this Section resides in sections 110(a) and 301(a) of the
Clean Air Act. Specifically, the requirement in section 110(a)(2)(D)
that SIPs include ``adequate provisions'' to mitigate certain transport
effects on other States implicitly authorizes emissions inventory
reporting to EPA, as reporting will be needed and appropriate to verify
that a State is in fact meeting its NOX budget. Section
110(a)(2)(F) provides additional authority for requiring that SIP call
submissions include provisions for emissions reporting by sources to a
State, correlation of source information by the State, and steps by the
State to make the correlated information available to the public.
Section 110(a)(2)(K), in turn, requires a State to submit to EPA as
requested, data related to modeling the effect of NOX and
other emissions on ambient air quality. The reported emissions
inventory data described in this Section will be used by EPA in air
quality modeling to assess the effectiveness of the transport
rulemaking's regional strategy. Finally, section 301(a) grants EPA
broad
[[Page 25916]]
authority to prescribe such regulations as are necessary to carry out
its functions under the CAA. These proposed regulations are necessary
for EPA to properly carry out its evaluation of compliance with the SIP
call.
3. Background for Reporting Requirements
In the November 7, 1997 NPR, EPA indicated that it intended to work
with affected States to determine what reporting procedures are needed
to provide adequate assurance that the emissions budgets are being
achieved. On January 13, 1998, EPA held a 1-day workshop with the
States to discuss tracking issues. The objectives of the workshop were
to determine what type and frequency of inventory reporting are
feasible for the different source sectors (power generating sources,
other point sources, area sources, and mobile sources) to identify key
reporting issues related to each sector, and to develop recommendations
on reporting requirements to ensure compliance with the SIP call. The
goal was to share information and ideas rather than to reach consensus.
A summary of the meeting is contained in the docket (docket number V-B-
18) for this rulemaking.
The workshop participants generally thought that existing reporting
requirements for attainment SIPs should be used whenever possible to
minimize any new reporting burden. The States further recommended that
the degree of reporting rigor should be directly related to the sectors
that the State chooses to control in its NOX transport
strategy. Reporting every 3 years was considered feasible for all
source sectors. Reporting on an annual basis was considered both
achievable and necessary for all source sectors that a State chooses to
regulate specifically for the purpose of meeting the NOX
budgets proposed in the SIP call. This would include all NOX
sources within the State which are subject to measures included by the
State in its transport SIP revision in response to this SIP call. In
addition, it was noted that sources or source categories that would be
participating in a trading program would need to meet the reporting
protocols specific to that program. Consideration was also given to
establishing uniform monitoring and reporting requirements and a
centralized data base for reporting for other sources. Several States
indicated support for this concept if there were easy access to the
data by all parties. For all source sectors, the States suggested that
emissions rather than indicators should be reported.
4. Proposal
After taking into account the suggestions on tracking of the
participants in the workshop, EPA today is proposing inventory
reporting requirements for States subject to the NOX SIP
call. The regulatory text appears in proposed Sec. 51.122 and is
described below.
The EPA is proposing that States report emissions annually starting
with data for the year 2003 8 for any emissions source
(point, area, or mobile) to which additional controls are being applied
for the purpose of meeting the NOX budget, with certain
exceptions as discussed below, and from any emissions source that will
either sell or buy NOX emission allowances. The EPA is also
proposing that States develop and submit comprehensive statewide
NOX inventories, including all NOX sources,
controlled and uncontrolled, every 3 years, starting with data for the
year 2002.
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\8\ 2003 would be the year for which the data would be reported.
The actual reporting schedule is given in the Reporting Schedule
Section.
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The tracking requirements for meeting the NOX SIP call
budget attempt to make use of existing inventory reporting mechanisms
as much as possible so that existing requirements are not duplicated.
However, the reporting requirements outlined below are more
comprehensive than current reporting requirements for attainment SIPs
in two respects. This is because EPA proposes that States report
emissions from area sources and mobile sources annually if the State
adopts new measures to reduce emissions from these sources for purposes
of meeting the NOX budget. Currently, there is no annual
reporting requirement for area or mobile sources. In addition, States
are not currently required to report on a 3 year cycle emissions from
area and mobile sources in attainment areas. States would be required
to report Statewide area and mobile source ozone season emissions every
third year under the proposed requirements.
Details of reporting for specific source types are set forth below.
5. Annual Reporting
Annual NOX emissions reporting requirements for point,
area and mobile source emissions are to start for the year 2003. The
State must submit annual reports for all sources the State chooses to
regulate specifically for the purpose of meeting the NOX
budgets proposed in the SIP call. This would include all NOX
sources within the State which are subject to measures included by the
State in its transport SIP revision in response to this SIP call. For
example, a State would not have to submit an annual report for
NOX emissions for a cement kiln which was controlled prior
to 1998 for RACT purposes. However, if the State chose to go beyond
RACT requirements for the cement kiln in order to meet its budget, the
State would have to report annually the emissions for the source.
Emissions inventory reports are to be submitted according to the
Reporting Schedule Section below.
a. Point Sources.9 The EPA proposes that States be
required to report NOX emissions annually for all point
sources that are subject to regulations specifically for the purpose of
meeting the NOX budgets proposed in this SIP call. The State
must report emissions from such point sources both for the whole year
and for the ozone season (May 1 to September 30). The direct reporting
from sources to EPA of data used for compliance with the requirements
of a trading program meeting the requirements of 40 CFR Part 96 can be
used to satisfy this requirement. The EPA is also taking comment on
requiring electrical generating units and large industrial boilers to
use the monitoring provisions in 40 CFR Part 75 to account for their
emissions. This topic is more thoroughly discussed in Section IV.A.3,
Approvability Criteria.
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\9\ The EPA is proposing to define point source for this rule as
a non-mobile source which emits 100 tons or more per year of
NOX emissions. Non-mobile sources which emit less than
100 tons per year of NOX would be considered area
sources. This definition of point source is consistent with current
reporting requirements for NOX emissions.
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b. Area Sources. The EPA proposes that the State determine area
source NOX ozone season emissions for source categories that
are controlled beyond otherwise applicable Federal, State or local
measures to meet the NOX budget and report these annually to
EPA. A State need not report annually the emissions from an area source
sector if the State does not require additional NOX
reductions from that sector in order to meet the transport rule's
NOX budget.
c. Mobile Sources. The EPA proposes that a State determine
statewide mobile source NOX ozone season emissions and
report these to EPA annually if the State is requiring additional
controls for purposes of meeting the NOX budget. Reductions
from Federal measures are already assumed in the budget. A State need
not report annually the emissions from mobile sources if the State does
not require additional NOX reductions from that sector in
order to meet the transport rule's NOX budget.
[[Page 25917]]
6. Reporting Every Third Year (3-Year Cycle or Triennial Reporting)
Consistent with current 3-year reporting requirements, EPA proposes
that for every third year, starting in 2002, States would be required
to submit to EPA statewide NOX emissions data from all
NOX sources (point, area, and mobile) within the
State.10 These data would include data from all source
categories in the State regardless of whether those sources are being
controlled to meet the requirements of the transport rulemaking. For
triennial reporting for area and mobile sources, only ozone season
emissions must be reported. For triennial reporting for point sources,
both ozone season and annual emissions must be reported.
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\10\ The actual submittal of data by the State would only be
required 12 months after the end of 2002. The data should be
submitted according to the schedule in the Reporting Schedule
Section.
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7. 2007 Report
The EPA proposes that in 2007, States submit to EPA statewide
NOX emissions data from all NOX sources (point,
area, and mobile) within the State. This would include data from all
source categories in the State regardless of whether those sources are
being controlled to meet the requirements of the transport rulemaking.
For the 2007 report, only ozone season emissions must be reported for
area and mobile sources, while both ozone season and annual emissions
must be reported for point sources. The data reporting requirements are
identical to the reporting requirements for the 3-year cycle
inventories, and this reporting requirement is being proposed to allow
evaluation of whether budget requirements are met for 2007. This one-
time special inventory is necessary because the ordinary 3-year
reporting cycle does not fall in the year 2007. States which must
submit the 2007 inventory may project incremental changes in emissions
from 2007 to 2008 to allow the 2008 inventory requirement to be more
easily met and to reduce the burden on States which must submit full
NOX inventories in consecutive years, i.e., 2007 and 2008.
8. Ozone Season Reporting
The EPA is proposing that the States provide ozone-season
inventories for the sources for which the State reports annual,
triennial and 2007 emissions. The ozone season emissions may be
calculated from annual data by prorating emissions from the ozone
season by utilization factors that must be reported and that are
further defined in 40 CFR 51.122. For area and mobile sources, only
ozone season data must be reported for the annual, triennial, and 2007
inventories. For point sources, the State must report emissions for the
whole year, as well as for the ozone season, since States are already
required under other existing inventory provisions to submit the data
for the whole year. For the annual report, emissions need only be
reported for source categories that a State chooses to regulate
specifically for the purpose of meeting the NOX budgets
proposed in the SIP call. This would include all NOX sources
within the State which are subject to measures included by the State in
its transport SIP revision in response to this SIP call. For the
triennial and 2007 reports, ozone season emissions from all
NOX source categories within the State, controlled or
uncontrolled, must be reported. The EPA is proposing that each State
provide its ozone season calculation method to EPA for approval.
9. Data Reporting Procedures
When submitting a formal NOX budget emissions report and
associated data, the State should formally notify the appropriate EPA
Regional Office of its activities. The EPA proposes that States would
be required to report emissions data in an electronic format to the
location given below. Several options are available for data reporting.
The State may choose to continue reporting to the EPA Aerometric
Information Retrieval System (AIRS) using the AIRS facility subsystem
(AFS) format for point sources. (This option will continue for point
sources for some period of time after AIRS is reengineered (before
2002), at which time this choice may be discontinued or modified.) A
second option is for the State to convert its emissions data into the
Emission Inventory Improvement Program/Electronic Data Interchange
(EIIP/EDI) format. This file can then be made available to any
requestor, either using E-mail, floppy disk, or value added network, or
can be placed on a file transfer protocol (FTP) site. As a third
option, the State may submit its emissions data in a proprietary format
based on the EIIP data model. For the last two options, the terms
``submitting'' and ``reporting'' data are defined as either providing
the data in the EIIP/EDI format or the EIIP based data model
proprietary format to EPA, Office of Air Quality Planning and
Standards, Emission Factors and Inventory Group, directly or notifying
that group that the data are available in the specified format and at a
specific electronic location (e.g., FTP site). A fourth option for
annual reporting (not for third year reports) is to have sources submit
the data directly to EPA. This option will be available to any source
in a State that is both participating in a trading program meeting the
requirements of 40 CFR part 96 and that has agreed to submit data in
this format. The EPA will make both the raw data submitted in this
format and summary data available to any State that chooses this
option. The EPA also solicits comment on whether this option should be
expanded to additional stationary sources.
For the latest information on data reporting procedures, call the
EPA Info Chief help desk at (919) 541-5285 or email to
[email protected].
10. Reporting Schedule
The EPA is proposing that States submit the required annual and
triennial emissions inventory reports no later than 12 months after the
end of the calendar year for which the data are collected. Because
downwind nonattainment areas will be relying on the upwind
NOX reductions to assist them in reaching attainment by the
required dates, EPA believes it is important that data be submitted as
soon as practicable to verify that the necessary emissions reductions
are being achieved. Early reports will allow States to more quickly
respond to implementation problems detected by the reports. States
should formally notify the appropriate EPA Regional Office when making
the submittals.
In a related rulemaking effort, EPA is currently developing the
consolidated emissions inventory reporting rule. Among other things,
the rule will be proposing that all States in the Nation submit
statewide inventories of ozone precursors (NOX, VOC, CO)
every 3 years beginning with 1999 data. The third year reporting
requirement for the transport rule has been developed to be consistent
with that reporting cycle. However, the proposed 2002 start date for
the transport rule emissions reports is 3 years later than the start
date for the consolidated rule reports. The EPA is considering an 18-
month reporting schedule for the latter rule. The EPA expects that, as
States gain experience in developing statewide emissions inventories,
less time will be needed to gather and quality assure the data. Once
States have completed the first cycle of reporting for 1999 under the
consolidated rule, they may have sufficient procedures in place to
allow for an accelerated reporting schedule. Therefore, because of the
importance of the NOX inventory reports for determining
compliance with the NOX budgets, EPA believes it is
appropriate
[[Page 25918]]
to require a 12-month reporting schedule for the transport rulemaking.
The EPA recognizes that there are different constraints on data
collection for the point, mobile, and area source categories.
Therefore, EPA is also soliciting comment on whether different
reporting schedules should be established for the different source
categories, such that data that can be obtained more readily should be
submitted sooner. For example, because point sources are already known
to State agencies, and their operating parameters will not change
significantly from year to year, the time needed to collect and quality
assure data may be shorter than for the other categories. The new data
submission procedures discussed above may allow further reductions in
the reporting time. The EPA is soliciting comment on whether the State
reporting time for point source emissions should be shortened to no
later than 6 or 9 months after the end of the calendar year for which
the data are collected.
For mobile and area sources, the necessary reporting time frames
may be longer than for point sources due to the delay in obtaining
activity data from information sources outside the inventory preparing
agency. In many cases, surveys to collect new activity data are
required by the inventory preparing agency to be able to calculate
emissions estimates. As with point sources, the new data submission
procedures may allow reductions in the reporting time. The EPA is
soliciting comment on whether no later than 6 or 9 months after the end
of the applicable calendar year would be a feasible time frame for
submitting mobile and area source emissions inventory reports.
If different reporting schedules are established for the different
source categories in the final rule, the EPA is proposing that, for the
third year complete statewide inventory, States submit a summary report
identifying the separate submittals and totaling the statewide
NOX ozone season emissions to demonstrate progress toward,
and ultimately compliance with, their NOX budget.
11. Confidential Data
Emissions data being requested in today's proposal would not be
considered confidential by the EPA (See 42 U.S.C. 7414). However, some
States may restrict the release of certain types of data, such as
process throughput data. Where Federal and State requirements are
inconsistent, the EPA Regional Office should be consulted for final
reconciliation.
12. Data Elements To Be Reported
In addition to reporting ozone season NOX emissions, the
State should report other critical data necessary to generate and
validate these values. This includes data used to identify source
categories such as site name, location and (source classification code)
SCC codes. It also includes data used to generate the NOX
emissions values such as fuel heat content and activity level. The
specific data elements required for each source category are further
defined in 40 CFR 51.122.
V. NOX Budget Trading Program
In the November 7, 1997 proposed rulemaking to reduce the transport
of ozone and facilitate attainment of the NAAQS for ozone, EPA offered
to develop and administer a multistate NOX trading program
to assist States in the achievement of these goals; today's notice
proposes such a program. The trading program being proposed employs a
cap on total emissions in order to ensure that emissions reductions
under the proposed transport rulemaking are achieved, while providing
the flexibility and cost effectiveness of a market-based system. This
Section provides background information and a description of the
NOX Budget Trading Program, as well as an explanation of how
the trading program would interface with other State and Federal
programs. In addition, a model rule for the trading program is
proposed. States can voluntarily choose to participate in the
NOX Budget Trading Program by adopting the model rule, which
is a fully approvable control strategy for achieving emissions
reductions required under the proposed transport rulemaking.
Should the States voluntarily choose to participate in the
NOX Budget Trading Program by adopting the model rule, EPA's
authority to cooperate with and assist the States in the implementation
of the trading program resides in both State law and the CAA. With
respect to State law, any State which elects to adopt the model rule as
part of its transport SIP will be authorizing EPA to assist the State
in implementing the trading program with respect to the sources in that
State. With respect to the CAA, EPA believes that the Agency's
assistance to those States that choose to participate in the trading
program will facilitate the implementation of the program and minimize
any administrative burden on the States. One purpose of title I of the
CAA is to offer assistance to States in implementing title I air
pollution prevention and control programs (42 U.S.C. 101(b)(3)). In
keeping with that purpose, section 103(a) and (b) generally authorize
EPA to cooperate with and assist State authorities in developing and
implementing pollution control strategies, making specific note of
interstate problems and ozone transport. Finally, section 301(a) grants
EPA broad authority to prescribe such regulations as are necessary to
carry out its functions under the CAA. Taken together, EPA believes
that these provisions of the Act authorize EPA to cooperate with and
assist the States in implementing the NOX Budget Trading
Program in the ways set forth in the model rule.
A. Program Summary
1. Purpose of the NOX Budget Trading Program
The OTAG concluded that an emissions trading program could
facilitate cost effective emissions reductions from large combustion
sources (for more information on OTAG, see Section V.B.1.). When
designed and implemented properly, a market-based program offers many
advantages over its traditional command-and-control counterpart. The
OTAG articulated five principal advantages of market-based systems: (1)
Reduced cost of compliance; (2) creation of incentives for early
reductions; (3) creation of incentives for emissions reductions beyond
those required by regulations; (4) promotion of innovation; and (5)
increased flexibility without resorting to waivers, exemptions and
other forms of administrative relief (OTAG 1997 Executive Report, pg.
57). These benefits result primarily from the flexibility in compliance
options available to sources and the monetary reward associated with
avoided emissions in a market-based system. The cost of compliance in a
market-based program is reduced because sources have the freedom to
pursue various compliance strategies, such as switching fuels,
installing pollution control technologies, or buying authorizations to
emit from a source that has over-complied. Since an emission rate or
emissions level below the level mandated allows the generation of
credits or allowances that may be sold on the market, pollution
prevention becomes more cost effective, and innovations in less-
polluting alternatives and control equipment are encouraged.
A market system that employs a fixed tonnage limitation (or cap)
for a source or group of sources provides the greatest certainty that a
specific level of emissions will be attained and maintained since a
predetermined level
[[Page 25919]]
of reductions is ensured. With respect to transport of pollution, an
emissions cap also provides the greatest assurance to downwind States
that emissions from upwind States will be effectively managed over
time. The capping of total emissions of pollutants over a region and
through time ensures achievement of the environmental goal while
allowing economic growth through the development of new sources or
increased use of existing sources. In an uncapped system, (where, for
example, sources are required only to demonstrate that they meet a
given emission rate), the addition of new sources to the regulated
sector or an increase in activity at existing sources can increase
total emissions even though the desired emission rate control is in
effect.
In the NOX Budget Trading Program, EPA proposes to
implement jointly with participating States, a capped market-based
program for certain combustion sources to achieve and maintain an
emissions budget consistent with the proposed transport rulemaking. An
emissions cap or budget trading program for large combustion sources is
a proven and cost-effective method for achieving emissions reductions
while allowing regulated sources compliance flexibility.
Although participation in the NOX Budget Trading Program
is discretionary, EPA encourages States to participate in the trading
program as a cost-effective way of meeting their emissions reductions
obligations under the proposed transport rulemaking. Specifically,
today's proposal is designed to assist States in: (1) Achieving,
through a program covering certain large stationary combustion sources,
emissions reductions required under the proposed transport rulemaking;
(2) ensuring flexibility for regulated sources; (3) reducing compliance
costs for sources; and (4) reducing administrative costs to States.
Adoption of the NOX Budget Trading Rule would ensure
consistency in certain key operational elements of the program among
participating States, while allowing each State flexibility in other
important program elements. Uniformity of the key operational elements
across the NOX Budget Trading Program region is necessary to
ensure a viable and efficient trading program with low transaction
costs and minimum administrative costs for sources, States, and EPA.
The effect of NOX emissions on air quality in down wind
nonattainment areas depends, in part on the distance between sources
and receptor areas. Sources that are closer to the nonattainment area
tend to have much larger effects on air quality than sources that are
far away. In light of this, and as discussed in Section VII, the Agency
plans to evaluate alternative approaches in developing the final rule.
The Agency solicits comments on whether a trading program should
factor in differential effects of NOX emissions in an
attempt to strike a balance between achieving the cost savings from a
broader geographic scope of trading and avoiding the adverse effects on
air quality that could result if the geographic domain for trading is
inappropriately large or trades across areas are not appropriately
adjusted to reflect differential environmental effects. The Agency
could consider establishing ``exchange ratios'' for tons traded between
areas. The large number of areas in the region violating the standards
and the several different weather patterns associated with summertime
ozone pollution episodes complicate the development of a stable set of
trading ratios. Alternatively, the Agency could consider establishing
subregions for trading within the 23-jurisdiction area and apply a
discount to or prohibit trades between regions.
The Agency solicits comments on this issue. If after review of
alternative approaches (including sub-regional modeling analysis
submitted by the States and other commenters), EPA concludes that an
alternative approach is appropriate, EPA will issue a SNPR.
2. Emissions Reductions Required by the Proposed Transport Rulemaking
Each of the 22 States and the District of Columbia, determined by
EPA in the proposed transport rule to make a significant contribution
to nonattainment or interfere with maintenance in another jurisdiction,
has been assigned a statewide NOX emissions budget. Each of
these States must submit a SIP revision delineating the controls that
will be implemented to meet its specified budget. Each State has
complete discretion to develop and adopt a mix of control measures
appropriate for meeting its assigned emissions budget. Today's proposal
assumes that compliance with the emissions reductions requirements for
the transport rulemaking will begin on May 1, 2003, as proposed in the
transport rulemaking. If a different compliance deadline is required in
the final transport rulemaking, the deadlines in the proposed trading
rule will be adjusted accordingly.
In the proposed transport rulemaking, EPA calculated seasonal
NOX emissions budgets for States, assuming activity growth
levels through 2007 and the application of reasonable, cost-effective
controls that are currently available to achieve NOX
reductions. The statewide budgets were developed by applying
appropriate controls to each sector of the total State emissions
inventory: large electricity generating devices, point sources other
than large electricity generators, nonroad engines, highway vehicles,
and area sources. The statewide NOX budget development
process is fully described in Section III.B. of the November 7, 1997
proposal (62 FR 60346).
As outlined in the proposed transport rulemaking, budget levels
calculated for nonroad engine, highway vehicle, and area source
inventory sectors assume continued application of controls already
required for those source sectors in addition to implementation of
Federal measures, such as the National Low Emissions Vehicle Program.
The statewide seasonal NOX budgets proposed for the large
electricity generating source sector (fossil-fuel burning electricity
utility units and nonutility units serving electricity generators
greater than 25 MWe) were based on applying a uniform NOX
emission rate of 0.15 lb/mmBtu to projected generating activity levels.
Budget estimates for States' nonutility point source sector were
developed assuming a 70 percent reduction from future emissions levels
of large sources (greater than 250 mmBtu/hour), and application of RACT
to medium sized sources (100-250 mmBtu/hour) in this category.
Though States are free to independently determine their control
strategies to achieve their statewide budgets, several Federal and/or
State programs are already under way or planned for most of the
inventory source sectors to assist States in meeting their budgets. For
example, meeting individual budget components for highway vehicles and
nonroad engines can be achieved through Federal programs without
adopting additional new control strategies. In addition, EPA is
offering to administer certain aspects of today's proposed regional
NOX Budget Trading Program in order to assist States in
developing a regulatory strategy for large stationary combustion
sources.
3. Benefits of Participating in the NOX Budget Trading
Program
Participation in the NOX Budget Trading Program would
enable States that have been identified in the proposed transport
rulemaking to achieve the required emissions reductions from stationary
combustion sources while minimizing the
[[Page 25920]]
administrative burden faced by both States and sources. The SIP
revision process required by the proposed transport rulemaking would be
significantly streamlined for States choosing to include the
NOX Budget Trading Program as a part of the SIP. The EPA
proposes that adoption of the model rule will be considered a SIP-
approvable control strategy for the proposed transport rulemaking.
States electing to participate in the trading program may either adopt
the model rule by reference or develop State regulations that are in
accordance with the model rule.
The permitting process under the trading program would be
significantly streamlined since there will be no need for enforceable
compliance plans and few circumstances necessitating permit revisions.
Emissions monitoring, a central requirement of the trading program, as
well as the availability to the public of emissions data, allowance
data, and annual reconciliation information, would ensure that
participating States and the public have confidence that the required
emissions reductions are being achieved.
Cost savings for sources in States included in the trading program
are projected to be substantial. As estimated in the ``Proposed Ozone
Transport Rulemaking Regulatory Analysis'' (September 1997 docket #
III-B-01), annual incremental costs for a rate-based control approach
(at 0.15 lbs/mmBtu) are estimated to be $501 million higher in 2005
than the costs of participating in the NOX Budget Trading
Program (assuming the same emission rate) for the 23 jurisdictions in
the proposed transport rulemaking. Moreover, the annual average cost
effectiveness of emissions reductions achieved through a regional
trading program for the electric power industry is projected to be
approximately $1,250 per ton by 2010, while the cost effectiveness of
the rate-based approach is projected to be $2,050 per ton by 2010
(pages 2-24 through 2-27).
Sources included in the trading program can also expect increased
compliance flexibility, as compared to a rate-based approach that
requires each affected source to comply with the 0.15 lbs/mmBtu
emission rate and necessitates installation of control equipment for
any affected source that cannot meet the limit. Participation in the
trading program provides sources the choice of numerous compliance
strategies. Moreover, sources can choose to over-comply and generate
excess allowances that can be sold on the market or, as discussed
below, possibly banked for future use. In addition, sources may change
their control approach at any time without regulatory agency approval.
4. EPA's Proposal
Initially, the following sources would be included in the
NOX Budget Trading Program: fossil fuel-fired units (i.e.,
stationary boilers, combustion turbines, and combined cycle systems)
that serve an electrical generator of capacity greater than 25 MWe; and
fossil fuel-fired units that do not serve a generator and that have a
heat input capacity greater than 250 mmBtu/hr. All such sources located
within a State that chooses to join the trading program would be
required to participate in the program. Conversely, sources located in
States that do not join the trading program would not be eligible to
participate. The NOX budget sources initially included in
the trading program represent about 80 percent of the point source
portion of the 2007 NOX baseline emissions inventory and
about 65 percent of the point source portion of the 2007 NOX
budget as proposed in the ozone transport rulemaking. Additionally,
these sources represent about 90 percent of the emissions reductions
required in the proposed ozone transport rulemaking. This core group of
sources, therefore, captures the majority of NOX emissions
from the point source sector. States, however, have the option of
extending the program to include additional point sources at their
discretion, provided these additional point sources can fulfill the
requirements set forth for the trading program in this proposal. The
EPA is also taking comment on allowing certain new and modified major
sources to participate in the trading program at their discretion as a
way of potentially meeting the new source offset provisions under
section 173 of the CAA, provided the source meets the permitting,
monitoring, and accountability requirements of the trading
program.11 The EPA requests comments on broadening the
applicability of this trading program to include more types of sources
such as process sources, mobile sources, or area sources. Commenters
should address each type of source that they recommend be included in
the applicability of this program. For each source type, commenters
should describe procedures for monitoring emissions and identify
responsible parties for the source type. Criteria for monitoring and
for responsible parties are outlined below. Additionally, comment is
requested on any other types of concerns or issues associated with
inclusion of these other source types (e.g., environmental justice; net
cost savings likely to accrue from trading; administrative costs for
sources, States, and EPA).
---------------------------------------------------------------------------
\11\ For discussion on this subject, see Section F, below, that
addresses New Source Review.
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Sources in the trading program would be required to monitor and
report their emissions in accordance with relevant portions of 40 CFR
part 75, which is currently under revision to provide greater
flexibility to regulated sources. (40 CFR part 75 revisions will be
proposed in a notice entitled ``Acid Rain Program; Continuous Emission
Monitoring Revisions'' that will be published in the Federal Register
in the near future.) The monitoring of emissions is necessary for
accountability and to ensure that a ton from one source in one State is
equivalent to a ton from another source in the same or another State.
The NOX allowances--each allowance representing a
limited authorization to emit one ton of NOX--would be the
currency used in the trading program. An emissions budget and an
allowance-based system ensure achievement of environmental goals within
a cost-effective, market-based program and can be implemented through
existing infrastructure. A fixed number of NOX allowances
would be allocated to regulated sources in each State for each ozone
season in the amount of the NOX budget set for the trading
program in the State. States would have the responsibility for
allocating allowances among regulated sources. The proposed
NOX Budget Trading Rule establishes timing requirements for
the submission of NOX allowance allocations to EPA by
participating States for inclusion into the NOX Allowance
Tracking System (NATS), which would be operated by EPA.
In addition to timing requirements, today's proposal provides
options for a recommended methodology for States to allocate
NOX allowances to their sources covered by the
NOX Budget Trading Program. A specific recommendation would
be included in the final trading rule. States would have the
flexibility to deviate from EPA's recommendation as long as the timing
requirements (40 CFR 96.41) are met and total NOX allowances
allocated to regulated sources do not exceed the number of tons that
the State apportions to these sources in the SIP. This would help
ensure that the trading program can operate efficiently and effectively
across multiple States.
In addition to EPA's traditional role in the approval and oversight
of the SIP, EPA would be responsible for managing the emissions data
and market functions
[[Page 25921]]
of the program, as well as performing annual reconciliation of
monitored emissions and allowances. States choosing to join the trading
program would be responsible for promulgating the supporting State
regulations; submitting NOX allowance allocations to EPA for
inclusion in NATS; and enforcing the permitting, monitoring and excess
emissions requirements. As established in the proposed transport
rulemaking, the control period would extend from May through September.
Based on results presented in the regulatory analysis for the proposed
transport rule that suggest no significant changes in the location of
emissions reductions resulting from an unrestricted trading program
with a consistent control level (``Proposed Ozone Transport Rulemaking
Regulatory Analysis,'' September 1997, pages 2-20 and 2-23, docket #
III-B-01), trading could occur across participating States free from
restrictions (other than the requirement to comply with existing
emissions limits under title I and title IV of the Act). These and
other program parameters, however, are predicated on the proposed
transport rule and may be modified if the final transport rule differs
from the proposal.
B. Evolution of the NOX Budget Trading Program
Market-based systems to control NOX emissions have been
developed within the United States, including: The South Coast Air
Quality Management District's Regional Clean Air Incentives Market
(RECLAIM) and the Ozone Transport Commission's (OTC) NOX
Budget Program. Today's proposed NOX Budget Trading Program
builds directly upon the OTC program and recommendations from OTAG. In
addition, EPA held two public workshops in November and December of
1997 specifically to solicit input on the development of the trading
program. The proceedings of these workshops are also summarized in this
Section.
1. OTC's NOX Budget Program
The goals and implementation strategy of the OTC's NOX
Budget Program are similar to those of the proposed transport rule and
today's proposed NOX Budget Trading Program. Taking into
account the work that has been done by the OTC, EPA has tried to
develop a proposal that will minimize conflicts between the two
programs by building upon the terms and provisions in the OTC program.
Section V.E of this preamble further discusses the integration issues
for the two programs.
On September 27, 1994, the OTC adopted a Memorandum of
Understanding (MOU) committing the signatory States to the development
and proposal of regionwide NOX emissions reductions in two
phases beginning in 1999 and 2003. The signatory States were Maine, New
Hampshire, Vermont, Massachusetts, Connecticut, Rhode Island, New York,
New Jersey, Pennsylvania, Maryland, Delaware, and the District of
Columbia.
The OTC MOU requires reductions in ozone season NOX
emissions from utility and large industrial combustion facilities in
order to further the effort to achieve the health-based NAAQS for
ozone. These emissions reduction requirements will be implemented
through a regionwide cap-and-trade program. The OTC States, in
collaboration with EPA, industry, and environmental groups, drafted and
approved a model rule in May 1996. This model rule serves as a template
for States to adopt their own rules to implement the budget program
defined by the OTC MOU. In addition to adopting rules, States in the
OTC program are responsible for allocating NOX allowances
among regulated sources, certifying monitors and monitoring plans,
auditing and recertifying sources, and enforcing the provisions of
their State rules. In addition to EPA's traditional role in the
approval and oversight of the SIP, EPA serves as the administrator for
the NATS and the Emissions Tracking System (ETS), the data systems used
to implement the OTC program. This entails issuing NOX
allowances and opening accounts, processing transfers and quarterly
emissions reports, conducting annual reconciliation of emissions and
allowances, and providing technical assistance to States and sources as
needed.
To implement the program, the OTC MOU emissions reduction
requirements were applied to a 1990 baseline for NOX
emissions in the Ozone Transport Region (OTR) to create an emissions
budget for each of the 2 target years: 1999 (Phase II) and 2003 (Phase
III). (Phase I required the installation of RACT by May 1995.) This
budget was apportioned among all the States; each State is responsible
for allocating its budget to regulated sources in its State. Sources
are allowed to buy, sell, or trade NOX allowances, and
ultimately must hold allowances sufficient to cover all NOX
emitted during the ozone season. Beginning in 1999, the total
NOX emissions from regulated sources cannot exceed the
number of allowances allocated in the OTR.
In order to ensure that NOX emissions reductions are
achieved and allowances are fungible, budget sources are required to
monitor and report their NOX emissions. Most sources use
CEMS, as approved by EPA under 40 CFR Part 75. For smaller oil-and gas-
burning units, alternative monitoring methods are available.
At the conclusion of each ozone season, sources have an opportunity
to evaluate their reported emissions and obtain any additional
NOX allowances they may need to offset their emissions
during the ozone season. By December 31 of each year, a regulated
source submits a compliance certification report. Should a source lack
sufficient allowances to offset emissions for the season, the OTC model
rule requires subtraction of allowances from that source's allocation
for the following year. If enough NOX allowances are not
held, an automatic offset will be imposed during the following year's
ozone season where an amount of NOX allowances will be
deducted from the source in an amount equaling three NOX
allowances for each ton of excess emissions. The source is also subject
to the application of existing State and Federal enforcement protocols
and penalties.
The NOX allowances that are not used are automatically
carried over into the following year as banked allowances. The banking
provisions of the OTC model rule provide for unlimited banking of
allowances with a ``progressive flow control'' management scheme to
control the withdrawal and use of banked allowances. (For a more
detailed discussion of banking, see Section V.E.). Explicit program
audit provisions are established in the OTC model rule to ensure that
the use of banked NOX allowances does not threaten the
integrity of the system.
Finally, the OTC model rule makes provisions for possible rule
modifications in the future. This ``mid-course correction'' provides an
opportunity to revise the 2003 emissions reduction target and budget
and to modify the OTC model rule in response to refined air quality
modeling or other altered circumstances.
2. OTAG Process
The OTAG, a partnership among the 37 easternmost States and the
District of Columbia, EPA, industry representatives and environmental
groups, was charged with assessing the significance of ozone transport
and with recommending to EPA control strategies for reducing this
transport. The OTAG's initial meetings were in May and June of 1995,
and its final recommendations were issued to
[[Page 25922]]
EPA on July 8, 1997 (see 62 FR 60376, Appendix B). The OTAG completed
an extensive and comprehensive analysis of ozone transport and control,
and EPA has taken OTAG's work and conclusions into account in
developing this rulemaking.
The analysis and conclusions of the Trading and Incentives
Workgroup of OTAG are particularly relevant to EPA's creation of the
NOX Budget Trading Program. The Trading and Incentives
Workgroup was charged with designing market-based approaches to reduce
NOX emissions. This group identified two basic paths to
market system implementation--identified as ``Track One'' and ``Track
Two''--which could be used to facilitate achievement of the statewide
budgets delineated in the proposed transport rulemaking. ``Track One''
was defined as an interstate cap-and-trade program for stationary
sources, administered by a central regulatory authority, such as EPA.
``Track Two'' was defined as a market-based system without an emissions
cap. As discussed above, trading with a cap better ensures that
environmental goals will be met than trading without a cap. Therefore,
for the purposes of assisting State achievement of the statewide
budgets set forth in the proposed transport rulemaking, EPA is focusing
on implementing a ``Track One'' type of program with today's proposed
rule and is building upon OTAG's analysis and recommendations regarding
the development of Track One programs.
3. EPA Model Trading Program Workshops
The EPA held two public workshops to solicit comments and
suggestions from States and other stakeholders on a NOX cap-
and-trade program prior to developing today's proposed NOX
Budget Trading Rule. This Section describes the workshop process.
Greater detail regarding program development and feedback received
through the workshop process is provided within relevant Sections of
this preamble.
The trading rule workshops were held on November 4 and 5, 1997 in
Washington DC, and December 10 and 11, 1997 in Arlington, Virginia.
Written comments during this pre-proposal phase were welcomed through
December 31, 1997. Each workshop consisted of a 2-day forum: the first
day was devoted to EPA/State discussions, and the second day was open
to all interested parties. Over 150 people participated in each of the
workshops. To facilitate meaningful comments from these participants,
EPA developed working papers on critical issues that were made
available for review prior to each workshop. These papers discussed
major issues relevant to developing a NOX Budget Trading
Rule, delineated options and, in some cases, offered recommendations.
The issues associated with each working paper were presented at the
workshops, followed by open discussion periods allowing workshop
participants to comment and discuss each issue.
The first workshop, addressed the foundations of the NOX
Budget Trading Program development. To achieve the required
NOX emissions reductions in the most cost-effective manner,
the goals of the trading program were defined as meeting the budget,
facilitating trading, and creating a workable program. The necessity of
operating the NOX Budget Trading Program within the
framework of the proposed transport rulemaking dictated further
requirements, such as a seasonal control period. Four fundamental
trading rule components (applicability, monitoring, emissions
limitations, and banking) were discussed at length.
After broad concepts for the NOX Budget Trading Program
framework were introduced and discussed at the first workshop, EPA
revised and augmented the working papers in accordance with comments
and discussion. At the second workshop, EPA presented recommendations
and considerations of additional issues, seeking further input from
participants. The original working papers on applicability, monitoring,
emissions limitations, and banking were expanded, and new papers on the
use of output in allocations and the creation of an energy efficiency
set-aside were introduced in response to interest expressed at the
first workshop. In addition, a paper presenting a skeleton of all the
components of a model rule was presented to provide context for input
and an indication of how the NOX Budget Trading Rule as a
whole was evolving.
The EPA found the workshop process to be very helpful in generating
useful recommendations for developing the framework for the model rule.
Today's NOX Budget Trading Rule proposal incorporates
comments and suggestions raised at both workshops, along with nearly
fifty written comments received following the workshops. Listening to
issues important to States through the workshop process was essential
for EPA to develop a program that would meet States' needs. Since the
ultimate cost savings of the regional trading program will increase
with the number of participating States, it is advantageous to design a
regional trading program that will likely be adopted by the greatest
number of States. The workshops also served as a forum to discuss which
program elements should be consistent among participating States, since
consistency in State-adopted rules is essential for a viable regional
cap-and-trade program. Also of importance in the workshop process was
working with stakeholders, such as affected sources, in order to ensure
that the trading program offers the necessary flexibility, as well as
compatibility with other programs.
The working papers, a detailed summary of the input received during
both workshops, and written comments are included in the proposed
transport rulemaking docket (A-96-56, Section 2a).
4. RECLAIM Program
The RECLAIM program, which was adopted by the South Coast Air
Quality Management District in October, 1993, and began January 1,
1994, provides another example of a cap-and-trade market system. This
program regulates NOX and sulfur oxides (SOX)
emissions from facilities that generally emit four or more tons per
year of either pollutant from permitted equipment in the South Coast
Air Basin, centered in Los Angeles.12 The RECLAIM program
currently includes approximately 330 facilities.
---------------------------------------------------------------------------
\12\ Some sources with annual emissions less than four tons are
included in the program by virtue of their inclusion in a SIC
category in which the majority of sources emit greater than four
tons per year.
---------------------------------------------------------------------------
The RECLAIM program replaced command-and-control regulations with a
market program to provide facilities with added flexibility and lowered
compliance costs in achieving reductions required to meet State and
Federal requirements for clean air programs. Facilities in the program
are collectively required to cut their emissions by a specific amount
each year under the program, resulting in an almost 80 percent
reduction by 2003 for both SOX and NOX. Each
facility participating in RECLAIM is allocated RECLAIM trading credits
(RTCs) equal to its annual emissions limit. Initially, allocations are
based on past peak production and the requirements of existing rules
and control measures for each facility. Allocations decline annually
through the 2003 compliance year, then remain constant during
subsequent years. The RTCs, each representing the limited authorization
to emit one pound of pollutant, expire annually. Facilities may trade
these RTCs among themselves, providing that every quarter, each
facility holds credits
[[Page 25923]]
equal to or greater than their actual emissions for that quarter.
In terms of NOX emitters, the RECLAIM program generally
requires stationary sources that emit ten or more tons of
NOX annually or which burn any solid fuels to use CEMS to
quantify their emissions. Smaller sources have additional monitoring
options. Sources that emit four or more tons of NOX and less
than ten tons may use default emission rates. They must demonstrate
that these rates are appropriate by monitoring process variables,
performing periodic emissions testing, and conducting periodic tune-ups
of equipment. The smallest sources in the RECLAIM program (those with
annual emissions of less than four tons) may choose to use default
emission rates that require less extensive testing and demonstration
than those available to the larger sources.
The program's annual report for 1996 concluded that RECLAIM was
continuing to meet its emissions reduction goals; an active trading
market had developed; and the compliance rate, once it is finalized for
the 1996 compliance year, will be in the 85 to 90 percent range.
C. NOX Budget Trading Program
1. General Provisions
Today's proposed NOX Budget Trading Rule will be
incorporated into the 40 CFR as a new part 96. The subparts of 40 CFR
part 96 are described below. The provisions of 40 CFR part 96 will
become effective and apply to sources only if a State incorporates 40
CFR part 96 by reference into the State's regulation or adopts
regulations that are in accordance with 40 CFR part 96.
a. Purpose. Subpart A of today's proposed NOX Budget
Trading Rule includes Sections describing: To whom the NOX
trading program would apply; the standard requirements for participants
in the program (permitting, NOX allowances, monitoring,
excess emissions, and liability provisions); exemptions for retired
units from the program requirements; definitions, measurements, and
abbreviations; and computation of deadlines stated within the proposal.
b. Definitions, Measurements, Abbreviations, and Acronyms.
Many of the definitions, measurements, abbreviations, and acronyms
are the same as those used in 40 CFR part 72 of the Acid Rain Program
regulations, in order to maintain consistency among programs. However,
additional terms specific to the NOX Budget Trading Program,
such as control period (the period beginning May 1 of each year and
ending on September 30 of the same year), NOX Budget unit (a
unit subject to the emissions limitation under the NOX
Budget Trading Program), and several others are added. Key definitions
are discussed in relevant Sections below describing the rule.
c. Applicability. The EPA proposes that the NOX Budget
Trading Rule be applicable to a core group of sources that includes all
fossil fuel-fired, stationary boilers, combustion turbines, and
combined cycle systems (i.e., ``units'') that serve an electrical
generator of capacity greater than 25 MWe and to any fossil fuel-fired,
stationary boilers, combustion turbines, and combined cycle systems not
serving a generator that have a heat input capacity greater than 250
mmBtu/hr. A unit is considered fossil fuel-fired if fossil fuels
account for more than 50 percent of the unit's heat input on an annual
basis. These sources represent about 80 percent of the point source
portion of the 2007 NOX baseline emissions inventory and
about 65 percent of the point source portion of the 2007 NOX
budget in the proposed ozone transport rulemaking. Additionally, these
sources represent about 90 percent of the emissions reductions required
in the proposed ozone transport rulemaking.
The EPA proposes the above core group of sources based on their
significant contribution of NOX emissions, range of cost-
effective emissions reduction options, ability to monitor emissions,
and ability to identify responsible parties. The following discussion
examines the monitoring and responsible party criteria for the
NOX Budget Trading Program's applicability. Additional
options for the trading program's applicability are also presented for
consideration. The EPA solicits comment on the appropriateness of
including all categories described above in the core group of sources,
whether the size cut-offs should be higher or lower for these source
categories, and the appropriateness of including other source
categories in the core group.
i. Monitoring. In general, sources that participate in a cap-and-
trade program must have the ability to accurately and consistently
account for their emissions. Accuracy is an important design parameter
because it ensures that emissions for all sources covered by the
trading program are within the cap. In addition, because each
NOX allowance will have economic value, it is important to
ensure that emissions (and thus allowances used) are accurately
quantified. Consistency is an important feature because it ensures that
accuracy is maintained from source to source and year to year. It also
ensures that the sources in the trading program are treated equitably.
Finally, consistency facilitates administration of the program for both
the regulated community and State and Federal agencies.
When considering what source types to include in the proposed
trading program (e.g., large boilers, process sources, mobile sources,
area sources), EPA determined that the core sources were capable of
accurate and consistent monitoring as outlined below.
Large Electric Utility Units: For several years, units
serving electricity generators greater than 25 MWe (with some
exemptions for cogeneration and nonutility electricity generating
units) have been complying with the title IV monitoring provisions. The
EPA proposes to include these sources in the NOX Budget
Trading Program.
Other Large Electricity Generating Units: Additionally,
with deregulation of electric utilities, it is not clear how ownership
of the electricity generating facilities will evolve. Therefore, EPA
proposes to include all large electricity generating sources,
regardless of ownership, in the trading program. As there is no
relevant physical or technological difference between utilities and
other power generators, the same monitoring provisions and the size
cut-off of greater than 25 MWe are applicable to all units which serve
generators.
Other Large Steam Producing Units: There is also no
fundamental physical or technological difference between a boiler,
combustion turbine, or combined cycle system that produces steam for
eventual production of electricity or for other industrial
applications. Thus, EPA believes that the same monitoring provisions
can be applied to a boiler, combustion turbine, or combined cycle
system used for industrial steam.13
---------------------------------------------------------------------------
\13\ Further, assuming a generator efficiency of approximately
\1/3\, the 25 MWe cutoff being used for electrical power producers
is roughly equal to a 250 mmBtu/hr cutoff for steam producing
boilers, combustion turbines, and combined cycle systems.
---------------------------------------------------------------------------
ii. Responsible Party. Another critical element of a trading
program is to be able to identify a responsible party for each
regulated source. The responsible party for a source covered by the
trading program would be required to demonstrate compliance with the
provisions of the NOX Budget Trading Program. In general,
the large sources included in the proposed trading program have readily
identifiable owners and operators that would serve as the responsible
party.
[[Page 25924]]
iii. Inclusion of Additional Source Categories. During the public
workshops, several commenters recommended allowing a State to include
additional sources beyond the core group into the trading program. As
the applicability criteria proposed today are intended to define the
minimum set of units required to participate in a trading program,
inclusion of additional sources is allowed. Some States have existing
or planned programs very similar to the one proposed today, but with
different applicability criteria (e.g., the OTC NOX Budget
Program). States may choose to modify the applicability language to
bring in smaller sources of the same type as those included in the core
group or additional source categories. All additional sources (e.g., a
certain industrial process) must meet all trading program requirements
(including monitoring requirements of 40 CFR part 75 subpart H) and be
able to identify a responsible party. The EPA believes that smaller
sources of the same type as those included in the core group should be
able to meet the trading program requirements and, thus, could be
included in a State's trading rule without affecting EPA's streamlined
approval of the SIP as described in Section V.D of this preamble.
The EPA is also taking comment on allowing or requiring additional
stationary source categories beyond the proposed core group to be part
of the trading program. There are three ways that some or all of the
sources included in these additional categories could be included. The
sources could be included as part of the core program applicability, as
an additional list of source categories that a State could choose to
include 14, or they could be individually opted-in according
to the provisions under 40 CFR part 96 subpart I of the trading rule.
---------------------------------------------------------------------------
\14\ 40 CFR part 96 subpart E of the proposed trading rule
addresses the allocation of NOX allowances to
NOX Budget units which includes the core group of sources
as well as any additional sources the State may choose to include in
the trading program.
---------------------------------------------------------------------------
The EPA believes that there are a number of additional source
categories that could account for their emissions using the monitoring
protocols in 40 CFR part 75. Bringing a source or source category that
meets these protocols into the trading program would also not affect
EPA's streamlined approval of the SIP. The EPA proposes to develop a
list of additional source categories beyond the core group that a State
may bring into the trading program without affecting EPA's streamlined
approval of the SIP.
If a State chose to bring other source categories beyond those
included in this proposed list into the trading program, a more
thorough EPA review may be needed. There are two main reasons for this
review. The first is to ensure that the monitoring protocols that the
State intended to use for the source or source category would provide
accurate information and be consistent with the monitoring protocols
being used for the core sources in the program. The second is to ensure
that EPA could successfully administer the regional NOX
trading program with the addition of these sources. For example, EPA
would have to determine that the reporting requirements for these
source categories could be supported with the information systems that
EPA develops and the resources that EPA employs to administer the
program.
The EPA believes that the source categories that are simplest to
consider adding are sources that vent all of their emissions to a
stack, because existing monitoring protocols (e.g., 40 CFR part 75) can
be used to accurately and consistently quantify mass emissions for
these categories of sources. The two existing capped NOX
trading programs (the OTC program and the RECLAIM program) have also
focused on these types of sources.
The OTC program has generally focused on the same types of sources
that are in the proposed core group, electrical generating units and
large industrial boilers that burn primarily fossil fuels. One notable
exception to this is that Connecticut intends to cover municipal waste
incinerators in Phase III of their program, which starts in 2003. The
RECLAIM program has focused on a larger breadth of sources. These
include industrial boilers and electrical generating units, but they
also include: internal combustion engines, heaters, furnaces, kilns and
calciners, ovens, fluid catalytic cracking units, dryers, fume
incinerators/afterburners, test cells, tail gas units, sulfur acid
production units and waste incinerators. In both programs, the
monitoring requirements have been based on a tiered system that
requires more stringent monitoring for units with higher emissions.
Both programs require CEMS for larger units. In general, this would
include units larger than 250 mmBtu with capacity factors of greater
than 10 percent for the OTC program and units with emissions of ten or
more tons of NOX per year for the RECLAIM program. Both
programs also offer less stringent, non-CEMS alternatives for smaller
sources.
While RECLAIM has been able to account for emissions from a larger
group of source categories than EPA is proposing to include in the core
group, RECLAIM has had difficulty with some of these additional source
categories. For instance, RECLAIM's 1996 audit explained that the
standing working group on RECLAIM CEMS Technical issues (a group formed
to address issues relating to RECLAIM monitoring) has focused on issues
``associated mainly with the difficult situations faced by refineries
in implementing CEMS requirements.'' The audit goes on to explain that
``this is attributed to the variability of the fuel used in refinery
equipment [e.g., catalytic cracking units] as compared to natural gas,
the operational variability of much of the affected equipment, and the
fact that many of the sources in an older refinery were never
constructed with CEMS monitoring in mind''. Additionally, discussions
with RECLAIM staff have indicated that units that have high
concentrations of particulate emissions and emit to open baghouses,
such as asphalt heaters and metal melting furnaces, have been difficult
to monitor because of the high concentration of particulates. In short,
RECLAIM's experience has indicated that the problems faced by these
source categories require more resources for both the regulated
community and the regulatory agency. Therefore, while EPA is taking
comment on including all types of stationary sources that emit to
stacks in the program, EPA believes that some sources are better suited
for participating in a trading program because their emissions can more
easily be accurately and consistently quantified.
Based on information available to EPA at this time, the specific
additional source categories for which EPA is particularly interested
in taking comment are: Process heaters, internal combustion engines,
kilns and calciners, and municipal waste incinerators. If any of these
source categories are included in the final rule as a part of the core
group, EPA is proposing that they be included with applicability cut-
offs roughly equivalent to the 25 megawatt cut-off used for electrical
generating facilities and the 250 mmBtu cutoff used for industrial
boilers. The EPA requests comment on the appropriateness of these cut-
offs.
The EPA is taking comment on these particular additional categories
because EPA believes these sources have the capacity to generate
significant amounts of NOX and are capable of monitoring
using the protocols set forth in 40 CFR part 75. These are also source
categories that are currently participating in the RECLAIM trading
program or those that
[[Page 25925]]
at least one of the States in the northeast region has considered
including in the OTC NOX Budget Trading Program.
The EPA believes that these source categories are capable of using
40 CFR part 75 monitoring because they vent all of their emissions to a
stack or stacks, which could be monitored using CEMS. The EPA believes
that the particular monitoring protocols in 40 CFR part 75 that would
be applicable for these sources would be dependent on the fuel burned,
the size of the source, and the magnitude of the emissions of the
particular unit that was being included in the program. This is
consistent with the way that the monitoring protocols are set forth for
core sources. For example, all units that burned solid fuel (including
all municipal waste combustors and cement kilns and process heaters
that burned coal) would use a NOX emission rate CEM and a
flow CEM to determine NOX mass.
Units that burn oil or gas (internal combustion engines and some
process heaters and kilns) would have several other options depending
upon their size. Large oil or gas units could use a NOX
emission rate CEM and a fuel flow meter to determine NOX
mass. Infrequently operated units could qualify to use the emission
rate curve methodology set forth in Appendix E of 40 CFR part 75, and
units with potential emissions 15 of under 25 tons per year
could use the default emission factor protocols for low mass emitters
set forth in 40 CFR 75.19.
---------------------------------------------------------------------------
\15\ The phrase ``potential emissions'' has a different meaning
than the phrase ``potential to emit'' used elsewhere by the Agency.
---------------------------------------------------------------------------
The EPA notes that the currently proposed provisions in 40 CFR
75.19 do not contain default emission factors applicable for these
types of units and requests comments on what factors would be
appropriate. While smaller and less frequently operated units could use
these simplified monitoring methodologies, they would also be allowed
to use any of the monitoring methodologies available to other units in
the program. The low mass emitter methodology as it is currently
proposed was designed to provide very low emitting units a very cost
effective way to account for their emissions using conservative
uncontrolled default emission factors. Because it is based on
conservative uncontrolled default emission factors, it does not allow
units that use it to quantify emissions reductions. The owner or
operator of a unit that qualified to use this methodology might choose
to use another methodology such as the Appendix E methodology or CEMS
because this would be more representative of the unit's actual emission
rate. Another option that is not in the proposed 40 CFR part 75
rulemaking would be to change the low mass emitter methodology to allow
units to use unit specific emission rates and actual unit heat inputs
to get more accurate emissions estimates. Since the emission rates that
were being used would not be as conservative, units would have to do
more quality assurance to demonstrate that their reported emissions
were more representative of their actual emissions. This might include
periodic testing of emission rates and/or periodic tuning requirements
for the equipment. These concepts could also be used in conjunction
with controlled default emission rates to verify that the controls are
operating properly and that the lower default rates are appropriate.
All of these concepts are similar to the monitoring methodologies
allowed for the smallest size units in the RECLAIM program.
The EPA is seeking comment on the following issues related to
monitoring for both the specific additional source categories that EPA
believes are most able to account for their emissions consistently and
accurately and any additional stationary source categories that emit to
a stack. (All comments related to the use of 40 CFR part 75 for
monitoring for these sources should be submitted in the separate
rulemaking on 40 CFR part 75 revisions--40 CFR part 75 revisions will
be proposed in a notice entitled ``Acid Rain Program; Continuous
Emission Monitoring Revisions'' that will be published in the Federal
Register in the near future--rather than in the instant proceeding.)
1. Can these source categories monitor and report
NOX mass emissions using the protocols set forth in the
proposed revisions to 40 CFR part 75? If not, why not?
2. Are there other protocols that should be included which would
provide emissions measurement and reporting for these additional
sources with accuracy and consistency comparable to that provided under
40 CFR part 75?
3. Are the thresholds set forth in 40 CFR part 75 for different
monitoring methodologies appropriate for these types of sources? For
example, in order to qualify to use the load vs. emission rate curve
methodology set forth in Appendix E of 40 CFR part 75, a unit must have
an average capacity factor of less than 10 percent for 3 years and have
a maximum capacity factor of no more than 20 percent in any one of
those years.
The EPA is also seeking comment on the following issues related to
these source categories:
1. Should any of these source categories be included in the core
program applicability, i.e., should their inclusion be mandatory for a
State to participate in the NOX Budget Trading Program?
2. Should States, at their option, be allowed to include any of
these source categories and still receive streamlined approval of their
SIPs?
In addition, EPA is taking comment on whether any other additional
stationary source categories should be included. Finally, EPA is taking
comment on whether individual States including these source categories
would raise concerns about shifting of production activity (and thus
emissions) to other States that do not choose to include these
categories.
There is more uncertainty for the ability of source categories not
identified in the core group or in the list of additional source
categories to meet the trading program requirements. Adding other
source categories not identified in the final NOX Budget
Trading Program would entail additional obligations for the State
(e.g., allocating allowances, certifying monitors, and enforcing
trading program requirements), would mean that EPA's approval of the
SIP would not be as streamlined, and could affect EPA's ability to
administer the region-wide program. Therefore, EPA would strongly
encourage any State wishing to participate in the trading program to
work with EPA before proposing a rule with expanded applicability
criteria beyond that identified in the final NOX Budget
Trading Rule.
iv. Individual Opt-Ins. The EPA is proposing that individual point
sources, not otherwise subject to the trading program and located in a
State that is participating in the NOX Budget Trading
Program, be allowed to opt-in to the program. For a source to opt-in,
it must meet the same monitoring and accountability requirements as
other NOX Budget sources. Thus, under the proposed rule,
initial opt-ins would be boilers, combustion turbines, and combined
cycle systems below the proposed (or State defined) applicability
threshold. The EPA requests comment on whether individual opt-ins
should also include any additional sources that may be included as part
of the core group of sources as a result of the above discussion under
Section iii, Inclusion of Additional Source Categories. The proposed
opt-in provisions are further discussed in the opt-in Section of this
preamble.
[[Page 25926]]
v. Additional Options for Applicability. The EPA solicits comments
on three different options that may be incorporated into the core
applicability provision of the proposed trading rule. One option is to
expand the trading program's core applicability to include smaller, new
sources of the same type as are now proposed for the core applicability
that commence operation on or after May 1, 2003, the start of the first
ozone season (the first compliance period, after September, 2002). For
example, the trading program could apply to all new units serving
electricity generators 10 MWe or greater and new units not serving
electricity generators and having a heat input capacity equal to or
greater than 100 mmBtu/hr. The possibility exists that a significant
number of smaller new units would be constructed and that activity from
existing NOX Budget units could be shifted to these new
units. Over time, the increased number of smaller, new units not
included in the trading program could make up a significant portion of
the overall NOX emissions in comparison to the
NOX emissions from the source categories purportedly
included in the NOX Budget Trading Program. To reduce this
potential, it may be desirable to adjust the applicability criteria for
new units to ensure that the trading program continues to cover a
significant portion of the NOX emissions for the source
categories covered by the program.
A second option would be to expand the core applicability to
include all new and modified sources that meet the definition of major
new or modified source under the part D nonattainment NSR program and
that are of the same type of source included in the proposed core
applicability, even if these sources are smaller than the source size
under option one, above. This would enable the trading program to
integrate more fully with the NSR program. Under this option, the
trading program applicability would include all new and modified units
(whether or not they serve electricity generators) that commence
operation on or after May 1, 2003. If smaller new sources were included
in the trading program, these sources would have to meet the monitoring
requirements of subpart H of 40 CFR part 75; the proposed revisions to
40 CFR part 75 contain new protocols for units with low NOX
mass emissions. Sources' compliance requirements could be streamlined
significantly if they could meet their NSR offset obligations by
participating in the NOX Budget Trading Program (see Section
F, below).
A third option would be to provide an exemption from the trading
program for existing units that have a very low federally enforceable
NOX emissions limit (e.g., 25 tons per year), regardless of
the nameplate capacity or the maximum potential hourly heat input of
the unit. Commenters at the public workshops raised this option noting
that a trading program generally reduces the cost of compliance.
However, for some very infrequently used or very low emitting units,
there may be more cost-effective ways to ensure any necessary
reductions.
vi. Area and Mobile Sources. Comments were received at the public
workshops about the opportunity to include additional sources beyond
large stationary sources in the trading program. There was not
consensus among workshop participants on this issue. However, most
States in attendance were opposed to including area and mobile sources
in the trading program at this time.
As noted above, EPA has identified key criteria that are important
to the success of the trading program. First, it is essential that
these sources are able to monitor at a level of accuracy consistent
with the basic objectives of the program. In addition, the proposed
trading program requires that all sources covered under the program be
held accountable through a responsible party for their total emissions
that occur from May through September of each year.
The EPA may consider inclusion of portions of mobile source or area
source categories which best meet the key concerns mentioned above
(e.g., measurement and accounting of all emissions and identification
of responsible parties). Over the past decade, EPA and the States have
developed procedures and protocols for Mobile Source Emissions
Reduction Credit programs. This effort has focused on the generation of
credits for specific categories of programs, including scrappage and
clean-fueled fleet programs.
Key issues for the development of these mobile source programs
include ensuring that the credits generated reflect real emissions
reductions, development and implementation of an effective monitoring
program, and identification of a responsible party for the
implementation of the program and the ensuing emissions reductions. The
EPA requests comment on the adequacy of the existing programs in
addressing key issues for mobile source credit programs. Comment is
also requested on whether these types of programs, as existing or with
modification, should be considered for inclusion in the NOX
Budget Trading Program.
The EPA is interested in innovative ideas for including area and
mobile sources in cap-and-trade type trading programs. Comments should
address the categories of each source type that could most successfully
be incorporated into a cap-and-trade program and that best address the
key issues. Commenters should address how inclusion of the specific
category recommended may be implemented and the expected effects of
including these source types in the program (e.g., integrity of the
program, public support, flexibility, cost savings, administrative
feasibility). Additionally, comment is requested on any other types of
concerns or issues associated with inclusion of these source types
(e.g., environmental justice \16\).
---------------------------------------------------------------------------
\16\ The EPA is aware of concerns relating to environmental
justice issues. These concerns focus on the possibility that car
scrappage programs might allow significant toxic VOC emissions
increases in specific areas by concentrating region wide emissions
in a local area. The National Environmental Justice Advisory Council
(NEJAC) has recommended that the Agency involve stakeholders,
analyze local environmental impacts of existing and proposed trading
programs, and report back to NEJAC. Refer to Document IV-H-10 in EPA
Air Docket A-96-56.
---------------------------------------------------------------------------
d. Retired Unit Exemption. 40 CFR part 96 subpart A of today's
proposal provides an exemption from NOX Budget Trading
Program requirements for retired units. The purpose of this provision
is to free retired NOX Budget units from unnecessary
requirements (e.g., emissions monitoring and reporting). The EPA
proposes an exemption beginning on the day the unit permanently
retires, requiring no notice and comment period regarding the
retirement. This provision proposes that the NOX AAR (i.e.,
the person authorized by the owners and operators to make submissions
and handle other matters) submit notification to the permitting
authority of the NOX Budget unit's retirement within 30 days
of the cessation of activity. In response, the permitting authority
would amend the operating permit in accordance with the exemption and
notify EPA of the unit's status as exempt. Criteria within this
provision ensure that all program requirements prior to the exemption
are fulfilled and records are kept on site to verify the non-emitting
status of the retired unit. A retired unit could continue to hold
NOX allowances previously allocated or be allocated
NOX allowances in the future depending on the allocation
provisions adopted by the State where the retired unit is located. The
number of future year NOX allowances that a retired unit
would be allocated would be dependent on the
[[Page 25927]]
given State's allocation system. The NOX allowance
allocations are discussed below in Section V.C.5 of this preamble.
In order to resume operation without violating program
requirements, the NOX AAR of the NOX Budget unit
must submit a permit application to the permitting authority no less
than 18 months (or less, if so specified by the applicable State
permitting regulations) prior to the date on which the unit is first to
resume operation, to allow the permitting authority time to review and
approve the application for the unit's re-entry into the program. If a
retired unit resumes operation, EPA proposes to automatically terminate
the exemption under this part.
e. Standard Requirements. Today's proposal delineates, in proposed
40 CFR part 96 subpart A the standard requirements, that NOX
budget units and their owners, operators, and NOX AARs must
meet under the NOX Budget Trading Program. This provision
sets forth and provides references to other portions of the trading
rule for the full range of program requirements: permits, monitoring,
NOX emissions limitations, excess emissions, recordkeeping
and reporting, liability, and effect on other authorities. For example,
the permitting, monitoring, and emissions limit requirements are
discussed in general and the relevant Sections of the trading rule are
cited. The liability provisions state that the requirements of the
trading program must be met, and any knowing violations or false
statements are subject to enforcement under the applicable State or
Federal law. Violations and the associated liability are established to
be unit-specific, except in the case of common stacks. The provision
addressing the effect on other authorities establishes that no
provision of the trading program can be construed to exempt the owners
or operators of a NOX Budget unit from compliance with any
other provision of the applicable, approved SIP, any federally
enforceable permit, or the CAA. This provision ensures, for example,
that a State may set a binding source-specific NOX
limitation and, regardless of how many allowances a NOX
Budget unit holds under the trading program, the emissions limit
established in the SIP cannot be violated.
f. Computation of Time. Proposed 40 CFR 96.7 clarifies how to
determine the deadlines referenced in the proposal. For example,
deadlines falling on a weekend or holiday are extended to the next
business day. These are the same computation-of-time provisions as are
in the regulation for the Acid Rain Program.
2. NOX Authorized Account Representative
40 CFR part 96 subpart B of today's proposed NOX Budget
Trading Rule establishes the process for certifying the NOX
AAR and describes his or her duties. A 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.
Because the NOX AAR is representing the owners and operators
of all the NOX Budget units at a NOX Budget
source, the NOX AAR must certify that he or she was selected
by an agreement binding on all such owners and operators and is
authorized to act on their behalf. The NOX AAR's
responsibilities include: the submission of permit applications to the
permitting authority, submission of monitoring plans and certification
applications, holding and transferring NOX allowances, and
submission of emissions data and compliance reports. While the Acid
Rain Program refers to the ``designated representative'' as the
representative of owners and operators for non-allowance matters and
the ``authorized account representative'' as the person for allowance
matters, today's proposal uses only one term for all matters and
somewhat streamlines the procedures for selection.
The Agency recognizes that the NOX AAR cannot always be
available to perform his or her duties. Therefore, the rule proposes to
allow for the appointment of one alternate NOX AAR
(alternate NOX AAR) for a NOX budget source. The
alternate NOX AAR would have the same authority and
responsibilities as the NOX AAR. Therefore, unless expressly
provided to the contrary, whenever the term ``NOX authorized
account representative'' is used in the rule, it should be read to
apply to the alternate NOX AAR as well. While the alternate
NOX AAR would have full authority to act on behalf of the
NOX AAR, all correspondence from EPA, including reports,
would be sent only to the NOX AAR.
Today's proposal requires the completion and submission of the
account certificate of representation form in order to certify a
NOX AAR for a NOX budget source and all
NOX budget units at the source. There would be one standard
form which would be submitted by sources to EPA. The EPA would
establish a compliance account for each unit in the NATS. The form
would include: The plant name, State, and identifying number (ORIS or
facility code); the NOX AAR name, the NOX AAR
identification number (if already assigned), address, phone, fax, and
e-mail (as well as similar information for the alternate NOX
AAR, if applicable); the name of every owner and operator of the source
and each NOX budget unit at the source; and certification
language and signature of the NOX AAR and alternate, if
applicable.
In order to change the NOX AAR, alternate NOX
AAR, or list of owners and operators, EPA is proposing that a new
complete account certificate of representation be submitted. The EPA
believes the NOX AAR requirements afford the regulated
community with flexibility, while ensuring source accountability and
simplifying the administration of the trading program.
3. Permits
a. General Requirements. The EPA has attempted to minimize the
number of new procedural requirements for NOX Budget
permitting and to defer, whenever possible, to the permitting programs
already established by the permitting authority. The proposed
NOX Budget Trading Program regulations assume that the
NOX budget permit would be a portion of a federally
enforceable permit issued to the NOX Budget source and
administered through permitting vehicles such as operating permits
programs established under title V of the CAA and 40 CFR part 70. The
term ``NOX budget permit'' throughout this preamble and the
NOX Budget Trading Program regulations therefore refers to
the NOX Budget Trading Program portion of the permit issued
by the permitting authority to a NOX budget source.
b. Title V/Non-Title V Permits. Although many of the NOX
Budget sources that would participate in the NOX Budget
Trading Program must apply for and receive a title V permit, this would
not be the case for every NOX budget source. Sources
presently required to have a title V permit are those that are
``major'' sources, as defined in title V and 40 CFR parts 70 and 71.
Since there would be some NOX budget sources that are not
major sources, the NOX Budget Trading Program would require
only that a NOX budget source have a federally enforceable
permit, rather than require that each NOX Budget source have
a title V permit. The EPA believes that requiring all NOX
budget sources to have a title V permit would be unduly burdensome and
that proper implementation of a NOX Budget Trading Program
can be achieved through federally enforceable permitting vehicles in
addition to those established under title V and 40 CFR part 70 or 71.
[[Page 25928]]
For sources required to have a title V permit, the NOX
Budget Trading Program attempts, wherever possible, to allow the
regulations promulgated by the permitting authority under title V and
40 CFR part 70 or 71 to determine how the NOX budget permit
would be administered. For those sources not required to have a title V
permit, the NOX Budget Trading Program attempts, wherever
possible, to allow the permitting authority's non-title V permit
regulations to govern how the NOX budget permit would be
administered. Essentially, this would enable the NOX Budget
Trading Program to operate within the regulatory framework already
established by permitting authorities for both title V and non-title V
permits.
The proposed rule requires that every NOX budget unit
have a federally enforceable permit. The EPA is concerned, however,
that some States may not currently have permitting vehicles for the
issuance of federally enforceable permits to smaller units that would
be subject to the proposed trading rule. For such States, adoption of
the NOX budget rule would also require the State either to
issue permits under its title V program to sources that would not
otherwise require title V permits or to develop other permitting
programs through which federally enforceable permits could be issued to
such units.
Therefore, EPA requests comment on the option, for States without
programs for issuing federally enforceable permits for smaller
NOX budget units, of not requiring such units to obtain
federally enforceable permits. Under this option, the State's
NOX Budget Trading Rule would state that NOX
budget units that are not covered by a federally enforceable permit
would still be subject to the emissions, monitoring, and other non-
permit requirements of the trading rule, would have their emissions
reported to and recorded on the EPA-administered Emissions Tracking
System, and would have their NOX allowance allocations,
deductions, and transfers recorded on the EPA-administered NATS. The
EPA requests comment on whether, under these circumstances, the units'
obligations (e.g., to hold sufficient NOX allowances each
control period to cover NOX emissions and to monitor
emissions in accordance with 40 CFR part 75 subpart H) would be
federally enforceable, with or without a federally enforceable permit
reiterating the unit's requirements under the NOX Budget
Trading Program.
The EPA is soliciting comment on several other aspects of this
issue. First, EPA is interested in State assessments of the extent of
the problem in issuing federally enforceable permits to all sources
included in the trading program. In particular, EPA seeks information
on how many NOX budget units (or what percent of States'
NOX budget units) would not be issued federally enforceable
permits, but for the permit requirements of the proposed trading rule,
and on the extent to which non-title V permitting programs are
currently established and available for permitting NOX
budget units. Second, EPA seeks comments regarding the feasibility of
the approach described above, under which federally enforceable permits
would not be required for smaller NOX budget units if the
State lacked an existing program for issuing federally enforceable
permits to such units. Lastly, EPA is interested in receiving
suggestions regarding other possible approaches to address this matter.
c. NOX Budget Permit Application Deadlines. The proposed
rule sets the initial NOX budget permit application
deadlines for units in operation before January 1, 2000 with either
title V or non-title V permits so that the permits will be issued by
May 1, 2003. May 1, 2003 is the beginning of the first control period
for the NOX Budget Trading Program, and therefore also the
date by which initial NOX budget permits for existing units
must be effective. Application submission deadlines are based on the
permitting authority's title V and non-title V requirements for final
action on a permit application. For instance, if a permitting
authority's permitting regulations allowed 12 months for final action
by the permitting authority on a permit application, the application
deadline for units in operation before 2000 governed by the permitting
rule would be May 1, 2002 (12 months prior to May 1, 2003). The same
principle applies to NOX budget units commencing operation
on or after January 1, 2000, except that the application submission
deadline is calculated from the later of the date the NOX
budget unit commences operation or from May 1, 2003. The NOX
budget permit renewal application deadlines are the same as those that
apply to permit renewal applications in general for sources with title
V or non-title V permits. For instance, if a permitting authority
requires submission of a title V permit renewal application by a date
which is 12 months in advance of a title V permit's expiration, the
same date would also apply to the NOX budget permit
application.
d. NOX Budget Trading Program Permit Application. The
NOX Budget Trading Program requires that a NOX
budget permit application properly identify the source and include the
standard requirements under proposed 40 CFR 96.6. The NOX
Budget Trading Program permit application should include all elements
of the program (including the standard requirements). Such an approach
allows the permitting authority to incorporate virtually all of the
applicable NOX Budget Trading Program requirements into a
NOX budget permit by including as part of such permit the
NOX budget permit application submitted by the source.
Directly incorporating the NOX budget permit application
into the NOX budget permit and, thus, into the source's
operating permit or the overarching permit minimizes the administrative
burden on the permitting authority of including the NOX
Budget Trading Program applicable requirements, and mirrors the
approach successfully implemented by many permitting authorities in
issuing Phase II Acid Rain permits under titles IV and V.
e. NOX Budget Permit Issuance. As stated earlier, most
of the procedures needed by a permitting authority to issue
NOX budget permits have already been established by the
permitting authority through permitting vehicles such as operating
permits programs under title V and 40 CFR part 70 or 71. Generally, the
permits regulations promulgated by the permitting authority cover:
Permit application, permit application shield, permit duration, permit
shield, permit issuance, permit revision and reopening, public
participation, and State and EPA review. The proposed NOX
Budget Trading Program permit regulations generally require use of the
procedures under these other regulations and add some requirements such
as NOX budget permit application submission and renewal
deadlines, NOX budget permit application information
requirements and permit content, and initial NOX budget
permit effective dates.
f. NOX Budget Permit Revisions. For revisions to the
NOX budget permit, the NOX Budget Trading Program
again defers to the regulations addressing permits revisions
promulgated by the permitting authority under title V and 40 CFR part
70 or 71 (for sources requiring a title V permit) or to non-title V
permitting regulations (for sources not requiring a title V permit).
The proposal also provides that the allocation, transfer, or deduction
of NOX allowances is automatically incorporated in the
NOX budget permit, and does not require a permit revision or
reopening by the permitting authority. The NOX budget permit
must, however, expressly state that each unit
[[Page 25929]]
must hold enough NOX allowances to account for
NOX emissions by the allowance transfer deadline for each
control period and that there are offsets if the unit does not. The EPA
believes that requiring the permitting authority to revise or reopen a
NOX budget permit each time a NOX allowance
allocation, transfer, or deduction is made would be burdensome and
unnecessary. This is similar to the approach taken in the Acid Rain
Program, where the transfer of SO2 allowances are treated as
``automatic permit amendments'' that do not require any action by the
permitting authority.
4. Compliance Certification
40 CFR part 96 subpart D of today's proposed NOX Budget
Trading Rule sets forth the requirements concerning certification by
the NOX AAR at the end of each control period that the unit
was in compliance with the emissions limitation and other requirements
of the NOX Budget Trading Program. The NOX AAR
must submit a compliance certification report for each NOX
budget unit, by November 30 following the control period, to both the
permitting authority and the Administrator. This report must identify
the NOX budget unit and include a compliance certification
statement. The compliance certification statement must indicate whether
all of the applicable requirements of the NOX Budget Trading
Program, including the requirement to hold allowances greater than or
equal to emissions and the requirement to monitor and report according
to the provisions in 40 CFR part 96 subpart H of today's proposal, were
met by the unit for the most recent control period. The report also
allows the NOX AAR to specify which allowances (by serial
number) should be deducted from the NOX budget unit's
compliance account and to specify the proportion of NOX
allowances to deduct for each unit if a group of units share a common
stack.
The EPA is proposing that annual compliance certification reports
must be submitted for several reasons. First, the report provides
important information, such as whether there were any changes to the
unit's monitoring plan used by EPA to evaluate the unit's monitoring
and to determine compliance. Second, the report provides an opportunity
for the owner or operator to use the flexibilities allowed in today's
proposal to choose which NOX allowances would be deducted to
meet emissions reduction requirements rather than using the default
methodologies for deducting allowances that are also set forth in
today's proposal. The EPA is proposing that a copy of the compliance
certification report be sent to both EPA and to the permitting
authority because EPA needs the information in order to administer the
compliance period reconciliation process and the permitting authority
needs the information in order to ensure compliance with the SIP. The
EPA is proposing a deadline of November 30 following the control period
for submission because EPA believes this is sufficient time to compile
the information required in the report, while still allowing EPA to
perform reconciliation before the next control period begins.
5. NOX Allowance Allocations
40 CFR part 96 subpart E of today's proposed model rule addresses
the allocation of NOX allowances to NOX budget
units. Within each participating State, the NOX Budget
Trading Program would establish a State trading program budget (i.e., a
cap of seasonal NOX emissions for all units included in the
program) equal to a fixed total number of NOX allowances
that each State allocates to its NOX budget units for each
control period. States would have the ultimate responsibility for
determining the size of their respective trading program budgets. 40
CFR part 96 subpart E of today's proposed rule sets timing requirements
for when the allocations should be completed by each State and
submitted to EPA for inclusion into the NATS and provides an option for
how States may allocate NOX allowances to the NOX
budget units.
a. Development of State Trading Program Budget. Today's proposal
establishes in 40 CFR part 96 subpart E the total number of
NOX tons for the NOX Budget Trading Program
within a specific State. The proposed rule sets the State trading
program budget at the level of NOX emissions apportioned by
an approved SIP for the ozone transport rulemaking to the State's
sources meeting the definition of ``NOX budget unit'' in the
2007 statewide emissions budget. Sources meeting the definition of
``NOX budget unit'' would include the sources in the trading
program's core group of sources as well as additional sources that a
State may choose to include in the program as discussed above in
Section V.C.1.c. The proposed transport rulemaking provides States the
flexibility to meet the statewide emissions budgets with a different
mix of control measures than were calculated in the transport
rulemaking, thus potentially changing the total amount of
NOX tons apportioned to the NOX budget units.
Therefore, a State may determine the number of NOX tons
allotted for the State trading program budget provided the State
complies with the overall requirements of the proposed transport
rulemaking. Once a State sets the trading program budget, the limit is
set for the total number of NOX allowances that the State
may allocate to the State's NOX budget units for any one
control period.
b. Timing Requirements. Today's proposed rule sets requirements for
when a State would finalize NOX allowance allocations for
each control period in the NOX Budget Trading Program and
submit them to EPA for inclusion into the NATS. This topic was
discussed at both of the public workshops as explained later in this
Section. The timing requirements ensure that all NOX budget
units would have sufficient time and the same amount of time to plan
for compliance for each control period, and sufficient time and the
same amount of time to trade NOX allowances. The timing
requirements would also contribute to the efficient administration of
the NOX Budget Trading Program. By establishing this
schedule at the outset of the trading program, both the States and EPA
would be able to develop internal procedures for effectively
implementing the NOX allowance provisions of the trading
program. This is particularly important for EPA with its role as
administrator of the NATS for all participating States. The timing
requirements would ensure that EPA would be able to record in the NATS
the time sensitive NOX allowance allocations for the
NOX budget units in all participating States at the same
time for each control period.
At the public workshops, a range of options were discussed and
commented on for the timing requirements. The timing options generally
range from year-by-year allocations, in which the NOX
allowance allocations would be placed into the NATS on an annual basis
for the upcoming control period; to a 5 to 10 year allocation where
NOX allowance allocations would be periodically placed into
the NATS for 5 to 10 control periods; to a single, permanent allocation
where the NOX allowance allocations would be set only once
at the beginning of the trading program and recorded in the NATS for an
extended, rolling block of time (e.g., a rolling 30 year period).
Some commenters stated that timing options which provide an
opportunity to periodically update the allocation of NOX
allowances to NOX budget units have certain advantages.
First, the current restructuring of the electricity industry may
significantly affect the mix
[[Page 25930]]
of electricity generators that produce electricity in the future. As
the utilization of existing electricity generators changes and new
electricity generators begin operations, an allocation regime which is
periodically updated would provide an opportunity to reallocate
NOX allowances based on this changing environment. Second,
depending on the formula that is used to allocate the NOX
allowances, trading programs that periodically update the allocations
may provide an opportunity to reward energy efficiency improvements at
specific NOX budget units. Incentives may be provided for
energy efficiency improvements by rewarding NOX budget units
that increase their production efficiency over time with a larger
number of NOX allowances during the next allocation period.
However, commenters also noted that allocation systems that are
adjusted annually may restrict a NOX budget unit's ability
to plan for compliance by creating uncertainty year to year about the
amount of future allocations that the NOX budget unit would
receive. In addition, annual allocations prevent a NOX
budget unit from officially transferring future year NOX
allowances because the NATS only contains the current year's
NOX allowances under this type of system. These commenters
generally favored an allocation system that periodically allocates
NOX allowances for 5 to 10 control periods at a time.
Other commenters noted the advantages of a single, permanent
allocation where the NOX allowance allocations would be set
only once at the beginning of the trading program. Permanent
allocations provide a long planning horizon for the NOX
budget units that receive an allocation. Some commenters noted that
permanent allocations provide a strong incentive for the owners or
operators of high emitting units to retire or replace the units.
Additionally, permanent allocations provide an incentive to improve a
NOX budget unit's energy efficiency and require less
resources to administer as compared to updating allocation systems. In
a permanent allocation system, all NOX allowances are
allocated to NOX budget units at the beginning of the
trading program. New NOX budget units that begin operations
after the allocation of NOX allowances would be required to
obtain NOX allowances from the market in order to comply
with the trading program requirements, or there would need to be a new
source set-aside that increased from year to year, coupled with a
declining allocation to existing sources. Therefore, commenters that
support an allocation mechanism that provides NOX allowances
to new NOX budget units were generally opposed to the
permanent allocation approach.
In light of the comments from the public workshops, today's
proposed rule attempts to strike a balance between systems that change
the allocations on an annual basis and systems that establish a single,
permanent allocation by proposing a system that allocates
NOX allowances for 5 to 10 years at a time. The proposed
rule includes the following timing requirements for the allocation of
NOX allowances: by September 30, 1999, the State would
submit to EPA NOX allowance allocations for the control
periods in the years 2003, 2004, 2005, 2006, and 2007. This initial
submission date would provide the initial allocation information to
NOX budget units more than 3 years before the start of the
trading program and would enable a State to include the first five
years of NOX allowance allocations as a part of its overall
SIP submission to meet the requirements of the proposed transport
rulemaking. After this initial allocation, two timing options are
proposed for the allocations following the year 2007. One option, which
is set forth in the proposed rule, is: by January 1, 2003 and January 1
of each year thereafter, the State would submit to EPA allocations for
the control period in the year that is 5 years after the applicable
submission deadline. Under this option, a State would ensure that its
NOX budget units are always allocated 5 years worth of
NOX allowances in the NATS. A second option, on which
comment is also requested, is: By January 1, 2003, a State would submit
to EPA NOX allowance allocations for the control periods in
2008, 2009, 2010, 2011, and 2012. The State would maintain this
schedule of submitting NOX allowance allocations for 5
control periods by January 1 every five years after January 1, 2003.
This option would ensure that the State's NOX budget units
are allocated no less than 5 years, and as much as 10 years, worth of
NOX allowances in the NATS at any one time. Under the second
option, future allocations are made less frequently and, for some
years, based on older data on unit utilization. The second option would
also require a larger new source set-aside (as discussed below) to span
the longer time frame before new sources would be incorporated in the
updated allocation. In addition to the specific options described
above, EPA also solicits comments on the full range of possible timing
requirements including a single, permanent allocation system and an
annually changing allocation system.
Today's proposed trading rule includes a provision that if a State
were to fail to meet the timing requirements for submitting
NOX allowance allocations to EPA, EPA would allocate
NOX allowances to NOX budget units in that State
in accordance with 40 CFR 96.42 within 60 days of the applicable
deadline. Section 96.42 is the Section of the model rule that will
contain EPA's recommended approach for allocating NOX
allowances to NOX budget units, which is discussed below.
This provision is designed to ensure that all NOX budget
units included in the NOX Budget Trading Program would
receive NOX allowance allocations at the same time for each
control period. The EPA solicits comment on this provision.
c. Options for NOX Allowance Allocation Recommendation
i. Basis for Developing an Allocation Recommendation. The EPA
proposes that the final NOX Budget Trading Rule include a
recommended NOX allowance allocation. This was discussed at
length at the public workshops. Three approaches to addressing
NOX allowance allocations in the trading program were
presented at the workshops. First, the rule could prescribe one method
for allocating NOX allowances. States that choose to
participate in the NOX Budget Trading Program would need to
allocate NOX allowances as prescribed by the rule. This
option would have the benefit of going through public comment as a part
of the rule development process. The second approach was for the rule
to recommend one method for allocating NOX allowances.
States may choose to use the recommendation, to adjust the
recommendation, or to develop an allocation method that is completely
different from the recommendation. The third approach was for the rule
to be silent on the method for allocating NOX allowances and
require the participating States to independently develop State
specific allocation methods.
Workshop participants covered the entire range of approaches in
their comments. Commenters in favor of a prescriptive allocation method
argued that a standard system ensures that there is equity between
NOX budget units in different States, that the same
environmental goals are pursued within all participating States (e.g.,
promotion of energy efficient units through output based emission
limitations), that all State programs have the necessary consistency to
promote interstate trading, and that a standard system
[[Page 25931]]
reduces industry and government resources necessary to develop and
implement NOX allowance allocations in each State. On the
other end of the spectrum, commenters in favor of States having
complete flexibility in the allocation method asserted that it is
important for States to have the freedom to develop systems that
address their specific needs. Furthermore, as long as all States follow
the timing requirements for allocations in the proposed rule, the
different State methods should be sufficiently compatible to realize
the benefits of trading.
The EPA is sensitive to the argument that a more prescriptive
proposed rule would ensure a consistent and administratively efficient
multi-state program that is equitable for similar NOX budget
units. However, EPA also recognizes that the States which have
commented on this subject have unanimously supported some degree of
flexibility for developing allocation methods. Because EPA believes it
is important for as many States as possible to participate in the
NOX Budget Trading Program, EPA is proposing that the final
rule contain a recommendation for how States may allocate
NOX allowances but allow States the flexibility to differ
from the recommendation. By including the recommended allocation
method, the final rule would provide a complete model for the
NOX Budget Trading Program. This has the potential to ease
the regulatory process for States that prefer the recommendation by
providing a rule that can be quickly adapted for promulgation as a
State rule and, as discussed below, more quickly considered by EPA as
part of SIP review. In addition, in order to help facilitate
administration of the program, EPA plans on ensuring that the necessary
data collection protocols exist to support the option recommended in
the final rule. This would include both standard data collection
requirements and standard data reporting requirements.
ii. Options for an Allocation Recommendation. NOX
allowances could be distributed to NOX budget units and
other private parties by allocations based on actual operating data,
via auctions, or by a variety of other mechanisms. Most of the workshop
discussions and comments focused on how to allocate NOX
allowances based on actual operating data. In general terms, three
different processes at a unit may be measured and used as a metric for
allocating NOX allowances: (1) The actual emissions (in tons
of NOX) from the unit, (2) the actual heat input (in mmBtu)
of the unit, and (3) the actual production output (in terms of
electricity generation and/or steam energy) of the unit. The option of
allocating NOX allowances based on a unit's actual
NOX emissions was not generally recommended because it is
regarded as providing a perverse incentive by rewarding more
NOX allowances to units that have the greatest
NOX emissions. Heat input and output are regarded as more
neutral measures of a unit's utilization, and therefore, more equitable
options for basing allocations.
The EPA solicits comments on three options using input or output
data for the allocation recommendation that would be included in the
final trading rule.17 The first option is to base the
allocation recommendation on heat input data. This option may be
desirable because accurate protocols exist for monitoring this data and
reporting it to EPA, and several years of certified data are available
for most of the affected sources. Additionally, methods currently exist
for calculating allocations based on heat input data. It should be
noted that in some specific instances, these protocols are designed to
conservatively estimate heat input. For instance, new units that do not
certify their monitors by the compliance deadline, may report heat
input using the unit's maximum potential heat input. In another
instance, low mass emitting units that use a simplified emissions
estimation methodology would also report using the unit's maximum
potential heat input. In both of these cases, the potential over-
reporting of heat input, could lead to a larger percentage of
allowances being allocated to these units. One potential option for
these instances would be to require units in these types of situations
to report one heat input value to be used for emissions estimation
purposes and another less conservative value to be used for purposes of
allowance allocations. Another option would be to apply a discount to
reported heat input values in certain circumstances (e.g., during
periods when monitors are not certified) for purposes of allocating
allowances. The EPA seeks comment on whether this issue needs to be
addressed to ensure equitable allocation of allowances. The other two
options incorporate the use of output data for the allocation
recommendation. The EPA believes that basing allocations on output has
the potential benefit of promoting energy efficiency in an allocation
system that periodically reallocates the NOX allowances (see
Section V.C.9.b of this preamble).
---------------------------------------------------------------------------
\17\ It is important to note that in today's trading program
proposal, a State would have the flexibility of determining
allocations to its NOX budget units by whatever system it
desires regardless of EPA's allocation recommendation.
---------------------------------------------------------------------------
The second option for which EPA solicits comments would base the
allocation recommendation on heat input data for the first five control
periods of the trading program (control periods in the years 2003-
2007). The allocation recommendation would then be converted to use
output data for the control periods after the year 2007. Under this
option, heat input data would be used for the first five years because
a number of issues for the measurement, collection, and use of output
data may not be fully resolved for all of the NOX budget
units that would be included in the trading program prior to the time
that the allocation recommendation would need to be finalized for the
initial allocation period. Section V.C.9.b of this preamble discusses a
number of the issues associated with measuring and using output data.
To facilitate the use of output data under this option, EPA proposes to
work with stakeholders to design the output based system that would be
used after the initial allocation period. As a part of this output
based system, EPA would amend its Electronic Data Reporting format so
that output data would be available for States through EPA's Emissions
Tracking System.
In order to implement this option, EPA suggests the following
schedule for developing the output based system that would be used in
the allocation recommendation for the control periods after the year
2007: (1) EPA would issue a proposed system for output based
allocations by the spring of 1999; (2) EPA would finalize an output
based system by fall of 1999; (3) States wishing to use an output based
system would adopt the necessary rules by fall of 2000; (4) output data
could be measured and collected at NOX budget units during
the control periods in the years 2001 and 2002; (5) output data would
be available for States to calculate allocations for the control
periods after the year 2007, in time to meet the allocation timing
requirements established in today's proposed rule. As discussed under
Section V.C.5.b, allocations for the control period in the year 2008
would be submitted to EPA by January 1, 2003 for inclusion into the
NATS. The EPA solicits comments on this suggested schedule for
establishing a method for output based allocations and comments on the
issues raised under Section V.C.9.b of this preamble.
[[Page 25932]]
The third option for which EPA solicits comments would base the
allocation recommendation on output data, to the extent practicable,
for all NOX budget units from the start of the trading
program. The allocations for the first five control periods of the
trading program would be based on output data currently reported to
government agencies other than EPA (such as the Department of Energy's
Energy Information Agency, the Federal Energy Regulatory Commission, or
State Public Utility Commissions). Depending upon the availability of
information, it may be necessary in this option to use output for
electricity generating facilities and input data for non-electricity
generating facilities for the initial allocation period. The allocation
recommendation would then be converted to use output data for all
NOX budget units for the control periods after the year
2007. As in the second option described above, EPA proposes to work
with stakeholders to design a complete output based system that would
be used after the initial allocation period. Unlike the output data
used in the initial allocation period, the allocations for control
periods after the year 2007 would be based on output data that would be
reported in EPA's Electronic Data Reporting format and designed
specifically to support a NOX allowance allocation system.
The EPA suggests the same schedule as outlined above in the second
option for developing the complete output based system for allocating
NOX allowances.
iii. Framework for an Allocation Recommendation. As discussed above
under Section V.C.5.c.i, EPA proposes to include a specific
recommendation in the final trading rule for allocating NOX
allowances to NOX budget units. This allocation
recommendation may be based on either input or output data as outlined
in one of the three options presented above under Section V.C.5.c.ii.
In addition to the data used to support the allocations, EPA also
solicits comments on two other key elements for an allocation
recommendation: (1) Using a portion of the State's NOX
allowances as a set-aside for new NOX budget units for
control periods for which the unit was not allocated NOX
allowances, and (2) using either a fuel neutral or output neutral
calculation to determine allocations for NOX budget units.
Today's proposed rule includes an example of a specific allocation
methodology that uses heat input data and addresses the above key
elements. This allocation methodology would be appropriate for
implementing an allocation system entirely based on heat input data or
for implementing the initial allocation period of an allocation system
that starts out using input data and later is converted to the use of
output data. The allocation methodology would need to be modified for
the use of output data to implement an allocation system that
eventually converts to output data or for an allocation system that
begins with using output data. The EPA solicits comment on the
following allocation methodology for using input data and on the
appropriateness of using the basic framework of this methodology for an
output based allocation system. Furthermore, the allocation methodology
establishes an allocation set-aside account equaling 2 percent of the
State trading program budget for each control period for new
NOX budget units (i.e., units that commence operation during
or after the period on which general NOX allowance
allocations are based). Based on analyses conducted using the
Integrated Planning Model (IPM) and on the proposal to reallocate
allowances every five years, 2 percent appears to be a reasonable
portion of NOX allowances to set aside for new units. The
remaining 98 percent of the NOX allowances are to be
allocated to existing NOX budget units. The EPA requests
public comment on the use of a set-aside and on the proposed size of
the set-aside, which EPA believes should be large enough to accommodate
all new units entering the trading program.
Initial, unadjusted allocations to existing NOX budget
units, which equal 98 percent of the State trading program budget,
would be based on actual heat input data (in mmBtu) for the units
multiplied by an emission rate of 0.15 lb/mmBtu. For the control
periods in the years 2003 through 2007, the heat input used in the
allocation calculation equals the average of the heat input for the two
highest control periods for the years 1995, 1996, and 1997. For the
control periods after 2007, the heat input equals the heat input
measured during the control period of the year that is six years before
the year in which the allocations are being calculated. Therefore, the
allocation calculation combined with the timing requirements discussed
under Section V.C.5.b of this preamble results in the following
schedule: The allocation for the control period in 2008 should be
submitted to EPA by January 1, 2003 and based on heat input data for
the control period in the year 2002; the allocation for the 2009
control period should be submitted to EPA by January 1, 2004 and based
on 2003 control period heat input data. This schedule would continue
indefinitely or until revised (e.g., to base allocations on output)
through rulemaking. The heat input data used for calculating the
allocations is to be data collected in accordance with the requirements
of 40 CFR part 75 for units that were subject to these requirements for
the year or years specified by the allocation calculation. For units
not subject to 40 CFR part 75 requirements for the year or years
specified by the allocation calculation, the heat input data used in
the calculation should be the best available heat input data reported
by the unit to the State. Once the initial allocation calculation is
completed for all the existing NOX budget units, the
allocation for each unit would be adjusted proportionately so that the
total allocation equals 98 percent of the State trading program budget.
A separate, allocation set-aside for new units would be established
for each control period. Each set-aside would initially hold
NOX allowances equal to 2 percent of the NOX
allowances in the State trading program budget 18.
NOX allowances in the allocation set-aside would be
available to NOX budget units for control periods that the
unit was not allocated allowances because the unit commenced operation
during or after the period on which general NOX allowance
allocations are based. To receive NOX allowances from the
allocation set-aside, the NOX AAR for a unit would submit to
the State a NOX allowance request, in writing or in a format
specified by the State. The request would be for no more than 5
consecutive control periods, starting with the control period during
which the unit is projected to commence operation. For the 6th year and
later, 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 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 NOX budget
unit. The NOX AAR may not request an amount of
NOX allowances for each control period that exceeds 0.15 lb/
mmBtu multiplied by the NOX
[[Page 25933]]
budget unit's maximum design heat input (in mmBtu) for the hours in the
control period starting with the first day in which the unit is
projected to operate. Maximum design heat input is used because actual
heat input information for the baseyear period used for existing units
would not be available since the new unit would have commenced
operation during or after the baseline period.
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\18\ The EPA is soliciting comment in Section F, below, on
allowing certain sources, to which the trading program would not be
generally applicable, to opt into the NOX Budget Trading
Program in order to fulfill the new source offset provisions under
section 173 of the CAA. If this alternative is incorporated into the
final trading rule, then the size of the allocation set-aside should
be based on the expected new sources that are covered by the general
applicability criteria and the additional sources that may opt in.
---------------------------------------------------------------------------
Under this proposal, the State would review and allocate
NOX allowances to new units requesting NOX
allowances according to the order that the requests were received. Upon
review, the State would make any necessary adjustments to the requests
according to the requirements governing NOX allowance
requests. 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 and verified by the
State, the State would allocate the full (or adjusted) amount of
NOX allowances requested to the NOX budget unit.
If the set-aside for the control period for which NOX
allowances are requested has a smaller amount of NOX
allowances than the number requested and verified, the State would deny
in part the request and only allocate the remaining number of
NOX allowances in the set-aside to the NOX budget
unit. Once the set-aside for a control period has been depleted of all
NOX allowances, the State would not allocate any
NOX allowances to additional units requesting NOX
allowances for the control period. NOX budget units with
NOX allowance requests that were denied in whole or part
would be responsible for obtaining the necessary amount of
NOX allowances from the NOX allowance market in
order to demonstrate compliance with the provisions of the proposed
rule. The State would act on all NOX allowance requests
within 60 days upon receipt of the request and notify the
NOX AAR that submitted the request and the EPA of the number
of NOX allowances (if any) allocated for the control period.
After September 30 of each year, the EPA would transfer NOX
allowances remaining in the set-aside for the control period to the
set-aside for the following control period.
For new NOX budget units that have been allocated
NOX allowances from the allocation set-aside, the EPA would
deduct NOX allowances following each control period based on
the unit's actual utilization for the control period, determined in
accordance to the requirements under 40 CFR part 96 subpart H of the
proposed rule. Because, as discussed above, 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 on allocating NOX allowances to existing units. Without
the adjustment procedures, a new unit (e.g., a peaking unit) could be
allocated NOX allowances assuming utilization far out of
proportion to actual utilization and the set-aside could be
insufficient to provide NOX allowances for all new units at
such an allocation level.
Under the actual utilization adjustment procedure, EPA would deduct
a number of NOX allowances according to the following
equation: NOX allowances deducted for actual utilization
adjustment = (Number of NOX allowances allocated for control
period)-((actual control period utilization (in mmBtu) x 0.15 lb/
mmBtu)). The NOX allowances deducted must have the same or
an earlier compliance use date as the year of the control period for
which NOX allowances were allocated from the set-aside. (As
discussed below in Section V.C.7.b of this preamble, the proposed rule
reflects unlimited banking of NOX allowances once the
trading program begins in 2003. However, EPA is proposing several
options concerning banking (including no banking) and requesting
comment on them.) The NOX AAR may identify the serial
numbers of the NOX allowances to be deducted. In the absence
of such identification, the EPA would deduct NOX allowances
on a first-in, first-out basis. The EPA would transfer the
NOX allowances deducted into the State's set-aside for the
following control period.
If additional NOX allowances are moved into a set-aside
resulting from the transfer of NOX allowances from a
previous year's set-aside or from the actual utilization adjustment,
the State would allocate NOX allowances to those
NOX allowance requests that were denied in whole or in part
pursuant to the NOX allowance request provisions under this
Section of the proposed rule. However, requests for NOX
allowances by new units would not be granted retrospectively for
control periods that have ended.
An additional option that was considered for inclusion in an EPA
recommended allocation methodology was the use of a price signal
auction for a portion of NOX allowances. The transparency of
the first SO2 allowance auctions under Title IV accelerated
price discovery and provided useful information to industry for making
compliance decisions in the early years of the program. The value for
this type of auction for NOX allowances was discussed at the
December public workshop. Commenters generally questioned the need for
a price signal auction for NOX allowances because of the
market instruments currently available from the private sector,
including several allowance price indexes. Based on these comments, EPA
did not include a price signal auction in the proposed options for the
allocation recommendation. The EPA solicits comment on this option.
The EPA solicits comments on any other allocation recommendation
that may be made in the final rule. Comments should be of comparable
detail to the example outlined in this Section.
6. NOX Allowance Tracking System
40 CFR part 96 subpart F of today's proposed trading rule covers
the NATS. The proposed rule is intended to be reasonably consistent
with the NATS that was developed for implementation of the OTC's
NOX Budget Program. Such consistency would help to allow the
integration of the two programs in the future. It would also save
industry and government the time and resources necessary to develop new
tracking systems.
The NATS would be 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 or individuals. Specifically, the NATS would track the
allocation of all NOX allowances, holdings of NOX
allowances in accounts, deduction of NOX allowances for
compliance purposes, and transfers between accounts. The primary role
of NATS is to provide an efficient, automated means of monitoring
compliance with the NOX Budget Trading Program. The NATS
would also provide the allowance market with a record of ownership of
allowances, dates of allowance transfers, buyer and seller information,
and the serial numbers of allowances transferred. Although today's
proposal assigns each allowance a unique serial number, EPA requests
comments on the necessity of serial numbers and on whether the
administrative burden to allowance holders and EPA of tracking and
reporting serial numbers outweighs the benefits of serial numbers for
tax and accounting purposes.
The EPA is proposing that NATS contain three primary types of
accounts: compliance accounts, overdraft accounts, and general
accounts.
[[Page 25934]]
Compliance accounts are created for each NOX budget unit,
and overdraft accounts are created for each source with two or more
NOX budget units, upon receipt of the account certificate of
representation form. General accounts are created for any organization
or individual upon receipt of a general account information form.
a. Compliance Accounts. As part of the implementation of the
NOX Budget Trading Program, EPA is proposing to establish
compliance accounts for each NOX budget unit upon receipt of
the account certificate of representation form. These accounts would be
identified by a 12-digit account number incorporating the plant's
Office of Regulatory Information System's (ORIS) code or facility
identification number as well as the number of the unit for which the
compliance account is established. Allocations for the first six years
(2003-2008), as prescribed by each State, would be transferred into
these compliance accounts prior to the first control period in 2003.
Prior to the second control period, in 2004, and each year thereafter,
allocations for the new sixth year, as prescribed by each State, would
be transferred into each compliance account (e.g., in 2004, year 2009
NOX allowances would be allocated). As for the deadline for
transferring NOX allowances to cover emissions in the
control period (i.e., the NOX allowance transfer deadline of
midnight on November 30), each compliance account (supplemented as
discussed below by an overdraft account) must hold sufficient
NOX allowances to cover the NOX budget unit's
NOX emissions for that year's control period.
b. Overdraft Accounts. Today's proposed trading rule provides for
an overdraft account that would be automatically created for each
source with two or more NOX budget units, and represented by
the source's NOX AAR. The NOX AAR may choose
whether he or she wishes to utilize the account by transferring
allowances into the account before the annual reconciliation process.
NOX allowances transferred into the overdraft account for a
NOX budget source by the NOX allowance transfer
deadline would be available for deduction during annual reconciliation
if a NOX budget unit at that source fails to hold sufficient
NOX allowances to cover emissions in its compliance account.
This is similar to the approach used in the OTC NOX Budget
Program and provides additional flexibility for owners and operators in
complying with the requirement to hold NOX allowances
covering emissions. If the compliance account and the overdraft account
together do not contain enough NOX allowances, then the unit
would be out of compliance. The compliance account must be depleted of
all NOX allowances before the overdraft account is utilized.
The proposed rule would deduct NOX allowances from the
overdraft account beginning with the unit having the lowest NATS
account number. The unit that fails to hold sufficient NOX
allowances between the compliance account and the overdraft account
would be subject to the same consequences that would apply were only
its compliance account being tapped for compliance, including the
automatic excess emissions offset deduction and the applicable
penalties under State law and the CAA. If the final trading rule
includes provisions for the banking of NOX allowances, such
provisions would apply to the NOX allowances held in the
overdraft accounts as well as those held in compliance accounts.
Today's proposal allows the NOX AAR to identify specific
serial numbers for deduction from a compliance account. In the absence
of a specific identification of NOX allowances to be
deducted, a FIFO (first-in, first-out) method would determine the order
in which NOX allowances would be deducted. The proposal does
not, however, allow for the identification of specific NOX
allowances to be deducted from an overdraft account because
NOX allowance deductions from the overdraft account would
take place automatically, in a set order, after the NOX
allowance transfer deadline has passed.
c. Compliance. Once a control period has ended, NOX
budget units would have a window of opportunity (i.e., until the
NOX allowance transfer deadline of midnight on November 30)
to evaluate their reported emissions and obtain any additional
NOX allowances they may need to cover the emissions during
the ozone season. On November 30 of each year, the NOX AAR
must also submit a compliance certification report for each
NOX budget unit. Should the NOX budget unit not
obtain sufficient NOX allowances to offset emissions for the
season, three NOX allowances for each ton of excess
emissions would be deducted from the unit's compliance account for the
following control period. EPA believes that it is important to set up
this automatic offset deduction because it ensures that non-compliance
with the NOX emission limitations of this part is a more
expensive option than controlling emissions. The automatic offset
provisions do not limit the ability of the permitting authority or EPA
to take enforcement action under State law or the CAA.
d. General Accounts. Today's proposal allows any person or group to
open a general account in NATS. These accounts would be identified by
the ``9999'' that would compose the first four digits of the NATS
account number. Unlike compliance accounts and overdraft accounts,
general accounts cannot be used for compliance but can be used for
holding or trading NOX allowances (e.g., by NOX
allowance brokers or owners of multiple NOX budget units).
General accounts are currently used for SO2 allowances in
the Acid Rain Program.
To open a general account, a person or group must complete the
standard general account information form, which is similar to the
account certificate of representation that precedes the opening of a
compliance account and any overdraft account. The form would include:
the NOX AAR name, phone, fax, and e-mail (as well as similar
information for the Alternate NOX AAR, if applicable);
NOX AAR mailing address; the names of all parties with an
ownership interest with the respect to the NOX allowances in
the account; and certification language and signatures of the
NOX AAR and alternate, if applicable.
Revisions to information regarding an existing general account are
made by submitting a new general account information form which would
be sent to EPA in all cases, whether the form is used to open a new
account, or revise information on an existing one. The EPA would notify
the NOX AAR cited on the application of the establishment of
his or her account in the NATS or of the registration of requested
changes.
7. Banking
a. General Discussion. Banking is the retention of unused
allowances from one control period for use in a later control period.
Banking allows sources to create reductions beyond required levels and
``bank'' the unused allowances for use later. Generally speaking,
banking has several advantages: it can encourage earlier or greater
reductions than are required from sources, stimulate the market and
encourage efficiency, and provide flexibility in achieving emissions
reduction goals (e.g., by allowing for periodic increased generation
activity that may occur in response to interruptions of power supply
from non-NOX emitting sources). In addition, a banked
allowance is one less ton of pollutant emitted in a given year. On the
other hand, banking may result in banked allowances being used to allow
emissions in a given year to exceed a State's trading program budget.
The
[[Page 25935]]
following discussion summarizes the general issues associated with
banking and then presents four specific banking options for
consideration.
i. Banking After the Start of the Program. Banking after a program
starts and the budget is imposed allows sources to retain any
allowances not surrendered for compliance at the end of each control
period. Once the trading program budget is in place, sources may over-
control for one or more seasons and withdraw from the bank in a later
season. This type of banking provides the general advantages as
described above (encourages early reductions, stimulates the market,
and provides flexibility to sources), while also potentially causing
NOX emissions in some control periods to be greater than the
allowances allocated for those seasons.
ii. Banking Prior to the Start of the Program. Banking of credits
or allowances for reductions prior to the start of the program allows
sources to accumulate NOX allowances for compliance use once
the program begins. In addition to the general advantages of banking,
this option allows sources to possibly delay required emissions
reductions for some sources once the program begins by using banked
allowances for compliance. As OTAG analyses concluded, the accumulation
of significant amounts of allowances prior to the start of the program
could defer the date at which the trading program budget is actually
achieved, even though the early reductions may enable some air quality
benefits to be realized sooner than anticipated. Early reductions can
be realized either through the award of early reduction credits or the
creation of a phased-in program.
iii. Management of Banking. Banking clearly introduces another
variable into a cap-and-trade program; it may, in fact, inhibit or
prohibit achievement of the desired emissions budget in a given season.
To limit this variability and promote achievement of a budget, OTAG
suggested several different management options: Adjusting the trading
program budget downward by decreasing allocations so that expected
variations would stay below the desired emissions level; imposing an
accelerated rate of retirement on allowances used for emissions during
ozone episodes; establishing an absolute limit on the amount of banked
allowances that could be used each season or a discount rate on the use
of banked allowances over a given level (flow control); and applying a
transaction-specific discount rate to all banked allowances used in the
future. In considering these options identified by OTAG for managing
the use of banked allowances, it is important to remember that the
model trading rule is being developed to attain the seasonal budget set
forth in the proposed transport rulemaking.
The ``flow control'' option would allow banking, but would
discourage the ``excessive use'' of banked allowances by establishing
either an absolute limit on the number of banked allowances that could
be used each season or a rate discounting the use of allowances over a
given level. In the latter case, the number of banked allowances in the
system would be tabulated each year to determine what percentage of the
overall budget was banked, and therefore whether flow control could
affect the use of banked allowances for compliance in the upcoming
control period. If this percentage were below a predetermined amount
(e.g., 10 percent as is the case with the OTC, since this level roughly
equated emissions variations in years of low nuclear power
availability), all banked allowances could be used without discounts in
the upcoming control period. If this percentage were above the
predetermined amount, a withdrawal ratio would be applied to each
account holding banked NOX allowances that could be used for
compliance to determine the number that could be used to cover
emissions at a 1-to-1 rate, and the number which, if used, would have
to be used at a 2-to-1 rate. It is important to note that the
withdrawal ratio would be applied only to banked NOX
allowances that could be used for compliance purposes, and therefore
only to NOX allowances banked in compliance and overdraft
accounts. The withdrawal ratio would be determined each year prior to
the control period to which it would pertain, but it would not be
applied until the time of compliance certification at the end of that
control period. This schedule provides the sources one full control
period to plan for the application of flow control on their compliance
and overdraft accounts.
To illustrate flow control, assume the total trading program budget
across all participating States was 300,000 allowances, and 35,000
allowances were banked following a control period. Since more than 10
percent of the total trading program budget is banked, a withdrawal
ratio would be applied to all accounts holding banked allowances that
can be used for compliance in the upcoming control period. In this
case, the ratio applied to accounts with banked allowances would be
0.86 (determined by dividing 10 percent of the total trading program
budget by the total number of banked allowances, or 30,000/35,000).
Thus, if a source holds 1,000 banked allowances at the end of this
upcoming control period, it will be able to use 860 on a 1-for-1 basis,
but will have to use the remaining 140, if necessary, on a 2-for-1
basis. As a result, if the source used all its banked NOX
allowances to cover emissions in the upcoming control period, the 1,000
allowances would equate to 930 tons of NOX emissions (860 +
140/2).
In this manner, flow control manages the use of banked allowances
beyond a predetermined level, here 10 percent of the region wide
trading program budget. This discourages but does not prohibit the use
of banked allowances and, thus, mitigates the effects of ``excessive
use'' of banked allowances in a given control period. While limiting
the annual flow of emissions on the one hand, flow control also
preserves the benefits of banking, granting flexibility to sources,
stimulating the market and maintaining some incentive to over-comply.
Since the withdrawal ratio is known to sources prior to the control
period, sources have certainty about how excessive use of banked
allowances will be treated, and both States and EPA can minimize their
involvement and let the market function relatively unfettered.
b. Options. The EPA is proposing, and requests comment on, four
options for whether and how banking may be incorporated into the
NOX Budget Trading Program: (1) Banking is not a feature;
(2) banking begins when the trading program begins; (3) units may
generate early reduction credits for use after the start of the program
and banking continues after the program begins; and (4) banking begins
with the first-phase of a two-phase trading program and continues
thereafter. The EPA is not adopting or recommending an option in this
proposal. In the final rule, EPA intends to adopt a specific approach
to banking based on the comments received on the four options and any
other approaches suggested by commenters. Although EPA has not focused
on any one approach at this time, the proposed rule reflects, for the
purpose of illustration, option 2 (i.e., banking when the trading
program begins and without any management of banked NOX
allowances).
Each of the four options is discussed below. If banking is allowed,
development of a banking provision involves trade offs on the following
design features: the length of time (if any) permitted for reductions
yielding NOX allowances prior to the start of the
[[Page 25936]]
trading program as determined in the proposed transport rulemaking; the
level at which these reductions can be generated; and the type of
management imposed on the use of banked NOX allowances. The
longer the period of time allowed for early reductions and the less
stringent the level at which NOX allowances can be
generated, the more concern there will be about exceeding the program
budget once the program begins. Because of this concern, arising from
the potentially numerous banked NOX allowances available at
the start of the program, there may be a need for management of the use
of banked NOX allowances.
The EPA used the IPM model to help investigate the ramifications of
different options. The results of this analysis were presented in the
working paper on emissions banking presented at EPA's December 1997
model rule workshop, entitled ``Second Draft Working Paper: Emissions
Banking. December 1997 Analysis of Banking in a NOX Trading
Program''. This paper is available as item number V-A-28 in Docket No.
A-96-56 of the Air and Radiation Docket (see the ADDRESSES Section at
the beginning of today's notice for further guidance on obtaining
information from the docket). The EPA hopes that these analyses will
help stakeholders consider the trade-offs in designing programs with
banking and provide EPA comments on the best way to structure a trading
program. Commenters should consider how best to strike a balance
between the advantages of flexibility, encouraged early reductions, and
potential lower compliance costs versus the potential exceedance of
prescribed budgets due to excessive use of banked allowances in a given
control period.
i. Option 1: No Banking. Not allowing banking in the NOX
Budget Trading Program would result in the automatic retirement of any
NOX allowances not surrendered for compliance following each
control period. Under this option, the only NOX allowances
available for compliance in each control period would be those
allocated within the budget for that control period. As a result,
States would be assured of achieving their budgets established under
the NOX Budget Trading Program each control period. However,
the ``no banking'' option does eliminate incentives for early
reductions, reduces the program's flexibility, and may contribute to a
``use or lose'' mentality for the use of allowances by sources at the
end of each control period.
ii. Option 2: Banking After Program Start Only. This option, which
does not provide for early reductions, but allows banking of
NOX allowances after the start of the program, was the
approach used in the supporting analysis for the proposed transport
rulemaking. This option is presented without the imposition of a
management system on the use of banked NOX allowances
because the volume of banked NOX allowances is not expected
to be excessive absent the opportunity for early reductions.
iii. Option 3: Early Reduction Credits. This option allows for the
generation of early reduction credits for some time period prior to the
start of the trading program; the NOX allowances resulting
from early reductions are banked for use once the program starts, and
banking is an option throughout the life of the program.
Sources demonstrating tonnage emissions reductions in excess of a
predetermined level in the year or years prior to the start date for
the program earn early reduction credits; each credit is redeemed for a
one-time award of one NOX allowance. The NOX
allowances awarded for the generation of early reduction credits may be
created as additional to the trading program budget, or may be drawn
from the budget. If the NOX allowances awarded for early
reductions come from the trading program budget, each State
participating in the NOX Budget Trading Program would
establish a set-aside of a small percentage of its seasonal trading
program budget for purposes of awarding the generation of early
reduction credits. For example, this set-aside could be 2-3 percent of
the State trading program budget, pulled from each of the first five
years of allocated NOX allowances. The resulting set-aside
could be distributed at the conclusion of the period in which early
reduction credits can be generated, on a pro rata basis. Any
NOX allowances not awarded from this reserve would be
returned to the State trading program budget for distribution as
allocations. The EPA requests comment on this option of taking early
reduction credits from the State trading program budgets and details
regarding how this could be accomplished, if in a different manner than
that suggested here.
If the NOX allowances awarded for early reductions
originate from within the trading program budget, their award could
pose a threat to achievement of the budget once the program begins,
even though future allocations will necessarily be decreased by an
amount equivalent to the NOX allowances awarded for early
reductions. The shift of available NOX allowances to the
beginning of the program could potentially result in more emissions
than budgeted levels in the early years of the program. If the
NOX allowances awarded for early reductions are created
outside of the trading program budget, there should be even more
concern regarding potential exceedance of the trading program budget
since all awarded NOX allowances are in excess of budgeted
levels of emissions and thus, potentially have a more pronounced and
extended impact on the achievement of the trading program budget. This
concern is addressed later in this Section.
The award of NOX allowances for early reductions under
the NOX Budget Trading Program, whether from within or
outside of the budget, would require a case-by-case determination by
participating States that the reductions claimed were real, surplus,
and quantifiable. Part of this determination would be made based on
monitored data. This monitored data should be based on the same
standards that are being used to support the ongoing trading program.
Therefore, any source wishing to receive early reduction credits would
be required to have monitors in place and certified for the entire
period that the awards are being made. Early reduction credits could be
determined and awarded on either a unit-, source-, company-, or State-
level basis. A unit- or source-level determination would necessitate a
more substantial proof of legitimacy due to concerns of load-shifting
to other units or sources. Load shifting is a particular concern in
this instance because relatively few units would be pursuing the early
reduction credits, leaving the majority of similar sources at a less
stringent control level or no required level. Generally speaking, the
opportunity for load shifting from sources subject to some emission
control (e.g., units seeking early reduction credits) increases with
the number of similar units or sources that are not subject to an
equivalent emission control. Whether the load shifting is to units or
sources with the same owner or with a different owner as compared to
the original unit or source, such load shifting could eliminate the
environmental benefit of reduced emissions at the original unit or
source. The applicant would have to demonstrate that the requested
credits were real and surplus, and not the result of load or production
shifting. A company or State-level determination, on the other hand,
would reduce, but may not eliminate, load-shifting concerns. The
activity of all units owned by the company in the State (but not any
other units) would be accounted for in the consideration of eligibility
for
[[Page 25937]]
early reduction credits. The EPA solicits comment on using a company-
level determination in order to reduce concern over utilization
shifting.
Incorporating early reduction credits into the NOX
Budget Trading Program would also require determinations of the control
level beyond which to award early reduction credits and the time period
during which the credits can be earned. The control level should be set
within the range of the already established title IV and title I levels
and the level in the proposed transport rulemaking; EPA solicits
comment on the level of 0.15 lb/mmBtu as proposed in the transport
rulemaking. The time in which the credits could be earned could be
either one, two, or three years prior to the start of the program; EPA
solicits comment on a time period of two years. If the NOX
allowances awarded for early reductions come from outside of the
trading program budget, a control level above 0.15 lb/mmBtu or a time
period longer than two years may threaten program integrity by allowing
the possibility of a large bank being established prior to the start of
the program that could significantly delay achievement of the budget.
If the NOX allowances are awarded from within the budget,
this control level and time period are still appropriate to protect
program integrity, and also ensure that the NOX allowance
set-aside to reward early reductions does not withdraw too many
NOX allowances from the future trading program budget, and
pose undue burden on sources in the program. Placing a limit on the
number of NOX allowances which may be awarded for early
reductions, such as two percent of the first budget period, and
reducing the first period budget by a like amount, could help to
protect program integrity and ensure that too many allowances are not
withdrawn from the first budget period.
The existence of early reduction credits in the NOX
Budget Trading Program could necessitate the consideration of a
management scheme to control the use of banked allowances. A management
scheme could be required even if the NOX allowances are
withdrawn from the budget, since exceedance of the budget would still
be quite possible due to the shift of available NOX
allowances to the beginning of the program. As discussed above, a flow
control management scenario, whereby the use of banked NOX
allowances over a predetermined percentage of the trading program
budget would be constricted by a weighted withdrawal ratio, would be
one way of discouraging the ``excessive use'' of banked allowances
throughout a control period. Under this approach, a withdrawal ratio of
two banked NOX allowances to one for the current control
period would be imposed on the use of some banked NOX
allowances whenever the percentage of banked NOX allowances
in the NOX Budget Trading Program region exceeds 10 percent
of the trading program budget for that control period. EPA acknowledges
other percentages and withdrawal ratios are also feasible, but solicits
comment on 10 percent and 2-for-1 as reasonable levels to ensure
program integrity while providing the opportunity to bank
NOX allowances. The proposed flow control management
scenario is the same system used in the OTC's model rule to manage the
use of banked NOX allowances. This system simply acts as a
safeguard against excessive withdrawals of banked allowances in a given
control period; if large amounts of banked NOX allowances
are not used, it will not be invoked.
These four factors together--the origin of the NOX
allowances awarded for early reductions, the time period for
reductions, the level beyond which credits can be earned, and the
subsequent management scheme for banked NOX allowances--
together determine the impact of the award of early reduction credits
on achievement and maintenance of the NOX Budget Trading
Program budget.
iv. Option 4: Phased-In Program. For this option of a program
utilizing phased-in emissions reductions, an initial limit or cap would
be set at a level representing an emissions reduction less stringent
than the desired budget that is the ultimate goal of the trading
program. A NOX budget source could over-control with respect
to this preliminary level at one or more units and accrue
NOX allowances, building up a bank to be used to defer
emissions reduction requirements when the first phase level is
ratcheted downward to achieve the final budget under the trading
program. Banking would begin with the first phase of the program and be
allowed throughout the life of the program.
Implementing the NOX Budget Trading Program as a phased-
in program requires similar trade-offs to those required to implement
early reduction credits, including consideration of the time period of
the first phase during which banked allowances can be accumulated, the
stringency of the control level and resulting budget mandated in the
first phase, and the management scheme imposed. The implementation of a
phased-in program, however, unlike the award of early reduction
credits, requires all sources to participate in the first phase. In
effect, a phased-in program creates an earlier compliance deadline for
sources in all States participating in the NOX Budget
Trading Program. Unlike an early reduction credit approach, a phased-in
approach would not require applicants to demonstrate that
NOX allowances were surplus of load shifting or States to
conduct case-by-case reviews of applications because load shifting
would be much less of a concern. This lowered environmental risk should
allow a less stringent performance level to be used in the early phase,
which would increase the opportunity to bank NOX allowances.
Monitoring and reporting in accordance with prescribed methodologies
would be required by the new, earlier compliance deadline in order to
track compliance and ensure the integrity of reductions and resulting
generation of excess allowances.
To provide time for such monitoring and reporting to be put in
place for all NOX budget units, the first phase could be no
sooner than two years prior to the start of the trading program at the
level of control and timing mandated in the proposed transport
rulemaking. The EPA solicits comment on a time period of two years. As
would be the case with early reduction credits, the level of control
for the first phase would be set at a level within the range of the
title IV level and the level established in the proposed transport
rulemaking. The EPA solicits comment on a level of 0.25 lb/mmBtu, a
somewhat less stringent level than that considered without a phased-in
program. However, even this level of control would enhance the ability
of units to bank NOX allowances and so would increase the
need for a management scheme to ensure program integrity. The EPA also
solicits comment on a flow control approach incorporating a withdrawal
ratio of two to one for some banked NOX allowances used for
compliance in the current control period whenever the percentage of
banked allowances in the NOX Budget Trading Program region
exceeds 10 percent of the trading program budget for that control
period. Once again, it is important to note the interdependence of the
time period for reductions prior to the program start, the level beyond
which allowances can be earned, and subsequent management scheme for
banked NOX allowances.
8. Allowance Transfers
The EPA is proposing that once a NOX AAR is appointed
and an account is established in the NATS, NOX allowances
can be transferred to or from the accounts with the submission of an
allowance transfer form to EPA.
[[Page 25938]]
Transfers can occur between any accounts at any time of year with one
exception: transfers of current and past year allowances into and out
of compliance accounts and overdraft accounts are prohibited after the
NOX allowance transfer deadline (November 30) of each year
until EPA completes the annual reconciliation process by deducting the
necessary allowances.
There would be one standard NOX allowance transfer form.
This form would be submitted to the EPA in all cases. The form would
include: The transferror and transferee NATS account numbers; the
transferror's printed name, phone number, signature, and date of
signature; and a list of allowances to be transferred, by serial
number.
The EPA is moving towards electronic submission of allowance
transfers. Full capability is expected by 2000. AARs would be informed
of developments and/or requirements for electronic submissions as they
arise.
9. Emissions Monitoring and Reporting
a. Requirements for Point Sources. 40 CFR part 96 subpart H of
today's proposed model rule sets forth the emissions monitoring and
reporting requirements for the NOX Budget Trading Program.
The EPA is proposing that units subject to the NOX Budget
Trading Program be required to meet the monitoring and reporting
provisions that are contained in a proposed new 40 CFR part 75 subpart
H to the monitoring and reporting provisions of the Acid Rain
regulations. These revisions are being proposed in a separate
rulemaking that contains a new subpart H of 40 CFR part 75, which
addresses how NOX mass emissions (i.e., tons of
NOX emitted) should be monitored and reported and which
references relevant provisions in the other subparts of 40 CFR part 75
(revisions to be published in the Federal Register in the near future).
All comments on the new subpart H of 40 CFR part 75 should be submitted
in the separate rulemaking on 40 CFR part 75 revisions rather than in
the instant proceeding.
The EPA is proposing that States use the proposed 40 CFR part 75
subpart H to support the monitoring and reporting for this program to
ensure that emissions are consistently and accurately monitored and
reported from unit to unit and from State to State. This consistency
and accuracy in monitoring is necessary to ensure that a NOX
allowance actually represents one ton of emissions and that one ton of
reported emissions from one source is equivalent to a ton of reported
emissions from another source. This establishes the integrity of the
NOX allowance (i.e., the authority to emit one ton of
NOX) and instills confidence in the market mechanisms that
are designed to provide sources with flexibility in achieving
compliance. The consistency and accuracy in reporting is necessary to
ensure that compliance can be determined quickly and consistently and
that buyers and sellers of NOX allowances can determine the
value of what they are trading.
The EPA believes that the NOX mass emissions monitoring
provisions in 40 CFR part 75, as it is proposed to be revised, provide
a reasonable and cost effective way to consistently and accurately
monitor NOX mass. One of the main advantages of using these
provisions to support this program is that many of the NOX
budget units, i.e., existing utility units subject to the Acid Rain
program, are already required to meet the monitoring and reporting
requirements in the existing 40 CFR part 75. Under the proposed
revisions to 40 CFR part 75, the main new requirement for these units
would be to calculate and report hourly, quarterly, seasonal and annual
NOX mass emissions. In almost all cases, these values could
be determined using existing 40 CFR part 75 monitoring systems.
In addition to sources currently subject to the Acid Rain Program,
many additional sources in the OTC that are not subject to the Acid
Rain Program, but that are covered by both the OTC's NOX
Budget Program and this proposal, will be meeting many of the
monitoring and reporting requirements in existing 40 CFR part 75 by
April 1, 1998 in order to comply with the OTC's NOX Budget
Program. Units covered by the proposed trading rule but not required to
use the provisions of 40 CFR part 75 to comply with either the Acid
Rain Program or the OTC's NOX Budget Program will also
benefit from using monitoring and reporting requirements that are based
in large part on existing 40 CFR part 75 requirements that are already
being used by a large number of units. Since existing State monitoring
regulations vary greatly, and since many States do not currently
require the monitoring and reporting of NOX mass, it is
necessary, for purposes of supporting the proposed trading program, to
create consistent monitoring and reporting requirements. If 40 CFR part
75 monitoring and reporting are used in the trading program, units not
currently using 40 CFR part 75 will have the benefit of much of the
expertise and software that has already been developed to support the
Acid Rain Program and the OTC NOX Budget Program.
The notice of the proposed rulemaking concerning revisions to 40
CFR part 75 sets forth in detail the proposed revisions related to
monitoring NOX mass emissions. While comments on the
proposed revisions to 40 CFR part 75 (including proposed 40 CFR part 75
subpart H) should be submitted in the separate 40 CFR part 75
rulemaking, an overview of the 40 CFR part 75 revisions is provided
here to assist commenters in the instant rulemaking. The proposed 40
CFR part 75 revisions require units to determine NOX mass
emissions by monitoring NOX emission rate (in lbs/mmBtu) and
heat input (in mmBtu) on an hourly basis and by multiplying those two
values together. Coal units and other units that burn solid fuel that
are covered by the NOX Budget Trading Program would be
required to measure NOX emission rate using a NOX
emission rate CEM consisting of a NOX concentration CEM and
a diluent CEM (CO2 or O2 CEM) and measure heat
input using a diluent CEM and a flow CEM. All gas and oil units covered
by the NOX Budget Trading Program would be allowed to use
this option or alternatively could measure heat input by using a fuel
flowmeter and performing fuel sampling and analysis. This option for
determining heat input is set forth in Appendix D of 40 CFR part 75 and
referenced in the new subpart H of 40 CFR part 96. Gas and oil units
that qualified as either peaking units or low mass emitting units under
40 CFR part 75 would also have additional lower cost monitoring
methodologies available to them. Peaking units, for example, could do
source testing to create heat input versus NOX emission rate
curves. Then based on hourly measurement of heat input from a fuel
flowmeter and fuel sampling and analysis, the heat input versus
NOX emission rate curves would be used to estimate the
hourly NOX emission rate. This option for determining
NOX emission rate is set forth in Appendix E of 40 CFR part
75 and referenced in 40 CFR part 96 subpart H. This rate would be used
in conjunction with heat input determined using the provisions in
Appendix D of 40 CFR part 75 to determine NOX mass. A unit
that qualifies as a low mass emitting unit could use a default
NOX emission rate and the unit's maximum rated hourly heat
input to determine NOX mass emissions. The low mass
emissions unit provisions are in proposed 40 CFR 75.19 and referenced
in 40 CFR part 96 subpart H.
The proposed 40 CFR part 75 subpart H requires units to report
hourly NOX mass emissions throughout the year, rather than
just in the seasonal control period. The EPA is proposing to make
[[Page 25939]]
the monitoring and reporting requirements year round, as under the Acid
Rain Program, because EPA believes that this will facilitate
integration with other monitoring and reporting requirements, such as
New Source Performance Standards (NSPS) requirements, Compliance
Assurance Monitoring (CAM) requirements and other State requirements.
In the long run, EPA believes that this consolidation can help to ease
the overall monitoring and reporting burden on sources.
The proposed changes to 40 CFR part 75 also highlight several
additional issues that are particularly pertinent to monitoring
NOX mass emissions. These include: an alternative way to
measure NOX mass emissions using a NOX
concentration CEM and a flow CEM, specific requirements for monitoring
NOX emission rate at common stacks and heat input at common
stacks and common fuel pipes, and the reporting of NOX mass
emissions on a total hourly basis rather than on an hourly mass
emissions rate basis. More information on these issues can be found in
the notice of proposed rulemaking for 40 CFR part 75 which will be
published in the Federal Register in the near future. All comments on
the proposed revisions to 40 CFR part 75, including any related to
NOX mass emissions, should be submitted in the 40 CFR part
75 rulemaking proceeding, rather than in the instant proceeding.
While units would be required to meet the technical monitoring
requirements set forth in 40 CFR part 75, the general and
administrative requirements related to monitoring are set forth in the
proposed trading rule. These include: compliance dates, prohibitions,
requirements for certification and recertification of monitors,
recordkeeping and reporting requirements and procedures for requests
for alternatives to the monitoring requirements.
The EPA is proposing that units that commence operation before
January 1, 2000 have certified monitors installed and operating for
this program by May 1, 2001, which is earlier than the compliance date
(May 1, 2003) for emissions reductions in the proposed transport
rulemaking and this trading program. Since no precertification of
emissions reductions is needed for sources to make trades, it is
important to make sure that the monitoring that is used to certify the
emissions is verified before the start of the trading program. While
up-front certification of monitors provides a great deal of assurance
that sources would be able to account for their emissions, up-front
reporting verifies that they can report their emissions. In addition,
other aspects of the trading program that are discussed in other parts
of this proposal, including a rolling allocation scheme based on
updated monitored data and the banking of allowances before the
beginning of the program, would require monitoring earlier than May 1,
2003. If a unit commences operation on or after January 1, 2000, it
would be required to have certified monitors installed and operating by
the later of: May 1, 2001; or 180 days after the unit commences
operations or, if the unit is subject to any Acid Rain emission
limitation, 90 days after the unit commences commercial operation.
Deadlines for installation and certification of monitors are also
established with regard to new stacks or flues constructed after the
general installation and certification deadlines. Regardless of the
deadline for installation and certification of monitors, if any unit is
operating on or before May 1, 2001, but the monitors for that unit are
not certified by May 1, 2001, the owner or operator must still account
for emissions beginning on May 1, 2001 so that this data will be
available to support the allocation provisions and possible provisions
providing the opportunity to bank allowances before the beginning of
the program. Similarly, if any unit is not operating on or before May
1, 2001 the owner or operator must account for emissions from the date
and hour the unit commences operation. The owner or operator has three
options for accounting for emissions until all of the required monitors
are certified: Reference method monitoring; maximum potential values;
or data from the monitors before certification is completed if certain
quality assurance and data validation procedures are followed. This
would be consistent with the requirement to hold NOX
allowances for all emissions in the ozone season and would assist with
NSR integration, which requires accounting of all emissions.
The prohibitions Section of the trading rule sets forth several
general prohibitions that would apply to all units included in the
program. Units would not be able to use alternatives to the
requirements in proposed subpart H of 40 CFR part 96 (and proposed
revised 40 CFR part 75) unless that alternative was approved according
to the procedures set forth for approval of alternatives to the
monitoring requirements. The procedures for requests for alternatives
to the monitoring requirements vary depending upon whether or not the
unit involved is also subject to 40 CFR part 75 for purposes of
compliance with title IV of the Act.
Units subject to 40 CFR part 75 for purposes of compliance with an
Acid Rain emission limitation would already meet most of the
requirements for the NOX Budget Trading Program, by meeting
the requirements for title IV. Before an owner or operator could
deviate from the monitoring requirements for 40 CFR part 75 for this
trading program or both this program and title IV, approval would have
to be obtained from EPA. The EPA would take action on the petition for
alternative monitoring in consultation with the appropriate State
agency. This differs from the requirements for sources not subject to
title IV who would need approval from both the State and EPA. The EPA
believes that this is appropriate because EPA currently has authority
to approve petitions for these sources. The additional requirements
would involve reporting new data and, in a few cases, use of monitors
not being used for purposes of title IV. The NOX budget
units subject to title IV would continue to meet the same requirements
as other units subject to title IV, but would be required to include
some additional data in the quarterly reports that they are already
submitting for title IV purposes. This data would include hourly,
quarterly, annual and ozone season NOX mass emissions data.
In addition, if a unit subject to title IV had to install additional
monitors to comply with this program, those monitors would have to meet
the certification and recertification requirements of the
NOX Budget Trading Program. The only reason that a unit
would have to install additional monitors for this program would be if
its currently installed monitors did not allow it to calculate
NOX mass. This would only be an issue if a unit shared a
common stack with other units and chose to measure NOX
emission rate at the unit level, but measured heat input at the common
stack level. For purposes of the Acid Rain Program, this unit would be
allowed to apportion heat input to the unit level. While EPA believes
this methodology is accurate enough for purposes of using heat input to
determine reduced utilization, EPA does not believe that it is accurate
enough for purposes of determining NOX mass; EPA's rationale
is discussed in the preamble to the 40 CFR part 75 rulemaking which
will be published in the Federal Register in the near future.
The NOX budget units not subject to title IV would be
subject to essentially the same requirements for certification
[[Page 25940]]
and recertification and monitoring and reporting. The owner or operator
of a unit would be responsible for initially certifying monitors. The
owner or operator would be responsible for providing the permitting
authority both a monitoring plan and notification of the time and date
of the original certification tests in advance of those tests. The
owner or operator would also be responsible for recertifying monitors
if any major changes were made to the monitors and would be required to
report emissions and other supporting data on a quarterly basis.
An owner or operator wishing to deviate from the monitoring
requirements set forth in 40 CFR part 75 would have to petition for
approval to do so. Unlike certifications and recertifications which
would only have to be approved by the permitting authority, these
petitions would have to be approved by both EPA and the permitting
authority. There are three main reasons that petitions would have to be
approved jointly. The first is that in order to ensure that emissions
are accounted for equivalently from source to source and State to
State, it is important that there be consistency in approving any
alternatives to the allowed monitoring methodologies. By working with
the permitting authority in all of the approvals for alternatives, EPA
can help ensure this consistency. The second is that in order for EPA
to fulfill its role as the repository for emissions data, it is
important that all of the data be reported in a consistent format and
that EPA be aware of any deviations from that consistent format. The
final reason is that EPA cannot approve a SIP that allows a State the
unlimited ability to approve alternatives not specifically spelled out
in the SIP. If a State wants to approve a methodology that is not
specifically part of the SIP, EPA would have to be involved in this
approval.
b. Output Information. In general, the information available
concerning the operation of a unit can be placed into one of three
categories: Input, process, and output. Heat input is a measure of
input; specifically, it is the chemical energy of the fuel burned.
Variables related to combustion, such as temperature, are process
variables. Measures of output from a unit include emissios; steam
energy, and, for a unit serving an electricity generator, electrical
power produced. Today's proposal presents options for allocating
NOX allowances based on actual information on unit
operation. The EPA has received comments that allocations of
NOX allowances under the trading program should be made on
the basis of electrical and/or steam output, rather than heat input,
measurement.
A system where NOX allowances are reallocated on an
ongoing basis (as is being proposed today) may decrease the incentives
for reducing NOX emissions through the use of more efficient
fuels or more efficient equipment. For example, assume a certain unit
currently uses 500 mmBtu/hr to generate 50 MWe. Under a simple heat
input based allocation scenario, if that unit increased its efficiency
by 20 percent, so that it could produce 50MWe while using only 420
mmBtu/hr, it would lose 20 percent of its NOX allowances in
the next NOX allowance reallocation, even though it is
producing the same electricity. However, under an allocation scheme
based on output, if this unit's electricity production did not change,
it would receive the same number of NOX allowances. Since a
decrease in the amount of fuel needed is generally accompanied by a
decrease in NOX emissions, a unit increasing its efficiency
would either have more NOX allowances to sell on the market
or would need to purchase less NOX allowances to be in
compliance. Thus, basing allocations on output gives units additional
efficiency options for compliance, which should reduce the overall cost
of the program. As an additional benefit, decreases in fuel usage would
reduce emissions of other pollutants such as SO2, mercury,
and carbon dioxide (CO2).
However, EPA is concerned that there may be some issues not yet
fully addressed concerning allocation of NOX allowances
based on output. First are issues concerning the development of
measurement protocols for output. Measurement protocols are critical
for making a fair and expeditious allocation of NOX
allowances. There are two general locations at which power output of an
electricity generating facility could be measured: gross generation at
the generator, or net generation after plant power requirements have
been consumed. Gross generation seems less appropriate, since an
allocation based on output would primarily be intended to address
efficiency improvements and allocation by gross generation fails to
account for a plant's power requirements whose efficiency could be
improved. To the extent the power is sold, net generation could be
measured at the point of sale. Measurement at the point of sale has an
advantage in that it is tracked by the source and the dispatch
authority for crediting sales. A workable program requires only that
all participants measure generation at the same general location and
with the same method.
A second set of issues in allocating using output concerns how to
relate product output to emissions output. Electrical generation and
distribution systems at plants can be complex, with multiple units
emitting through one or more stacks and serving multiple generators. If
output is to be measured at the plant level, then it would be
appropriate to measure total emissions from the plant, even if that
meant measuring emissions from small units. Alternatively, the
electrical output from small units could be measured and subtracted
from plant-level electrical output to avoid the need to monitor
emissions from small or infrequently used units.
For units producing steam that does not feed into a generator,
different issues arise. These sources have steam production in addition
to (or instead of) power generation as their final output. Allocating
emissions to both types (steam producing and power generating) of
sources would require the development of a method for converting the
steam energy to an electrical power equivalent. The method would likely
require assumptions about the efficiency of the conversion. The use of
any general efficiency assumption, without considering the
configuration and operation of each individual plant, could lead to
penalizing plants that operate more efficiently than the general case
(by not allocating enough allowances) and giving windfalls to plants
that operate less efficiently than the general case (by allocating more
allowances than warranted).
The EPA solicits comments on how the issues discussed above could
be addressed in order to allow States to base the initial
NOX allowance allocations for this trading program on an
output measure or convert an allocation system initially based on input
to one based on output. As further explained in the allocation Section
of the preamble, EPA may use this information in the development of a
final rule that would provide States the opportunity of using output
based allocations.
10. Opt-Ins
The NOX Budget Trading Program includes provisions
allowing for units that otherwise would not be subject to the trading
program and that are located in a State that is participating in the
trading program to voluntarily elect to participate (i.e., opt in). The
opt-in provisions can further reduce the cost of complying with the
NOX budget by allowing those units, which may not otherwise
be required to reduce NOX emissions for a State to meet its
budget,
[[Page 25941]]
to opt in to the trading program and make incremental, lower-cost
reductions. The NOX allowances freed up by the opt-in
source's control action can be sold to other NOX budget
units for their compliance with the NOX emission limitation.
In general, units that opt in are treated like other NOX
budget units and are subject to the same requirements to monitor, to
hold allowances to account for emissions, and to have a NOX
budget permit. Units that have opted in may also elect to withdrawal
from the program if certain requirements are met.
a. Applicability for Opt-In Units. Today's proposal allows sources
(i.e., units) to opt-in that are similar to, but smaller in capacity
than, the sources covered under the proposed applicability provisions
of the NOX Budget Trading Program. A State would account for
the opt-in unit in the State's SIP by adding the opt-in unit's
NOX emissions to the trading program budget in the SIP and
subtracting the opt-in unit's NOX emissions from the part of
the SIP not covered under the NOX Budget Trading
Program.19 The applicability Section of this preamble
discusses and requests comment on the participation of other source
types and sizes under the trading program. It also discusses whether
other additional source categories should be included in the trading
program. The sources in these categories could be included as part of
the core program applicability, they could be included as an additional
list of source categories that a State could choose to include as core
sources, or they could be listed as sources that could choose to
individually opt in.
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\19\ Today's proposal also solicits comment on allowing sources
not meeting the above description to opt in, at their discretion, if
they are subject to part D nonattainment NSR preconstruction
permitting requirements as major new sources or major modifications
to existing sources and they can meet the other eligibility criteria
of this trading program. The trading program budget in the SIP would
not be increased for the new emissions at these opt-in sources
because they would be entering the trading program in order to
offset their new emissions (see Section F, below).
---------------------------------------------------------------------------
b. Allowance Allocations for Opt-In Units. Today's proposal
allocates NOX allowances to an opt-in unit on a year-by-year
basis. An opt-in unit is required to monitor and report the
NOX emission rate and the heat input according to the
provisions under 40 CFR part 96 subpart H of the proposed rule for one
control period prior to the unit entering the trading program. The
NOX emission rate and heat input measured at the unit during
this initial period of time would become the unit's baseline emission
rate and baseline heat input, respectively. The EPA requests comment on
whether emissions rate or heat input data from periods prior to this
initial period should also be used to set these baselines. The
allocation for an opt-in unit is calculated by multiplying the lesser
of the unit's baseline emission rate (in lb/mmBtu) or the most
stringent State or Federal emissions limitation applicable to the
NOX budget opt-in source during the control period by the
lesser of the unit's baseline heat input or the unit's actual heat
input (in mmBtu) measured during the control period prior to the
allocation calculation. The State would notify EPA by December 1 to
allocate NOX allowances to an opt-in unit for the next
year's control period. While the proposal recommends opt-in allowance
allocations based on heat input, EPA solicits comment on whether the
allocations should be based on output. The options for using output and
the factors considered are analogous to those discussed above
concerning general allocations to NOX budget units.
The EPA proposes to allocate NOX allowances to opt-in
units on a year-by-year basis to ensure that shifts in utilization from
these units to other units not covered under the cap do not result in
any significant increases in overall NOX emissions. Such
increases in emissions may occur if units outside the cap increase
their utilization (and emissions) while NOX allowances
remain under the cap from an opt-in unit that reduces its utilization.
The year-by-year allocation regime limits this potential problem while
still maintaining continuing economic benefits for a unit to opt in
because each of the future year allocations are calculated based on the
unit's baseline emissions rate multiplied by the lesser of the baseline
heat input or the previous year's utilization. By reducing a unit's
actual emission rate below the baseline emission rate, an opt-in unit
would continue to earn NOX allowances to sell in the market
in future years as long as they continued to operate at the same level.
The EPA solicits comment on the appropriateness of the year-by-year
allocations to account for the potential shifts in utilization for the
different types of possible opt-in units including units that serve
electricity generators as well as other types of industrial units.
c. Units Sharing Stacks or Fuel Pipe Headers With NOX
Budget Units. Today's proposal does not include special or simplified
opt-in provisions for non-NOX budget units that share a
common stack or common fuel pipe header with a NOX budget
unit. Allowing these units to participate in the trading program may
streamline the monitoring and reporting requirements for the
NOX budget units. For example, if a non-NOX
budget unit sharing a common stack with a NOX budget unit is
opted in to the trading program, it may no longer be necessary to
apportion common stack emissions between two units. The NOX
AAR may simply elect the percentage of NOX allowances to be
deducted for each unit, provided that the total number deducted covers
the common stack emissions. The EPA solicits comment on the
desirability and method of opting in such units.
d. Withdrawal and Termination of Opt-In Units. The proposed trading
rule addresses how an opt-in unit may withdraw from the trading
program. An opt-in unit may withdraw from the NOX Budget
Program at any time, but a request to withdraw may be effective only on
a date specified by the NOX AAR that is before or after a
control period. The EPA believes that the administrative burden for a
permitting authority in processing a withdrawal effective during a
control period, particularly in ascertaining the disposition of
NOX allowances and in determining compliance for a partial
control period, is sufficient to warrant the prohibition of an
effective date of withdrawal during a control period. Further, an opt-
in source could seek to withdraw during a control period because the
opt-in source projects that it will not hold enough NOX
allowances to account for its NOX emissions for that control
period. Under such a scenario, allowing the unit to ``opt out'' of the
program during a control period could easily result in higher
NOX emissions, since an opt-in unit could emit enough
NOX to use up its NOX allowance allocation for
the control period prior to the end of that control period, withdraw
from the program, and continue to emit NOX after withdrawal
during the control period. Such emissions would not be accounted for
with the requisite surrender of NOX allowances required
under the NOX Budget Program and could occur outside of a
State's overall budget for NOX.
If a NOX budget opt-in unit becomes a NOX
budget unit under 40 CFR 96.4, the opt-in permit is terminated. This
change in status for an opt-in unit could occur as a result of a
modification, reconstruction, or repowering that may take place at the
unit. An opt-in unit that becomes a NOX budget unit under 40
CFR 96.4 is required to notify the permitting authority within 30 days
of the change in status of the opt-in unit. The permitting authority
revises the opt-in permit to reflect the NOX budget permit
content requirements of 40 CFR 96.23 effective as of the date of the
[[Page 25942]]
change in status. The NOX allowances are deducted or
allocated as necessary to ensure that the appropriate number of
allowances are allocated to the unit consistent with 40 CFR part 96
subpart E of the proposed trading rule for each partial or full control
period after the effective date of the change in status. In addition to
the potential of an opt-in unit changing its status and becoming a
NOX budget unit under 40 CFR 96.4, it is also possible that
an opt-in unit may become subject to the major new source review (NSR)
requirements under section 173 of the Act by making a physical change
or a change in the method of operation. In this case, triggering
nonattainment NSR may also terminate an opt-in permit as discussed
above. In Section C.1.c.v above, EPA seeks comment on treating all
sources that are subject to major nonattainment NSR and that are of the
same type of source included in the proposed core applicability as
NOX budget units.
11. Program Audits
The EPA would publish a report annually, commencing after the first
year of compliance, that would contain, for each NOX budget
unit, the control period NOX emissions and the number of
NOX allowances deducted for all reasons. This would be done
in order for States to track emissions and NOX allowance
transaction activity in neighboring and upwind States. The proposed
transport rulemaking has requirements for reporting of additional data
to determine compliance for affected States. The EPA would also publish
a report beginning in 2007 and every five years thereafter to assess
the level of activity and/or emissions shifting from sources included
in the NOX Budget Program to sources not included. An
assessment of opt-in sources (e.g., how many, from what sector, source
size, duration of participation in program) would also be included in
this periodic report.
12. Administration of Program
The administration of this program would be somewhat different from
the administration of a typical State program. This is both because of
the trading aspects of the program and because of the regional nature
of the trading program. In order for the market forces underlying the
trading program to work, the sources that participate in the trading
program must have confidence in the market. This confidence stems from
a number of factors including: a belief that all of the sources
included in the program are following the same set of rules, and a
belief that trades can be made easily, quickly and with a great deal of
confidence that they will not be altered or denied. Several things can
help to foster these beliefs and thus a confidence in the market. The
first is to start with a consistent set of rules. This can be done by
developing a model rule and having all States and sources that
participate in the trading program abide by the ground rules set forth
in the model rule. The second is to implement those rules in a
consistent and efficient manner. Because of the multi-state nature of
the program, it would be difficult for any individual State to do that
by itself. Therefore, EPA is proposing that this program be implemented
jointly by EPA and the States that choose to participate in the
program. As part of this joint implementation, States would have
specific roles, EPA would have specific roles, and there would be roles
that States and EPA would perform jointly.
States would be responsible for developing and promulgating rules
consistent with the model rule and for submitting those rules as part
of the SIP. States would also be responsible for identifying sources
subject to the rule, issuing new or revised permits as appropriate, and
determining NOX allowance allocations. In addition, they
would be responsible for receiving, reviewing and approving most
monitoring plans and monitoring certification applications, observing
monitor certification and ongoing quality assurance testing and
performing audits. The final primary area of State responsibility would
be enforcement of the trading program. If violations occur, the State
would take the lead in pursuing enforcement action. However, once the
rules are approved as part of the SIP, they would become federally
enforceable, and EPA could also take enforcement action.
The EPA would have two primary roles in administration of the
program. The first role would be EPA's traditional role in the approval
and oversight of the SIP. The second would be a more unique role for
EPA, in which EPA would administer significant portions of the program.
In EPA's traditional role in the SIP process, EPA would be
responsible for taking action to approve or disapprove the SIP revision
once it was submitted to EPA. Once the SIP revision was approved, EPA
would play an oversight role in ensuring that the SIP was completely
implemented. This oversight role might include audits of the State
program, or taking enforcement action, if EPA believed that sources
were violating the SIP.
In EPA's more unique role as administrator of portions of the
program, EPA would run both the emissions tracking system (ETS) and the
NATS. ETS is the system that units would use to report their emissions
data and that EPA would then use to verify total emissions for the
control season. The EPA would use the same system that it is currently
using to track emissions data from the Acid Rain Program and that it
will soon be using to track emissions data from the OTC NOX
Budget Program. There are a number of advantages to the sources,
States, and EPA to using this existing system. Since many units are
already reporting to the system for purposes of the Acid Rain Program
and more units will soon be reporting to the system for purposes of the
OTC NOX Budget Program, using this existing system will
represent little change for many units and EPA. This will help to
reduce administrative costs for both units and EPA and will help to
minimize startup problems associated with a new program. It also means
that each State will not need to develop, maintain and operate such a
system.
In addition to receiving the emissions data, quality assuring it,
and providing reports to both States and units about the emissions
data, EPA would have several other responsibilities as the
administrator of ETS. The EPA would be involved in approval of any
petitions for alternatives to the allowable monitoring methods. The EPA
would also be involved in providing units and States assistance in
using ETS. This assistance may include: Answering individual questions
from units and States, providing guidance documents and training for
units and States, and providing software to assist in the submittal of
emissions data.
As the administrator of NATS, EPA would be responsible for
receiving applications for NOX AARs, tracking all official
transfers of NOX allowances, and using the end of control
season emissions data and NOX allowance data to determine
compliance for the control season. In order for EPA to play this role,
each State would have to provide EPA with its NOX allowance
allocations consistent with a prescribed schedule and format. The
NOX AARs for individual sources would have to provide EPA
with information about all official NOX allowance transfers
in a prescribed format. The NOX AAR's would also have to
provide EPA with an end of control season compliance certification. At
the end of the control season, EPA would use all of this data to
determine how many NOX allowances should be deducted from
each unit's compliance account or each source's overdraft account. In
the event
[[Page 25943]]
that there were not enough NOX allowances to cover a unit's
emissions for a control period, EPA would notify the State and would
automatically deduct NOX allowances for the next year's
control period according to the emissions offset provisions set forth
in the proposed trading rule.
The main joint role that EPA and States would have is for the
approval of alternatives to the allowable monitoring methods. This role
is more fully discussed in Section V.C.9 of the preamble on monitoring.
D. SIP Approvability
The EPA's proposed ozone transport rulemaking set forth the general
elements that a SIP needed to include (see 62 FR 60364-71). These
criteria are more fully explained in Section IV.A of this supplemental
proposal. One of the components of an approvable SIP is that it include
fully adopted State rules for the regional transport strategy with
compliance dates. One possible control strategy that a State might
choose would be to implement this NOX Budget Trading Rule
(40 CFR part 96). If a State chooses to implement the NOX
Budget Trading Rule, the proposed ozone transport rulemaking explains
that the trading rule will incorporate all necessary SIP criteria into
the program design. In general, today's proposed trading rule meets the
necessary SIP criteria. However, Section IV.A describes two criteria
that a SIP must meet for EPA to approve the NOX Budget
Trading Rule portion of the SIP (see Section IV.A.3 for further
discussion).
E. OTC Integration
Twelve of the thirteen OTC jurisdictions have committed to the
implementation of a cap-and-trade program in order to achieve region-
wide NOX emissions reductions starting in 1999 to help
reduce ozone transport and make progress toward attainment. Nine of
those twelve jurisdictions are also included in the proposed ozone
transport rulemaking. The goals and implementation strategy of the OTC
program are similar to those of the proposed transport rule and today's
proposed NOX Budget Trading Program. However, there is a
potential for conflict between the OTC Program and today's proposal.
The EPA was involved in the development of the OTC Program and is aware
of the issues that the OTC States faced in developing that program.
Taking into account the work that has been done, EPA has tried to
develop a proposal that will minimize conflicts between the two
programs. Some differences still exist concerning applicability,
allocations, banking and the use of banked allowances, emissions
monitoring, and permitting. The purpose of this Section is to identify
how EPA believes that these specific issues can be resolved, so that
the goals of the OTC program can be achieved in concert with today's
proposal. The EPA believes that these differences can be resolved as
the OTC States undertake rulemakings to implement Phase III (beginning
in 2003) of the OTC program.
1. Applicability
a. State Applicability. On a regional level, the NOX
Budget Trading Program is applicable to any of the 23 jurisdictions
identified in the proposed transport rulemaking electing to
participate. Three of the OTC States (Maine, New Hampshire, and
Vermont), however, are not among the 23 jurisdictions cited in the
proposed transport rulemaking. The OTC States have requested EPA to
consider how these States may participate in the trading program. The
EPA sees, and requests comment on, two options for addressing these
States. One option is to exclude Maine, New Hampshire, and Vermont from
participation in the NOX Budget Trading Program; the other
is to offer the States the opportunity to join the trading program by
complying with the overall requirements of the proposed transport
rulemaking. The EPA proposes the two alternative options and requests
comment on them.
Denying Maine, New Hampshire, and Vermont the opportunity to
participate in the NOX Budget Trading Program can be
justified by their exclusion from the proposed transport rulemaking.
Based on analysis of the entire 37 State OTAG region, EPA proposed to
determine that only 23 jurisdictions are significant contributors to a
nonattainment or maintenance problem in another State. Since these
three States were not among the 23 jurisdictions covered by the
proposed transport rulemaking, arguably they should not be permitted to
participate in the trading program designed to help achieve mandated
reductions in the targeted States. Excluding Maine, New Hampshire, and
Vermont from the trading program would restrict the ability for sources
in these States to trade NOX allowances with sources in
other OTC States that are included in the proposed transport rulemaking
and participating in today's proposed trading program. A second option
would be to allow Maine, New Hampshire, and Vermont to participate in
the NOX Budget Trading Program by voluntarily enrolling in
the proposed ozone transport rulemaking and implementing the
requirements therein. This second option would assist with the
integration of the OTC program with the NOX Budget Trading
Program by maintaining the ability for sources located in Maine, New
Hampshire, and Vermont to trade NOX allowances with sources
located in the other participating OTC States.
b. Source Applicability. The source applicability criteria for
today's proposed NOX Budget Trading Program identifies a
minimum, core group of sources. These core sources are fossil fuel-
fired units (i.e., stationary boilers, combustion turbines, and
combined cycle systems) serving electrical generators greater than 25
megawatts and other units not serving generators and having a heat
input greater than 250 mmBtu per hour. Beyond the core sources, this
proposal contains criteria for States to include additional sources in
the trading program, as well as the process for allowing individual
units to opt in.
The OTC program applies to a similar universe: fossil fuel-fired
boilers and indirect heat exchangers of 250 mmBtu or greater,
electricity generating units of 15 megawatts or greater, and ``opt-in''
sources. The main difference in applicability criteria between the OTC
program and today's proposed NOX Budget trading program is
that the OTC includes units between 15 and 25 megawatts. However,
today's proposal allows States to include smaller sources of the same
type as those included in the core group such as electrical generating
units between 15 and 25 megawatts, without affecting EPA's streamlined
approval of the SIP as described in Section V.D of this preamble. This
allows the OTC program applicability provisions to be reasonably
compatible with those in the NOX Budget Trading Program.
2. Allocations
Today's proposal establishes NOX allowances as the
currency for the NOX Budget Program, and recommends a
methodology for participating States to allocate NOX
allowances among NOX budget sources. States are provided the
flexibility to deviate from the recommendation, as long as the timing
requirements for completion of allocations and submission of the
information to EPA for inclusion into the NATS are met, the control
periods for which allowances are allocated are the same, and total
NOX allowances allocated do not exceed the number of tons
that the State apportions to NOX budget sources in the SIP.
The OTC provides States full discretion to develop and adopt their
own allocation methodologies. The
[[Page 25944]]
resulting allocation processes are in some cases incompatible with
EPA's software capabilities, beyond the scope of EPA's resources to
administer, and inconsistent with the efficient and orderly functioning
of a NOX allowance market. This experience showed the need
for greater consistency among States for the allocation process. As a
result, the OTC States would need to revise their allocation
methodologies for Phase III of the OTC to be consistent with the timing
requirements of the NOX Budget Trading Program. Since the
OTC is still discussing the implementation of Phase III, EPA believes
that the schedule for this proposal provides an opportunity to develop
allocation plans that meet the timing requirements in today's proposed
trading program. Each OTC State would still be able to determine the
specific allocation to each source provided the total number of
allowances allocated did not exceed the trading program budget.
3. Emissions Banking
The OTC program provides for the banking of early reductions in
1997 and 1998 and of excess Phase II NOX allowances in 1999
through 2002. Furthermore, the OTC program includes the use of a flow
control mechanism to manage the use of banked allowances as described
under Section V.C.7 of this preamble and an audit to assess the
program's performance. Today's proposal solicits comments on four
banking options that are discussed under the banking Section of this
preamble. The EPA requests comments on how the OTC banking provisions
may be integrated with the banking options under the proposed
NOX Budget Trading Program.
4. Emissions Monitoring and Reporting
The monitoring and reporting requirements in the proposed
NOX Budget Trading Program are based on the requirements in
proposed revisions to 40 CFR part 75, the monitoring and reporting
regulations under the Acid Rain Program. The monitoring and reporting
requirements in the OTC's NOX Budget Program are based on
the current version of 40 CFR part 75 and on additional guidance that
was developed in a collaborative process among States, sources, and
EPA. This additional guidance sets forth requirements for reporting
NOX mass emissions which are not currently set forth in 40
CFR part 75 and provides some additional flexibilities for sources not
subject to the Acid Rain Program. For sources that are subject to both
the Acid Rain Program and the OTC NOX Budget Program, use of
the revised 40 CFR part 75 would require few changes to address the
NOX mass monitoring and reporting requirements in this
proposal. However, for some sources that are only subject to the OTC
NOX Budget Program, the use of the revised 40 CFR part 75 in
the proposal may require some changes.
The most significant change under the proposed NOX
Budget Trading Program would be that all units that burn coal or other
solid fuels would be required to use a flow monitor and a diluent
monitor to measure heat input. Under the OTC NOX Budget
Program, these units currently have two options for monitoring heat
input: the first option is to use a flow monitor and a diluent monitor,
and the second is to petition the State to use an alternative heat
input methodology. There are two main reasons that EPA is proposing to
limit the options for monitoring heat input for these types of units.
First, EPA believes that in order to ensure fairness and to ensure that
the emissions reductions required by this program are realized, it is
important to have accurate and consistent monitoring across all of the
sources. To date, no source under the OTC NOX Budget Program
has completed any testing to demonstrate that the alternatives are as
consistent and accurate as the flow monitoring methodology. Second, EPA
does not believe that there are significant cost savings associated
with allowing the alternatives. In order to demonstrate that the
alternative is as consistent and accurate as the flow monitoring
methodology, the source is required to do initial certification testing
and ongoing quality assurance testing very similar to the testing
required for the use of flow monitoring methodology. The capital costs
associated with setting up platforms and ladders so that this testing
can be performed is one of the most significant capital costs
associated with the flow monitor methodology, but this cost would also
have to be incurred in order to perform testing on the alternative
methodology. Similarly, some of the most significant costs associated
with the ongoing use of the flow monitor methodology are ongoing
quality assurance and data reporting. Performing similar quality
assurance and data reporting is also a requirement for any alternative
methodology. For these reasons, EPA believes the costs would be
similar. In addition, if the alternatives are allowed, there would be
an additional administrative burden placed on both States and sources
in preparing and reviewing applications for alternative methodologies.
In addition to the specific requirement to use flow monitors for
coal-fired facilities, the proposed revisions to 40 CFR part 75 change
some of the ongoing quality assurance tests for flow monitors. The
number of levels at which flow relative accuracy test audits (RATAs)
have to be performed is reduced, but an additional quarterly quality
assurance of the flow monitors has been added. The EPA believes that
the combined effect of these changes reduces the overall cost of flow
monitoring, while at the same time improving the quality of the data.
Another significant change between the OTC NOX Budget
Program and the proposed NOX Budget Trading Program would be
in the options allowed for low mass emitting units, or peaking units,
that burn oil and/or gas. The OTC NOX Budget Program offers
a number of different options for these units, in addition to the CEM
options that are allowed for all sources in the program. While these
different options provide more flexibility, they also create more
confusion and complexity for smaller sources. The EPA believes that by
proposing fewer options, and simplifying these allowable options as
much as possible, both cost and confusion for smaller sources can be
minimized. The two non-CEM options that the proposed revisions to 40
CFR part 75 will allow for smaller sources are the use of a default
emission rate based on unit type and fuel burned, and the use of source
testing to determine unit specific NOX emission rate versus
load curves. The use of default emission rates is proposed to be
limited to units that have actual emissions and projected emissions
using such default emission rates of less than 25 tons per year. The
use of the unit specific NOX emission rate versus load
curves is proposed to be limited to units that qualify as peaking units
(a unit that has an average capacity of no more than 10.0 percent for
three years, with a maximum capacity of no more than 20.0 percent in
any one of those years.)
Most of the other changes in the proposed revisions to 40 CFR part
75 that would affect OTC NOX Budget Trading Program sources
are designed to reduce monitoring costs and provide additional
flexibilities. These include: a reduction in fuel sampling for units
that use fuel sampling and analysis to determine heat input; more
flexibility for the scheduling of quality assurance testing to
accommodate unexpected unit outages; and an option to reduce the amount
of missing data that must be reported during periods of monitor
recertification. More information on all of the proposed revisions to
40 CFR part
[[Page 25945]]
75 can be found in the proposal for that rule (notice entitled ``Acid
Rain Program; Continuous Emission Monitoring Revisions'' that will be
published in the Federal Register in the near future); comments on them
should be submitted in that separate rulemaking.
5. Permitting
The OTC program does not explicitly require permits that are issued
or modified for use under the OTC program to be federally enforceable.
The proposed NOX Budget Trading Rule requires federally
enforceable permits. The EPA's rationale for requiring federally
enforceable permits is further explained in Section V.C.3 of this
preamble. This would potentially require the OTC States to amend the
permitting provisions in the OTC program.
F. New Source Review
Under section 173 of the CAA, new and modified major sources
located in nonattainment areas must offset their new emissions. The EPA
believes that this requirement can be met through a source's
participation in the NOX Budget Trading Program defined in
today's proposed rule. Simply put, in a system where the level of
emissions cannot exceed an absolute mass emissions cap, new sources of
emissions subject to the system must acquire sufficient NOX
allowances elsewhere in the system to offset any new emissions. Those
sources from whom NOX allowances are acquired must also hold
sufficient NOX allowances to cover their emissions.
Therefore, since the trading program budget would not be increased for
sources seeking offsets, NOX allowances which are acquired
necessarily come from actual emissions decreases that take place from
other sources that are covered by the cap.
A key issue is how sources whose emissions increases are subject to
the major NSR offset requirements may become participants in the
trading program. All new units meeting the proposed applicability
criteria, and all emissions increases at existing units meeting these
criteria, would be subject to the NOX Budget Trading Rule
and, therefore, would be participants in the trading program. However,
sources in need of NSR offsets but which do not meet the proposed
applicability criteria may wish to participate in the trading program
so as to satisfy their NSR offset requirement. The EPA notes that
today's proposed rule makes no specific provision for the inclusion of
these types of sources. Since EPA believes there may be significant
benefits to integrating any new source review requirements with the
NOX Budget Trading Program, inclusion in the trading program
of new sources that do not meet the proposed applicability criteria may
well be helpful to both those sources and States that are concerned
about finding offsets for new sources. The EPA solicits comments on
allowing the opt in of new and modified sources, not otherwise subject
to the program, in order to satisfy the section 173 offset provisions
through participation in the trading program. Commenters should
consider how these sources would be integrated into the trading program
in a simple and straightforward manner which would not compromise any
of the program's goals or requirements. For example, EPA expects that
any source opting into the trading program would have to meet the
permitting, monitoring, and accountability requirements applicable to
core sources. At this time, EPA also solicits recommendations on: (1)
How the section 173(c)(1) requirements pertaining to the geographic
location of offsets can be met under the NOX Budget Trading
Program and (2) how to reconcile the seasonal nature of the proposed
rule with the NSR requirements that the total annual tonnage of new
emissions increases must be offset.
G. End Use Energy Efficiency and Renewable Energy
1. Background
This Section discusses the potential for a provision within a
State's NOX Budget Trading Rule to recognize and encourage
the contribution that energy efficiency and renewables can make in
meeting the NOX budget. The December workshop with State,
industry and non-governmental organization representatives included a
discussion of a possible role for energy efficiency and renewables. As
stated in the December workshop, energy efficiency and renewables can
be important components of an effective NOX reduction
strategy. Greater deployment of energy efficiency and renewables
technologies cannot only be a cost-effective means of preventing
emissions of NOX. It can also be a cost-effective way of
preventing emissions of greenhouse gases, such as carbon dioxide
(CO2), and toxic substances, such as mercury.
There is a large potential for greater energy efficiency
improvements that reduce energy demand. In addition, renewable
resources that reduce demand at the consumer level are available,
including technologies that generate electricity, such as rooftop
photovoltaics, and technologies that reduce electricity demand such as
solar hot water heaters. Greater penetration of energy efficiency and
distributed renewable resources in the marketplace can save companies
and individuals money and promote economic growth, thus reducing the
economic cost of compliance with environmental requirements. These
savings can be passed on to consumers through lower electricity rates.
The EPA has examined the potential for energy efficiency and
renewables in the SIP call region. The most recent information on this
potential comes from the Department of Energy's (DOE's) ``5-lab
study,'' which quantifies the potential for energy efficiency and
renewables to reduce carbon emissions in the U.S. via two scenarios.
The first is the study's ``Efficiency'' case which consists of the
potential for cost-effective energy efficiency and renewables
technologies to penetrate the market given an invigorated promotion
effort for greater market transformation. The second scenario is the
``High Efficiency'' case, which demonstrates the potential for
emissions reductions from energy efficiency and renewables measures
that are optimistic, but feasible to undertake. Both the DOE study and
the findings and results from similar analyses that have been conducted
in the last several years in different States or groups of States
within the proposed ozone transport rulemaking region show substantial
potential for NOX reductions and ancillary benefits from
greater adoption of energy efficiency and renewable technologies.
According to an analysis based on the DOE 5-lab study, approximately
1,700 TBtu of energy can be saved by 2007, resulting in over 100,000
tons of avoided seasonal NOX emissions in the SIP call
region if the area achieves the increased rate of energy efficiency
improvement outlined in the ``Efficiency'' case. These potentials
increase to over 3,000 TBtu of energy saved and over 200,000 tons of
avoided seasonal NOX emissions (or 13 percent of the total
tons of reductions needed) under the 5-lab ``High Efficiency'' case.
The associated carbon emissions reductions are nearly 30 million metric
tons of carbon equivalent (MMTCE) by 2007 for the ``Efficiency'' case,
and over 50 MMTCE for the ``High Efficiency'' case.
In a recent study of energy efficiency opportunities in the mid-
Atlantic States region (including New York, New Jersey and
Pennsylvania), the American Council for an Energy-Efficient Economy
(ACEEE) concluded that over
[[Page 25946]]
2,800 TBtu of energy could be saved in this area by 2010 under their
aggressive efficiency scenario. This translates into over 200,000 tons
of seasonal NOX reduced by 2007, and nearly 160 million
metric tons (MMT) of carbon emissions avoided. Enhanced deployment of
energy efficiency technologies and distributed renewable resources,
therefore, may be an important policy tool for States to consider in
achieving multiple environmental objectives.
There are substantial economic benefits and compliance cost
implications for using energy efficiency as a NOX reduction
strategy in the proposed ozone transport rulemaking region. The
economic benefits of achieving the 5-lab study's ``Efficiency'' case
level of improvement include the potential for creating a net increase
of over 80,000 jobs. For the ``High Efficiency'' case, over 160,000 new
jobs would be created. The mid-Atlantic study shows a net increase of
approximately 16,000 new jobs created in the region, with a
corresponding increase in gross State product (GSP) of over $60 billion
by achieving the efficiency potential outlined in the study. Taking
advantage of all of the energy efficiency and renewables potential in
the SIP call region prior to applying other NOX control
methods, such as selective catalytic reduction (SCR) or selective non-
catalytic reduction (SNCR), can lower the overall compliance costs of
meeting the NOX budget as well as reduce overall societal
costs. The EPA's initial analyses show that compliance costs can be
reduced in 2005 by nearly $150 million through accelerated adoption of
energy efficiency and renewables consistent with the 5-lab study in the
proposed ozone transport rulemaking region.
2. Energy Efficiency and Renewables Set-Aside Options
The EPA recognizes and has performed analyses that demonstrate the
benefits of aggressive adoption of energy efficiency and renewables
technologies as a NOX reduction strategy in the proposed
NOX Budget Trading Program for the proposed ozone transport
rulemaking region. However, EPA is not proposing a specific approach
for an energy efficiency and renewables set-aside for NOX
Budget Trading Program in this action.
During the December workshop and in the discussion paper that was
distributed afterward, EPA stated that an energy efficiency and
renewables set-aside approach put forward by the Agency should meet
three important goals: (1) reduce the total economic cost of meeting
the proposed NOX budget, (2) promote energy efficiency and
renewables as effective NOX and pollutant-reducing
strategies through the accelerated adoption of such practices and
technologies, and (3) reduce future CO2-related liabilities
by recognizing the positive impacts of energy efficiency and renewables
on carbon emissions. In addition, EPA stressed that two key principles
should guide the design of its approach for a set-aside program: (1) A
set-aside program should encourage actions that increase efficiency
that would not otherwise occur without the program, and (2) the set-
aside program should maintain the integrity of the NOX cap.
The EPA noted in its December workshop discussion paper that the
difficulties in designing an approach consistent with our objectives of
reducing cost and meeting the goals and principles above are not
trivial. At this time, EPA does not have adequate information to
propose an approach that will accomplish the goals and meet the
Agency's purposes, while adhering to the principles and addressing the
design issues outlined at the December workshop.
The EPA is not including a proposal in this notice to include an
energy efficiency and renewables set-aside in the NOX Budget
Trading Program. The EPA continues to consider whether and how to
develop an approach to include energy efficiency and renewables in the
NOX Budget Trading Program. As part of this action, EPA
today requests that interested parties submit information addressing
the design issues and questions that require further investigation
which are outlined below. Should EPA conclude in the future that there
is adequate information to design an approach for including an energy
efficiency and renewables set-aside to meet its purposes, EPA will
either issue a proposal or guidance as appropriate.
While EPA continues to examine the possibility of designing an
approach for a set-aside, EPA encourages States to consider including
energy efficiency and renewables in their State NOX Budget
Trading programs.
Issue (1) Rewarding Efficiency Improvements Above ``Business
as Usual''
In developing an approach for energy efficiency and renewables in
the NOX Budget Trading Program, EPA believes it is important
that the system encourage actions that increase the penetration of
energy efficiency and renewables improvements beyond the normal rate at
which they are currently and continuously incorporated into all sectors
of the U.S. economy. Some remarks received in response to the
discussion paper were of the opinion that it is unnecessary to be
concerned with business-as-usual projects (or ``anyway'' tons or
``anyway'' projects), specifically because the respondents believe that
the restructuring of the electric utility industry will result in the
decline of demand side management (DSM) programs and reduce the rate of
business-as-usual energy efficiency and renewables adoption to below a
meaningful level. However, because energy efficiency projects often
yield very attractive internal rates of return, many above 35 percent,
and because there are many public information programs and private
businesses aiming at getting more energy efficient and renewables
products and choices into the market, there is likely to be a
continuing level of energy efficiency improvement in the U.S. economy.
Allocating NOX allowances to existing, mandated and expected
energy efficiency and renewables measures means that fewer allowances
will be available to encourage incremental projects. The issue is in
determining how to differentiate between the various types of measures
and, particularly in future years, determining what types of measures
were likely to have happened without the set-aside program. In regard
to the amount of ``business-as-usual'' energy improvement due to energy
efficiency and renewables, EPA requests the following information:
Question 1. How do States determine the amount of ``business-as-
usual'' energy efficiency and renewables occurring across all sectors
of the economy?
Question 2. What information do States and other entities have
about the amounts and types of energy efficiency and renewables that
have been occurring over the last 3-5 years?
The EPA suggested three options for determining projects eligible
for set-aside NOX allowances in its December workshop
discussion paper. One option is to limit the reward of ``business-as-
usual'' projects may be to require that projects attain a sizable
efficiency improvement, over and above a set minimum. This will require
the development of a set of average energy improvement metrics for the
residential, commercial and industrial sectors. As an example, projects
for efficiency in the commercial building sector would be compared to a
target set below the average energy use per square foot that achieves a
particular and higher level of efficiency than that of ``business as
usual'' in that sector. Only projects that meet or exceed the target
would be eligible to be awarded allowances, and
[[Page 25947]]
the size of the award would be based on the increment of improvement
between the ``business as usual'' average and the achievement or
exceedance of the target.
Two other options involve varying the length of the efficiency
reward for different types of energy efficiency improvement measures,
or restricting the number of NOX allowances available to
certain types of improvements. Under the second approach, certain types
of energy efficiency improvements that have already been implemented or
are likely to be implemented without an additional incentive (e.g.,
regulatorily mandated improvements unless implemented early, or energy
efficiency improvements of products that bring them up to the industry
average) would be allocated a shorter stream of allowances, while new
and innovative energy efficiency improvements (incremental projects
above ``business-as-usual'') would be allocated a longer stream of
NOX allowances. Under the third approach, the number of
NOX allowances allocated to energy efficiency improvements
likely to occur anyway is restricted to some portion (e.g., 50 percent)
of the full number of NOX allowances they qualify for given
the actual or expected load reduction.
Of the three options, the first seems to offer the best possibility
for limiting rewards for energy efficiency improvements that would have
occurred anyway. Options two and three would allocate a potentially
smaller portion of NOX allowances to projects that have
already been implemented, are mandated, or are deemed to belong to a
classification of improvements judged to be those likely to occur
anyway. Either of these latter two approaches is difficult because it
requires that a State be able to differentiate between those measures
that would have been implemented anyway versus other types of energy
efficiency improvements. Option one would require that projects attain
a sizable efficiency improvement, over and above a set minimum. This
would require the development of a set of energy improvement metrics
for the residential, commercial and industrial sectors to use to
distinguish baseline from accelerated or enlarged adoption of energy
efficiency and renewables. One possibility for energy efficiency
projects under this option would be to develop a set of energy use or
intensity benchmarks that these projects would be required to meet or
exceed in order to be eligible.
The EPA could use information from its own energy efficiency
programs, such as Energy Star Buildings and Energy Star Homes, as a
starting point for developing benchmarks in the residential and
commercial buildings sectors. For example, in its Energy Star Homes
program, home builders agree to construct new homes that will be 30
percent more energy efficient than the Model Energy Code (MEC). The EPA
could establish the ``30 percent better than MEC'' as the benchmark
that must be attained for applicants wishing to receive set-aside
NOX allowances based on new home developments that are more
energy efficient. The applicant would have to first demonstrate that
the homes built meet this benchmark, and then could be awarded
NOX allowances based on the improvement that reaching the
benchmark represents in that sector. In considering the development of
benchmarks to limit the rewarding of ``business-as-usual'' projects,
EPA requests the following information:
Question 3. Do States and potential applicants for energy
efficiency and renewables NOX allowances have sufficient
information about energy improvement metrics (e.g., energy use per
square foot, MEC) or can they gather sufficient information about
upgrade projects in order to be able to compare the results of these
projects with a benchmark developed for that category (residential,
commercial or industrial) of upgrade?
Question 4. If so, specifically what types of energy improvement
measurements and information about upgrade projects are recorded or
gathered by States and/or potential applicants for energy efficiency
and renewables upgrades or projects?
Question 5. In addition to Energy Star Buildings and Energy Star
Homes what other options are there for developing benchmarks in the
residential and commercial buildings sectors?
Question 6. What kinds of benchmarks could be developed for
industrial sector energy efficiency and renewables improvements, and
how could they be developed? Since industries have both process and
non-process energy use, how could benchmarks be developed for process
(e.g., motors, compressed air, fans) and non-process (facility lighting
and HVAC) efficiency measures in the industrial sector?
Question 7. In order to be able to use benchmarks for industrial
sector energy efficiency it is necessary to separate the facility's
non-process energy use from its process-related energy use. What
methods might be used for distinguishing between an industrial
facility's non-process energy use from its process energy use?
Issue (2) Appropriate Size of the Set-Aside Allowance Pool
The EPA indicated in the December workshop discussion paper that
the energy efficiency and renewables allowance pool within the budget
for the NOX Budget Trading Program should be set at an
amount large enough to maximize the opportunities to promote energy
efficiency and renewables projects, but not so large as to overstate
the efficiency potential so that there are excess NOX
allowances that go unallocated. As pool size is related to the
rewarding ``business-as-usual'' issue, EPA listed two alternatives in
the December workshop discussion paper: (1) Limit the size of the pool
and allocate NOX allowances based on criteria that would
minimize their allocation to ``business-as-usual'' projects, or (2)
establish a larger pool so that there is room for both ``business-as-
usual'' projects as well as incremental energy efficiency projects
being undertaken. Using three different methods and the projections for
energy efficiency potential from the 5-lab study, EPA showed that a
set-aside pool in the range of 5-20 percent of the total electricity
NOX budget for a State or across the region could be
considered
Note: these figures do not include a portion of the nonutility
boiler NOX budget.
The EPA received remarks indicating that a set-aside pool should be
not less than 20 percent to allow for the full potential of both energy
efficiency and renewables projects. Another recommendation made to EPA
is that no specific pool size should be set within the budget for the
NOX Budget Trading Program. Rather, a State could opt to
take all proposals for efficiency and renewables ``off-the-top'' of the
allocation pool, and allocate the remainder to NOX Budget
units. Other respondents to the December discussion paper remarked that
an ``off-the-top'' scheme would allow too little certainty for
NOX Budget units in planning for how to meet the
NOX cap. With regard to pool size, EPA requests the
following information:
Question 8. What is a reasonable estimate for a pool size within
the budget for the NOX Budget Trading Program to award
incremental energy efficiency projects that would not be undertaken
without the availability of set-aside NOX allowances?
Question 9. For States that may be interested in an ``off-the-top''
allocation method as opposed to a fixed percentage set-aside for energy
efficiency and renewables projects, what allocation mechanisms could be
designed to provide greater certainty to NOX budget
[[Page 25948]]
units about the number of non-set-aside NOX allowances for
planning purposes for the upcoming ozone season?
Once a pool size is determined, the main issue of concern is how to
translate load reductions into allowances. The December workshop
discussion paper outlines three basic methods under consideration by
EPA. The first method would be to develop a flat, region-wide, average
NOX rate that represents the average NOX
emissions reductions expected for a kWh reduced. For this method, the
rate could be based on one of three NOX rates: (1) The
average NOX rate calculated by dividing the total
NOX emissions in an area on an annual or seasonal basis by
the total fossil fuel generation in that area for the same time period,
expressed in lbs per kWh State or region specific data; (2) an average
NOX rate calculated by multiplying the proposed ozone
transport rulemaking NOX rate of 0.15 lbs per mmBtu by a
system wide average heat rate in Btu per kWh; or (3) an average
``marginal'' NOX rate in lbs per kWh representing the
generation mix most likely to be backed out on the ``margin.'' This
marginal NOX rate is calculated by dividing the difference
in NOX emissions in an uncapped scenario between a reference
or baseline amount of electricity demand and a reduced amount of demand
(e.g., from energy efficiency) by the amount of generation (kWh)
avoided due to the reduction in energy demand.
The second method would be to develop a regional or a State
specific NOX rate (average or marginal) in lbs/kWh utilizing
the IPM model which would more accurately take into account the
generation mix in each State and the power pools in which they
participate. Developing a regional or a State specific rate would
therefore take into account the amount of NOX reduction
actually attributed to energy efficiency in an uncapped NOX
environment. This method would likely result in different
NOX factors for each State. The third method would be to
develop measure-specific marginal NOX rates which would more
accurately represent the load shape associated with particular energy
efficiency measures (i.e., commercial lighting or industrial motors),
or alternatively, NOX factors for ``typical'' residential,
commercial and industrial loads. This method would therefore more
accurately represent the marginal generation units that would likely be
dispatched less.
The third method, if used to develop measure-specific factors,
could potentially result in dozens of different NOX rates
and would likely be too administratively burdensome. The first and
second methods may result in either overstating or understating
emissions reductions for a particular State. One respondent expressed a
preference for State-specific NOX factors to be used in
translating energy savings into NOX reductions and the
corresponding NOX allowances. Although State-by-State
factors may more accurately reflect the fuel mix of a particular State,
the use of different rates and whether States consistently use either
an average or a marginal NOX rate may impact the value of
allowances. If inconsistent methods are used from one State to the
next, then one State's efficiency allowances may be construed to be of
greater value than another State's. In order to evaluate the three
methods or an alternative to these methods, EPA requests the following
information:
Question 10. What access do States or end users have to information
necessary to obtain or calculate the average NOX rate or the
marginal NOX rate for their State or power pool that may be
used for translating energy efficiency savings into tons of
NOX reductions?
Question 11. If a marginal NOX rate is not available or
calculable and an average NOX rate is used, how would a
State or end user take into account the type of different fossil fuel
mix that the efficiency savings is coming from? Is this necessary to
do?
Issue (3) Eligibility of and Allocation to Applicants and
Projects
Although the scope of the set-aside comprises appropriate end use
energy efficiency and distributed renewables improvements, it is not
intended to limit the types of entities that may apply for allowances
based on completed end use efficiency and renewables upgrades. But
keeping in mind EPA's overall objective of rewarding real reductions,
States may want to consider what types of end users could implement
efficiency and renewables actions that best fit the criteria of
providing real reductions, and focus their efforts on providing
incentive for those types of entities. The EPA generally believes that
entities that would be provided this incentive should be entities that
would not otherwise be holding allowances for the purposes of being
able to emit NOX. Entities holding such NOX
allowances for these purposes have a direct incentive to take actions
that will lower their need for NOX allowances or free up
NOX allowances for trading, and so do not need an additional
incentive. With regard to the industrial sector, the previous
discussion and questions about whether benchmarks can be determined for
improvements in the industrial sector, and whether or not industrial
building energy use can be separated from industrial process use may be
relevant to this discussion. Concerning which end users it may be more
or less appropriate to award with NOX allowances for
reductions achieved through greater energy efficiency and use of
renewable resources, EPA requests the following information:
Question 12. In determining which entities should be eligible to
apply for set-aside NOX allowances, is it appropriate to
limit eligibility to those entities that would not otherwise be holding
NOX allowances for the purposes of being able to emit
NOX? If not, why not?
In addition, for reasons of administrative ease, it may be best for
entities to be required to meet a minimum level of efficiency
improvement or NOX reduction. The purpose of this
requirement would be to prevent the submission of large numbers of
applications for small amounts of reductions, which may cause an
excessive administrative burden, particularly in terms of time required
for processing and verification. For example, applications for
NOX allowances of less than one ton of NOX may be
impractical because an allowance is defined as one ton of
NOX emissions. It may be advisable to set a higher threshold
of NOX reductions, such as five or ten tons or more, as a
minimum for application. This would mean that an applicant for set-
aside NOX allowances would have to bring in energy
efficiency and renewables projects that total no less than five or ten
tons of NOX reductions in order to be considered for an
award. Concerning minimum thresholds for an award, EPA requests the
following information:
Question 13. How many applications could a State reasonably review
on an annual basis for the set-aside without causing an inordinate
administrative burden? What would be the incremental administrative
cost associated with the application process for the set-aside?
There is also a concern about whether or not the location of the
applying entity or where the energy efficiency or renewables
improvement is implemented matters. The location of the applying entity
theoretically should not matter, as long as the energy efficiency and
renewables improvements result in NOX reductions in the
proposed ozone transport rulemaking region.
However, there may be concern about awarding allowances for end use
efficiency for projects in a State within the ozone transport
rulemaking region where the load reduction or the majority
[[Page 25949]]
of the load reduction is realized at an electricity generating unit
that is located outside the NOX Budget Trading Program
region. If it is likely that the end use efficiency will result in load
reductions occurring outside of the proposed ozone transport rulemaking
region, then the amount of NOX allowances to be awarded
should perhaps be adjusted to exclude the reductions occurring outside
the region. This is in keeping with the principle of maintaining the
integrity of the NOX budget. However, in order to do this,
States must be able to reasonably estimate what amount of generation is
produced within the region versus that which is being imported from
outside the area. In this regard, EPA requests the following
information:
Question 14. Will States be able to reasonably estimate the amount
of generation produced within their States and being imported from
within the proposed ozone transport rulemaking region versus that which
is being imported from outside the region? How?
Question 15. Is it necessary to make adjustments that would be to
account for reductions from energy efficiency or renewables occurring
outside the proposed ozone transport rulemaking region, and if so, what
mechanisms are there for doing so?
There is also the matter of whether allowances for energy
efficiency improvements should be awarded for actions that occur during
the years prior to the start date for the NOX Budget Trading
Program. Since the first year for the trading program is 2003, it may
be possible to award NOX allowances for energy efficiency
and renewables measures that are initiated and come on line between the
finalization of the proposed NOX Budget Trading Rule and the
2003 control period. This would effectively give end users credit for
early actions taken to become more energy efficient or to bring on new
renewable resources prior to the need for additional/other controls to
meet the NOX budget. In considering giving credit for early
actions in the form of NOX allowances from the set-aside
pool, EPA requests the following information:
Question 16. What amount or level of incremental energy efficiency
improvements or renewable resources, greater than ``business-as-
usual,'' could/may come on line if credit for early action is given in
the form of NOX allowances from a set-aside that would be
available for trading once the trading program begins?
Question 17. If no incremental projects could come on line under an
early credit scheme, what are the barriers preventing them?
Another topic of importance in this area is the timing of
applications for projects to be considered for NOX
allowances and how entities should apply. This concerns whether or not
an end user may be awarded energy efficiency or renewables
NOX allowances prior to the implementation of the
improvement, or if an award can only be made after the improvement is
in place and has demonstrated results. While it would be unwise to
award allocations based on estimated savings alone, greater incentive
is provided to potential projects if the applicant has some degree of
reasonable certainty of receiving allowances for a project that is
being considered, provided that the expected energy savings and
NOX reductions are achieved. One option is to design a two-
step application process, where an applicant makes a submission
sufficiently prior to the first ozone season for which that efficiency/
renewable project will be operational. The State would review the
project proposal and pre-qualify that the project is eligible for
allowances. Then prior to an ozone season, the applicant must make a
demonstration (e.g., of six months or more) and verify whether the
appropriate efficiency standard(s) or benchmark(s) has been met. If the
demonstration and verification requirements are met, the State would
then issue the appropriate amount of an allowance award. This option
may provide more certainty to the project sponsor or applicant prior to
undertaking the project and may give the State a better estimate of
what level of activity will occur for efficiency set-aside allowances
prior to the ozone season. However, this option will require two rounds
of review for each project or application and so may be more
administratively burdensome.
Another option would be to use a single-step application process,
where applications would be made several months ahead of an ozone
season for projects that are in place and can demonstrate and verify
reductions at time of application. If the project meets eligibility
criteria and expected reductions have occurred in line with efficiency
standard or benchmark, the State would certify that applicant be
awarded allowances for the appropriate ozone season(s). This second
option may be less burdensome, but it may be more difficult to
determine under this method which projects could be interpreted as
``business-as-usual'' types of projects, since they will already have
been put in place without any guarantee of receiving NOX
allowances. In regard to determining the process for a project to apply
for allowances, EPA requests the following information:
Question 18. Which option for reviewing and processing of
applications for energy efficiency and renewables NOX
allowances is preferable and why? What is the estimated administrative
burden associated with each option?
Question 19. Are there other options for reviewing and processing
applications that offer a reasonable degree of incentive and certainty
to applicants while minimizing the administrative burden to States?
What is the estimated administrative burden?
The final matter in this issue area is how to handle over or under
subscription of an energy efficiency and renewables set-aside pool. Two
options outlined in EPA's December workshop discussion paper for
dealing with leftover NOX allowances in a given year or
period include: (1) Banking the allowances to be used for potential
shortfalls in future years, or (2) retiring them. The two options
outlined in the December workshop discussion paper for dealing with
shortfalls in NOX allowances in a given year or period
include: (1) Deferring allocation of allowances for later applicants in
the cycle until the following year, or (2) setting aside a larger
portion of allowances from the NOX budget to award end use
energy efficiency and renewables if shortfalls become a chronic
problem. One response to this issue in the December workshop discussion
paper recommends not setting a specific level of allowances in the set-
aside, but rather allocating all NOX allowances necessary to
cover the eligible applications for efficiency and renewables measures
in a given period first, then allocating the balance of allowances to
NOX budget units. However, the EPA is concerned that this
method provides too little certainty to NOX budget units in
terms of being able to plan for the number of allowances they will need
for a given ozone season and to consider allowance trading. Another
suggestion received recommends discounting the allowances in the pool
sufficiently to be able to cover any over subscription in a given
period. This method would likely result in differences in the amount of
allowances allocated to equivalent projects that are submitted for
consideration in different periods. With respect to under or over
subscription of the allowance pool, EPA requests the following
information:
Question 20. Which of the options listed above for over
subscription and for under subscription of the set-aside
[[Page 25950]]
pool is more administratively feasible for a State, and why?
Question 21. What other options or suggestions could be considered
for handling the over subscription or under subscription of the set-
aside pool?
Issue (4) Persistence of Efficiency Award
Because energy efficiency and renewables measures result in
permanent improvements in energy use and NOX reductions, it
may be appropriate to award energy efficiency and renewables
NOX allowances to these projects for more than one year.
This provides a stream of allowances and provides greater incentive for
incremental projects to be undertaken. There are tradeoffs, however,
between the length of the stream of allowances awarded to a project and
the ability to maintain sufficient availability of allowances over time
to provide incentive for new projects that might not otherwise be
financially viable. A shorter stream of energy efficiency
NOX allowances provides greater availability of such
NOX allowances over time to reward new projects, but
provides less of an incentive (due to lower value) to undertake such
projects. A longer stream provides more financial incentive, but limits
the availability of allowances for future projects.
One respondent to the EPA December workshop discussion paper
suggested that a five-year stream of allowances should be sufficient to
provide incentive for new projects that might not otherwise be
financially viable. And since the proposed NOX Budget
Trading Rule sets a five-year period as the duration of the initial
allowance allocation to NOX budget units, EPA believes that
it is appropriate to set the duration of energy efficiency awards to
five years. With regard to an appropriate duration of award for energy
efficiency and renewables projects, EPA requests the following
information:
Question 22. How large an incentive would a multi-year or a five-
year stream of allowances provide for new energy efficiency or
renewables projects that might not occur otherwise?
Question 23. What kinds of incremental projects might be
implemented as the result of a multi-year or five-year stream of
NOX allowances?
Issue (5) Verification Requirements and Procedures
In order to ensure that energy savings are measured in a reliable
and consistent manner that provides valid information about the
NOX reductions achieved, and that can be used in translating
these savings into their associated NOX reductions for
purposes of awarding NOX allowances, a set-aside program
should have effective verification requirements and procedures.
Some respondents to the December workshop discussion paper affirmed
the need for strong measurement and verification protocols, but also
stressed that it is important that the methods chosen should not be too
complex. In addition, it was suggested that the methods and the degree
of verification fit the type of measure and the entity. However, it is
important that the methods used for measurements are reasonably
consistent among all entities participating in any set-aside programs
in the proposed ozone transport rulemaking region. Further, some
respondents stated that the methods used for awarding set-aside
allowances should be as accurate as the methods used for monitoring
NOX budget units for their use of allowances.
There are three major existing energy efficiency measurement
protocols that may be used to verify reductions for purposes of a set-
aside program: (1) The Conservation Verification Protocol (CVP) of the
Acid Rain Program, (2) the International Performance Measurement and
Verification Protocol (IPMVP) developed by DOE with energy service
company (ESCO) input, and (3) New Jersey's Measurement Protocol for
Commercial, Industrial and Residential Facilities (MPCIRF).
The CVP prescribes measurement methods and confidence levels for
utilities to use in claiming sulfur dioxide (SO2) allowances
for savings produced by DSM measures. Although the CVP is
comprehensive, this protocol may not be appropriate to EPA's purposes
in a NOX set-aside program because the CVP was developed for
utilities, and the set-aside focuses on demand side improvements. DOE
developed the IPMVP with ESCOs so they could use them with their
customers to develop performance contracts for efficiency measures. The
IPMVP however, has no regulatory component, and some of the
verification methods it prescribes do not require the actual
measurement of energy savings. The MPCIRF prescribes precise monitoring
and verification methodologies by project type and also provides
procedures for developing new monitoring and verification methods. In
order to determine what kinds of reliable protocols exist or may need
to be developed, EPA requests the following information:
Question 24. What is the degree of reliability and validity of the
verification methods used in these protocols? What is the
administrative burden associated with the use of one or more of these
protocols?
Question 25. Are there particular parts or sections of one or more
of these protocols that work particularly well and should be included
in or used as a model in developing a new measurement and verification
protocol? Why?
Question 26. What other protocols besides the CVP, the IPMVP and
the MPCIRF exist that States or other entities have used to monitor and
verify energy efficiency projects?
Question 27. What is the degree of reliability and validity of the
verification methods used in these alternative protocols, and what is
the associated administrative burden?
Where the degree of reliability and validity in the measurement of
energy efficiency and renewables improvements is low, it is possible
for a tradeoff to be made between the level of verification required
(i.e., the certainty of load reduction) and the possibility that a
given measure will not result in the expected load reduction. A
discount factor or rate that is commensurate with the level of
uncertainty of the reductions can be applied to lower the total amount
of load reduction that would be awarded allowances. The less stringent
the verification requirements, the higher the discount rates should be
set.
One option in developing alternative verification/NOX
allowance discounting strategies is to determine the uncertainty bounds
associated with a specific verification approach, and then set the
discount rate such that there is, for example, a 90 or 95 percent
probability that all of the allowances that would be awarded represent
true load reductions. For a more conservative approach, the rate could
be set at a 99 percent probability level. One variation on this option
is to establish several verification/discount strategies rather than
just one. These strategies could range from a low verification/high
discount rate to a high verification/low or no discount rate. With
regard to verification/allowance discounting strategies, EPA requests
the following information:
Question 28. What are other options to the verification/allowance
discounting strategies outlined above?
Question 29. What kinds of record keeping are currently done by
States or others to monitor the progress and track the results of
energy efficiency and renewables projects being done?
Question 30. Which option seems most manageable for States? Why?
[[Page 25951]]
VI. Interaction with Title IV NOX Rule
On April 13, 1995, EPA promulgated NOX emission rate
limitations (in lb/mmBtu) for certain types of coal-fired utility
boilers for the Acid Rain Program under title IV of the Act (60 FR
18751, April 13, 1995). The EPA set limits of 0.45 and 0.50 lb/mmBtu,
respectively, for tangentially fired boilers and dry bottom, wall fired
boilers (``Group 1 boilers''). On December 19, 1996, EPA promulgated
additional NOX emission rate limitations for Phase II of the
program, i.e., revised limits for Group 1 boilers and new limits for
cell burner, cyclone, wet bottom, and vertically fired boilers (``Group
2 boilers'') (61 FR 67112, December 19, 1996). In setting the December
19, 1996 NOX limits, EPA also promulgated a final rule
provision (which was to be included in 40 CFR part 76 of the acid rain
regulations) that addressed the relationship between NOX
requirements under titles I and IV of the CAA. As part of recent
litigation in which the December 19, 1996 regulations were upheld by
the Court (Appalachian Power v. U.S. EPA, No. 96-1497, slip op. (D.C.
Cir., February 13, 1998)), EPA requested a remand, which was granted by
the Court, of 40 CFR 76.16 in order to provide additional opportunity
for public comment on the provision. The EPA is therefore including in
today's action a proposed 40 CFR 76.16 that is largely the same as the
remanded rule provision. Obviously, in proposing a new 40 CFR 76.16,
EPA is not requesting comment on any aspect of the December 19, 1996
final rule, including any issues addressed by the Court in Appalachian
Power.
The EPA believes that NOX reduction initiatives under
title I and title IV should be coordinated, consistent with statutory
requirements, in a way that promotes the goal of achieving necessary
NOX reductions in a cost-effective manner. In particular,
today's proposed 40 CFR 76.16, which is proposed to be added to 40 CFR
part 76 of the Acid Rain regulations under title IV, promotes this goal
through provisions that address the interaction of: (i) efforts under
title I, e.g., the proposed transport rulemaking, to reduce
NOX emissions through cap-and-trade programs; and (ii) the
establishment of the title IV Phase II NOX limits, i.e., the
revised limits of 0.40 and 0.46 lb/mmBtu respectively for tangentially
fired and dry bottom, wall-fired utility boilers and the new limits of
0.68, 0.86, 0.84, and 0.80 lb/mmBtu respectively for cell burner,
cyclone, wet bottom, and vertically fired utility boilers.
Many utility boilers subject to the title IV Phase II
NOX limits are likely to face significant, additional
NOX reduction requirements as a result of the proposed SIP
call. If, as EPA recommends, the proposed SIP call requirements are
implemented in the form of a cap-and-trade program and the program
results in utility NOX emission reductions exceeding those
that would be required by utility boilers complying with title IV Phase
II NOX limits, EPA believes that the cap-and-trade system
should be relied on, in lieu of the title IV Phase II NOX
limits, to the fullest extent permissible under the CAA. Under such an
approach, the reductions achievable under title IV will still be
realized but in a manner that allows utilities to take advantage of the
cost savings that result from flexibility, within a cap, to trade
allowances among utilities, as well as among boilers owned by a single
utility. Under the Acid Rain Program in title IV (as under other
emission limit programs), each individual utility boiler must generally
meet the applicable NOX limit; only boilers with the same
owner or operator may average their emissions and comply with a
weighted average NOX limit under a NOX averaging
plan.20 Relief from the title IV Phase II NOX
limits is appropriately limited to utility boilers in the State or
States covered by the cap-and-trade regime.
---------------------------------------------------------------------------
\20\ In addition, if it is demonstrated that a boiler with
installed NOX control technology designed to meet the
applicable standard NOX limit cannot meet that limit, the
boiler may be assigned a less stringent, alternative emission
limitation under title IV.
---------------------------------------------------------------------------
Under today's proposed Sec. 76.16, the Administrator retains the
authority to relieve boilers subject to a cap-and-trade program under
title I from the Phase II NOX limits under section 407(b)(2)
if the Administrator finds that alternative compliance through the cap-
and-trade program will achieve the same or more overall NOX
reductions from those boilers than will the section 407(b)(2) emission
limitations. Section 76.16 sets forth the criteria that the cap-and-
trade program must meet in order to ensure that the program will yield
the necessary NOX reductions. Since alternative compliance
will be allowed only if the necessary NOX reductions will
still be made, this approach is consistent with the purposes of title
IV and the Act in general.
The EPA believes that it has the authority under section 407(b)(2)
to provide relief from the revised Group 1 limits and the Group 2
limits where the cap-and-trade program, replacing those limits,
provides for the same or greater NOX emissions reductions
and thus the same or greater environmental protection. With regard to
Group 1 boilers not subject to the existing Group 1 limits until 2000
(i.e., Group 1 Phase II boilers), section 407(b)(2) provides that the
Administrator ``may'' establish more stringent emission limitations if
more effective low NOX burner technology is available (42
U.S.C. 7651f(b)(2)). The Administrator exercised her discretion to
revise generally the Group 1 limits because more effective low
NOX burner technology is available, and the resulting
additional reductions are cost effective, represent a reasonable step
toward achieving regional NOX reductions that are likely to
be needed, and are consistent with section 401(b) (61 FR 671137). If it
is determined that, for boilers in certain States, NOX
emissions will be the same or lower under a cap-and-trade program than
under the revised Group 1 limits (and the Group 2 limits), it is
reasonable to conclude that it is not necessary to revise the Group 1
limits for those boilers. Imposing the revised Group 1 limits on
boilers subject to such a cap-and-trade program could limit the
flexibility of utilities under the cap-and-trade program and thereby
limit the potential cost savings from trading. While emissions
averaging under section 407(e) provides some flexibility for a utility
to overcontrol at its cheaper-to-control boilers and undercontrol at
its more-expensive-to-control boilers, averaging is limited by statute
to boilers with the same owner or operator. In contrast, under a cap-
and-trade program, utilities may overcontrol at some of their units and
sell NOX allowances to other utilities that may undercontrol
at some of their units. It is this greater flexibility, within a total
annual emissions cap, that provides the opportunity to reduce
compliance costs. If boilers subject to a cap-and-trade program are
relieved of compliance with the revised Group 1 limits, this will
likely result in achievement of reductions in a more cost-effective
manner than if the revised Group 1 limits continued to be imposed on
these boilers.
Section 407(b)(2) gives the Administrator discretion to make more
stringent the initial Group 1 limits established in 1995, i.e., 0.45
and 0.50 lb/mmBtu respectively for tangentially fired and dry bottom
wall-fired utility boilers (60 FR 18751), but not to relax these
initial limits. Thus, the initial Group 1 limits will apply to Group 1
boilers covered by a cap-and-trade program. While retaining the initial
Group 1 limits means that there may be less flexibility than if there
were no
[[Page 25952]]
section 407 limits on these boilers, relieving the boilers of the
revised Group 1 limits still results in some increased flexibility and
therefore is likely to yield cost savings.
Similarly, with regard to Group 2 boilers, section 407(b)(2)
requires that the Administrator, taking account of environmental and
energy impacts, set emission limits that are based on the reductions
achievable using available control technologies with cost effectiveness
comparable to low NOX burners on Group 1 boilers. In setting
the Group 2 limits, the Administrator relied in part on the additional
NOX reductions that will result and determined that these
reductions are cost effective, represent a reasonable step toward
achieving necessary regional NOX reductions, and are
consistent with section 401(b) (61 FR 67114). Again, if greater
reductions from boilers in a State or group of States can be achieved
through a cap-and-trade program in a more cost-effective manner than
through imposition of Group 2 limits (and revised Group 1 limits) on
the boilers, it is reasonable to relieve those units of the Group 2
limits. Taking account of these environmental and cost impacts, the
Administrator can, in such circumstances, allow the cap-and-trade
program to apply in lieu of the Group 2 limits.
Proposed 40 CFR 76.16 establishes the procedural and substantive
requirements for relieving boilers of the revised Group 1 limits and
the Group 2 limits. The proposed rule itself does not grant or require
such relief. Instead, under the proposed rule, the Administrator has
the discretion to act, on a case-by-case basis consistent with the
established procedures, to provide such relief if he or she determines
that the substantive requirements are met.
Consideration of whether to relieve boilers under a cap-and-trade
program of the section 407(b)(2) limits may be initiated either by a
petition by a State or group of States or on the Administrator's own
motion. Because of the large number of utility companies and coal-fired
boilers and the complexities that would result if relief from the
section 407(b)(2) limits were considered on a boiler-by-boiler or
utility-by-utility basis, the rule requires that any request for, and
any determination whether to grant, such relief be made for an entire
State or entire group of States. The cap-and-trade program involved
must cover, for an entire State or group of States, all the units for
which relief is sought or considered. This approach has the added
benefit of making it more likely that the cap-and-trade program
involved will be broad enough to provide a robust NOX
allowance market.
Further, the cap-and-trade program may be established through SIPs
or FIPs covering the States involved. The relief from section 407(b)(2)
limits is potentially available whether the cap-and-trade program is
adopted voluntarily by States or imposed by EPA under title I. State
petitions for such relief may be submitted, and the Administrator's
consideration of whether to grant relief may begin, before the SIPs or
FIPs (including revised SIPs or FIPs) establishing the cap-and-trade
program are final and federally enforceable. This allows the process of
deciding whether to grant relief from the section 407(b)(2) limits to
be coordinated with the processing of these SIPs or FIPs. However,
relief may not be granted until the SIPs or FIPs establishing the cap-
and-trade program are actually in place, i.e., are final and federally
enforceable.
The substantive requirements that must be met by the cap-and-trade
program are essentially the same whether the program is implemented
through a SIP or FIP and whether the consideration of relief from
section 407(b)(2) limits is initiated by petition or on the
Administrator's own motion. The Administrator has discretion to grant
relief only if the cap-and-trade program meets certain requirements
aimed at ensuring that the necessary NOX reductions will
still be achieved and that the program creates an opportunity for cost
savings. First, each unit that is in the State or group of States and
that would otherwise be subject to title IV NOX emission
limits must be subject to either (i) a cap on total annual
NOX emissions or (ii) two or more seasonal caps that
together limit total annual NOX emissions. This allows for a
cap-and-trade program with different caps during different seasons,
e.g., a summer cap consistent with the proposed trading rule and a cap
for the rest of the year.
Second, the units must be allowed to trade authorizations to emit
NOX within the applicable cap. This element is what provides
utilities the flexibility to reduce the costs of making the reductions
necessary for achievement of the cap. If a utility demonstrates that
relief from the title IV Phase II NOX limits for units in a
given State will make compliance less cost effective by limiting the
utility's ability to use NOX averaging plans to comply with
the title IV NOX limits that will still be applicable to the
utility's units, the Administrator is required to take this into
consideration in determining whether to approve such relief for units
in that State.
Third, the units must surrender authorizations to emit
NOX (i.e., NOX allowances) to account for their
NOX emissions during the period covered by the cap. It
should be noted that this provision--and indeed the proposed 40 CFR
76.16 in general--do not address, and do not either require or bar,
banking of NOX allowances.
In addition, the units must be required to surrender allowances to
account for any NOX emissions consequences of reducing
utilization at the generation facilities covered by the cap and
shifting utilization to generation facilities not covered by the cap.
This addresses a problem that potentially arises if a cap-and-trade
program covers some but not all generation facilities. If, for example,
a utility can reduce the use of a unit covered by the cap and offset
the resulting reduced generation with increased generation at a unit
not covered by the cap, circumvention of the cap may result. Shifting
of utilization may be accomplished because of the nature of the
electricity industry, which in general operates through an interstate
transmission grid to which the generation facilities are connected.
Because of the offsetting utilization changes at the two units, the
atmosphere may receive the same total amount of NOX
emissions from the units. In addition, since only the reduced-
utilization unit is subject to the cap and so allowances are used only
to account for that unit's emissions, the unused allowances are
available for use by other units subject to the cap. The net result is
that the total emissions in the atmosphere (including emissions by the
reduced-utilization unit, the increased-utilization unit, and the units
acquiring and using the unused allowances) may exceed the cap. This is
analogous to the reduced utilization problem in the SO2 cap-
and-trade program in Phase I, during which most units in the U.S. are
not covered by the requirement to hold allowances for their
SO2 emissions (58 FR 60950, 60951, January 11, 1993).
Section 408(c)(1)(B) of the CAA and 40 CFR 72.91 and 72.92 of the acid
rain regulations require SO2 allowance surrender to account
for the emissions consequences of reduced utilization (60 FR 18462-63,
1995).
The NOX cap-and-trade program must include appropriate
allowance surrender provisions to address this problem by requiring
NOX allowance surrender to the extent necessary to account
for the increased NOX emissions, if any, at generation
facilities (i.e., combustion devices serving
[[Page 25953]]
generators) not covered by the cap. The EPA recognizes that any
allowance surrender provisions can only approximate the emissions
consequences of shifting utilization from within-the-cap facilities to
outside-the-cap facilities, (60 FR 18466). The EPA will evaluate
NOX allowance surrender provisions in light of this
limitation and of the importance of adopting provisions that are
workable and not overly complicated. The EPA believes that effective
NOX allowance surrender provisions can be developed that are
less complex than those in place for reduced utilization in the
SO2 allowance trading program. The EPA also notes that the
larger the group of States covered by the cap, and the more
comprehensive the coverage by the cap of generation facilities in such
States, the smaller the potential for shifting utilization from units
under the cap to units outside the cap. The proposed rule, therefore,
provides that the Administrator will consider showings that accounting
for shifting utilization is not necessary because such shifting will
not likely result in higher total NOX emissions from sources
in the State or the group of States involved or other States.
Fourth, the total annual emissions by all units that are subject to
the cap and that would otherwise be subject to the section 407(b)
limits must be equal to or less than the total annual emissions of such
units if they were subject to the section 407(b) limits (without
adjusting for alternative emission limitations and NOX
averaging plans). In determining the units' total annual emissions
under the section 407(b) limits, the effect of alternative emission
limitations--which reduce the amount of NOX reductions
achieved and whose precise levels for individual units would be
difficult if not impossible to project--will not be considered.
Requiring the cap-and-trade program to yield the same or fewer total
annual emissions than the section 407(b) limits without considering
alternative emission limitations will help ensure that the
environmental benefits of the section 407(b)(2) are preserved under the
cap-and-trade program (Economic Incentive Program Rules, 59 FR 16690,
16694, April 7, 1994).
In addition, the effect of averaging will not be considered in
determining the units' total annual NOX emissions because of
the following reasons. If averaging is limited to units that are also
subject to the cap-and-trade program, averaging is unnecessary to
consider separately because it would not affect the total emissions of
the averaging units under the section 407(b) limits (60 FR 18756 which
explains that, considering actual annual utilization, actual weighted
average emission rate of units in averaging plan cannot exceed weighted
average emission rate if each unit had emitted at its 40 CFR 76.5,
76.6, or 76.7 limit and 60 FR 18769). If averaging includes units not
subject to the cap-and-trade program and those units select emission
rates under the plan that exceed the standard limits, this could have
the effect of understating the reductions achieved under the title IV
limits.
In order to avoid disputes over what period to use in comparing
total annual emissions under the cap-and-trade program and the section
407(b) limits, the rule specifies how to select the period. The
approach in the rule ensures that actual data is available for such
period.
In addition to the substantive requirements for relieving units of
the section 407(b)(2) limits, the rule addresses the procedures that
the Administrator must follow in determining whether to exercise his or
her discretion to grant relief. The Administrator must make this
determination in a draft decision, subject to notice and comment, and
then in a final decision. The draft decision must set forth not only
the determination and its basis but also the specific procedures that
will govern the issuance and any appeal of the final decision.
The proposed 40 CFR 76.16 imposes certain minimum procedural
provisions that must be set forth in the draft decision. These
procedural requirements are closely modeled after the procedures in 40
CFR part 72 of the Acid Rain regulations for the issuance of Acid Rain
permits. Notice of the draft decision must be provided by service on
interested persons, designated representatives of any sources with
units otherwise subject to the title IV Phase II NOX limits,
and the air pollution control agencies in States that may be affected
by the draft decision. The State agencies that must be provided notice
include not only the States in which the units involved are located,
but also neighboring States. The description in the proposed rule of
the neighboring States (and areas in which there are federally
recognized Indian Tribes) on which notice must be served is based on
the provisions of the definition of ``affected States'' and the
affected State review provisions in the 40 CFR part 71 regulations,
which govern federal issuance of title V operating permits (61 FR
34202, 34229, and 34242-43, July 1, 1996). Notice must also be provided
in the Federal Register and equivalent State publications. Notice in
newspapers in general circulation in the areas in which the units
involved are located is not required. The EPA maintains that newspaper
notice in these circumstances is unnecessary, particularly since any
NOX cap-and-trade program being evaluated will have to go
through notice and comment in order to be included in a SIP or FIP.
Newspaper notice could also be unworkable in light of the number of
units and States that could be involved.
The provisions for public comment period and public hearing are
essentially the same as those in 40 CFR part 72. Notice must be given
of the final decision in the same manner as notice of the draft
decision. Any appeals of the final decision are governed by 40 CFR part
78, which governs other acid-rain-related decisions of the
Administrator.
Finally, after the Administrator decides to relieve units of the
section 407(b)(2) limits in light of a given cap-and-trade program, the
SIP or FIP could potentially be revised in a way that may affect the
cap-and-trade program and the basis for the Administrator's decision.
In such circumstances, the Administrator may reconsider the decision to
grant relief from the section 407(b)(2) limits. The ability to
reconsider is explicitly preserved in the rule in order to ensure that
the environmental benefit of the section 407(b)(2) limits that would
otherwise apply to the units involved continues to be realized.
VII. Air Quality Assessment of the Statewide Emissions Budgets
A. Background Information
This Section contains an assessment of the impacts of the proposed
budgets on ozone concentrations within the OTAG region. The assessment
is based on photochemical modeling of the entire OTAG region for three
emissions scenarios, a Base Year, a 2007 Base Case and the proposed
statewide budgets. Modeling was performed for the four OTAG episodes
using the OTAG version of UAM-V. The emissions associated with each
State's budget were modeled collectively to examine the net benefits of
the budgets applied across the 23 jurisdictions. The procedures for
developing the emissions inputs for the Base Case and the Budget
scenario are described in Section VII.B, Emissions Scenarios. A number
of metrics were used to evaluate the impacts of the budgets on ozone
concentrations, as described in Section VII, C, Analysis of Modeling
Results. Finally, the results of
[[Page 25954]]
this assessment are provided in Section VII.D, Analysis Results and
Findings. All of the model-ready emissions inputs and model predictions
can be obtained in electronic form from the following EPA website:
http://www.epa.gov/scram001/regmodcenter/t28.htm
B. Emissions Scenarios
The EPA modeled three emissions scenarios for each of the four OTAG
episodes: Base Year, 2007 CAA Base Case, and 2007 Budget (command and
control). Collectively, these scenarios are designed to provide a means
to examine the expected impacts of the proposed budgets on ozone within
the OTAG modeling domain. The Base Year scenario is intended to
generally reflect emissions during the 1994-1996 time period. The CAA
Base Case reflects growth to 2007 and controls mandated by the 1990
Clean Air Act Amendments, similar to the OTAG ``2007 Base1c'' scenario.
The 2007 Budget scenario caps NOX emissions, by State, at
the level in the SIP call, as modified to correct minor errors and
omissions identified by EPA subsequent to the November 7, 1997 SIP
call.
1. Development of Emissions Inputs
a. Electric Generation Sources. For electric generation units
(EGU), the Base Year is a composite of 1995 and 1996. The 1996
emissions were used unless heat input at a State level was higher in
1995. For those States, 1995 emissions were used. This is consistent
with the budget development approach. For the 2007 Base Case, growth
was applied to existing sources and CAA mandated controls, including
title IV and RACT, were applied to all sources in the modeling domain.
No additional controls beyond those mandated by the CAA were applied.
For the 2007 Budget scenario, growth was applied to existing sources
and the emission rate for each source >25 MWe in the 23 jurisdictions
covered by the SIP call was set at .15 lb/mmBtu. Note that this
application of the .15 lb/MMBtu limit does not reflect an emissions
trading program. For sources outside the 23 jurisdictions but inside
the modeling domain, the 2007 CAA Base Case emission rates were
retained. Details on the development of these emissions scenarios are
described in the revised Budget TSD.
b. Non-Electric Generation Point Sources. For the non-EGU point
sources, the Base Year is 1995. The emissions are essentially the OTAG
1990 emissions projected to 1995 with a few minor changes. The 2007
emissions are the OTAG Base1c emissions with changes. The main change
that was made was to reclassify certain sources as non-utility where
they were incorrectly classified as utilities in the OTAG inventory.
For the Budget scenario, a 70 percent reduction was applied to
uncontrolled 2007 projected emissions for large sources (i.e. >250
MMBtu/hr). For medium sources (i.e. <=250 MMBtu/hr and emitting more
than 1 ton/day) RACT was applied. For all small sources in the 23
jurisdictions and all sources outside these areas but inside the
modeling domain, the 2007 CAA Base Case emissions were used.
c. Mobile and Area Sources. For the highway, nonroad and stationary
area source sectors, EPA used the OTAG 1995 emissions for the Base Year
and the OTAG 2007 Basic emissions for the 2007 CAA Base Case. For the
Budget scenario, emissions for these sectors were modeled using OTAG
``level 0'' for highway mobile and OTAG ``level 1'' for stationary and
nonroad area sources within the 23 jurisdictions covered by the SIP
call. For areas outside these areas but inside the modeling domain, the
2007 CAA Base Case emissions were used.
2. Emission Summaries
State-level summaries of the weekday NOX emissions used
for modeling the Base Year, 2007 CAA Base Case, and Budget scenario are
shown in Tables VII-1 through VII-3, respectively. For the purpose of
these summaries, area sources include both stationary and nonroad area
sources. The mobile emissions are day-specific and are presented for
July 7, 1988. Where partial States are included in the modeling domain,
only the emissions from the part of the State in the domain are
presented. Table VII-4 shows the percent reduction between the 2007 CAA
Base Case and the Budget NOX emissions used as input for
modeling.
C. Analysis of Modeling Results
1. Technical Procedures
The impacts of the proposed budgets on 1-hour and 8-hour ozone
concentrations in each State are evaluated using various ozone
``metrics'' 21. The focus of the analysis is on ozone
predictions above the 1-hour and 8-hour NAAQS in areas which currently
measure violations of these standards. This State-level assessment is
supplemented with the OTAG Standard Table of Metrics to quantify the
impacts in several ozone ``problem areas'' identified by OTAG. The
remainder of this Section describes the procedures for calculating the
metrics used in this assessment.
---------------------------------------------------------------------------
\21\ Metrics are an aggregate of ozone concentrations or the
difference in ozone concentrations between two or more scenarios.
Metrics are used to provide a means of quantitatively evaluating
multiple strategies.
---------------------------------------------------------------------------
a. State-Level Analysis. Nine metrics were used to quantify the
impacts of the budgets on ozone concentrations in each State. The
metrics are listed below and defined in Section C.1.a.ii, Procedures
for Calculating State-Level Metrics.
1-Hour Metrics
Metric 1--the number of grid cells with 1-hour daily maximum ozone
concentrations >=125 ppb,
Metric 2--the magnitude and frequency of the ``ppb'' reductions in
1-hour daily maximum ozone concentrations >=125 ppb,
Metric 3--the number of days with 1-hour daily maximum ozone
concentrations >=125 ppb, and
Metric 4--the ``areal exposure'' to hourly ozone concentrations
>=125 ppb 22 (see definition in Section C.1.a.ii, Procedures
for Calculating State-Level Metrics).
---------------------------------------------------------------------------
\22\ In brief, this metric represents the sum of the
concentrations for all hourly ozone values >=125 ppb, divided by the
area (km2) covered by predictions >=125 ppb.
---------------------------------------------------------------------------
8-Hour Metrics
Metric 5--the number of grid cells with average second high 8-hour
ozone concentrations >=85 ppb,
Metric 6--the magnitude and frequency of the ``ppb'' reductions in
average second high 8-hour ozone concentration >=85 ppb,
Metric 7--the number of grid cells with 8-hour daily maximum ozone
concentrations >=85 ppb,
Metric 8--the magnitude and frequency of the ``ppb'' reductions in
8-hour daily maximum 8-hour ozone concentrations >=85 ppb, and
Metric 9--the number of days with 8-hour daily maximum ozone
concentrations >=85 ppb.
i. Selection of Grid Cells for Analysis. As noted above, the focus
of this analysis is to evaluate the impacts of the budgets on
concentrations in areas which violate the NAAQS. In this regard, the
first step in calculating the metrics was to select appropriate sets of
grid cells for analysis. The approach to grid cell selection is similar
to that used in the proposed SIP call, Section II, ``Weight of Evidence
Determination of Significant Contribution'' to quantify the
contributions from upwind subregions on downwind nonattainment.
Different sets of grid cells were selected for analyzing the results
relative the 1-hour NAAQS and the 8-hour NAAQS. For both standards,
there are two generic types of grid cells. The first type must meet the
following
[[Page 25955]]
two-part test: (a) The grid cell must correspond geographically to
(i.e. overlay) a county which currently violates the NAAQS and (b) the
grid cell must have predicted ozone concentrations above the
concentration level of the NAAQS (e.g. >=125 ppb for the 1-hour NAAQS
and >=85 ppb for the 8-hour NAAQS). The second generic type of grid
cell must meet only the second part of this two part test. That is, the
grid cell must have predicted ozone above the NAAQS but may or may not
be associated with a county violating the NAAQS. The 1-hour and 8-hour
State-level metrics identified above were calculated for both types of
grid cells. The rationale and procedures followed in the grid cell
selection process are described below.
First, 1994-1996 ambient monitoring data were used to identify
counties which currently violate the 1-hour and 8-hour NAAQS. A list of
these counties is contained in the docket for this notice. The grid
cells in the OTAG region were then screened to identify those grids
which at least partially overlay one of the 1-hour violating counties.
The same procedure was followed using the 8-hour violating counties.
This process resulted in one set of grid cells associated with areas
violating the 1-hour NAAQS and a separate set associated with areas
violating the 8-hour NAAQS. The next step was to select the subset of
1-hour ``violating grid cells'' which also have predicted ozone
concentrations above the NAAQS. For this, the 1-hour daily maximum
concentrations for the 2007 Base Case model runs were examined to
identify which grid cells had predicted values >=125 ppb during any one
of the 4 episodes. The grid cells that met this test were then selected
for analysis using the 1-hour metrics.
For the 8-hour analysis, the procedures for selecting the subset of
grid cells was more complicated due to the distinction between the form
of the 8-hour NAAQS and the episodic nature of the model predictions.
In this regard, two sets of 8-hour predictions were included for
analysis. One set considers those grid cells with 8-hour daily maximum
concentrations >=85 ppb in the 2007 Base Case model runs (this set is
analogous to the set of 1-hour data described above). Thus, a set of
grid cells which (a) corresponds to counties violating the 8-hour NAAQS
and (b) has 8-hour predictions >=85 ppb was selected for calculating
the 8-hour metrics. However, although the analysis of 8-hour daily
maximum values may provide useful information on the impacts of the
budgets relative to high 8-hour concentrations, these data do not
necessarily correspond to the form of the 8-hour NAAQS. In this regard,
we also considered the approach followed in the proposed SIP call for
dealing with this issue. That approach involved using ozone
measurements to ``link'' the fourth highest 8-hour form of the NAAQS,
based on three years of data, to the episodes modeled by OTAG (Staff
Report-Procedures for Linking the OTAG Episodes to the 8-Hour Ozone
NAAQS, October 1997, docket number, II-A-25). The results of that
analysis indicate that the episodic average of the second highest 8-
hour observed concentrations during the 1991, 1993, and 1995 episodes
correspond best ``overall'' to the fourth highest 8-hour values
calculated using 3 years of measured data. For the assessment of the
budgets, the second highest 8-hour values averaged across the 1991,
1993, and 1995 episodes were calculated for each grid cell. Those grid
cells which (a) correspond to counties violating the 8-hour NAAQS and
(b) have an average second high 8-hour prediction >=85 ppb were
selected for calculating the 8-hour metrics. Thus, for the 8-hour
analysis, separate metrics were calculated for the daily maximum 8-hour
values and for the average second high 8-hour values.
The previous discussion dealt with selecting grid cells which meet
the two-part ``monitoring plus modeling'' test for both the 1-hour and
8-hour NAAQS. The other type of grid cell selected for analysis must
only meet the model prediction part of the tests described above. The
rationale for using this second type of grid cell is discussed next.
Although the ``violating county'' grid cells may be most appropriate
for this assessment because they are associated with areas violating
the NAAQS, there are a number of limitations with this approach which
warrant further consideration. First, in terms of the modeling data,
the requirement that high ozone predictions spatially coincide with
violating counties may be overly limiting given the uncertainties in
the modeled wind regimes associated with the regional nature of the
meteorological inputs. Also, the set of ``violating county'' grid cells
excludes all grid cells that are over water and not touching any State
land areas. In the real atmosphere, sea breeze and lake breeze wind
flows can transport high ozone levels over water back on-shore to
affect coastal land areas. This meteorological process is not fully
treated in the model because of the coarse horizontal resolution of the
grid cells (i.e. 12 km). Thus, high concentrations predicted just
offshore may be inappropriately excluded from an analysis that is
limited to the set of ``violating county'' grid cells. In terms of
limitations to the monitoring data, there are relatively large areas in
some portions of the domain without any monitors. Since the model
predicts concentrations in grid cells which cover the entire domain,
the model predictions may indicate an ozone problem in areas without
monitors. In an attempt to address these concerns, grid cells were
selected for analysis based on model predictions only. The criteria for
selecting these grid cells involved the modeling part of the two part
test described above. That is, for the 1-hour NAAQS a set of grid cells
was selected if they have daily maximum 1-hour predictions >=125 ppb.
Similarly, there are two sets of 8-hour grid cells. One set contains
those grid cells with daily maximum 8-hour predictions >=85 ppb and the
other set contains grid cells with an average second high 8-hour value
>=85 ppb. Also, note that in this approach, all grid cells over land as
well as over each of the Great Lakes and in a band 60 km (5 grid cells)
wide along the East Coast are considered depending on whether or not
they passed these 1-hour and 8-hour concentration tests.
ii. Procedures for Calculating State-Level Metrics. Each of the 1-
hour and 8-hour metrics identified in Section C.1.a, State-Level
Analysis, was calculated for the two types of grid cells described
above. The procedures for calculating these metrics are described next.
The results are discussed in Section D, Analysis Results and Findings.
Metric 1 was calculated by first screening the 2007 Base Case 1-hour
daily maximum predictions for each grid cell to select only those days
with concentrations >=125 ppb. The daily maximum predictions from the
Budget scenario for these same days and grids were also selected for
analysis. The values from the Budget scenario were then subtracted from
the corresponding 2007 Base Case values to derive a set of ``ppb''
differences for each day 23 and grid cell with ozone >=125
ppb in the Base Case. These ``ppb'' reductions were then grouped into
seven concentration ranges (i.e. 2-5 ppb, 5-10 ppb, 10-15 ppb, 15-20
ppb, 20-25 ppb, and >25 ppb) and tallied by State. Metric 2 is simply a
tabulation of the number of grid cells with at least one daily maximum
ozone 1-hour concentration >=125 ppb. This metric was calculated
[[Page 25956]]
for both the 2007 Base Case and the Budget scenario. For Metric 3, the
number of days with a daily maximum ozone prediction >=125 ppb was
tallied for each grid cell for both the 2007 Base Case and for the
Budget scenario. These data were aggregated to show the number of grid
cells that had 1 day, 2-4 days, 5-9 days, 10-14 days, or >=15 days with
predicted 1-hour daily maximum ozone concentrations >=125 ppb. Metric 4
(areal exposure) was calculated by first summing all hourly
concentrations that are >=125 ppb (i.e. add together the predicted
hourly ``ppb'' values that are >=125 ppb) for each grid cell
individually, for each day. These ``daily exposure'' values in each
grid were then summed by grid cell over all days in all 4 episodes to
produce the total exposure for each grid cell. The resulting grid cell
exposure values were summed by State for all grid cells (with
predictions >=125 ppb) in the State. The State total exposure values
were then divided by the total area covered by the grid cells used in
the calculations to produce the ``areal exposure'' values in units of
ppb-hrs per km \2\.
---------------------------------------------------------------------------
\23\ Note that EPA followed the procedures established by OTAG
by excluding predictions from the first three days of each episode
from the calculation of metrics. These days are considered ``ramp-
up'' days when ``initial'' conditions to the model might effect
predictions.
---------------------------------------------------------------------------
Procedures for calculating the five 8-hour metrics are similar to
those followed for calculating the corresponding 1-hour metrics except
that the 8-hour values (i.e. the 8-hour daily maxima and the average
second high 8-hour values) were used in the calculations.
b. OTAG Standard Table of Metrics. As part of OTAG, a Standard
Table of Metrics was developed to evaluate the relative effectiveness
of OTAG's strategies. This table contains a set of 22 metrics which are
calculated for each of 22 geographic areas. The OTAG Standard Table of
Metrics for the Budget scenario compared to the 2007 Base Case is
provided in the docket. From this full set of data, five of the metrics
calculated for the 12 OTAG ozone ``problem areas'' were selected for
analysis because of their relevance to this assessment. These metrics
are listed below. The remaining OTAG metrics were not considered as
applicable primarily because they do not focus on concentrations above
the NAAQS. The 12 OTAG ``ozone problem areas'' are shown in Figure 1.
The other 10 areas for which the OTAG metrics were calculated overlap
these 12 areas. Note that the OTAG metrics are calculated using all
grid cells that meet the criteria of the individual metrics. No attempt
was made by OTAG to relate the grid cells used in these calculations to
counties violating the NAAQS.
1-hr Metrics
Number of grid cells with a 1-hour daily maximum ozone
concentrations >124 and >140 ppb,
``Weighted sum of differences'' when the 2007 Base Case
prediction is >124 ppb,
Number of grid cells with a decrease of more than 4 ppb
(2007 Base vs Budget) in daily maximum ozone when the 2007 Base Case
ozone is >124 ppb, and
Number of grid cells with an increase of more than 4 ppb
(2007 Base vs Budget) in daily maximum ozone when the 2007 Base Case
ozone is >124 ppb.
8-hr Metrics
Number of grid cells with 8-hour daily maximum ozone
concentrations >84 and >100 ppb.
The preceding 1-hour and 8-hour OTAG metrics are self-explanatory,
except for the ``weighted sum of differences.'' In calculating this
metric the change in daily maximum 1-hour ozone in a grid cell is
multiplied by the corresponding 2007 Base Case ozone prediction in that
grid cell. These concentration-``weighted'' differences are calculated
for each day and then summed for the episode. Finally, the sum of
``weighted'' differences is divided by the sum of the 2007 Base Case
daily maximum concentrations to produce the values for this metric.
This metric provides a means for examining the ``average'' ozone
reduction in a way that gives more importance or ``weight'' to
reductions that occur at high concentrations.
D. Analysis Results and Findings
1. Introduction
The results and conclusions found in this Section are based on the
suite of metrics outlined above in Section C, Analysis of Modeling
Results. The discussion is organized such that the impacts on 1-hour
concentrations and the impacts on 8-hour concentrations are presented
separately. For each NAAQS the results for the State-level metrics are
followed by the results for the OTAG ``problem areas.''
As indicated in Section C.1, Technical Procedures, the focus of
this assessment is on the impacts of the budgets on 1-hour and 8-hour
ozone above the NAAQS in areas which currently measure violations of
these standards. In this regard, the discussion of the State-level
impacts addresses only those metrics calculated using the ``violating
county'' grid cells. The data for all metrics calculated using the set
of grid cells selected based on model predictions only are included in
the docket. Also, the discussion for the 8-hour NAAQS is based on the
metrics calculated for the average second high 8-hour concentrations
since this was found to best represent the form of the 8-hour NAAQS.
The data for metrics calculated using the 8-hour daily maximum
predictions are included in the docket.
For the State-level analyses, the modeling domain was divided into
several regions. The impacts across the 23 jurisdictions subject to the
SIP call are addressed separately for States in the Midwest, Southeast,
and Northeast. The States included in each of these regions are listed
in Table VII-5. For completeness, all of the metrics were also
calculated for those States within the domain that are not subject to
the SIP call. These data are included in the docket.
a. Impacts on 1-Hour Ozone Concentrations. The State-level analyses
of 1-hour concentrations included Metrics 1-4: (1) The number of grid
cells with 1-hour daily maximum concentrations >= 125 ppb; (2) the
magnitude and frequency of the ``ppb'' reductions in 1-hour daily
maximum ozone concentrations >= 125 ppb; (3) the number of days with 1-
hour daily maximum ozone concentrations >= 125 ppb; and, (4) the
``areal exposure'' to hourly ozone concentrations >= 125 ppb. For ease
of communication in the discussion of results, the following
terminology is used in referring to these metrics:
Metric 1: the extent of ``nonattainment,''
Metric 2: the magnitude and frequency of ``nonattainment,''
Metric 3: the number of ``nonattainment'' days in each grid cell,
and
Metric 4: exposure to ``nonattainment.''
In addition to the State-level analysis, the impacts on 1-hour
ozone in the OTAG ``problem areas'' were investigated using several of
the standard OTAG metrics, including: (1) The number of grid cells with
daily maximum 1-hour ozone >124 ppb; and the number of grid cells with
daily maximum 1-hour ozone >140 ppb; (2) the weighted sum of
differences when the 2007 Base Case prediction is >124 ppb; and, (3)
the number of grid cells with an increase of more than 4 ppb when the
2007 Base Case ozone is >124 ppb versus the number of grid cells with a
decrease of more than 4 ppb when the 2007 Base Case ozone is >124 ppb.
This last metric is designed to compare the regional benefits of
NOX emissions reductions to possible local disbenefits.
[[Page 25957]]
The results for these OTAG metrics follow the discussion of the State-
level results.
i. State-Level Analyses--1-Hour Concentrations. The 1-hour metrics
for States in the Midwest, Southeast, and Northeast are provided in
Tables VII-6, VII-7, and VII-8, respectively. For the Midwest, the
results indicate that the overall extent of 1-hour nonattainment
(Metric 1) is reduced by 74 percent in this region as a result the
emissions reductions provided by the Budget scenario. The results for
Metric 2 indicate that over 50 percent of the ``ppb'' reductions in
ozone are in the 10-15 ppb range or greater, with reductions in the
magnitude of nonattainment at more than 25 ppb in Illinois and Indiana.
In Michigan, nearly all of the reductions were in the range of 10-15
ppb or more. The results for Metric 3 show a large reduction in the
number of 1-hour nonattainment days in four out of the five States
having nonattainment in the 2007 Base Case. Note that although the
number of nonattainment days in Ohio did not decline, the
concentrations on these days were reduced, but not to below 125 ppb. In
terms of exposure to nonattainment (Metric 4), there were large
reductions in exposure for each of the 3 episodes that produced high
concentrations in this region (i.e. 1988, 1991, and 1995). Overall,
exposure to nonattainment was reduced by 77 percent in the Midwest as a
result of the emissions reductions associated with the budget.
States in the Southeast are also predicted to have large benefits
in mitigating the 1-hour nonattainment problem as a result of the
budgets. The overall extent of nonattainment (Metric 1) is predicted to
decline by 44 percent in this region with reductions of approximately
50 percent in Tennessee and Alabama. Large ``ppb'' reductions are also
predicted using Metric 2. The four States with 1-hour nonattainment
problems in the region (Alabama, Georgia, Tennessee, and Virginia) have
reductions of 15 ppb or more. In Alabama, 34 percent of the reductions
exceed 20 ppb and in Georgia, 48 percent of the reductions exceed 20
ppb. The number of nonattainment days is also reduced in the Southeast
(Metric 3), but not to the same degree as in the Midwest. Still, the
number of grid cells with one or more nonattainment days is reduced by
25 percent in Georgia and by 38 percent and 43 percent in Alabama and
Tennessee, respectively. Looking at Metric 4 indicates that the total
exposure to nonattainment across the Southeast was cut in half. For
individual States and specific episodes, the reduction in exposure in
this region ranged from 30 percent to 100 percent.
The emissions reductions in the budget are predicted to produce an
overall 48 percent decline in the extent of nonattainment in the
Northeast (Metric 1). The extent of nonattainment in Maryland and
Pennsylvania was reduced by approximately 50 percent and by more than
70 percent in Delaware, Massachusetts, New Jersey, and Rhode Island.
The ``ppb'' reductions (Metric 2) were greater than 25 ppb in Delaware,
Maryland, Massachusetts, New Jersey, and Pennsylvania. The results for
Metric 2 also indicate that the magnitude of nonattainment is reduced
by 15 ppb or more in seven of the Northeast States (Connecticut,
Delaware, Maryland, Massachusetts, New Jersey, New York, and
Pennsylvania). The total number of grid cells across the region with
more than two nonattainment days declined by 46 percent (Metric 3),
while the number of grid cells with more than five nonattainment days
declined by 75 percent. Also, the exposure to nonattainment (Metric 4)
in the Northeast was reduced in half as a result of the budgets. Except
for Washington, DC, which had relatively low exposure because it covers
a much smaller area than the Northeast States, the total exposure to
nonattainment was reduced in the range from 44 percent in Connecticut
to 89 percent in Maine.
ii. Ozone Problem Area Analyses--1-Hour Concentrations. In
reviewing the metrics for the ozone ``problem areas,'' the analyses are
restricted to the 3 sections of the Northeast Corridor and selected
ozone problem areas: Richmond, Atlanta, Nashville, St. Louis,
Louisville-Cincinnati, Lake Michigan Area, Detroit, Pittsburgh and
Charlotte. The metrics are presented in Table VII-9 for each episode
considered along with a composite for all four episodes.
The results for the three portions of the Northeast Corridor
indicate that there is an overall decline of 40 percent to 67 percent
in the number of grid cells with concentrations exceeding 124 and a
somewhat comparable decrease of 51 percent to 65 percent in exceedences
of 140 ppb. Reductions in these two metrics occur across all four
episodes. The ``weighted sum of differences'' metric provides a way to
quantify the ``ppb'' reductions in ozone with greater ``weight'' given
to the reductions when concentrations are high. The results for this
metric indicate that most of the ``ppb'' reductions in the three
Northeast Corridor areas range from approximately 12 ppb to 18 ppb.
Examining the 1-hour metrics for the other problem areas indicates
that all of the areas were predicted to have large decreases in the
number of grid cells exceeding 124 ppb and 140 ppb. In general, the
reductions in this metric are comparable to what was predicted for the
Northeast Corridor. Specifically, in six areas (Nashville, Louisville-
Cincinnati, Richmond, St Louis, Pittsburgh, and Charlotte), the number
of grid cells >124 ppb decreases by 70 percent or more. Considering the
``weighted sum of differences'' metric, the ``ppb'' reduction in six of
the areas outside the Northeast Corridor (Atlanta, Richmond, Nashville,
Louisville-Cincinnati, Pittsburgh, and Charlotte) were generally close
to, or greater than, 20 ppb.
In addition to evaluating the impact of the budgets in terms of
ozone reductions, the model predictions were also examined to determine
the extent of any increase or ``disbenefit'' in ozone concentrations.
In this regard, EPA compared the number of grid cells exceeding 124 ppb
that had more than a 4 ppb increase versus the number of such grid
cells with more than a 4 ppb decrease. The results indicate that the
extent of reductions in ozone far exceeds any increases. In two of the
three Northeast Corridor areas, as well as in all of the other problem
areas, more than 90 percent of the daily maximum values exceeding 124
ppb were reduced by 4 ppb or more. In terms of ozone ``disbenefits,''
five areas had no increases greater than 4 ppb. In those areas with a
predicted increase, these increases represent a very small fraction of
the total number of exceedences of 124 ppb.
b. Impacts on 8-Hour Ozone Concentrations. The analyses presented
in this Section for the 8-hour ozone concentrations follow the same
format as the previous discussion on 1-hour ozone concentration
metrics. The State-level analysis is presented first followed by the
analysis of the OTAG Metrics. The State-level metrics include Metric 5:
the number of grid cells with average second high 8-hour ozone
concentrations >= 85 ppb and Metric 6: the magnitude and frequency of
the ``ppb'' reductions in average second high 8-hour ozone
concentrations >= 85 ppb. Note that fewer 8-hour metrics are considered
in this analysis because the link to the form of the 8-hour NAAQS
results in a single average second high value in each grid cell. Thus,
metrics involving ``multiple days'' or ``multiple hours'' are not
directly applicable to the 8-hour NAAQS. Like the 1-hour discussion,
for ease of communication of results, the following terminology is used
in referring to these metrics:
[[Page 25958]]
Metric 5: the extent of ``nonattainment'' and
Metric 6: the magnitude and frequency of reductions in
``nonattainment.''
The 8-hour analysis includes the same geographic regions as the 1-
hour analysis.
i. State-Level Analyses--8-Hour Concentrations. The results for the
8-hour metrics are presented for the Midwest, Southeast and Northeast
in Tables VII-10, VII-11, and VII-12, respectively. In the Midwest, the
proposed budgets reduced the overall extent of 8-hour nonattainment
(Metric 5) by 89 percent. Six States (Kentucky, Indiana, Illinois,
Michigan, Ohio, and West Virginia) have reductions of more than 80
percent. The magnitude and frequency of reductions is also large
(Metric 6). Specifically, 97 percent of all of the ``ppb'' reductions
are 5 ppb or greater and 21 percent of the reductions are 15 ppb or
greater. In the Southeast, the overall extent of nonattainment (Metric
5) declines by 78 percent. All of the States in this region (Alabama,
Georgia, North Carolina, South Carolina, Tennessee, and Virginia) show
a decline in this metric of 60 percent or more. In addition, 80 percent
of the ``ppb'' reductions are 10 ppb or greater with reductions of over
20 ppb in North Carolina. The Northeast region has a somewhat lesser
reduction in the extent of 8-hour nonattainment (Metric 5) compared to
the other two regions, with an overall reduction in this metric of 65
percent. Two States (New Jersey and Connecticut) have reductions in the
extent of 8-hour nonattainment of approximately 60 percent while two
other States (Delaware and Pennsylvania), along with Washington, DC
have reductions in this metric of over 90 percent. In terms of the
magnitude of the ``ppb'' reductions in nonattainment (Metric 6),
approximately 97 percent of the reductions are greater than 5 ppb, 62
percent are greater than 10 ppb, and 9 percent are greater than 15 ppb.
Looking at the individual States indicates that four States (Delaware,
Maryland, New Jersey, and Pennsylvania) all have ``ppb'' reductions in
the 15-20 ppb range.
ii. Ozone Problem Area Analyses--8-Hour Concentrations.
To investigate impacts on 8-hour ozone in the OTAG ``problem
areas,'' two of the standard OTAG metrics were analyzed:
the number of grid cells with 8-hour daily maximum ozone >
84 ppb; and
the number of cells with 8-hour daily maximum ozone > 100
ppb.
The results, as provided in Table VII-13, indicate that the extent
of high 8-hour concentrations in the northern and central portions of
Northeast Corridor is generally reduced by 30 percent to 40 percent,
considering all 4 episodes combined. The reductions are somewhat
greater in the southern Corridor at 46 percent to 67 percent. For the
problem areas outside the Corridor, seven of the areas (Atlanta,
Charlotte, Louisville-Cincinnati, Nashville, Pittsburgh, and Richmond)
had reductions of approximately 60 percent or more in the extent of 8-
hour concentrations exceeding 84 ppb and 100 ppb.
2. Summary and Conclusions
In summary, the air quality impacts of the proposed budgets were
modeled for the four OTAG episodes. The result were evaluated by
comparing ozone predictions from the Budget scenario to a 2007 Base
Case reflecting emissions reductions associated with CAA control
programs. A number of 1-hour and 8-hour metrics were used to quantify
the impacts at the State-level. In addition, several of the relevant
metrics from the OTAG Standard Table of Metrics were examined to
evaluate the impacts in ozone ``problem areas'' within the region.
The results of this analysis lead to the following major
conclusions:
(1) The emissions reductions associated with the proposed statewide
budgets are predicted to produce large reductions in both 1-hour and 8-
hour concentrations in areas which currently violate the NAAQS and
which would likely continue to have violations in the future without
the SIP call budget reductions.
(2) Looking at individual ozone ``problem areas'' considered by
OTAG shows similar results, based on the available metrics.
(3) Any ``disbenefits'' due to the NOX reductions
associated with the budgets are expected to be very limited compared to
the extent of the ``benefits'' expected from these budgets.
(4) Even though the budgets are expected to reduce 1-hour and 8-
hour ozone concentrations across all 23 jurisdictions, the analysis
indicates that nonattainment problems requiring additional local
control measures will likely continue in some areas currently violating
the NAAQS (see also Section I.B, Updates with 1994-96 Air Quality
Data).
E. Alternative Approaches
The effect of NOX emissions on air quality in areas
violating air quality standards depends, in part, on the distance
between sources and receptor areas. Sources that are closer to areas
violating air quality standards tend to have larger effects on air
quality than sources that are far away. If there is significant
variation in the contribution of emissions in different subregions
within the 23-jurisdiction area, alternative approaches to calculating
States' budgets other than those based on the application of uniform
control measures will be evaluated. On the other hand, the large number
of nonattainment areas spread out over the region and the several
different weather patterns associated with summertime ozone pollution
episodes should also be considered when evaluating a subregional
approach. The EPA plans to evaluate alternative approaches in
developing the final rule. These will consider alternative uniform
approaches at levels below and above the proposal level as well as
regional approaches that apply different control levels to different
geographic regions.
The EPA solicited comment in the November 7, 1997 NPR on approaches
for establishing State emissions budgets that factor in the
differential effects on air quality in areas violating a standard.
Comments advocating alternative approaches would be most helpful if
they set forth concrete proposals on what analysis should form the
basis of budget calculations. For example, some have suggested an
approach that would attempt to quantify more explicitly the cost
effectiveness of emissions reductions in terms of improvements in
ambient ozone concentrations in areas violating a standard (measured,
for example, as cost per population-weighted changes in parts per
billion peak ozone concentration) taking into account the location of
control measures through subregional modeling. If after review of
alternative approaches (including sub-regional modeling analyses
submitted by the States and other commenters), EPA concludes that a new
approach is appropriate, EPA will issue a SNPR.
BILLING CODE 6560-50-P
[[Page 25959]]
Figure VII-1. Twelve of the Ozone ``Problem Areas'' Selected by
OTAG
[GRAPHIC] [TIFF OMITTED] TP11MY98.000
BILLING CODE 6560-50-C
[[Page 25960]]
Table VII-1.--Base Year (1995/96) Modeling Emissions of NOX
[Tons/day]
----------------------------------------------------------------------------------------------------------------
State EGU Non-EGU Area Highway Total
----------------------------------------------------------------------------------------------------------------
Alabama........................................ 720.16 246.58 351.01 431.09 1748.84
Arkansas....................................... 188.47 58.55 212.98 232.64 692.64
Connecticut.................................... 54.10 36.10 128.47 211.86 430.53
Delaware....................................... 58.64 28.26 45.35 63.44 195.69
District of Columbia........................... 3.97 2.58 18.52 19.96 45.03
Florida........................................ 1004.44 121.73 375.44 793.65 2295.26
Georgia........................................ 634.73 185.30 290.50 655.60 1766.13
Illinois....................................... 862.93 519.40 552.99 724.46 2659.78
Indiana........................................ 1138.63 280.04 380.34 495.91 2294.92
Iowa........................................... 252.19 69.31 179.77 239.78 741.05
Kansas......................................... 277.06 159.31 430.15 193.23 1059.75
Kentucky....................................... 1107.62 103.18 457.30 358.09 2026.19
Louisiana...................................... 346.66 870.30 720.25 300.05 2237.26
Maine.......................................... 9.43 52.03 32.32 118.05 211.83
Maryland....................................... 336.13 90.36 186.20 307.20 919.89
Massachusetts.................................. 111.40 73.86 235.31 290.73 711.30
Michigan....................................... 555.44 353.14 383.65 633.21 1925.44
Minnesota...................................... 215.18 61.45 182.61 360.58 819.82
Mississippi.................................... 194.65 173.26 278.40 270.34 916.65
Missouri....................................... 588.13 74.08 237.45 417.50 1317.16
Nebraska....................................... 96.15 36.86 142.89 116.47 392.37
New Hampshire.................................. 65.36 6.97 43.95 96.20 212.48
New Jersey..................................... 143.02 143.33 265.11 404.10 955.56
New York....................................... 375.07 126.63 494.87 823.37 1819.94
North Carolina................................. 969.62 186.09 238.08 608.02 2001.81
North Dakota................................... 0.00 0.46 26.11 16.53 43.10
Ohio........................................... 1701.82 307.42 478.37 757.73 3245.34
Oklahoma....................................... 337.30 100.69 400.76 316.23 1154.98
Pennsylvania................................... 878.45 531.22 402.97 630.38 2443.02
Rhode Island................................... 21.82 2.21 28.05 53.40 105.48
South Carolina................................. 429.77 169.16 164.21 352.85 1115.99
South Dakota................................... 44.54 0.37 23.65 51.03 119.59
Tennessee...................................... 957.50 371.13 452.50 474.18 2255.31
Texas.......................................... 1172.84 1290.89 760.77 1200.77 4425.27
Vermont........................................ 0.20 1.04 13.32 60.65 75.21
Virginia....................................... 432.34 146.16 357.88 578.05 1514.43
West Virginia.................................. 873.65 282.88 137.26 168.66 1462.45
Wisconsin...................................... 311.71 110.90 224.92 360.40 1007.93
----------------------------------------------------------------
Total...................................... 17471.12 7373.23 10334.68 14186.39 49365.42
----------------------------------------------------------------------------------------------------------------
Table VII-2.--2007 CAA Base Case Modeling Emissions of NOX
[Tons/day]
----------------------------------------------------------------------------------------------------------------
State EGU Non-EGU Area Highway Total
----------------------------------------------------------------------------------------------------------------
Alabama........................................ 619.16 314.95 361.70 416.80 1712.61
Arkansas....................................... 241.34 67.74 278.52 218.21 805.81
Connecticut.................................... 62.85 37.62 120.02 159.47 379.96
Delaware....................................... 85.86 34.82 40.33 60.30 221.31
District of Columbia........................... 3.81 2.03 26.99 20.96 53.79
Florida........................................ 1193.66 143.06 396.06 935.38 2668.16
Georgia........................................ 635.45 224.98 306.47 599.03 1765.93
Illinois....................................... 908.72 442.08 558.24 622.86 2531.9
Indiana........................................ 1164.89 344.53 426.76 491.79 2427.97
Iowa........................................... 318.51 79.17 193.78 242.36 833.82
Kansas......................................... 278.16 200.10 387.65 206.14 1072.05
Kentucky....................................... 958.00 125.90 486.02 338.91 1908.83
Louisiana...................................... 370.72 797.24 764.56 288.99 2221.51
Maine.......................................... 7.31 62.32 39.78 116.31 225.72
Maryland....................................... 289.05 94.67 227.65 271.66 883.03
Massachusetts.................................. 188.69 72.86 239.72 240.22 741.49
Michigan....................................... 511.62 402.98 428.71 622.31 1965.62
Minnesota...................................... 269.07 74.35 188.95 375.95 908.32
Mississippi.................................... 239.02 180.66 406.62 246.82 1073.12
Missouri....................................... 604.78 81.31 224.18 420.19 1330.46
Nebraska....................................... 93.92 41.46 136.45 119.41 391.24
New Hampshire.................................. 118.61 8.03 36.31 86.94 249.89
New Jersey..................................... 154.00 145.28 271.11 381.86 952.25
[[Page 25961]]
New York....................................... 356.59 138.02 391.91 777.35 1663.87
North Carolina................................. 672.59 227.44 250.26 551.56 1701.85
North Dakota................................... 0.00 0.40 37.24 17.47 55.11
Ohio........................................... 1237.97 361.08 494.11 710.83 2803.99
Oklahoma....................................... 365.45 124.90 521.39 316.14 1327.88
Pennsylvania................................... 906.73 558.46 382.86 556.86 2404.91
Rhode Island................................... 10.47 2.34 22.85 51.46 87.12
South Carolina................................. 437.29 235.36 186.94 365.30 1224.89
South Dakota................................... 49.91 0.64 34.31 51.89 136.75
Tennessee...................................... 610.64 461.38 517.64 496.75 2086.41
Texas.......................................... 1271.05 1114.13 825.12 1073.35 4283.65
Vermont........................................ 0.20 1.04 13.76 63.05 78.05
Virginia....................................... 415.27 168.41 411.85 603.89 1599.42
West Virginia.................................. 571.47 283.37 115.44 158.49 1128.77
Wisconsin...................................... 325.87 141.67 225.54 315.35 1008.43
----------------------------------------------------------------
Total...................................... 16548.70 7796.78 10977.80 13592.61 48915.89
----------------------------------------------------------------------------------------------------------------
Table VII-3.--2007 Budget Modeling Emissions of NOX
[Tons/day]
----------------------------------------------------------------------------------------------------------------
State EGU Non-EGU Area Highway Total
----------------------------------------------------------------------------------------------------------------
Alabama........................................ 224.26 159.58 335.69 386.24 1105.77
Arkansas....................................... 241.34 67.74 262.83 202.88 774.79
Connecticut.................................... 47.31 22.25 101.66 118.71 289.93
Delaware....................................... 40.59 15.18 36.83 57.67 150.27
District of Columbia........................... 2.45 1.69 26.75 15.46 46.35
Florida........................................ 1193.66 143.06 351.44 875.17 2563.33
Georgia........................................ 246.29 96.16 267.79 529.59 1139.83
Illinois....................................... 278.01 278.58 477.65 529.99 1564.23
Indiana........................................ 377.70 195.89 398.19 454.61 1426.39
Iowa........................................... 318.51 79.17 176.64 227.15 801.47
Kansas......................................... 278.16 200.10 373.76 194.01 1046.03
Kentucky....................................... 283.92 79.77 462.46 315.42 1141.57
Louisiana...................................... 370.72 797.24 717.26 274.46 2159.68
Maine.......................................... 7.31 62.32 37.87 109.26 216.76
Maryland....................................... 103.61 51.86 196.22 195.28 546.97
Massachusetts.................................. 112.86 43.88 208.53 157.66 522.93
Michigan....................................... 203.44 235.01 388.17 555.53 1382.15
Minnesota...................................... 269.07 74.35 166.35 353.51 863.28
Mississippi.................................... 239.02 180.66 370.67 229.32 1019.67
Missouri....................................... 196.28 60.26 194.63 375.51 826.68
Nebraska....................................... 93.92 41.46 127.59 112.49 375.46
New Hampshire.................................. 118.61 8.03 34.64 86.94 248.22
New Jersey..................................... 83.04 83.57 241.65 268.82 677.08
New York....................................... 266.18 96.55 340.98 642.00 1345.71
North Carolina................................. 252.33 127.56 214.94 498.25 1093.08
North Dakota................................... 0.00 0.40 36.37 16.33 53.1
Ohio........................................... 381.07 207.70 458.48 631.24 1678.49
Oklahoma....................................... 365.45 124.90 503.59 294.70 1288.64
Pennsylvania................................... 357.05 314.54 343.61 499.34 1514.54
Rhode Island................................... 10.81 2.34 18.98 38.89 71.02
South Carolina................................. 151.97 127.09 164.62 337.58 781.26
South Dakota................................... 49.91 0.64 31.29 48.65 130.49
Tennessee...................................... 191.00 240.31 451.78 461.03 1344.12
Texas.......................................... 1271.05 1114.13 712.99 974.78 4072.95
Vermont........................................ 0.20 1.04 12.50 59.13 72.87
Virginia....................................... 176.69 73.05 379.47 544.69 1173.9
West Virginia.................................. 179.92 141.03 107.50 147.62 576.07
Wisconsin...................................... 124.49 77.21 192.28 284.20 678.18
----------------------------------------------------------------
Total...................................... 9108.20 5626.30 9924.65 12104.11 36763.26
----------------------------------------------------------------------------------------------------------------
[[Page 25962]]
Table VII-4.--Percent Reduction Between 2007 CAA Base Case and Budget
N0X Emissions for Modeling
[Tons/day]
------------------------------------------------------------------------
2007 Base Percent
State case Budget reduction
------------------------------------------------------------------------
Alabama.......................... 1712.61 1105.77 35.4
Arkansas......................... 805.81 774.79 3.9
Connecticut...................... 379.96 289.93 23.7
Delaware......................... 221.31 150.27 32.1
District of Columbia............. 53.79 46.35 13.8
Florida.......................... 2668.16 2563.33 3.9
Georgia.......................... 1765.93 1139.83 35.5
Illinois......................... 2531.9 1564.23 38.2
Indiana.......................... 2427.97 1426.39 41.3
Iowa............................. 833.82 801.47 3.9
Kansas........................... 1072.05 1046.03 2.4
Kentucky......................... 1908.83 1141.57 40.2
Louisiana........................ 2221.51 2159.68 2.8
Maine............................ 225.72 216.76 4.0
Maryland......................... 883.03 546.97 38.1
Massachusetts.................... 741.49 522.93 29.5
Michigan......................... 1965.62 1382.15 29.7
Minnesota........................ 908.32 863.28 5.0
Mississippi...................... 1073.12 1019.67 5.0
Missouri......................... 1330.46 826.68 37.9
Nebraska......................... 391.24 375.46 4.0
New Hampshire.................... 249.89 248.22 0.7
New Jersey....................... 952.25 677.08 28.9
New York......................... 1663.87 1345.71 19.1
North Carolina................... 1701.85 1093.08 35.8
North Dakota..................... 55.11 53.1 3.6
Ohio............................. 2803.99 1678.49 40.1
Oklahoma......................... 1327.88 1288.64 3.0
Pennsylvania..................... 2404.91 1514.54 37.0
Rhode Island..................... 87.12 71.02 18.5
South Carolina................... 1224.89 781.26 36.2
South Dakota..................... 136.75 130.49 4.6
Tennessee........................ 2086.41 1344.12 35.6
Texas............................ 4283.65 4072.95 4.9
Vermont.......................... 78.05 72.87 6.6
Virginia......................... 1599.42 1173.9 26.6
West Virginia.................... 1128.77 576.07 49.0
Wisconsin........................ 1008.43 678.18 32.7
--------------------------------------
Total........................ 48915.89 36763.26 24.8
------------------------------------------------------------------------
Table VII-5.--List of States in Each Analysis Region
------------------------------------------------------------------------
------------------------------------------------------------------------
Midwest................................... Illinois, Indiana, Kentucky,
Michigan, Missouri, Ohio,
West Virginia, Wisconsin.
Southeast................................. Alabama, Georgia, North
Carolina, South Carolina,
Tennessee, Virginia.
Northeast................................. Connecticut, Delaware,
District of Columbia,
Maryland, Massachusetts,
New Jersey, New York,
Pennsylvania, Rhode Island.
Non-SIP Call States....................... Arkansas, Florida, Iowa,
Kansas, Louisiana, Maine,
Minnesota, Mississippi,
Nebraska, New Hampshire,
North Dakota, Oklahoma,
South Dakota, Texas,
Vermont.
------------------------------------------------------------------------
Table VII-6.--1-Hr Air Quality Metrics for Midwest Region (Grid Cells Selected Based on ``Monitored'' and ``Modeled'' Nonattainment)
[Modeled values include Daily Max 1-hr for all 4 Episodes]
--------------------------------------------------------------------------------------------------------------------------------------------------------
MO WI IL IN MI OH KY WV Total
--------------------------------------------------------------------------------------------------------------------------------------------------------
Metric 1: Number of Grid Cell-Days with a Daily Max Ozone Value>=125 ppb
--------------------------------------------------------------------------------------------------------------------------------------------------------
2007 Base............................................ 4 0 10 3 23 3 0 0 43
2007 Budget.......................................... 2 0 2 0 4 3 0 0 11
--------------------------------------------------------------------------------------------------
Difference..................................... -2 0 -8 -3 -19 0 0 0 -32
Percent........................................ -50.00 0.00 -80.00 -100.00 -82.61 0.00 0.00 0.00 -74.42
--------------------------------------------------------------------------------------------------------------------------------------------------------
Metric 2: Number of Grid Cell-Days with Ozone Reductions, by Magnitude of the Reduction
--------------------------------------------------------------------------------------------------------------------------------------------------------
Magnitude of ozone reduction
2-5 ppb.............................................. 0 0 0 0 0 0 0 0 0
5-10 ppb............................................. 1 0 1 1 1 1 0 0 5
10-15 ppb............................................ 2 0 3 0 15 1 0 0 21
15-20 ppb............................................ 0 0 3 0 7 1 0 0 11
20-25 ppb............................................ 0 0 0 0 0 0 0 0 0
>25 ppb.............................................. 0 0 2 2 0 0 0 0 4
--------------------------------------------------------------------------------------------------------------------------------------------------------
[[Page 25963]]
Metric 3: Number of Grid Cells>=125 ppb, by Number of Days
--------------------------------------------------------------------------------------------------------------------------------------------------------
Baseline 2007 MO WI IL IN MI OH KY WV Total
Number of Days >=125 ppb:
=1 day........................................... 2 0 6 5 0 3 3 0 19
2-4 days......................................... 1 0 2 9 0 0 0 0 12
5-9 days......................................... 0 0 0 0 0 0 0 0 0
10-14 days....................................... 0 0 0 0 0 0 0 0 0
>=15 days........................................ 0 0 0 0 0 0 0 0 0
--------------------------------------------------------------------------------------------------
Total.......................................... 3 0 8 14 0 3 3 0 31
==================================================================================================
NOX SIP Call:
=1 day........................................... 0 0 2 4 0 0 3 0 9
2-4 days......................................... 1 0 0 0 0 0 0 0 1
5-9 days......................................... 0 0 0 0 0 0 0 0 0
10-14 days....................................... 0 0 0 0 0 0 0 0 0
>=15 days........................................ 0 0 0 0 0 0 0 0 0
--------------------------------------------------------------------------------------------------
Total.......................................... 1 0 2 4 0 0 3 0 10
==================================================================================================
Difference (days).............................. -2 0 -6 -10 0 -3 0 0 -21
Percent........................................ -66.7 0.0 -75.0 -71.4 0.0 -100.0 0.0 0.0 -67.7
--------------------------------------------------------------------------------------------------------------------------------------------------------
Metric 4: Percent Reduction in Areal Exposures to ozone >=125 ppb
--------------------------------------------------------------------------------------------------------------------------------------------------------
July '88 July '91 July '93 July '95 All
episodes
MO................................................... 58.3 49.5 * * 40.4
WI................................................... * * * * *
IL................................................... 84.8 49.9 * 100.0 75.0
MI................................................... * * * 88.6 88.6
KY................................................... * * * * *
IN................................................... * * * 100.0 100.0
OH................................................... * * * * *
WV................................................... * * * * *
-------------------------------------------------------
Total.......................................... 73.7 51.3 * 90.2 76.6
--------------------------------------------------------------------------------------------------------------------------------------------------------
*No areas >=125 ppb
Table VII-7.--1-Hr Air Quality Metrics for Southeast Region (Grid cells selected based on ``monitored'' and
``modeled'' nonattainment)
[Modeled values include Daily Max 1-hr for all 4 Episodes]
----------------------------------------------------------------------------------------------------------------
TN AL GA SC NC VA Total
----------------------------------------------------------------------------------------------------------------
Metric 1: Number of Grid Cell-Days with a Daily Max Ozone Value >+ 125 ppb
----------------------------------------------------------------------------------------------------------------
2007 Base.......................... 27 108 203 0 0 14 352
2007 Budget........................ 13 53 117 0 0 13 196
----------------------------------------------------------------------------
Difference................... -14 -55 -86 0 0 -1 -156
Percent...................... -51.85 -50.93 -42.36 0.00 0.00 -7.14 -44.32
----------------------------------------------------------------------------------------------------------------
Metric 2: Number of Grid Cell-Days with Ozone Reductions, by Magnitude of the Reduction
----------------------------------------------------------------------------------------------------------------
Magnitude of ozone reduction
2-5 ppb............................ 4 1 2 0 0 1 8
5-10 ppb........................... 11 20 9 0 0 6 46
10-15 ppb.......................... 7 27 31 0 0 4 69
15-20 ppb.......................... 3 23 64 0 0 1 91
20-25 ppb.......................... 0 16 53 0 0 0 69
>25 ppb............................ 0 21 44 0 0 0 65
----------------------------------------------------------------------------------------------------------------
Metric 3: Number of Grid Cells >= 125 ppb, by Number of Days
----------------------------------------------------------------------------------------------------------------
Baseline 2007 TN AL GA NC VA SC Total
Number of Days >= 125 ppb
= 1 day........................ 7 9 5 0 0 0 21
2-4 days....................... 6 14 15 0 1 0 36
5-9 days....................... 1 8 17 0 2 0 28
10-14 days..................... 0 1 3 0 0 0 4
>= 15 days..................... 0 0 0 0 0 0 0
----------------------------------------------------------------------------
Total........................ 14 32 40 0 3 0 89
============================================================================
NOx SIP Call:
= 1 day........................ 6 6 8 0 0 0 20
2-4 days....................... 2 11 10 0 1 0 24
5-9 days....................... 0 3 11 0 2 0 16
10-14 days..................... 0 0 1 0 0 0 1
>=15 days...................... 0 0 0 0 0 0 0
----------------------------------------------------------------------------
Total........................ 8 20 30 0 3 0 61
============================================================================
Difference (days)............ -6 -12 -10 0 0 0 -28
Percent...................... -42.9% -37.5% -25.0% 0.0% 0.0% 0.0% -31.5%
----------------------------------------------------------------------------------------------------------------
Metric 4: Percent Reduction in Areal Exposures to Ozone >= 125 ppb
----------------------------------------------------------------------------------------------------------------
July '88 July '91 July '93 July '95 All
Episodes
TN................................. 100.0 29.5 72.0 52.4 60.2
AL................................. 71.7 100.0 57.7 63.0 60.0
[[Page 25964]]
GA................................. 59.4 100.0 46.9 55.6 51.0
NC................................. * * * * * ......... .........
VA................................. 18.7% * * 58.2% 24.1% ......... .........
SC................................. * * * * * ......... .........
-------------------------------------------------------
Total........................ 50.1 89.7 51.0 57.5 53.0 ......... .........
----------------------------------------------------------------------------------------------------------------
*No areas >= 125 ppb.
Table VII-8.--1-Hr Air Quality Metrics for Northeast Region (Grid cells selected based on ``monitored'' and ``modeled'' nonattainment)
[Modeled values include Daily Max 1-hr for all 4 Episodes]
--------------------------------------------------------------------------------------------------------------------------------------------------------
MD DC DE PA NJ NY CT RI MA Total
--------------------------------------------------------------------------------------------------------------------------------------------------------
Metric 1: Number of Grid Cell-Days with a Daily Max Ozone Value >= 125 ppb
--------------------------------------------------------------------------------------------------------------------------------------------------------
2007 Base................................. 251 3 12 34 183 221 231 8 61 738
2007 Budget............................... 111 3 3 17 54 154 141 2 13 381
-------------------------------------------------------------------------------------------------------------
Difference.......................... -140 0 -9 -17 -129 -67 -90 -6 -48 -357
Percent............................. -55.78 0.00 -75.00 -50.00 -70.49 -30.32 -38.96 -75 -78.69 -48.37
--------------------------------------------------------------------------------------------------------------------------------------------------------
Metric 2: Number of Grid Cell-Days with Ozone Reductions, by Magnitude of the Reduction
--------------------------------------------------------------------------------------------------------------------------------------------------------
Magnitude of ozone reduction
2-5 ppb................................... 7 0 0 3 5 26 16 0 3 60
5-10 ppb.................................. 27 1 0 7 12 63 58 2 7 177
10-15 ppb................................. 43 0 0 14 41 89 115 6 27 335
15-20 ppb................................. 91 0 1 6 90 24 25 0 15 252
20-25 ppb................................. 40 0 6 2 19 1 0 0 2 70
>25 ppb................................... 32 0 5 1 12 0 0 0 7 57
--------------------------------------------------------------------------------------------------------------------------------------------------------
Metric 3: Number of grid Cells >= 125 ppb, by Number of Days
--------------------------------------------------------------------------------------------------------------------------------------------------------
Baseline 2007 PA NY MD DC DE NJ CT MA RI Total
Number of Days >= 125 ppb:
=1 days............................... 16 0 5 0 6 22 2 17 4 72
2-4 days.............................. 7 15 26 1 3 35 41 13 2 143
5-9 days.............................. 0 28 25 0 0 9 17 3 0 82
10-14 days............................ 0 0 1 0 0 0 0 0 0 1
>=15 days............................. 0 0 0 0 0 0 0 0 0 0
-------------------------------------------------------------------------------------------------------------
Total............................... 23 43 57 1 9 66 60 33 6 298
=============================================================================================================
NOX SIP Call:
=1 days............................... 15 6 12 0 3 24 18 13 2 93
2-4 days.............................. 1 27 23 1 0 12 37 0 0 101
5-9 days.............................. 0 11 7 0 0 0 3 0 0 21
10-14 days............................ 0 0 0 0 0 0 0 0 0 0
>=15 days............................. 0 0 0 0 0 0 0 0 0 0
-------------------------------------------------------------------------------------------------------------
Total............................... 16 44 42 1 3 36 58 13 2 215
=============================================================================================================
Difference (days)................... -7 1 -15 0 -6 -30 -2 -20 -4 -83
Percent............................. -30.4 2.3 -26.3 0.0 -66.7 -45.5 -3.3 -60.6 -66.7 -27.9
--------------------------------------------------------------------------------------------------------------------------------------------------------
Metric 4: Percent Reduction in Areal Exposures to Ozone >= 125 ppb
--------------------------------------------------------------------------------------------------------------------------------------------------------
July '88 July '91 July '93 July '95 All
episodes
PA........................................ 63.7 100.00 * 100.0 67.3
NY........................................ 40.2 55.33 * 43.5 47.2
MD........................................ 51.8 86.79 49.0 78.6 59.8
DC........................................ 8.9 * * * 8.9
DE........................................ 82.0 * * 100.0 84.5
NJ........................................ 74.5 95.81 100.0 100.0 81.2
CT........................................ 31.6 68.51 100.0 61.1 43.9
MA........................................ 82.2 95.78 * 85.2 86.7
ME........................................ 92.3 82.80 * * 89.3
-------------------------------------------------------
Total............................... 52.4 71.08 51.0 67.9 59.1
--------------------------------------------------------------------------------------------------------------------------------------------------------
*No areas >= 125 ppb
Table VII-9.--Selected OTAG Metrics for 1-Hr Standard
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
No. Cn So. Louis- Lk. MI
corridor corridor corridor Richmond Atlanta Nashville Cinci St. Louis area Detroit Pittsburgh Charlotte
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Peak 1-Hr Total--# of Grid Cells >124 ppb
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
July 4-11, 1988:
2007 Base Case......................................... 337 484 522 148 38 56 71 10 46 54 27 157
2007 Budget............................................ 147 314 214 27 19 14 22 4 0 34 1 19
------------------------------------------------------------------------------------------------------------------------------------
Difference........................................... -190 -170 -308 -121 -19 -42 -49 -6 -46 -20 -26 -138
Percent.............................................. -56.4% -35.1% -59.90% -81.8% -50.0% -75.0% -69.0% -60.0% -100.0% -37.0% -96.3% -87.9%
====================================================================================================================================
July 16-21, 1991:
2007 Base Case......................................... 497 282 111 1 10 0 19 5 113 0 0 0
2007 Budget............................................ 160 141 19 0 0 0 10 2 58 0 0 0
------------------------------------------------------------------------------------------------------------------------------------
Difference........................................... -337 -141 -92 -1 -10 0 -9 -3 -55 0 0 0
Percent.............................................. -67.8% -50.0% -82.9% -100.0% -100.0% 0.0% -47.4% -60.0% -48.7% 0.0% 0.0% 0.0%
====================================================================================================================================
[[Page 25965]]
July 22-29, 1993:
2007 Base Case......................................... 1 5 105 38 178 39 4 1 0 0 0 123
2007 Budget............................................ 0 3 28 11 84 7 0 0 0 0 0 23
------------------------------------------------------------------------------------------------------------------------------------
Difference........................................... -1 -2 -77 -27 -94 -32 -4 -1 0 0 0 -100
Percent.............................................. -100.0% -40.0% -73.3% -71.1% -52.8% -82.1% -100.0% -100.0% 0.0% 0.0% 0.0% -81.3%
====================================================================================================================================
July 10-18, 1995:
2007 Base Case......................................... 217 127 165 49 149 35 43 6 343 4 1 20
2007 Budget............................................ 137 74 37 19 47 6 9 0 233 1 0 3
------------------------------------------------------------------------------------------------------------------------------------
Difference........................................... -80 -53 -128 -30 -102 -29 -34 -6 -110 -3 -1 -17
Percent................................................ -36.9% -41.7% -77.6% -61.2% -68.5% -82.9% -79.1% -100.0% -32.1% -75.0% -100.0% -85.0%
====================================================================================================================================
2007 Base Case......................................... 217 127 165 49 149 35 43 6 343 4 1 20
2007 Budget............................................ 137 74 37 19 47 6 9 00 233 1 0 3
------------------------------------------------------------------------------------------------------------------------------------
Difference........................................... -80 -53 -128 -30 -102 -29 -34 -6 -110 -3 -1 -17
Percent.............................................. -36.9% -41.7% -77.6% -61.2% -68.5% -82.9% -79.1% -100.0% -32.1% -75.0% -100.0% -85.0%
====================================================================================================================================
All Episodes:
2007 Base Case......................................... 1052 898 903 236 375 130 137 22 502 58 28 300
2007 Budget............................................ 444 532 298 57 150 27 41 6 291 35 1 45
------------------------------------------------------------------------------------------------------------------------------------
Difference........................................... -608 -366 -605 -179 -225 -103 -96 -16 -211 -23 -27 -255
Percent.............................................. -57.8% -40.8% -67.0% -75.8% -60.0% -79.2% -70.1% -72.7% -42.0% -39.7% -96.4% -85.0%
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Peak 1-Hr Total--# \ 140
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
July 4-11, 1988:
2007 Base Case......................................... 122 219 229 35 20 21 5 2 0 16 1 34
2007 Budget............................................ 52 139 95 4 6 9 0 0 0 2 0 4
------------------------------------------------------------------------------------------------------------------------------------
Difference........................................... -70 -80 -134 -31 -14 -12 -5 -2 0 -14 -1 -30
Percent.............................................. -57.4% -36.5% -58.5% -88.6% -70.0% -57.1% -100.0% -100.0% 0.0% -87.5% -100.0% -88.2%
====================================================================================================================================
July 16-21, 1991:
2007 Base Case......................................... 149 114 11 0 4 0 5 0 28 0 0 0
2007 Budget............................................ 29 20 4 0 0 0 4 0 0 0 0 0
------------------------------------------------------------------------------------------------------------------------------------
Difference........................................... -120 -94 -7 0 -4 0 -1 0 -28 0 0 0
Percent.............................................. -80.5% -82.5% -63.6% 0.0% -100.0% 0.0% -20.0% 0.0% -100.0% 0.0% 0.0% 0.0%
====================================================================================================================================
July 22-29, 1993:
2007 Base Case......................................... 0 0 21 14 99 8 0 0 0 0 0 38
2007 Budget............................................ 0 0 4 0 38 1 0 0 0 0 0 5
------------------------------------------------------------------------------------------------------------------------------------
Difference........................................... 0 0 -17 -14 -61 -7 0 0 0 0 0 -33
Percent.............................................. 0.0% 0.0% -81.0% -100.0% -61.6% -87.5% 0.0% 0.0% 0.0% 0.0% 0.0% -86.8%
====================================================================================================================================
July 10-18, 1995:
2007 Base Case......................................... 142 59 35 22 49 3 14 0 191 0 0 4
2007 Budget............................................ 63 32 3 4 20 0 1 0 96 0 0 0
------------------------------------------------------------------------------------------------------------------------------------
Difference........................................... -79 -27 -32 -18 -29 -3 -13 0 -95 0 0 -4
Percent.............................................. -55.6% -45.8% -91.4% -81.8% -59.2% -100.0% -92.9% 0.0% -49.7% 0.0% 0.0% -100.0%
====================================================================================================================================
All Episodes:
2007 Base Case......................................... 413 392 296 71 172 32 24 2 219 16 1 76
2007 Budget............................................ 144 191 106 8 64 10 5 0 96 2 0 9
------------------------------------------------------------------------------------------------------------------------------------
Difference........................................... -269 -201 -190 -63 -108 -22 -19 -2 -123 -14 -1 -67
Percent.............................................. -65.1% -51.3% -64.2% -88.7% -62.8% -68.8% -79.2% -100.0% -56.2% -87.5% -100.0% -88.2%
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Weighted Sum of Differences When the Base is > 124 ppb
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
July 4-11, 1988............................................ -13.8 -9.6 -18.5 -22.3 -18.3 -23.9 -17.4 -18.5 -13.8 -10 -24.5 -25.1
July 16-21, 1991........................................... -15.1 -13.7 -16.9 -10.4 -29 0 -13.3 -6.1 -10.9 0 0 0
July 22-29, 1993........................................... -5.7 -4.6 -15.8 -20 -21.3 -21.7 -26.2 -10.9 0 0 0 -22.6
July 10-18, 1995........................................... -15.8 -11.5 -16.8 -19 -21.5 -22.1 -27.4 -16 -12.6 -8.5 -40.8 -23.7
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
# Grid Cells with more than a 4 ppb Decrease when Base is > 124 ppb
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
July 4-11, 1988............................................ 330 386 496 144 38 55 67 10 46 51 27 156
Percent of Total........................................... 97.9% 79.8% 95.0% 97.3% 100.0% 98.2% 94.4% 100.0% 100.0% 94.4% 100.0% 99.4%
July 16-21, 1991........................................... 496 276 104 1 10 0 16 3 104 0 0 0
Percent of Total........................................... 99.8% 97.9% 93.7% 100.0% 100.0% 0.0% 84.2% 60.0% 92.0% 0.0% 0.0% 0.0%
July 22-29, 1993........................................... 1 3 102 38 178 37 4 1 0 0 0 123
Percent of Total........................................... 100.0% 60.0% 97.1% 100.0% 100.0% 94.9% 100.0% 100.0% 0.0% 0.0% 0.0% 100.0%
July 10-18, 1995........................................... 217 111 161 48 149 35 43 6 326 4 1 20
Percent of Total........................................... 100.0% 87.4% 97.6% 98.0% 100.0% 100.0% 100.0% 100.0% 95.0% 100.0% 100.0% 100.0%
All Episodes............................................... 1044 776 863 231 375 127 130 20 476 55 28 299
Percent of Total........................................... 99.2% 86.4% 95.6% 97.9% 100.0% 97.7% 94.9% 90.9% 94.8% 94.8% 100.0% 99.7%
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
# Grid Cells with more than a 4 ppb Increase when Base is > 124 ppb
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
July 4-11, 1988............................................ 2 32 7 2 0 0 1 0 0 1 0 0
Percent of Total........................................... 0.6% 6.6% 1.3% 1.4% 0.0% 0.0% 1.4% 0.0% 0.0% 1.9% 0.0% 0.0%
July 16-21, 1991........................................... 0 0 2 0 0 0 2 0 2 0 0 0
Percent of Total........................................... 0.0% 0.0% 1.8% 0.0% 0.0% 0.0% 10.5% 0.0% 1.8% 0.0% 0.0% 0.0%
July 22-29, 1993........................................... 0 1 3 0 0 0 0 0 0 0 0 0
Percent of Total........................................... 0.0% 20.0% 2.9% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0%
July 10-18, 1995........................................... 0 0 1 0 0 0 0 0 0 0 0 0
Percent of Total........................................... 0.0% 0.0% 0.6% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0%
[[Page 25966]]
All Episodes............................................... 2% 33% 13% 2% 0% 0% 3% 0% 2% 1% 0% 0%
Percent of Total........................................... 0.2% 3.7% 1.4% 0.8% 0.0% 0.0% 2.2% 0.0% 0.4% 1.7% 0.0% 0.0%
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Table VII-10.--8-Hr Air Quality Metrics for Midwest Region (Grid Cells Selected Based on ``Monitored'' and ``Modeled'' Nonattainment)
--------------------------------------------------------------------------------------------------------------------------------------------------------
MO WI IL IN MI OH KY WV Total
--------------------------------------------------------------------------------------------------------------------------------------------------------
Metric 5: Number of Grid Cell-Days with an Average 2nd High Ozone Value >=85 ppb
--------------------------------------------------------------------------------------------------------------------------------------------------------
Scenario
2007 Base............................................ 2 0 7 31 21 39 43 7 150
2007 Budget.......................................... 2 0 1 3 1 2 7 0 16
--------------------------------------------------------------------------------------------------
Difference..................................... 0 0 -6 -28 -20 -37 -36 -7 -134
Percent........................................ 0.00 0.00 -85.71 -90.32 -95.24 -94.87 -83.72 -100.00 -89.33
--------------------------------------------------------------------------------------------------------------------------------------------------------
Metric 6: Number of Grid Cell-Days with Ozone Reductions, by Magnitude of the Reduction
--------------------------------------------------------------------------------------------------------------------------------------------------------
Magnitude of Ozone Reduction
2-5 ppb.............................................. 1 0 0 1 1 0 2 0 5
5-10 ppb............................................. 1 0 5 2 12 16 6 0 42
10-15 ppb............................................ 0 0 2 16 8 21 19 6 72
15-20 ppb............................................ 0 0 0 9 0 2 12 1 24
20-25 ppb............................................ 0 0 0 3 0 0 4 0 7
>25 ppb.............................................. 0 0 0 0 0 0 0 0 0
--------------------------------------------------------------------------------------------------------------------------------------------------------
Table VII-11.--8-Hr Air Quality Metrics for Southeast Region (Grid Cells Selected Based on ``Monitored'' and
``Modeled'' Nonattainment)
----------------------------------------------------------------------------------------------------------------
TN AL GA SC NC VA Total
----------------------------------------------------------------------------------------------------------------
Metric 5: Number of Grid Cell-Days with an Average 2nd High Ozone Value=85ppb
----------------------------------------------------------------------------------------------------------------
Scenario
2007 Base.......................... 48 39 44 13 52 16 212
2007 Budget........................ 10 12 17 1 4 3 47
----------------------------------------------------------------------------
Difference................... -38 -27 -27 -12 -48 -13 -165
Percent...................... -79.17 -69.23 -61.36 -92.31 -92.31 -81.25 -77.83
----------------------------------------------------------------------------------------------------------------
Metric 6: Number of Grid Cell-Days with Ozone Reductions, by Magnitude of the Reduction
----------------------------------------------------------------------------------------------------------------
Magnitude of Ozone Reduction
2-5 ppb............................ 5 0 0 0 0 0 5
5-10 ppb........................... 23 3 4 5 2 1 38
10-15 ppb.......................... 17 28 32 6 42 13 138
15-20 ppb.......................... 2 8 8 2 5 2 27
20-25 ppb.......................... 0 0 0 0 3 0 3
>25 ppb............................ 0 0 0 0 0 0 0
----------------------------------------------------------------------------------------------------------------
Table VII-12.--8-Hr Air Quality Metrics for Northeast Region (Grid Cells Selected Based on ``Monitored'' and ``Modeled'' Nonattainment)
--------------------------------------------------------------------------------------------------------------------------------------------------------
MD DC DE PA NJ NY CT RI MA Total
--------------------------------------------------------------------------------------------------------------------------------------------------------
Metric 5: Number of Grid Cell-Days with an Average 2nd High Ozone Value>=85 ppb
--------------------------------------------------------------------------------------------------------------------------------------------------------
Scenario
2007 Base................................. 84 1 30 73 99 45 29 0 11 257
2007 Budget............................... 40 0 1 4 37 33 11 0 6 91
-------------------------------------------------------------------------------------------------------------
Difference.......................... -44 -1 -29 -69 -62 -12 -18 0 -5 -166
Percent............................. -52.38 -100.00 -96.67 -94.52 -62.63 -26.67 -62.07 0.00 -45.45 -65
--------------------------------------------------------------------------------------------------------------------------------------------------------
Metric 6: Number of Grid Cell-Days with Ozone Reductions, by Magnitude of the Reduction
--------------------------------------------------------------------------------------------------------------------------------------------------------
Magnitude of Ozone Reduction
2-5 ppb................................... 1 0 0 1 1 6 1 0 1 11
5-10 ppb.................................. 18 1 3 19 17 34 28 0 9 129
10-15 ppb................................. 57 0 13 46 75 0 0 0 1 192
15-20 ppb................................. 7 0 14 7 6 0 0 0 0 34
20-25..................................... 0 0 0 0 0 0 0 0 0 0
>25 ppb................................... 0 0 0 0 0 0 0 0 0 0
--------------------------------------------------------------------------------------------------------------------------------------------------------
Table VII-13.--Selected OTAG Metrics for 8-Hr Standard
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
No. Cn. So. Louis- Lk. MI
corridor corridor corridor Richmond Atlanta Nashville Cinci St. Louis Area Detroit Pittsburgh Charlotte
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Peak 8-Hr Total--# of Grids > 84 ppb
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
July 4-11, 1988:
2007 Base Case......................................... 1624 1959 1696 580 154 485 1653 196 853 478 850 1195
2007 Budget............................................ 1132 1256 1115 313 68 139 447 32 435 253 197 450
------------------------------------------------------------------------------------------------------------------------------------
Difference........................................... -492 -703 -581 -267 -86 -346 -1206 -164 -418 -225 -653 -745
Percent.............................................. -30.3% -35.9% -34.3% -46.0% -55.8% -71.3% -73.0% -83.7% -49.0% -47.1% -76.8% -62.3%
====================================================================================================================================
[[Page 25967]]
July 16-21, 1991:
2007 Base Case......................................... 1333 1034 1058 112 56 93 875 129 615 172 605 71
2007 Budget............................................ 1019 573 552 12 21 10 198 37 512 51 81 0
------------------------------------------------------------------------------------------------------------------------------------
Difference........................................... -314 -461 -506 -100 -35 -83 -677 -92 -103 -121 -524 -71
Percent.............................................. -23.6% -44.6% -47.8% -89.3% -62.5% -89.2% -77.4% -71.3% -16.7% -70.3% -86.6% -100.0%
====================================================================================================================================
July 22-29, 1993:
2007 Base Case......................................... 161 204 610 206 855 395 545 56 79 23 59 1562
2007 Budget............................................ 88 134 315 92 374 125 78 17 24 2 0 387
------------------------------------------------------------------------------------------------------------------------------------
Difference........................................... -73 -70 -295 -114 -481 -270 -467 -39 -55 -21 -59 -1175
Percent.............................................. -45.3% -34.3% -48.4% -55.3% -56.3% -68.4% -85.7% -69.6% -69.6% -91.3% -100.0% -75.2%
====================================================================================================================================
July 10-18, 1995:
2007 Base Case......................................... 653 714 1489 527 693 708 1072 124 994 311 468 754
2007 Budget............................................ 437 321 642 142 260 160 215 52 712 150 20 96
------------------------------------------------------------------------------------------------------------------------------------
Difference........................................... -216 -393 -847 -385 -433 -548 -857 -72 -282 -161 -448 -658
Percent.............................................. -33.1% -55.0% -56.9% -73.1% -62.5% -77.4% -79.9% -58.1% -28.4% -51.8% -95.7% -87.3%
====================================================================================================================================
All Episodes:
2007 Base Case......................................... 3771 3911 4853 1425 1758 1681 4145 505 2541 984 1982 3582
2007 Budget............................................ 2676 2284 2624 559 723 434 938 138 1683 456 298 933
------------------------------------------------------------------------------------------------------------------------------------
Difference........................................... -1095 -1627 -2229 -866 -1035 -1247 -3207 -367 -858 -528 -1684 -2649
Percent.............................................. -29.0% -41.6% -45.9% -60.8% -58.9% -74.2% -77.4% -72.7% -33.8% -53.7% -85.0% -74.0%
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Peak 8-Hr Total--Grid Cells > 100 ppb
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
July 4-11, 1988:
2007 Base Case......................................... 817 862 975 302 64 149 383 25 320 139 215 458
2007 Budget............................................ 418 555 413 96 26 32 50 6 92 74 13 75
------------------------------------------------------------------------------------------------------------------------------------
Difference........................................... -399 -307 -562 -206 -38 -117 -333 -19 -228 -65 -202 -383
Percent.............................................. -48.8% -35.6% -57.6% -68.2% -59.4% -78.5% -86.9% -76.0% -71.3% -46.8% -94.0% -83.6%
====================================================================================================================================
July 16-21, 1991:
2007 Base Case......................................... 868 501 448 13 21 1 190 22 302 18 62 0
2007 Budget............................................ 511 305 109 0 4 0 22 7 204 1 0 0
------------------------------------------------------------------------------------------------------------------------------------
Difference........................................... -357 -196 -339 -13 -17 -1 -168 -15 -98 -17 -62 0
Percent.............................................. -41.1% -39.1% -75.7% -100.0% -81.0% -100.0% -88.4% -68.2% -32.5% -94.4% -100.0% 0.0%
====================================================================================================================================
July 22-29, 1993:
2007 Base Base Case.................................... 34 59 212 85 322 97 71 4 0 0 0 399
2007 Budget............................................ 11 30 63 25 151 23 1 0 0 0 0 81
------------------------------------------------------------------------------------------------------------------------------------
Difference........................................... -23 -29 -149 -60 -171 -74 -70 -4 0 0 0 -318
Percent.............................................. -67.6% -49.2% -70.3% -70.6% -53.1% -76.3% -98.6% -100.0% 0.0% 0.0% 0.0% -79.7%
====================================================================================================================================
July 10-18, 1995:
2007 Base Case......................................... 328 255 544 105 259 159 225 27 553 60 15 98
2007 Budget............................................ 230 139 139 34 112 28 27 1 423 17 1 6
------------------------------------------------------------------------------------------------------------------------------------
Difference........................................... -98 -116 -405 -71 -147 -131 -198 -26 -130 -43 -14 -92
Percent.............................................. -29.9% -45.5% -74.4% -67.6% -56.8% -82.4% -88.0% -96.3% -23.5% -71.7% -93.3% -93.9%
====================================================================================================================================
All Episodes:
2007 Base Case......................................... 2047 1677 2179 505 666 406 869 78 1175 217 292 955
2007 Budget............................................ 1170 1029 724 155 293 83 100 14 719 92 14 162
------------------------------------------------------------------------------------------------------------------------------------
Difference........................................... -877 -648 -1455 -350 -373 -323 -769 -64 -456 -125 -278 -793
Percent.............................................. -42.8% -38.6% -66.8% -69.3% -56.0% -79.6% -88.5% -82.1% -38.8% -57.6% -95.2% -83.0%
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
VIII. Impact on Small Entities
The Regulatory Flexibility Act, 5 U.S.C. 601 et seq. (RFA),
provides that whenever an agency is required to publish a general
notice of proposed rulemaking, it must prepare and make available a
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.'' Id., section 605(b). Courts
have interpreted the RFA to require a regulatory flexibility analysis
only when small entities will be subject to the requirements of the
rule. See, e.g., Mid-Tex Electric Cooperative, Inc. v. FERC, 773 F.2d
327 (D.C. Cir. 1985) (agency's certification need only consider the
rule's impact on regulated entities and not indirect impact on small
entities not regulated).
In the proposed rulemaking, which EPA published by notice dated
November 7, 1997, 62 FR 60318, EPA noted that the proposed rule would
not directly regulate small entities. Instead, the proposed rule would
require States to develop, adopt, and submit SIP revisions that would
achieve the necessary NOX emission reductions, and would
leave to the States the task of determining how to obtain those
reductions, including which entities to regulate. The EPA also noted,
in the proposed rule, that because affected States would have
discretion to choose which sources to regulate and how much emissions
reductions each selected source would have to achieve, EPA could not,
at the time of the proposal, predict the effect of the rule on small
entities.
The purposes of the RFA, the RFA's statutory requirements for
regulatory flexibility analyses, and the caselaw all shed light on the
meaning of the term ``impact'' as used in the RFA. These sources
indicate that a rule can have an ``impact'' of concern under the RFA
only with respect to sources subject to the requirements of the rule.
[[Page 25968]]
The RFA's ``Findings and Purposes'' section states,
It is the purpose of this Act to establish as a principle of
regulatory issuance that agencies shall endeavor, consistent with
the objective of the rule and of applicable statutes, to fit
regulatory and information requirements to the scale of the
businesses, organizations, and governmental jurisdictions subject to
regulation.
Pub. L. 96-354, section 2(b). This statement of purpose indicates that
Congress intended the RFA to ensure that agencies tailored the
requirements of their regulations to the resources and capabilities of
entities ``subject to [such] regulation.'' Other provisions of the RFA
reflect this statement of purpose. For example, RFA sections 603 and
604 require that the initial and final regulatory flexibility analyses
identify the types and estimate the numbers of small entities ``to
which the proposed rule will apply'' (sections 603(b)(3) and
604(a)(3)); and other RFA provisions make clear that the regulatory
flexibility analyses are to focus on how to minimize rule requirements
for small entities (sections 603(c)(1) and (4), 605(a)(5)). Taken as a
whole, these provisions suggest that agencies should undertake the RFA
analyses only with respect to rules to which small entities are
subject.
Two Federal court cases support this interpretation of ``impact':
Mid-Tex Elec. Co-op v. FERC, 773 F.2d 327, 342 (D.C. Cir. 1985),
summarized above, and United Distribution Companies v. FERC, 88 F.3d
1105 (D.C. Cir. 1996). In United Distribution Companies, the court
stated that the Mid-Tex court--
* * * conducted an extensive analysis of the RFA provisions
governing when a regulatory flexibility analysis is required and
concluded that no analysis is necessary when an agency determines
``that the rule will not have a significant economic impact on a
substantial number of small entities that are subject to the
requirements of the rule.''
Id. at 1170 (quoting Mid-Tex court, emphasis added by United
Distribution court). For a more detailed analysis by EPA of the RFA,
see ``Final Rule: National Ambient Air Quality Standards for Ozone,''
62 FR 38856, 38888 (July 18, 1997).
For the reasons indicated above, EPA certified that the proposed
rule would ``not have, if promulgated, a significant economic impact on
a substantial number of small entities.'' The Agency received a number
of comments on this certification, including several challenging the
certification as improper under the RFA. The EPA is currently
considering these comments and will respond to them in light of the
rulemaking record after comments are received on this supplemental
proposal.
Today's supplemental proposal does not contain anything that would
adversely affect small entities. The SIP criteria and emissions
reporting requirements proposed in today's action would apply only to
States, and would not, by themselves, subject any other entities to any
regulation. The NOX budget trading program is a
recommendation to States, but not a requirement, and thus does not
subject any entities to any requirements. In addition, the trading
program, if adopted by a State, would provide sources subject to the
State NOX controls additional flexibility in meeting SIP
requirements. Thus, the trading program would have a beneficial effect
on State-regulated sources, including small entities subject to those
State requirements. Accordingly, EPA certifies that this supplemental
proposal will not, if promulgated, have a significant economic impact
on a substantial number of small entities.
As noted in Section VI, Interaction with Title IV NOX
Rule, today's supplemental proposal includes, in addition to provisions
directly related to the NOX SIP call, a revision to the 40
CFR Part 76, which implements the NOX requirements of the
acid rain provisions in Title IV of the CAA Amendments and which
applies directly to sources. The revision is designed to lessen the
administrative requirements imposed on sources affected by the acid
rain program that are in States that adopt a NOX cap-and-
trade program. Because the only impact of this revision will be to ease
administrative requirements, it will not have any adverse effect on any
small entity that may be subject to the rule's requirements.
Accordingly, I certify that this part of today's proposed rule will not
have a significant economic effect on a substantial number of small
entities.
IX. Unfunded Mandates Reform Act
Title II of the Unfunded Mandates Reform Act of 1995 (UMRA), Public
Law 104-4, establishes requirements for Federal agencies to assess the
effects of their regulatory actions on State, local, and tribal
governments and the private sector. Under section 202 of the UMRA, 2
U.S.C. 1532, EPA generally must prepare a written statement, including
a cost-benefit analysis, for any proposed or final 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).
Before promulgating an EPA rule for which a written statement is
needed under section 202 of the UMRA, section 205, 2 U.S.C. 1535, of
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.
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.
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.
The EPA addressed these issues, in the proposed rulemaking as to
the proposed NOX SIP call. However, as noted in Section VI,
Interaction with Title IV NOX Rule, today's supplemental
proposal includes, in addition to provisions directly related to the
proposed NOX SIP call, a revision to the 40 CFR Part 76,
which implements the NOX requirements of the acid rain
provisions in Title IV of the CAA Amendments and which applies directly
to sources. The revision is designed to lessen the administrative
requirements imposed on sources affected by the acid rain program that
[[Page 25969]]
are in States that adopt a NOX cap-and-trade program.
Because the only impact of this part of the rule will be to ease
administrative requirements, it will not impose costs that would
trigger the requirements of UMRA sections 202, 204, or 205. For the
same reason, this part of the rule would not result in regulatory
requirements that might significantly affect small governments;
moreover, this part of the proposed rule would not impose requirements
unique to small governments. Thus, the requirements of section 203 (2
U.S.C. 1533) do not apply to the revisions to 40 CFR Part 76.
X. Paperwork Reduction Act
The information collection requirements in this proposed rule have
been submitted for approval to the Office of Management and Budget
(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. 1857.01) and a copy may be obtained from Sandy Farmer, OPPE
Regulatory Information Division, U.S. 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 compliance with the
regional control strategy be verified. Tracking emissions is the
principal mechanism to ensure compliance with the budget and to assure
the downwind affected States and EPA that the ozone transport problem
is being mitigated. If tracking and periodic reports indicate that a
State is not implementing all of its NOX control measures
beginning with the compliance date for NOX controls or is
off track to meet its statewide budget by 2007, EPA will work with the
State to determine the reasons for noncompliance and what course of
remedial action is needed. The reporting requirements are mandatory and
the legal authority for the proposed reporting requirements resides in
section 110(a) and 301(a) of the CAA. Emissions data being requested in
today's proposal would not be considered confidential by EPA. Certain
process data may be identified as sensitive by a State and are then
treated as ``State-sensitive'' by EPA.
The reporting and record keeping burden for this collection of
information is described below:
Respondents/Affected Entities: States, along with the District of
Columbia, which are included in the NOX SIP call.
Number of Respondents: 23.
Frequency of Response: Annually, triennially.
Estimated Annual Hour Burden per Respondent: 282.
Estimated Annual Cost per Respondent: $7,942.68.
Estimated Total Annual Hour Burden: 6,486.
Estimated Total Annualized Cost: $182,682.00.
There are no additional capital or operating and maintenance costs
associated with the reporting requirements of the proposed rule. During
the 1980s, an EPA initiative established electronic communication with
each State environmental agency. This included a computer terminal for
any States needing one in order to communicate with the EPA's national
data base systems. Costs associated with replacing and maintaining
these terminals, as well as storage of data files, have been accounted
for in the ICR for the existing annual inventory reporting requirements
(OMB # 2060-0088).
Burden means the total time, effort, or financial resources
expended by persons to generate, maintain, retain, or disclose or
provide information to or for a Federal agency. This includes the time
needed to review instructions; develop, acquire, install, and utilize
technology and systems for the purposes of collecting, validating, and
verifying information, processing and maintaining information, and
disclosing and providing information; adjust the existing ways to
comply with any previously applicable instructions and requirements;
train personnel to be able to respond to a collection of information;
search data sources; complete and review the collection of information;
and transmit or otherwise disclose the information.
An agency may not conduct or sponsor, and a person is not required
to respond to a collection of information unless it displays a
currently valid OMB control number. The OMB control numbers for EPA's
regulations are listed in 40 CFR part 9 and 48 CFR chapter 15.
Send comments 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, OPPE Regulatory
Information Division, U.S. 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 June 22, 1998. Include the ICR number in any
correspondence.
XI. Judicial Review
Section 307(b)(1) of the CAA indicates which Federal Courts of
Appeal have venue for petitions of review of final actions by EPA. This
Section provides, in part, that petitions for review must be filed in
the Court of Appeals for the District of Columbia Circuit if (i) the
agency action consists of ``nationally applicable regulations
promulgated, or final action taken, by the Administrator,'' or (ii)
such action is locally or regionally applicable, if ``such action is
based on a determination of nationwide scope or effect and if in taking
such action the Administrator finds and publishes that such action is
based on such a determination.''
Any final action related to the NOX SIP Call is
``nationally applicable'' within the meaning of section 307(b)(1). As
an initial matter, through this rule, EPA interprets section 110 of the
Act in a way that could affect future actions regulating the transport
of pollutants. In addition, the SIP Call, as proposed, would require 22
States and the District of Columbia to establish emissions budgets for
NOX. The SIP Call also is based on a common core of factual
findings and analyses concerning the transport of ozone and its
precursors between the different States subject to the SIP Call.
Finally, EPA plans to establish in the final rule uniform approvability
criteria that would be applied to all States subject to the SIP call.
For these reasons, the Administrator also is determining that any final
action regarding the NOX SIP Call is of nationwide scope and
effect for purposes of section 307(b)(1). Thus any petitions for review
of final actions regarding the SIP Call must be filed in the Court of
Appeals for the District of Columbia Circuit within 60 days from the
date final action is promulgated in the Federal Register.
XII. Regulatory Analysis
Under Executive Order 12866 (58 FR 51735, October 4, 1993), the
Agency must determine whether the 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
[[Page 25970]]
State, local, or tribal governments or communities;
(2) Create a serious inconsistency or otherwise interfere with an
action taken or planned by another agency;
(3) Materially alter the budgetary impact of entitlements, grants,
user fees, or loan programs or the rights and obligations of recipients
thereof; or
(4) Raise novel legal or policy issues arising out of legal
mandates, the President's priorities, or the principles set forth in
the Executive Order.
As EPA indicated in the proposed rulemaking, this action is a
``significant regulatory action'' because it would have an annual
effect on the economy of approximately $2 billion. 62 FR 60318, 60373.
Accordingly, the notice of proposed rulemaking was submitted to OMB for
review. For the same reason, today's supplemental notice of proposed
rulemaking was submitted to OMB for review. 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.
List of Subjects
40 CFR Part 51
Environmental protection, Administrative practice and procedure,
Air pollution control, Carbon monoxide, Intergovernmental relations,
Nitrogen dioxide, Ozone, Particulate matter, Reporting and
recordkeeping requirements, Sulfur oxides, Transportation, Volatile
organic compounds.
40 CFR Part 76
Environmental protection, Acid rain program, Air pollution control,
Nitrogen dioxide, Reporting and recordkeeping requirements.
40 CFR Part 96
Environmental protection, Administrative practice and procedure,
Air pollution control, Nitrogen dioxide, Reporting and recordkeeping
requirements.
Dated: April 28, 1998.
Carol M. Browner,
Administrator.
For the reasons set forth in the preamble, parts 51, 76, and 96 of
chapter I of title 40 of the Code of Federal Regulations are proposed
to be amended as follows:
PART 51--REQUIREMENTS FOR PREPARATION, ADOPTION, AND SUBMITTAL OF
IMPLEMENTATION PLANS
1. The authority citation for part 51 continues to read as follows:
Authority: 42 U.S.C. 7401, 7410, 7411, 7412, 7413, 7414, 7470-
7479, 7501-7508, 7601, and 7602.
Subpart G--Control Strategy
2. Subpart G is amended to add Secs. 51.121 and 51.122 to read as
follows:
Sec. 51.121 Requirements for state implementation plan revisions
relating to budgets for emissions of oxides of nitrogen.
(a) The EPA Administrator finds that the State implementation plans
(SIPs) for the States listed in paragraph (c) of this section are
substantially inadequate to comply with the requirements of section
110(a)(2)(D) of the Clean Air Act, 42 U.S.C. 7410(a)(2)(D), and to
mitigate adequately the interstate pollutant transport described in
section 184 of the Clean Air Act, 42 U.S.C. 7511c, with respect to
nonattainment areas under the 1-hour ozone national ambient air quality
standards (NAAQS), to the extent that those SIPs do not provide for
compliance with a budget of emissions of nitrogen oxides
(``NOX budget'') as described in paragraph (e) of this
section. To cure such inadequacy, each of the States listed in
paragraph(c) of this section must submit to EPA a SIP revision that
provides for compliance with such NOX budget and associated
SIP provisions described in this section.
(b) The EPA Administrator determines that the States listed in
paragraph (c) of this section must submit SIP revisions under section
110(a)(1) of the Clean Air Act, 42 U.S.C. 7410(a)(1), that provide for
compliance with a NOX budget, as described in paragraph (e)
of this section and associated SIP provisions described in this
section, to comply with the requirements of section 110(a)(2)(D) of the
Clean Air Act, 42 U.S.C. 7410(a)(2)(D), with respect to nonattainment
areas under the 8-hour ozone NAAQS.
(c) The States subject to paragraphs (a) and (b) of this section
are: Alabama, Connecticut, Delaware, Georgia, Illinois, Indiana,
Kentucky, Maryland, Massachusetts, Michigan, Missouri, New Jersey, New
York, North Carolina, Ohio, Pennsylvania, Rhode Island, South Carolina,
Tennessee, Virginia, West Virginia, Wisconsin, and the District of
Columbia.
(d)(1) The SIP submissions required under paragraphs (a) and (b) of
this section must be submitted by no later than September 30, 1999.
(2) The State makes an official submission of its SIP revision to
EPA only when:
(i) The submission conforms to the requirements of appendix V to
this part; and
(ii) The State delivers five copies of the plan to the appropriate
Regional Office, with a letter giving notice of such action.
(e)(1) The NOX budget for a State listed in paragraph
(c) of this section is defined as the total amount of NOX
emissions allowed from all sources in that State, as indicated in
paragraph (e)(4) of this section with respect to that State.
(2) The SIP must provide for compliance with the NOX
budget during each ozone season, which includes May 1 through September
30 of the year 2007 and each subsequent year.
(3) The SIP must require implementation of its control measures by
no later than September 30, 2002.
(4) The State-by-State amounts of the NOX budget are as
follows:
------------------------------------------------------------------------
State Budget
------------------------------------------------------------------------
Alabama.................................................... 155,617
Connecticut................................................ 39,909
Delaware................................................... 21,010
District of Columbia....................................... 7,000
Georgia.................................................... 159,013
Illinois................................................... 218,679
Indiana.................................................... 200,345
Kentucky................................................... 158,360
Maryland................................................... 73,628
Massachusetts.............................................. 73,575
Michigan................................................... 199,238
Missouri................................................... 116,246
New Jersey................................................. 93,464
New York................................................... 185,537
North Carolina............................................. 153,106
Ohio....................................................... 236,443
Pennsylvania............................................... 207,250
Rhode Island............................................... 10,132
South Carolina............................................. 109,267
Tennessee.................................................. 187,250
Virginia................................................... 162,375
West Virginia.............................................. 81,701
Wisconsin.................................................. 95,902
------------
Total.................................................. 2,945,046
------------------------------------------------------------------------
(f) Each SIP revision must set forth control measures to meet the
NOX budget which include the following:
(1) A description of enforcement methods including, but not limited
to:
(i) Procedures for monitoring compliance with each of the selected
control measures;
(ii) Procedures for handling violations; and
(iii) A designation of agency responsibility for enforcement of
implementation.
[[Page 25971]]
(2) Should a State elect to impose control measures on
NOX sources serving electric generators with a nameplate
capacity greater than 25 MWe or boilers with a maximum design heat
input greater than 250 mmBtu/hr as a means of meeting its
NOX budget, then those measures must either:
(i) Impose a NOX mass emissions cap on each source;
(ii) Impose a NOX emission rate limit on each source and
assume maximum operating capacity for every such source for purposes of
estimating mass NOX emissions; or
(iii) Impose any other regulatory requirement which the State has
demonstrated to EPA provides equivalent or greater assurance than
options in paragraphs (e)(2) (i) or (ii) of this section that the State
will meet its NOX budget.
(g)(1) Each SIP revision must demonstrate that the measures, rules,
and regulations contained in it are adequate to provide for the timely
compliance with the NOX budget during the 2007 ozone season.
(2) The demonstration must include the following:
(i) Each revision must contain a detailed baseline inventory of
NOX mass emissions from point, area, and mobile sources in
the year 2007 absent the control measures specified in the SIP
submission. The State must use the same baseline inventory that EPA
used in calculating the State's NOX budget.
(ii) Each revision must contain a summary of NOX mass
emissions in 2007 projected to result from implementation of each of
the new control measures and from all NOX sources together
following implementation of such control measures. The summary must
assume the same NOX mass emissions for mobile sources
assumed by EPA in calculating the State's budget, unless the State has
adopted measures more stringent than the Federal measures incorporated
into the budget calculation. The State must provide EPA with a summary
of the computations, assumptions, and judgments used to determine the
degree of reduction of projected emissions that will result from the
implementation of the control measures.
(iii) Each revision must identify the sources of the data used in
the projection of emissions.
(h) Each revision must comply with Sec. 51.116 (regarding data
availability).
(1) Each revision must provide for monitoring the status of
compliance with any rules and regulations adopted to meet the
NOX budget. Specifically, the revision must meet the
following requirements:
(i) The revision must provide for legally enforceable procedures
for requiring owners or operators of stationary sources to maintain
records of and periodically report to the State--
(A) Information on the amount of NOX emissions from the
stationary sources; and
(B) Other information as may be necessary to enable the State to
determine whether the sources are in compliance with applicable
portions of the control measures;
(ii) The revision must comply with Sec. 51.212 of this part
(regarding testing, inspection, enforcement, and complaints);
(iii) If the revision contains any transportation control measures,
then the revision must comply with Sec. 51.213 (regarding
transportation control measures);
(iv) If the revision contains measures to control NOX
sources serving electric generators with a nameplate capacity greater
than 25 MWe or greater or boilers with a maximum design heat input
greater than 250 mmBtu/hr, then the revision must require such sources
to use a continuous emissions monitoring system.
(2) [Reserved]
(i) [Reserved]
(j) Each revision must show that the State has legal authority to
carry out the revision, including authority to:
(1) Adopt emissions standards and limitations and any other
measures necessary for attainment and maintenance of the State's
NOX budget specified in paragraph (e) of this section;
(2) Enforce applicable laws, regulations, and standards, and seek
injunctive relief;
(3) Obtain information necessary to determine whether air pollution
sources are in compliance with applicable laws, regulations, and
standards, including authority to require recordkeeping and to make
inspections and conduct tests of air pollution sources.
(4) Require owners or operators of stationary sources to install,
maintain, and use emissions monitoring devices and to make periodic
reports to the State on the nature and amounts of emissions from such
stationary sources; also authority for the State to make such data
available to the public as reported and as correlated with any
applicable emissions standards or limitations.
(k)(1) The provisions of law or regulation which the State
determines provide the authorities required under this section must be
specifically identified, and copies of such laws or regulations be
submitted with the SIP revision.
(2) Legal authority adequate to fulfill the requirements of
paragraphs (j)(3) and (4) of this section may be delegated to the State
under section 114 of the Act.
(l)(1) A revision may assign legal authority to local agencies in
accordance with section 51.232.
(2) Each revision must comply with section 51.240 (regarding
general plan requirements).
(m) Each revision shall contain legally enforceable compliance
schedules setting forth September 30, 2002 as the date by which all
sources or categories of such sources must be in compliance with any
applicable requirement of the SIP revision.
(n) Each revision must comply with section 51.280 (regarding
resources).
(o) For purposes of the SIP revisions required by this section, EPA
may make a finding under section 179(a)(1) through (4) of the Act, 42
U.S.C. 7509(a)(1)-(4), starting the sanctions process set forth in
section 179(a) of the Act. Any such finding will be deemed a finding
under section 52.31(c) and sanctions will be imposed in accordance with
the order of sanctions and the terms for such sanctions established in
section 52.31.
(p) Each revision must provide for State compliance with the
reporting requirements set forth in section 51.122 of this part.
Sec. 51.122 Emissions reporting requirements for SIP revisions
relating to budgets for NOx emissions.
(a) For its transport SIP revision under section 51.121 of this
part, each State must submit to EPA NOX emissions data as
described in this section.
(b) Each revision must provide for periodic reporting by the State
of NOX emissions data to demonstrate that the emissions
budget set forth in section 51.121(e)(4) is being met.
(1) Annual reporting. Each revision must provide for annual
reporting of NOX emissions data from all of the following
sources and source categories:
(i) All NOX sources within the State which the State
chooses to regulate specifically for the purpose of meeting the
NOX budgets submitted under section 51.121(e)(4). This would
include all NOX sources within the State which are subject
to measures included by the State in its transport SIP revision
submitted under section 51.121. On road and nonroad mobile sources are
not included unless controls greater than those Federally mandated are
required for these sources.
(ii) The direct reporting of data from sources to EPA used for
compliance
[[Page 25972]]
with the requirements of a trading program meeting the requirements of
40 CFR part 96 and/or direct reporting of data from sources to EPA used
for meeting the monitoring and reporting requirements of subpart H of
40 CFR part 75 can be used to satisfy this requirement.
(2) Triennial reporting. Each plan must provide for triennial
(i.e., every third year) reporting of NOX emissions data
from all sources within the State.
(3) Year 2007 reporting. Each plan must provide for reporting of
year 2007 NOX emissions data from all sources within the
State.
(4) The data availability requirements in section 51.116 must be
followed for all data submitted to meet the requirements of paragraphs
(b)(1), (2) and (3) of this section.
(c) The data reported in paragraph (b) of this section for
stationary point sources must meet the following minimum criteria:
(1) For annual data reporting purposes the data must include the
following minimum elements:
(i) Inventory year.
(ii) State FIPS code.
(iii) County FIPS code.
(iv) Federal ID code (plant).
(v) Federal ID code (point).
(vi) Federal ID code (process).
(vii) Federal ID code (stack).
(vii) Site Name.
(viii) Physical Address.
(ix) SCC.
(x) Pollutant code.
(xi) Annual emissions.
(xii) Ozone Season emissions.
(xiii) Area designation.
(2) In addition, the annual data must include the following minimum
elements as applicable to the emissions estimation methodology.
(i) Fuel heat content (annual).
(ii) Fuel heat content (seasonal).
(iii) Source of fuel heat content data.
(iv) Activity throughput (annual).
(v) Activity throughput (seasonal).
(vi) Source of activity/throughput data.
(vii) Winter throughput (%).
(viii) Spring throughput (%).
(ix) Summer throughput (%).
(x) Fall throughput (%).
(xi) Work weekday emissions.
(xii) Emission factor.
(xiii) Source of emission factor.
(xiv) Hr/day in operation.
(xv) Operations Start time (hour).
(xvi) Day/wk in operation.
(xvii) Wk/yr in operation.
(3) The triennial and 2007 inventories must include the following
data elements:
(i) The data required in paragraphs (c)(1) and (c)(2) of this
section.
(ii) X coordinate (latitude).
(iii) Y coordinate (longitude).
(iv) Stack height.
(v) Stack diameter.
(vi) Exit gas temperature.
(vii) Exit gas velocity.
(viii) Exit gas flow rate.
(ix) SIC.
(x) Boiler/process throughput design capacity.
(xi) Maximum design rate.
(xii) Maximum capacity.
(xiii) Primary control efficiency.
(xiv) Secondary control efficiency.
(xv) Control device type.
(d) The data reported in paragraph (b) of this section for area
sources must include the following minimum elements:
(1) For annual inventories it must include:
(i) Inventory year.
(ii) State FIPS code.
(iii) County FIPS code.
(iv) SCC.
(v) Emission factor.
(vi) Source of emission factor.
(vii) Activity/throughput level (annual).
(viii) Activity throughput level (seasonal).
(ix) Source of activity/throughput data.
(x) Spring throughput (%).
(xi) Summer throughput (%).
(xii) Fall throughput (%).
(xiii) Control efficiency (%).
(xiv) Pollutant code.
(xv) Ozone Season emissions.
(xvi) Source of emissions data.
(xvii) Hr/day in operation.
(xviii) Day/wk in operation.
(xix) Wk/yr in operations.
(2) The triennial and 2007 inventories must contain at a minimum
all the data required in paragraph (d)(1) of this section.
(e) The data reported in paragraph (b) of this section for mobile
sources must meet the following minimum criteria:
(1) For the annual, triennial, and 2007 inventory purposes the
following data must be reported:
(i) Inventory year.
(ii) State FIPS code.
(iii) County FIPS code.
(iv) Emission factor.
(v) Source of emission factor.
(vi) Activity (VMT by Roadway Class).
(vii) Source of activity data.
(viii) Pollutant code.
(ix) Summer work weekday emissions.
(x) Ozone season emissions.
(xi) Source of emissions data.
(2) [Reserved.]
(f) Approval of ozone season calculation by EPA. Each State must
submit for EPA approval an example of the calculation procedure used to
calculate ozone season emissions along with sufficient information for
EPA to verify the calculated value of ozone season emissions.
(g) Reporting schedules. (1) Annual reports are to begin with data
for the year 2003.
(2) Triennial reports are to begin with data for the year 2002.
(3) Year 2007 data are to be submitted for the year 2007.
(4) States must submit data for a required year by 12 months after
the end of the calendar year for which the data are collected.
(h) Data Reporting Procedures. When submitting a formal
NOX budget emissions report and associated data, States
shall notify the appropriate EPA regional office.
(1) States are required to report emissions data in an electronic
format to the location given in paragraph (h)(5) of this section.
Several options are available for data reporting.
(2) An agency may choose to continue reporting to the EPA
Aerometric Information Retrieval System (AIRS) system using the AIRS
facility subsystem (AFS) format for point sources. (This option will
continue for point sources for some period of time after AIRS is
reengineered (before 2002), at which time this choice may be
discontinued or modified.)
(3) An agency may convert its emissions data into the Emission
Inventory Improvement Program/Electronic Data Interchange (EIIP/EDI)
format. This file can then be made available to any requestor, either
using E-mail, floppy disk, or value added network (VAN), or can be
placed on a file transfer protocol (FTP) site.
(4) An agency may submit its emissions data in a proprietary format
based on the EIIP data model.
(5) For options in paragraphs (h)(3) and (4) of this section, the
terms submitting and reporting data are defined as either providing the
data in the EIIP/EDI format or the EIIP based data model proprietary
format to EPA, Office of Air Quality Planning and Standards, Emission
Factors and Inventory Group directly or notifying this group that the
data are available in the specified format and at a specific electronic
location (e.g., FTP site).
(6) For annual reporting (not for triennial reports) a State may
have sources submit the data directly to EPA. This option will be
available to any source in a State that is both participating in a
trading program meeting the requirements of part 96 of this chapter and
that has agreed to accept data in this format. The EPA will
[[Page 25973]]
make both the raw data submitted in this format and summary data
available to any State that chooses this option.
(i) Definitions. As used in this section, the following words and
terms shall have the meanings set forth below:
(1) Annual emissions. Actual emissions for a plant, point, or
process, either measured or calculated.
(2) Ash content. Inert residual portion of a fuel.
(3) Area designation. The designation of the area in which the
reporting source is located with regard to the ozone national ambient
air quality standard. This would include attainment or nonattainment
designations. For nonattainment designations, the classification of the
nonattainment area must be specified, i.e., transitional, marginal,
moderate, serious, severe, or extreme.
(4) Boiler design capacity. A measure of the size of a boiler,
based on the reported maximum continuous steam flow. Capacity is
calculated in units of MMBtu/hr.
(5) Control device type. The name of the type of control device
(e.g., wet scrubber, flaring, or process change).
(6) Control efficiency. The emissions reduction efficiency of a
primary control device, which shows the amount of reduction of a
particular pollutant from a process' emissions due to controls or
material change. Control efficiency is usually expressed as a
percentage or in tenths.
(7) County/parish/reservation (FIPS). Federal Information Placement
System (FIPS). FIPS is the system of unique numeric codes developed by
the government to identify States, counties, towns, and townships for
the entire United States, Puerto Rico, and Guam.
(8) Day/wk in operations. Days per week that the emitting process
operates.
(9) Emission factor. Ratio relating emissions of a specific
pollutant to an activity or material throughput level.
(10) Exit gas flow rate. Numeric value of stack gas flow rate.
(11) Exit gas temperature. Numeric value of an exit gas stream
temperature.
(12) Exit gas velocity. Numeric value of an exit gas stream
velocity.
(13) Fall throughput (%). Portion of throughput for the three Fall
months (September, October, November). This represents the expression
of annual activity information on the basis of four seasons, typically
spring, summer, fall, and winter. It can be represented either as a
percentage of the annual activity (e.g., production in summer is 40
percent of the year's production), or in terms of the units of the
activity (e.g., out of 600 units produced, spring = 150 units, summer =
250 units, fall = 150 units, and winter = 50 units).
(14) Federal ID code (plant). Unique codes for a plant or facility,
containing one or more pollutant-emitting sources.
(15) Federal ID code (point). Unique codes for the point of
generation of emissions, typically a physical piece of equipment.
(16) Federal ID code (stack number). Unique codes for the point
where emissions from one or more processes are released into the
atmosphere.
(17) Federal Information Placement System (FIPS). The system of
unique numeric codes developed by the government to identify States,
counties, towns, and townships for the entire United States, Puerto
Rico, and Guam.
(18) Heat content. The thermal heat energy content of a solid,
liquid, or gaseous fuel. Fuel heat content is typically expressed in
units of Btu/lb of fuel, Btu/gal of fuel, joules/kg of fuel, etc.
(19) Hr/day in operations. Hours per day that the emitting process
operates.
(20) Maximum design rate. Maximum fuel use rate based on the
equipment's or process' physical size or operational capabilities.
(21) Maximum nameplate capacity. A measure of the size of a
generator, and is put on the unit's nameplate by the manufacturer. The
data element is reported in MW or KW.
(22) Ozone season. The period May 1 through September 30 of a year.
(23) Physical address. Street address of facility.
(24) Point source. A non-mobile source which emits 100 tons of
NOX or more per year. A non-mobile source which emits less
NOX per year than this amount is an area source.
(25) Pollutant code. A unique code for each reported pollutant that
has been assigned in the EIIP Data Model. Character names are used for
criteria pollutants, while Chemical Abstracts Service (CAS) numbers are
used for all other pollutants. Some States may be using SAROAD codes
for pollutants, but these should be able to be mapped to the EIIP Data
Model pollutant codes.
(26) Process rate/throughput. A measurable factor or parameter that
is directly or indirectly related to the emissions of an air pollution
source. Depending on the type of source category, activity information
may refer to the amount of fuel combusted, the amount of a raw material
processed, the amount of a product that is manufactured, the amount of
a material that is handled or processed, population, employment, number
of units, or miles traveled. Activity information is typically the
value that is multiplied against an emission factor to generate an
emissions estimate.
(27) SCC. Source category code. A process-level code that describes
the equipment or operation emitting pollutants.
(28) Secondary control efficiency (%). The emission reduction
efficiency of a secondary control device, which shows the amount of
reduction of a particular pollutant from a process' emissions due to
controls or material change. Control efficiency is usually expressed as
a percentage or in tenths.
(29) SIC. Standard Industrial Classification code. U.S. Department
of Commerce's categorization of businesses by their products or
services.
(30) Site name. The name of the facility.
(31) Spring throughput (%). Portion of throughput or activity for
the three spring months (March, April, May). See the definition of Fall
Throughput.
(32) Stack diameter. Stack physical diameter.
(33) Stack height. Stack physical height above the surrounding
terrain.
(34) Start date (inventory year). The calendar year that the
emissions estimates were calculated for and are applicable to.
(35) Start time (hour). Start time (if available) that was
applicable and used for calculations of emissions estimates.
(36) State/providence/territory (FIPS). Federal Information
Placement System (FIPS). FIPS is the system of unique numeric codes
developed by the government to identify States, counties, towns, and
townships for the entire United States, Puerto Rico, and Guam.
(37) Summer throughput (%). Portion of throughput or activity for
the three summer months (June, July, August). See the definition of
Fall Throughput.
(38) Summer work weekday emissions. Average day's emissions for a
typical day.
(39) VMT by Roadway Class. VMT stands for vehicle miles traveled
and is an expression of vehicle activity that is used with emission
factors. The emission factors are usually expressed in terms of grams
per mile of travel. Since VMT does not directly correlate to emissions
that occur while the vehicle is not moving, these non-moving emissions
are incorporated into EPA's MOBILE model emission factors.
(40) Winter throughput (%). Portion of throughput or activity for
the three winter months (December, January, February). See the
definition of Fall Throughput.
(41) Week/year in operation. Weeks per year that the emitting
process operates.
(42) Work Weekday. Any day of the week except Saturday or Sunday.
[[Page 25974]]
(43) X coordinate (latitude). East-west geographic coordinate of an
object.
(44) Y coordinate (longitude). North-south geographic coordinate of
an object.
PART 76--ACID RAIN NITROGEN OXIDES EMISSION REDUCTION PROGRAM
3. The authority citation for part 76 continues to read as follows:
Authority: 42 U.S.C. 7601 and 7651, et seq.
4. Section 76.16 is added to read as follows:
Sec. 76.16 Alternative compliance.
(a)(1) A State or group of States may submit a petition requesting
that the Administrator, on his or her own motion, may:
(i) Require the owners or operators of the Group 1, Phase II coal-
fired utility units with a tangentially fired boiler or a dry bottom
wall fired boiler in the State or the group of States to be subject to
the applicable emission limitations for NOX in Sec. 76.5, in
lieu of the applicable emission limitations for NOX in
Sec. 76.7; and
(ii) Provide that the owners or operators of the Group 2 coal-fired
utility units with a cell burner boiler, cyclone boiler, wet bottom
boiler, or vertically fired boiler in the State or the group of States
are not subject to the applicable emission limitations for
NOX in Sec. 76.6.
(2) A petition under paragraph (a)(1) of this section must
demonstrate that the requirements in paragraphs (b)(1) and (2) of this
section are met.
(3) A petition under paragraph (a)(1) of this section may be
submitted, but may not be approved by the Administrator, before the
State implementation plan or Federal implementation plan covering the
entire State, or the State implementation plans or Federal
implementation plans covering the entire group of States, under
paragraph (b) of this section become final and federally enforceable.
(b) The Administrator may take the actions in paragraphs (a)(1)(i)
and (ii) of this section if he or she finds that, under the State
implementation plan or Federal implementation plan covering the entire
State or the State implementation plans or Federal implementation plans
covering the entire group of States:
(1) Each unit that is in the State or the group of States and that,
but for the provisions of this section, would be subject to emission
limitations under this part
(i) Is subject to:
(A) A cap on total annual NOX emissions; or
(B) Two or more seasonal caps that together limit total annual
NOX emissions;
(ii) May trade authorizations to emit NOX within each
such cap, provided that the Administrator will consider (to the extent
demonstrated to his or her satisfaction) whether the cost savings from
trading will be offset by elimination of the ability of an owner or
operator of a unit in the State or the group of States to use a
NOX averaging plan under Sec. 76.11 in lieu of emission
limitations under Sec. 76.5, Sec. 76.6, or Sec. 76.7 that remain
applicable under the provisions of this section; and
(iii) Must use authorizations to emit NOX to account
for:
(A) Any NOX emissions by such unit; and
(B) Any NOX emissions resulting from reducing
utilization of such unit below its baseline utilization (adjusted for
changes in demand for electricity) and shifting utilization to any
other unit, or combustion device serving a generator, that is not
subject to each such cap, unless it is demonstrated to the satisfaction
of the Administrator that any NOX emissions under this
paragraph (b)(1)(iii)(B) will not result in higher total NOX
emissions from sources in the State or group of States or in other
States; and
(2)(i) Total annual NOX emissions by all units that are
in the State or the group of States and that, but for the provisions of
this section, would be subject to emission limitations under this part
will be equal to or lower than total annual NOX emissions by
such units if each such unit is treated as subject to the applicable
emission limitation in Sec. 76.5, Sec. 76.6, or Sec. 76.7 that would
apply but for the provisions of this section.
(ii) In the case of a petition under paragraph (a) of this section,
total annual NOX emissions by the units will be determined
using the actual utilizations of the units for the last 4 calendar
quarters prior to submission of the petition. In the case of action by
the Administrator on his or her own motion under paragraph (a) of this
section, total annual NOX emissions by the units will be
determined using the actual utilizations of the units for the last 4
calendar quarters prior to issuance of the draft decision under
paragraph (c) of this section.
(c) In acting on a petition or on his or her own motion under
paragraph (a) of this section, the Administrator will issue, for public
comment, a draft decision on the petition or a draft decision to act on
his or her own motion and then a final decision. The Administrator may
issue a draft decision, but not final decision, on a petition or on his
or her own motion before the State implementation plan or Federal
implementation plan covering the entire State, or the State
implementation plans or Federal implementation plans covering the
entire group of States, under paragraph (b) of this section become
final and federally enforceable. The draft decision will set forth
procedures that will govern issuance of the final decision and will
provide for:
(1) Service of notice of issuance of the draft decision on.
(i) Any interested person;
(ii) The designated representative of each source with one or more
units that, but for the provisions of this section, would be subject to
the applicable emission limitation in Sec. 76.6 or Sec. 76.7; and
(iii) The air pollution control agencies that:
(A) Have jurisdiction over a unit covered by the draft decision;
(B) Are in a State, or area in which there is a federally
recognized Indian tribe, whose air quality may be affected by the draft
decision and that is contiguous to the State, or the area in which
there is a federally recognized Indian tribe, where a unit covered by
the draft decision is located; or
(C) Are in a State, or area in which there is a federally
recognized Indian tribe, within 50 miles of a unit covered by the draft
decision.
(2) Publication of notice of issuance of the draft decision in the
Federal Register and in any State publication designed to give general
public notice in the States in which the units covered by the draft
decision are located;
(3) A public comment period of at least 30 days and extension or
reopening of the comment period by the Administrator for good cause;
(4) A public hearing, upon request or on the Administrator's own
motion, to the extent the Administrator determines that a public
hearing will contribute to the decision-making process by clarifying
one or more significant issues affecting the draft decision;
(5) Consideration by the Administrator of the comments on the draft
decision received during the public comment period or any public
hearing and written response by the Administrator to any such relevant
comments;
(6) Notice of issuance of a final decision using the methods set
forth in paragraphs (c)(1) and (2) of this section for providing notice
of the draft decision; and
[[Page 25975]]
(7) Appeals, governed by part 78 of this chapter, of the final
decision.
(d) If, after the Administrator issues a final decision under
paragraph (c) of this section and takes the actions set forth in
paragraphs (a)(1)(i) and (ii) of this section with regard to a State or
group of States, a State implementation plan or Federal implementation
plan covering the entire State or entire group of States is revised in
a way that may affect the basis for the findings on which such decision
is based, the Administrator may, upon petition or on his or her own
motion, reconsider such decision.
(e) For purposes of this section, the term ``State'' shall mean one
of the 48 contiguous States or the District of Columbia.
Authority: 42 U.S.C. 7401, 7403, 7410, and 7601.
5. Part 96 is added consisting of Secs. 96.1 through 96.88 to read
as follows:
PART 96--NOX BUDGET TRADING PROGRAM
Subpart A--NOX Budget Trading Program General Provisions
Sec.
96.1 Purpose.
96.2 Definitions.
96.3 Measurements, abbreviations, and acronyms.
96.4 Applicability.
96.5 Retired unit exemption.
96.6 Standard requirements.
96.7 Computation of time.
Subpart B--Authorized Account Representative for NOX Budget
Sources
96.10 Authorization and responsibilities of the NOX
authorized account representative.
96.11 Alternate NOX authorized account representative.
96.12 Changing the NOX authorized account
representative, alternate NOX authorized account
representative; changes in the owners and operators.
96.13 Account certificate of representation.
96.14 Objections concerning the NOX authorized account
representative.
Subpart C--Permits
96.20 General NOX Budget permit requirements.
96.21 Submission of NOX Budget permit applications.
96.22 Information requirements for NOX Budget permit
applications.
96.23 NOX Budget permit contents.
96.24 Effective date of initial NOX Budget permit.
96.25 NOX Budget permit revisions.
Subpart D--Compliance Certification
96.30 Compliance certification report.
96.31 Permitting authority's and Administrator's action on
compliance certifications.
Subpart E--NOX Allowance Allocations
96.40 State trading program budget.
96.41 Timing requirements for NOX allowance allocations.
96.42 NOX allowance allocations.
Subpart F--NOX Allowance Tracking System
96.50 NOX Allowance Tracking System accounts.
96.51 Establishment of accounts.
96.52 NOX Allowance Tracking System responsibilities of
NOX authorized account representative.
96.53 Recordation of NOX allowance allocations.
96.54 Compliance.
96.55 Banking. [Reserved]
96.56 Account error.
96.57 Closing of general accounts.
Subpart G--NOX Allowance Transfers
96.60 Scope and submission of NOX allowance transfers.
96.61 EPA recordation.
96.62 Notification.
Subpart H--Monitoring and Reporting
96.70 General requirements.
96.71 Initial certification and recertification procedures.
96.72 Out of control periods.
96.73 Notifications.
96.74 Recordkeeping and reporting.
96.75 Petitions.
Subpart I--Individual Unit Opt-ins
96.80 Applicability.
96.81 General.
96.82 NOX authorized account representative.
96.83 Applying for NOX Budget opt-in permit.
96.84 Opt-in process.
96.85 NOX Budget opt-in permit contents.
96.86 Withdrawal from NOX Budget Trading Program.
96.87 Change in regulatory status.
96.88 NOX allowance allocations to opt-in units.
Authority: 42 U.S.C. 7401, 7403, 7410, and 7601.
Subpart A--NOX Budget Trading Program General Provisions
Sec. 96.1 Purpose.
This part establishes general provisions and the applicability,
permitting, allowance, excess emissions, monitoring, and opt-in
provisions for the NOX Budget Trading Program 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 the requirements of this part only if such compliance
is required by a State that has jurisdiction over the unit and that
incorporates by reference or otherwise adopts the requirements of this
part. A State that adopts the requirements of this part authorizes the
Administrator to assist the State in implementing the NOX
Budget Trading Program by carrying out the functions set forth for the
Administrator in this part.
Sec. 96.2 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
[[Page 25976]]
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. For purposes of Sec. 96.70 and except as provided in
Sec. 96.5, for a unit that is a NOX Budget unit under
Sec. 96.4 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. For purposes of Sec. 96.70 and except as provided in
Sec. 96.5 or subpart I of this part, for a unit that is not a
NOX Budget unit under Sec. 96.4 on the date the unit
commences commercial operation, the date the unit becomes a
NOX Budget unit under Sec. 96.4 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. For purposes of Sec. 96.21, Sec. 96.42, or
Sec. 96.70 and except as provided in Sec. 96.5, for a unit that is a
NOX Budget unit under Sec. 96.4 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. For purposes of Sec. 96.21, 96.42, or 96.70 and except as
provided in Sec. 96.5 or subpart I of this part, for a unit that is not
a NOX Budget unit under Sec. 96.4 on the date of
commencement of operation, the date the unit becomes a NOX
Budget unit under Sec. 96.4 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 account means a NOX Allowance Tracking System
account, established by the Administrator for the 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.
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 use date means the first control period for which a
NOX allowance can be used for the purpose of meeting a
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, a permanent
record of emissions, expressed in pounds per million British thermal
units (lb/mmBtu) for nitrogen oxides. The equipment also provides, for
each hour, a permanent record of emissions, expressed in tons per hour
for nitrogen oxides. The following systems are component parts included
in a continuous emission monitoring system:
(1) Flow monitor;
(2) Nitrogen oxides pollutant concentration monitors;
(3) Diluent gas monitor (oxygen or carbon dioxide);
(4) A continuous moisture monitor 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.
EPA means the United States Environmental Protection Agency. 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 the combustion of fossil fuel, alone or in
combination with any other fuel, where the fossil fuel comprises more
than 50 percent of the annual heat input on a Btu basis.
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
[[Page 25977]]
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.
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 subpart H 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
subpart 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 the tonnage
equivalent of the NOX allowances allocated to a
NOX Budget unit for use in a control period adjusted, as of
the NOX allowance transfer deadline, by transfers to or from
the unit's compliance account, or the overdraft account of the source
where the unit is located, of NOX allowances available for
compliance deductions for the unit for the control period in accordance
with Sec. 96.54.
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 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 regional nitrogen
oxides air pollution control and emission reduction program established
in accordance with this part and pursuant to Sec. 51.121 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. 96.4 or Sec. 96.80.
Operating means, with regard to a unit under Secs. 96.22(d)(2) and
96.80, 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. 96.83(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. 96.83 is being or has been submitted 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. 96.83 is being or has
been submitted; 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. 96.83 is being or has been submitted; or
[[Page 25978]]
(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. 96.83 is being or has been submitted 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. 96.83 is being or has been submitted; 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. 96.53(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. 51.121(c) 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, that adopts a NOX Budget Trading Program pursuant
to Sec. 51.121 of this chapter. To the extent a State incorporates by
reference this part, the term ``State'' shall mean the incorporating
State. The term ``State'' shall have its conventional meaning where
such meaning is clear from the context.
State trading program budget means the total number of
NOX tons apportioned to all NOX Budget units in a
given State, in accordance with the NOX Budget Trading
Program, for use in a given control period.
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 as meeting the requirements of title V of
the Clean Air Act and part 70 or 71 of this chapter.
Ton or tonnage means any ``short ton'' (i.e., 2,000 pounds). For
the purpose of determining compliance with the NOX Budget
emissions limitation, total tons for a control period shall be
calculated as the sum of all recorded hourly emissions (or the tonnage
equivalent of the recorded hourly emissions rates) in accordance with
subpart H of this part, with any remaining fraction of a ton equal to
or greater than 0.50 ton deemed to equal one ton and any fraction of a
ton less than 0.50 ton deemed to equal zero tons.
Unit means a 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) for use within the plant
and for sale; or
(2) In the case of a unit that uses heat input for purposes other
than electrical generation, the total steam pressure (psia) produced 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.
Sec. 96.3 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. 96.4 Applicability.
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:
(a) Any unit that, any time on or after January 1, 1995, serves a
generator with a nameplate capacity greater than 25 MWe; or
(b) Any unit that is not a unit under paragraph (a) of this section
and that, any time on or after January 1, 1995, does not serve a
generator and has a maximum design heat input greater than 250 mmBtu/
hr.
Sec. 96.5 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. 96.2, 96.3, 96.4, 96.7 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
[[Page 25979]]
B of this part) shall submit a statement to the permitting authority
otherwise responsible for administering a 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 the 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. 96.22
for the unit not less than 18 months (or such lesser time provided
under the permitting authority's title V operating permits regulations)
prior to the later of May 1, 2003 or the date on which the unit is to
first resume operation.
(ii) A unit exempt under this section and located at a source that
is required, or but for this exemption would be required, to have a
non-title V permit shall not resume operation unless the NOX
authorized account representative of the source submits a complete
NOX Budget permit application under Sec. 96.22 for the unit
not less than 18 months (or such lesser time provided under the
permitting authority's non-title V permits regulations) 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. 96.6 Standard requirements.
(a) Permit Requirements. (1) The NOX authorized account
representative of each NOX Budget source and each
NOX Budget unit at the source shall:
(i) Submit to the permitting authority a complete NOX
Budget permit application under Sec. 96.22 in accordance with the
deadlines specified in Sec. 96.21(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
and each NOX Budget unit 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.
(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. 96.54, 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. 96.42(d) 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 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. 96.5 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 permitting
authority or 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
[[Page 25980]]
deemed to amend automatically, and become a part of, the NOX
Budget unit's NOX Budget permit 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. 96.54(d)(1); and
(ii) Pay any fine, penalty, or assessment or comply with any other
remedy imposed under Sec. 96.54(d)(3).
(2) [Reserved]
(e) Recordkeeping and Reporting Requirements. (1) Unless otherwise
provided, the owners and operators of the NOX Budget source
and each NOX Budget unit at the source shall keep on site at
the source each of the following documents for a period of 5 years from
the date the document is created. This period may be extended for
cause, at any time prior to the end of 5 years, in writing by the
permitting authority or the Administrator.
(i) The account certificate of representation for the
NOX authorized account representative for the source and
each NOX Budget unit at the source and all documents that
demonstrate the truth of the statements in the account certificate of
representation, in accordance with Sec. 96.13; ``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. 96.5 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. 96.5 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. 96.7 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. 96.10 Authorization and responsibilities of the NOX
authorized account representative.
(a) Except as provided under Sec. 96.11, 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. 96.13, 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. 96.13 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
[[Page 25981]]
for each NOX Budget source on behalf of which the submission
is made. Each such submission shall include the following certification
statement by the NOX authorized account representative: ``I
am authorized to make this submission on behalf of the owners and
operators of the NOX Budget sources or NOX Budget
units for which the submission is made. I certify under penalty of law
that I have personally examined, and am familiar with, the statements
and information submitted in this document and all its attachments.
Based on my inquiry of those individuals with primary responsibility
for obtaining the information, I certify that the statements and
information are to the best of my knowledge and belief true, accurate,
and complete. I am aware that there are significant penalties for
submitting false statements and information or omitting required
statements and information, including the possibility of fine or
imprisonment.''
(2) The permitting authority and the Administrator will accept or
act on a submission made on behalf of owner or operators of a
NOX Budget source or a NOX Budget unit only if
the submission has been made, signed, and certified in accordance with
paragraph (e)(1) of this section.
Sec. 96.11 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. 96.13, 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. 96.10(a), 96.12, 96.13, and
96.51, 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. 96.12 Changing the NOX authorized account
representative 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. 96.13. 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. 96.13. 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. 96.13 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 or notice 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.
[[Page 25982]]
Sec. 96.14 Objections concerning the NOX authorized account
representative.
(a) Once a complete account certificate of representation under
Sec. 96.13 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. 96.13 is received by the
Administrator.
(b) Except as provided in Sec. 96.12(a) or (b), no objection or
other communication submitted to the permitting authority or the
Administrator concerning the authorization, or any representation,
action, inaction, or submission of the NOX authorized
account representative shall affect any representation, action,
inaction, or submission of the NOX authorized account
representative or the finality of any decision or order by the
permitting authority or the Administrator under the NOX
Budget Trading Program.
(c) Neither the permitting authority nor the Administrator will
adjudicate any private legal dispute concerning the authorization or
any representation, action, inaction, or submission of any
NOX authorized account representative, including private
legal disputes concerning the proceeds of NOX allowance
transfers.
Subpart C--Permits
Sec. 96.20 General NOX budget trading program permit
requirements.
(a) Each NOX Budget source shall have a federally
enforceable permit, which 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, and State and EPA review.
(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, and State and EPA review.
(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. 96.21 Submission of NOX Budget permit applications.
(a) Duty to apply. The NOX authorized account
representative of any NOX Budget source with one or more
NOX Budget units shall submit to the permitting authority a
complete NOX Budget permit application under Sec. 96.22 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. 96.4 that commence operation before January 1, 2000, the
NOX authorized account representative shall submit a
complete NOX Budget permit application under Sec. 96.22
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. 96.4 that commences operation on or after January 1, 2000, the
NOX authorized account representative shall submit a
complete NOX Budget permit application under Sec. 96.22
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. 96.4 that commence operation before January 1, 2000, the
NOX authorized account representative shall submit a
complete NOX Budget permit application under Sec. 96.22
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. 96.4 that commences operation on or after January 1, 2000, the
NOX authorized account representative shall submit a
complete NOX Budget permit application under Sec. 96.22
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. 96.22 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. 96.22 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. 96.22 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. 96.4 or under subpart I of this part;
(c) The standard requirements under Sec. 96.6; and
(d) For each NOX Budget opt-in unit at the
NOX Budget source, the following
[[Page 25983]]
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 96.4 and is not covered by a retired unit exemption
under 40 CFR 96.5 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 96.2.''
Sec. 96.23 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. 96.22 as approved or adjusted by the permitting authority.
(b) Each NOX Budget permit is deemed to incorporate
automatically the definitions of terms under Sec. 96.2 and, upon
recordation by the Administrator under subparts F, G, or I of this
part, every allocation, transfer, or deduction of a NOX
allowance to or from the compliance accounts of the NOX
Budget units covered by the permit or the overdraft account of the
NOX Budget source covered by the permit.
Sec. 96.24 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. 96.21(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. 96.25 NOX Budget permit revisions.
(a) For a NOX Budget source with a title V operating
permit, except as provided in Sec. 96.23(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. 96.23(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. 96.30 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. 96.54 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. 96.54(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. 96.31 Permitting authority's and Administrator's action on
compliance certifications.
(a) The permitting authority or 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 allowances from or return
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.
[[Page 25984]]
Subpart E--NOX Allowance Allocations
Sec. 96.40 State trading program budget.
The State trading program budget allocated by the permitting
authority under Sec. 96.42 will equal the total number of tons of
NOX emissions apportioned to the NOX Budget units
under Sec. 96.4 in the State, as determined by the applicable, approved
State implementation plan.
Sec. 96.41 Timing requirements for NOX allowance
allocations.
(a) By September 30, 1999, the permitting authority will submit to
the Administrator the NOX allowance allocations, in
accordance with Sec. 96.42, for the control periods in 2003, 2004,
2005, 2006, and 2007. If the permitting authority fails to submit to
the Administrator the NOX allowance allocations in
accordance with this paragraph (a), the Administrator will allocate
NOX allowances for the applicable control periods, in
accordance with Sec. 96.42, within 60 days of the deadline for
submission by the permitting authority.
(b) By December 31, 2002 and December 31 of each year thereafter,
the permitting authority will submit to the Administrator the
NOX allowance allocations, in accordance with Sec. 96.42,
for the control period in the year that is 6 years after the year of
the applicable deadline for submission under this paragraph (b). If the
permitting authority fails to submit to the Administrator the
NOX allowance allocations in accordance with this paragraph
(b), the Administrator will allocate NOX allowances for the
applicable control period, in accordance with Sec. 96.42, within 60
days of the applicable deadline for submission by the permitting
authority.
Sec. 96.42 NOX allowance allocations.
(a)(1) The heat input (in mmBtu) used for calculating
NOX allowance allocations for each NOX Budget
unit under Sec. 96.4 will be:
(i) For a NOX allowance allocation under Sec. 96.41(a),
the average of the two highest amounts of the unit's heat input for the
control periods in 1995, 1996, and 1997; and
(ii) For a NOX allowance allocation under Sec. 96.41(b),
the unit's heat input for the control period in the year that is 6
years before the year for which the NOX allocation is being
calculated.
(2) The unit's total heat input for the control periods 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 permitting authority 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. 96.41, the permitting
authority will allocate to all NOX Budget units under
Sec. 96.4 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 98
percent of the tons of NOX emissions in the State trading
program budget under Sec. 96.40 in accordance with the following
procedures:
(1) The permitting authority will allocate NOX
allowances to each NOX Budget unit in an amount equaling
0.15 lb/mmBtu multiplied by the heat input determined under paragraph
(a) of this section.
(2) If the initial total number of NOX allowances
allocated to all NOX Budget units in the State for a control
period under paragraph (a)(1) of this section does not equal 98 percent
of the number of tons of NOX emissions in the State trading
program budget, the permitting authority 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 98 percent of the number of tons of NOX emissions in
the State trading program budget. This adjustment will be made by:
multiplying each unit's allocation by the total number of
NOX allowances allocated under paragraph (a)(1) of this
section divided by 98 percent of the number of tons of NOX
emissions in the State trading program budget, and rounding to the
nearest whole allowance as appropriate.
(c) For each control period under Sec. 96.41, the permitting
authority will allocate NOX allowances to NOX
Budget units under Sec. 96.4 in the State that commenced 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 permitting authority will establish a separate allocation
set-aside for each control period. Each allocation set-aside will be
allocated NOX allowances equal to 2 percent of the tons of
NOX emissions in the State trading program budget under
Sec. 96.40.
(2) The NOX authorized account representative of a
NOX Budget unit under paragraph (c) of this section may
submit to the permitting authority a request, in writing or in a format
specified by the permitting authority, to be allocated NOX
allowances for no more than five consecutive control periods under
Sec. 96.41, starting with the control period during which the
NOX Budget unit is projected to commence operation. 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
permitting authority issues a permit to construct the NOX
Budget unit.
(3) In a NOX allowance allocation request under
paragraph (c)(2) of this section, the NOX authorized account
representative 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 is projected to operate.
(4) The permitting authority will review, and allocate
NOX allowances pursuant to, NOX allowance
allocation requests under paragraph (c)(2) of this section in the order
that the requests are received by the permitting authority.
(i) Upon receipt of a NOX allowance allocation request,
the permitting authority will determine whether, and will make any
necessary adjustments to the request to ensure that, the control period
and the number of allowances specified are consistent with the
requirements of paragraphs (c)(2) and (3) 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 (c)(4)(i) of this section), the permitting authority will
allocate the full, adjusted amount of the NOX allowances
requested 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 (b)(4)(i) of this section), the permitting authority 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 permitting authority
will deny, and will not allocate any NOX allowances pursuant
to, any NOX allowance allocation requests under which
NOX allowances
[[Page 25985]]
have not already been allocated for the control period.
(5) Within 60 days of receipt of a NOX allowance
allocation request, the permitting authority will take appropriate
action under paragraph (c)(4) of this section and notify the
NOX authorized account representative that submitted the
request and the Administrator of the number of NOX
allowances (if any) allocated for the control period to the
NOX Budget unit.
(6) After September 30 of each year, the Administrator will
transfer any NOX allowances remaining in the allocation set-
aside for the control period for the year to the allocation set-aside
for the following control period.
(7) If additional NOX allowances are placed in the
allocation set-aside for the control period pursuant to paragraphs
(c)(6) or (d)(2) of this section, the permitting authority will
allocate NOX allowances, in accordance with paragraph (c)(4)
of this section, to any NOX allowance allocation requests
that were originally denied in whole or in part. The permitting
authority will notify the NOX authorized account
representative that submitted the request and the Administrator of the
number of NOX allowances (if any) allocated under this
paragraph (c)(7).
(d) For a NOX Budget unit that is allocated
NOX allowances under paragraph (c) of this section for a
control period, the Administrator will deduct NOX allowances
under Sec. 96.54(b) or (e) to account for the actual utilization of the
unit during the control period.
(1) The Administrator will calculate the number of NOX
allowances to be deducted to account for the unit's actual utilization
using the following formula, provided that the number of NOX
allowances to be deducted shall be zero if the number calculated is
less than zero:
Unit's NOX allowances deducted for actual utilization =
(Unit's NOX allowances allocated for control period)--
(Unit's actual control period utilization x 0.15 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 (c) of this section.
``Unit's actual control period utilization'' is the utilization (in
mmBtu), as defined in Sec. 96.2, of the unit during the control period.
(2) Any NOX allowances deducted by the Administrator in
accordance with paragraph (d) of this section will be transferred by
the Administrator to the permitting authority's allocation set-aside
for the following control period.
Subpart F--NOX Allowance Tracking System
Sec. 96.50 NOX Allowance Tracking System accounts.
(a) Nature and function of compliance accounts and overdraft
accounts. Consistent with Sec. 96.51(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 allowances pursuant to
subpart E of this part, transfers of allowances pursuant to subpart G
of this part, and deductions of allowances to cover NOX
emissions, account for actual utilization, or offset excess emissions
of NOX pursuant to Sec. 96.54 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. 96.51(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. 96.51 Establishment of accounts.
(a) Compliance accounts and overdraft accounts. Upon receipt of a
complete account certificate of representation under Sec. 96.13, the
Administrator will establish:
(1) A compliance account for each NOX Budget unit for
which the account certificate of representation was submitted; and
(2) An overdraft account for each source for which the account
certificate of representation was submitted and that has two or more
NOX Budget units.
(b) General accounts. (1) Any person may apply to open a general
account for the purpose of holding and transferring allowances. A
complete application for a general account shall be submitted to the
Administrator and shall include the following elements in a format
prescribed by the Administrator:
(i) Name, mailing address, e-mail address (if any), telephone
number, and facsimile transmission number (if any) of the
NOX authorized account representative and any alternate
NOX authorized account representative;
(ii) At the option of the NOX authorized account
representative, organization name and type of organization;
(iii) A list of all persons subject to a binding agreement for the
NOX authorized account representative 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.
(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 the 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: ``I
am authorized to make this
[[Page 25986]]
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 the 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 alternate NOX
authorized account representative shall submit a revision to the
application for a general account amending the list of persons having
an ownership interest with respect to the NOX allowances in
the general account to include the change.
(5)(i) Once a complete application for a general account under
paragraph (b)(1) of this section has been submitted and received, the
Administrator will rely on the application unless and until a
superseding complete application for a general account under paragraph
(b)(1) of this section is received by the Administrator.
(ii) Except as provided in paragraph (b)(4) of this section, no
objection or other communication submitted to the Administrator
concerning the authorization, or any representation, action, inaction,
or submission of the NOX authorized account representative
for a general account shall affect any representation, action,
inaction, or submission of the 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 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. 96.52 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. 96.53 Recordation of NOX allowance allocations.
(a) The Administrator will record the NOX allowances for
2003, 2004, 2005, 2006, and 2007 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. 96.88(a)(1) and (b) 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. 96.54, the Administrator will record
NOX allowances, as allocated to the unit under subpart E of
this part or under Sec. 96.88(a)(2) and (b), 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
[[Page 25987]]
identification number that will include digits identifying the year for
which the NOX allowance is allocated.
Sec. 96.54 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) Have compliance use dates prior to or the same as that 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. 96.60 by the NOX allowance transfer deadline for
that control period.
(b) Deductions for compliance. (1) Following the recordation, in
accordance with Sec. 96.61, 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. 96.42(d), 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. 96.42(d) 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. 96.30.
(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 with a compliance use date the
same as the year of the control period and that were allocated to the
unit under subpart E or I of this part;
(ii) Those NOX allowances with a compliance use date the
same as the year of the control period and that were transferred and
recorded in the account pursuant to subpart G of this part, in order of
their date of recordation;
(iii) Those NOX allowances with an earlier compliance
use date than the year of the control period and that were allocated to
the unit under subpart E or I of this part; and
(iv) Those NOX allowances with an earlier compliance use
date than the year of the control period and that were 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, with a compliance use date the same as the
year 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 their
compliance use date, 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, 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. 96.30.
Notwithstanding paragraph (b)(2)(i) of this section, the
Administrator will deduct NOX allowances until the number of
NOX allowances equals the identified percentage 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 in the year for which compliance is being determined 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. 96.55 Banking [Reserved].
Sec. 96.56 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
[[Page 25988]]
the NOX authorized account representative for the account.
Sec. 96.57 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, in writing or in a format specified by the
Administrator, requesting deletion of the account from the
NOX Allowance Tracking System and by correctly submitting
for recordation under Sec. 96.60 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. 96.60 or a statement, in writing
or in a format specified by the Administrator, 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. 96.60 Scope and 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. 96.61 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. 96.60;
(2) The transferror account includes each NOX allowance
identified by serial number in the transfer; and
(3) The transfer meets all other requirements of this part.
(b) A NOX allowance transfer that is submitted for
recordation following the NOX allowance transfer deadline
and that includes any NOX allowances with a compliance use
date that is prior to or the same as the year of 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. 96.53(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. 96.62 Notification.
(a) Notification of recordation. Within 5 business days of
recordation of a NOX allowance transfer under Sec. 96.61,
the Administrator will notify each party to the transfer. Notice will
be given, in writing or in a format to be specified by the
Administrator, 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. 96.61(a), the Administrator will notify, in
writing or in a format to be specified by the Administrator, 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. 96.70 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. 96.2 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. 96.2.
(a) Compliance dates. (1)(i) The owner or operator of each
NOX Budget unit under Sec. 96.4 that commences operation
before January 1, 2000 shall ensure that all monitoring systems
required under this subpart for monitoring NOX emission rate
and heat input are installed, all certification tests required under
Sec. 96.71 are successfully completed, and all other provisions of this
subpart and part 75 of this chapter applicable to such systems are met
on or before May 1, 2000.
(ii) The owner or operator of each NOX Budget unit under
paragraph (a)(1) of this section that has not successfully completed
all certification tests required under Sec. 96.71 by May 1, 2001 shall
determine and report hourly NOX emission rate and heat
input, starting on such date until all such certification tests are
successfully completed, using either:
(A) The maximum potential NOX emission rate and the
maximum potential hourly heat input of the unit;
(B) Reference methods under Sec. 75.22 of this chapter; or
(C) Monitored data validated using the procedures in
Sec. 75.20(b)(3) of this chapter where the term ``recertification'' is
replaced by the term ``initial certification.''
(2)(i) The owner or operator of each NOX Budget unit
under Sec. 96.4 that commences operation on or after January 1, 2000
shall ensure that all monitoring systems required under this subpart
for monitoring NOX emission rate and heat input are
installed, all certification tests required under Sec. 96.71 are
successfully completed, and all other provisions of this subpart and
part 75 applicable to such systems are met on or before the later of
the following dates:
(A) May 1, 2001; or
(B) Not later than the earlier of 180 days after the date on which
the unit commences operation or, for units under Sec. 96.4(a), 90 days
after the date on which the unit commences commercial operation.
(ii) The owner or operator of each NOX Budget unit under
paragraph (a)(2) of this section that has not successfully completed
all certification tests required under Sec. 96.71 by the later of May
1, 2001 or the date on which the unit
[[Page 25989]]
commences operation shall determine and report hourly NOX
emission rate and heat input, starting on such date until all such
certification tests are successfully completed, using either:
(A) The maximum potential NOX emission rate and the
maximum potential hourly heat input of the unit;
(B) Reference methods under Sec. 75.22 of this chapter; or
(C) Monitored data validated using the procedures in
Sec. 75.20(b)(3) of this chapter where the term ``recertification'' is
replaced by the term ``initial certification.''
(3)(i) The owner-operator of a NOX Budget unit that
completes construction of a new stack or flue after the applicable
deadline in paragraph (a)(1)(i) or (2)(i) of this section or under
subpart I of this part, shall ensure, with regard to such new stack or
flue, that all monitoring systems required under this subpart for
monitoring NOX emission rate and heat input are installed,
all certification tests required under Sec. 96.71 are successfully
completed, and all other provisions of this subpart and part 75 are met
not later than 90 days after the date on which emissions first exit to
the atmosphere through such new stack or flue.
(ii) The owner or operator of each NOX Budget unit under
paragraph (a)(3)(i) of this section that has not successfully completed
all certification tests required under Sec. 96.71 by not later than 90
days after the date on which emissions first exit to the atmosphere
through the new stack or flue under paragraph (a)(3)(i) of this section
shall determine and report hourly NOX emission rate and heat
input, starting on such date until all such certification tests are
successfully completed, using either:
(A) The maximum potential NOX emission rate and the
maximum potential hourly heat input of the unit;
(B) Reference methods under Sec. 75.22 of this chapter; or
(C) Monitored data validated using the procedures in
Sec. 75.20(b)(3) of this chapter where the term ``recertification'' is
replaced by the term ``initial certification.''
(4) The provisions of this subpart are applicable to a unit for
which an application for a NOX Budget opt-in permit is being
or has been submitted, as provided in subpart I of this part.
(b) Prohibitions. (1) No owner or operator of a NOX
Budget unit shall use any alternative monitoring system, alternative
reference method, or any other alternative for the required continuous
emission monitoring system without having obtained prior written
approval in accordance with Sec. 96.75.
(2) No owner or operator of a NOX Budget unit shall
operate the unit so as to discharge, or allow to be discharged,
NOX emissions to the atmosphere without accounting for all
such emissions in accordance with the applicable provisions of this
subpart and part 75 of this chapter.
(3) No owner or operator of a NOX Budget unit shall
disrupt the continuous emission monitoring system, any portion thereof,
or any other approved emission monitoring method, and thereby avoid
monitoring and recording NOX mass emissions discharged into
the atmosphere, except for periods of 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.
(4) No owner or operator of a NOX Budget unit shall
retire or permanently discontinue use of the continuous emission
monitoring system, any component thereof, or any other approved
emission monitoring system under this subpart, except under any one of
the following circumstances:
(i) During the period that the unit is covered by a retired unit
exemption under Sec. 96.5 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. 96.71(b)(2)(i).
Sec. 96.71 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 combined 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 petition shall be
resubmitted to the Administrator under Sec. 96.75(a) to determine if
the approval should apply under the NOX Budget Trading
Program.
(2) For any additional NOX emission rate CEMS required
under the common stack provisions in Sec. 75.72 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, and the
owner or operator of a NOX Budget unit that is subject to an
acid rain emissions limitation shall meet the following initial
certification and recertification procedures for any additional
NOX emission rate CEMS required under the common stack
provisions in Sec. 75.72 of this chapter.
(1) Requirements for initial certification or recertification. (i)
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
and shall ensure that all applicable certification tests are
successfully completed by the deadlines specified in Sec. 96.70(a). 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
is required.
(ii) Whenever the owner or operator makes a replacement,
modification, or change in a certified monitoring system that is
determined by the permitting authority or the Administrator to
significantly affect the ability of the system to accurately measure or
record NOX emission rate 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 by performing all of the recertification testing required under
Sec. 75.20 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 is determined by the permitting
authority or the Administrator to significantly change the flow or
concentration profile, the owner or operator shall recertify the
continuous emissions monitoring system. 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. Any change to a continuous
emissions monitoring system for which
[[Page 25990]]
the permitting authority or the Administrator determines that a
relative accuracy test audit (RATA) is not necessary, shall not require
recertification, and any other tests that the permitting authority or
the Administrator determines to be necessary (e.g., linearity checks,
calibration error tests, automated data acquisition and handling system
(DAHS) verifications) shall be performed. These other tests shall be
considered diagnostic tests rather than recertification tests. The data
validation procedures in Sec. 75.20(b)(3) of this chapter shall be
applied (replacing the term ``recertification'' with the term
``diagnostic'') to linearity checks, 7-day calibration error tests, and
cycle time tests when these are required as diagnostic tests.
(2) Certification approval process for initial certifications and
recertification. (i) Notification of certification. The NOX
authorized account representative shall submit to the permitting
authority a written notice of the dates of certification in accordance
with Sec. 96.73.
(ii) Certification application. The NOX authorized
account representative shall submit to 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 Sec. 75.73 of
this chapter.
(iii) Upon the earlier of the successful completion of the required
certification procedures of paragraph (b)(1) of this section or the
hour in which data that were considered conditionally valid according
to the procedures in Sec. 75.20(b)(3) of this chapter for the
monitoring system or component thereof, the monitoring system or
component thereof shall be deemed provisionally certified for use under
the NOX Budget Trading Program for a period not to exceed
120 days after receipt by the permitting authority of the complete
certification application for the monitoring system or component
thereof under paragraph (b)(2)(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
permitting authority does not invalidate the provisional certification
by issuing a notice of disapproval within 120 days of receipt of the
complete certification application by the permitting authority.
(iv) Certification application formal approval process. The
permitting authority 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)(2)(ii) of this section. In the event the permitting
authority does not issue such a notice within such 120-day period, each
monitoring system which meets the applicable performance requirements
of part 75 of this chapter and is included in the certification
application will be deemed certified for use under the NOX
Budget Trading Program.
(A) Approval notice. If the certification application is complete
and shows that each continuous emission monitoring system meets the
applicable performance requirements of part 75 of this chapter, then
the permitting authority 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)(2)(ii) of this section has been
received by the permitting authority. If the certification application
is not complete, then the permitting authority 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 permitting authority may issue a notice of disapproval
under paragraph (b)(2)(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)(2)(iv)(B) of this section has been met, the permitting
authority 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 permitting
authority 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)(2)(v) of this section for each
monitoring system or component thereof which is disapproved for initial
certification.
(D) Audit decertification. The permitting authority may issue a
notice of disapproval of the certification status of a monitor in
accordance with Sec. 96.72(b).
(v) Procedures for loss of certification. If the permitting
authority issues a notice of disapproval of a certification application
under paragraph (b)(2)(iv)(C) of this section or a notice of
disapproval of certification status under paragraph (b)(2)(iv)(D) of
this section, then:
(A) The owner or operator shall substitute, for each hour of unit
operation during the period of invalid data, the maximum potential
NOX emission rate or the maximum potential hourly heat input
of the unit as applicable, until the earlier of the time, date, and
hour (after the monitoring system or component thereof is adjusted,
repaired, or replaced) when certification tests are successfully
completed or the time, date, and hour specified under the data
validation procedures under Sec. 75.20(b)(3) 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 the procedures in
paragraphs (b)(2)(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 permitting authority's notice of disapproval, no later
than 30 unit operating days after the date of issuance of the notice of
disapproval.
Sec. 96.72 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 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. 96.71 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
[[Page 25991]]
of the audit, the permitting authority 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 permitting authority 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. 96.71 for each
disapproved system.
Sec. 96.73 Notifications.
The NOX authorized account representative for a
NOX Budget unit shall submit written notice to the
permitting authority and the Administrator in accordance with
Sec. 75.61 of this chapter, except that if the unit is not subject to
an acid rain emissions limitation, the notification is only required to
be sent to the permitting authority.
Sec. 96.74 Recordkeeping and reporting.
(a) The owner or operator of a NOX Budget unit that is
subject to an acid rain emissions limitation shall meet recordkeeping
and reporting requirements in subparts F and G of part 75 of this
chapter and paragraph (b) of this section, except that:
(1) For any additional NOX emission rate CEMS required
under the common stack provisions of Sec. 75.72 of this chapter, the
owner or operator shall meet the requirements of paragraph (b)(2) of
this section;
(2) If the NOX authorized account representative for the
unit is not the same person as the designated representative for the
unit under subpart B of part 72 of this chapter, all submissions under
subpart F or G of part 75 of this chapter must be signed by both the
NOX authorized account representative and the designated
representative; and
(3) Each quarterly report submitted to meet the requirements of
Sec. 75.64 of this chapter shall also include the data and information
required in Sec. 75.73 of this chapter.
(b) For NOX Budget units that are not subject to an acid
rain emissions limitation:
(1) Monitoring Plans. The owner or operator shall comply with
requirements of Sec. 75.62 of this chapter, except that the monitoring
plan shall include all of the information required by Sec. 75.73 of
this chapter.
(2) Certification Applications. The NOX authorized
account representative shall submit an application to the permitting
authority within 45 days after completing all initial certification or
recertification tests including the information required under
Sec. 75.73 of this chapter.
(3) Quarterly reports. (i) (A) Except as provided in paragraph
(b)(3)(i)(B) of this section, the NOX authorized account
representative shall submit electronically a quarterly report for each
calendar quarter beginning with the earlier of the calendar quarter
that includes the date of initial provisional certification under
Sec. 96.71(b)(2)(iii) or May 1, 2001. Data shall be reported from the
earlier of the date and hour corresponding to the date and hour of
provisional certification or May 1, 2001.
(B) If the unit commences operation after May 1, 2001, the
NOX authorized account representative shall submit
electronically a quarterly report for each calendar quarter beginning
with the calendar quarter in which the unit commences operation. Data
shall be reported from the date and hour corresponding to the date that
the unit commenced operation.
(ii) Each quarterly report shall be submitted to the Administrator
within 30 days following the end of each calendar quarter and shall
include, for each NOX Budget unit (or group of units using a
common stack), all of the data and information required in Sec. 75.73
of this chapter.
(iii) 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:
(A) 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
(B) With regard to a unit with add-on 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.
(iv) The NOX authorized account representative shall
comply with all of the quarterly reporting requirements in
Sec. 75.64(d), (f), and (g) of this chapter.
Sec. 96.75 Petitions.
(a)(1) The NOX authorized account representative of a
NOX Budget unit that is subject to an acid rain emissions
limitation 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. 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, in
consultation with the permitting authority.
(2) Notwithstanding paragraph (a)(1) of this section, if the
petition requests approval to apply an alternative to a requirement
concerning any additional CEMS required under the common stack
provisions of Sec. 75.70 of this chapter, the petition is governed by
paragraph (b) of this section.
(b)(1) The NOX authorized account representative of a
NOX Budget unit that is not subject to an acid rain
emissions limitation may submit a petition under Sec. 75.66 of this
chapter to the permitting authority and the Administrator requesting
approval to apply an alternative to any requirement of this subpart.
The NOX authorized account representative of a
NOX Budget unit that is subject to an acid rain emissions
limitation may submit a petition under Sec. 75.66 of this chapter to
the permitting authority and the Administrator requesting approval to
apply an alternative to a requirement concerning any additional CEMS
required under the common stack provisions of Sec. 75.50 of this
chapter. (2) Application of an alternative to any requirement of this
subpart is in accordance with this subpart only to the extent the
petition under paragraph (b)(1) of this section is approved by both the
permitting authority and the Administrator.
Subpart I--Individual Unit Opt-Ins
Sec. 96.80 Applicability.
A unit that is in the State, is not a NOX Budget unit
under Sec. 96.4, 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. 96.5 that is in effect, or that is not operating, is not
eligible to become a NOX Budget opt-in source.
[[Page 25992]]
Sec. 96.81 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. 96.82 NOX authorized account representative.
A unit for which an application for a NOX Budget opt-in
permit is being or has been 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. 96.83 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. 96.80 may submit to the permitting authority at any time,
except as provided under Sec. 96.86(g):
(1) A complete NOX Budget permit application under
Sec. 96.22;
(2) A monitoring plan submitted in accordance with subpart H of
this part; and
(3) A complete account certificate of representation under
Sec. 96.13, 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 a
complete NOX Budget permit application under Sec. 96.22 to
renew the NOX Budget opt-in permit in accordance with
Sec. 96.21(c) and, if applicable, an updated monitoring plan in
accordance with subpart H of this part.
Sec. 96.84 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. 96.83 is submitted, in
accordance with Sec. 96.20 and the following:
(a) Interim review of monitoring plan. The permitting authority
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. 96.83. A monitoring plan is sufficient, for
purposes of interim review, if the plan appears to contain information
demonstrating that the NOX emissions rate and heat input of
the unit are monitored and reported in accordance with subpart H of
this part. A determination of sufficiency shall not be construed as
acceptance or approval of the unit's monitoring plan.
(b) If the permitting authority 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 80 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 permitting authority will 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 permitting authority, in writing, 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. 96.83. 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. 96.20.
(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 permitting authority determines that the unit
does not qualify as a NOX Budget opt-in source under
Sec. 96.80, the permitting authority will issue a draft denial of a
NOX Budget opt-in permit for the unit in accordance with
Sec. 96.20.
(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. 96.83 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. 96.83.
(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. 96.85 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. 96.22 as approved or adjusted by the
permitting authority.
(b) Each NOX Budget opt-in permit is deemed to
incorporate automatically the definitions of terms under Sec. 96.2 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. 96.86 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 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 to be
effective, the NOX authorized account
[[Page 25993]]
representative must submit or must have submitted to the permitting
authority an annual compliance certification report in accordance with
Sec. 96.30.
(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 have 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. 96.54(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 with the same or earlier compliance
use date as any NOX allowances allocated to that source
under Sec. 96.88 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 permitting
authority will issue a notification to 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 permitting authority will issue a
notification to 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 permitting authority 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 permitting authority 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. 96.83 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. 96.87 Change in regulatory status.
(a) Notification. When a NOX Budget opt-in source
becomes a NOX Budget unit under Sec. 96.4, 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. 96.4, 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. 96.23 as of an effective date that is the date on which such
NOX Budget opt-in source becomes a NOX Budget
unit under Sec. 96.4.
(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 with the same or earlier compliance use date as:
(1) Any NOX allowances allocated to the NOX
Budget unit (as a NOX Budget opt-in source) under Sec. 96.88
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. 96.88
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 their compliance use date,
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. 96.42, 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. 96.42.
(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. 96.42 for the control period: the number of NOX
allowances otherwise allocated to the NOX Budget unit under
Sec. 96.42(c) 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,
[[Page 25994]]
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. 96.83(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 with the same or earlier compliance
use date as any NOX allowances allocated to the
NOX Budget opt-in source under Sec. 96.88 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 their compliance use date, 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. 96.54, the Administrator will close the
NOX Budget opt-in source's compliance account and will
establish, and transfer any remaining allowances to, a new general
account for the owners and operators of the NOX Budget opt-
in source. The NOX authorized account representative for the
NOX Budget opt-in source shall become the NOX
authorized account representative for the general account.
Sec. 96.88 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 permitting
authority will allocate NOX allowances to the NOX
Budget opt-in source and submit to the Administrator the allocation 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 permitting authority will
allocate NOX allowances to the NOX Budget opt-in
source, and submit to the Administrator allocations 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. 96.84(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 permitting authority 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. 96.84(c); or
(ii) The most stringent State or Federal NOX emissions
limitation applicable to the NOX Budget opt-in source during
the control period.
[FR Doc. 98-11873 Filed 5-8-98; 8:45 am]
BILLING CODE 6560-50-P