[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 (NO<INF>X</INF>)--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 
NO<INF>X</INF> 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 
<a href="/cdn-cgi/l/email-protection#7615191a13581217001f123613061758111900"><span class="__cf_email__" data-cfemail="20434f4c450e4441564944604550410e474f56">[email protected]</span></a>. 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<a href="/cdn-cgi/l/email-protection#e38c80888697a38693828e828a8fcd869382cd848c95"><span class="__cf_email__" data-cfemail="731c10181607331603121e121a1f5d1603125d141c05">[email protected]</span></a>. 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: <a href="http://
www.epa.gov/scram001/regmodcenter/t28.htm">http://
www.epa.gov/scram001/regmodcenter/t28.htm</a>.

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. NO<INF>X</INF> Budget Trading Program
    A. Program Summary
    1. Purpose of the NO<INF>X</INF> Budget Trading Program
    2. Emissions Reductions Required by the Proposed Transport 
Rulemaking
    3. Benefits of Participating in the NO<INF>X</INF> Budget 
Trading Program
    4. EPA's Proposal
    B. Evolution of the NO<INF>X</INF> Budget Trading Program
    1. OTC's NO<INF>X</INF> Budget Program
    2. OTAG Process
    3. EPA Model Trading Program Workshops
    4. RECLAIM Program
    C. NO<INF>X</INF> 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. NO<INF>X</INF> Authorized Account Representative (AAR)
    3. Permits
    a. General Requirements
    b. Title V/Non-title V Permits
    c. NO<INF>X</INF> Budget Permit Application Deadlines
    d. NO<INF>X</INF> Budget Trading Program Permit Application
    e. NO<INF>X</INF> Budget Permit Issuance
    f. NO<INF>X</INF> Budget Permit Revisions
    4. Compliance Certification
    5. NO<INF>X</INF> Allowance Allocations
    a. Development of State Trading Program Budget
    b. Timing Requirements
    c. Options for NO<INF>X</INF> Allowance Allocation 
Recommendation
    i. Basis for Developing an Allocation Recommendation
    ii. Options for an Allocation Recommendation
    iii. Framework for an Allocation Recommendation
    6. NO<INF>X</INF> 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 NO<INF>X</INF> 
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 NO<INF>X</INF> 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 <SUP>1</SUP> (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 NO<INF>X</INF> 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.
---------------------------------------------------------------------------

    \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 NO<INF>X</INF> 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, NO<INF>X</INF> 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 NO<INF>X</INF> emissions budget, as well as the 
definition of the NO<INF>X</INF>

[[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
------------------------------------------------------------------------

    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 
NO<INF>X</INF> 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
----------------------------------------------------------------------------------------------------------------


[[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 NO<INF>X</INF> 
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 NO<INF>X/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 NO<INF>X 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 NO<INF>X</INF> 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 NO<INF>X</INF>) 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, NO<INF>X</INF> emissions. At the same time, because most 
electricity generation relies on fossil-fuel inputs that, in turn, 
result in NO<INF>X</INF> emissions, even under this output-based 
approach, the State budgets would bear a strong relationship to amount 
of actual NO<INF>X</INF> 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 NO<INF>X</INF> 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-NO<INF>X</INF>-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:
    <bullet> 70 percent control for large (> 250 mmBtu/hr) sources 
(measured from uncontrolled 2007 emissions);
    <bullet> Reasonably Available Control Technology (RACT)-level 
controls for all other NO<INF>X</INF> sources with more than 1.0 tons 
per day (tpd) of NO<INF>X</INF> emissions (medium-sized sources);
    <bullet> Small source NO<INF>X</INF> 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 NO<INF>X/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 NO<INF>X 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 
NO<INF>X</INF> 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 NO<INF>X</INF> 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 NO<INF>X</INF> 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 NO<INF>X 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 NO<INF>X</INF> cap-and-trade program 
with a summer NO<INF>X</INF> 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 NO<INF>X</INF> point sources, EPA estimated annual compliance 
costs for achieving a total summer NO<INF>X</INF> 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 NO<INF>X</INF> 
emissions levels. Table III-9 shows the estimated annual compliance 
costs and average cost effectiveness.

  Table III-8.--Population of Emissions Sources and NO<INF>X Emissions After 
             Compliance with the Ozone Transport Rulemaking             
------------------------------------------------------------------------
                                                          Ozone season  
         Budget component               Number of      emissions  (1,000
                                         sources*          NO<INF>X 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 NO<INF>X     
  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 
NO<INF>X</INF> 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.<SUP>2</SUP>
---------------------------------------------------------------------------

    \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 
NO<INF>X</INF> 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 NO<INF>X</INF> 
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 NO<INF>X</INF> 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 NO<INF>X</INF> 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 
NO<INF>X</INF> 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 NO<INF>X</INF> 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:
    <bullet> 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.
    <bullet> 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 
NO<INF>X</INF> 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 (SO<INF>2</INF>) emissions, the South Coast Air Quality 
Management District's Regional Clean Air Incentives Market for 
SO<INF>2</INF> and NO<INF>X</INF>, and the Ozone Transport Commission's 
NO<INF>X</INF> 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 NO<INF>X</INF> 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.
---------------------------------------------------------------------------

    \3\ NO<INF>X</INF> 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.
---------------------------------------------------------------------------

    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 NO<INF>X</INF> 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 NO<INF>X</INF> 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\
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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 NO<INF>X</INF> 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\
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    To assist States with the development and implementation of an 
emissions budget for large combustion sources, EPA is proposing the 
NO<INF>X</INF> Budget Trading Program in section V of today's notice. 
States may voluntarily choose to participate in the NO<INF>X</INF> 
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 NO<INF>X</INF> 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 NO<INF>X</INF> 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 NO<INF>X</INF> 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 NO<INF>X</INF> sources, and particularly 
combustion NO<INF>X</INF> 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 (<a href="http://www.epa.gov/ttn/chief/
ap42etc.html">http://www.epa.gov/ttn/chief/
ap42etc.html</a>).
    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.
    <bullet> ``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

    <bullet> ``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

    <bullet> ``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

    <bullet> ``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

    <bullet> ``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.
    <bullet> ``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.
    <bullet> ``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 NO<INF>X</INF> 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).<SUP>6</SUP> This approach would allow States to create an 
offset ``pool'' composed of actual emissions reductions that generally 
will be achieved as a result of NO<INF>X</INF> control strategies 
adopted in response to the SIP call. To create an offset pool, at the 
time States revise their SIPs to include statewide NO<INF>X</INF> 
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 NO<INF>X</INF> 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 NO<INF>X</INF> emissions decreases where 
appropriate.)
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    The EPA currently anticipates that those States subject to the 
NO<INF>X</INF> 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 NO<INF>X</INF> 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.
    <bullet> ``Procedures for Preparing Emissions Projections'' EPA-
450/4-91-019, July 1991 (Hard copy only available).
    <bullet> ``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 NO<INF>X</INF> control measures beginning in 
September 2002 <SUP>7</SUP> 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 NO<INF>X</INF> 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.
---------------------------------------------------------------------------

    \7\ In this discussion of reporting requirements, September 2002 
is presumed to be the compliance date for NO<INF>X</INF> 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.
---------------------------------------------------------------------------

    The EPA will use 2007 data to assess how each State's SIP actually 
performed in meeting the statewide NO<INF>X</INF> 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 NO<INF>X</INF> 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 NO<INF>X</INF> 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 NO<INF>X</INF> 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 NO<INF>X</INF> 
budgets proposed in the SIP call. This would include all NO<INF>X</INF> 
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 NO<INF>X</INF> 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 <SUP>8</SUP> for any emissions source 
(point, area, or mobile) to which additional controls are being applied 
for the purpose of meeting the NO<INF>X</INF> budget, with certain 
exceptions as discussed below, and from any emissions source that will 
either sell or buy NO<INF>X</INF> emission allowances. The EPA is also 
proposing that States develop and submit comprehensive statewide 
NO<INF>X</INF> inventories, including all NO<INF>X</INF> sources, 
controlled and uncontrolled, every 3 years, starting with data for the 
year 2002.
---------------------------------------------------------------------------

    \8\ 2003 would be the year for which the data would be reported. 
The actual reporting schedule is given in the Reporting Schedule 
Section.
---------------------------------------------------------------------------

    The tracking requirements for meeting the NO<INF>X</INF> 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 NO<INF>X</INF> 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 NO<INF>X</INF> 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 NO<INF>X</INF> 
budgets proposed in the SIP call. This would include all NO<INF>X</INF> 
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 
NO<INF>X</INF> 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.<SUP>9</SUP> The EPA proposes that States be 
required to report NO<INF>X</INF> emissions annually for all point 
sources that are subject to regulations specifically for the purpose of 
meeting the NO<INF>X</INF> 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.
---------------------------------------------------------------------------

    \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 
NO<INF>X</INF> emissions. Non-mobile sources which emit less than 
100 tons per year of NO<INF>X</INF> would be considered area 
sources. This definition of point source is consistent with current 
reporting requirements for NO<INF>X</INF> emissions.
---------------------------------------------------------------------------

    b. Area Sources. The EPA proposes that the State determine area 
source NO<INF>X</INF> ozone season emissions for source categories that 
are controlled beyond otherwise applicable Federal, State or local 
measures to meet the NO<INF>X</INF> 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 NO<INF>X</INF> 
reductions from that sector in order to meet the transport rule's 
NO<INF>X</INF> budget.
    c. Mobile Sources. The EPA proposes that a State determine 
statewide mobile source NO<INF>X</INF> ozone season emissions and 
report these to EPA annually if the State is requiring additional 
controls for purposes of meeting the NO<INF>X</INF> 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 NO<INF>X</INF> reductions from that sector in 
order to meet the transport rule's NO<INF>X</INF> 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 NO<INF>X</INF> emissions data from all 
NO<INF>X</INF> sources (point, area, and mobile) within the 
State.<SUP>10</SUP> 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.
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

7. 2007 Report
    The EPA proposes that in 2007, States submit to EPA statewide 
NO<INF>X</INF> emissions data from all NO<INF>X</INF> 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 
NO<INF>X</INF> 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 NO<INF>X</INF> budgets 
proposed in the SIP call. This would include all NO<INF>X</INF> 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 
NO<INF>X</INF> 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 NO<INF>X</INF> 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 
<a href="/cdn-cgi/l/email-protection#87eee9e1e8a9e4efeee2e1c7e2f7e6eae6eeeba9e2f7e6a9e0e8f1"><span class="__cf_email__" data-cfemail="640d0a020b4a070c0d01022401140509050d084a0114054a030b12">[email protected]</span></a>.
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 
NO<INF>X</INF> 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 (NO<INF>X</INF>, 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 NO<INF>X</INF> inventory reports for determining 
compliance with the NO<INF>X</INF> 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 
NO<INF>X</INF> ozone season emissions to demonstrate progress toward, 
and ultimately compliance with, their NO<INF>X</INF> 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 NO<INF>X</INF> 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 NO<INF>X</INF> 
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. NO<INF>X</INF> 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 NO<INF>X</INF> 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 
NO<INF>X</INF> 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 
NO<INF>X</INF> 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 
NO<INF>X</INF> 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 NO<INF>X</INF> Budget Trading 
Program in the ways set forth in the model rule.

A. Program Summary

1. Purpose of the NO<INF>X</INF> 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 NO<INF>X</INF> 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 NO<INF>X</INF> 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 NO<INF>X</INF> 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 NO<INF>X</INF> 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 NO<INF>X</INF> 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 NO<INF>X</INF> 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 NO<INF>X</INF> 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 
NO<INF>X</INF> emissions budgets for States, assuming activity growth 
levels through 2007 and the application of reasonable, cost-effective 
controls that are currently available to achieve NO<INF>X</INF> 
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 NO<INF>X</INF> 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 NO<INF>X</INF> 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 NO<INF>X</INF> 
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 
NO<INF>X</INF> Budget Trading Program in order to assist States in 
developing a regulatory strategy for large stationary combustion 
sources.
3. Benefits of Participating in the NO<INF>X</INF> Budget Trading 
Program
    Participation in the NO<INF>X</INF> 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 
NO<INF>X</INF> 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 NO<INF>X</INF> 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 
NO<INF>X</INF> 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 NO<INF>X</INF> budget sources initially included in 
the trading program represent about 80 percent of the point source 
portion of the 2007 NO<INF>X</INF> baseline emissions inventory and 
about 65 percent of the point source portion of the 2007 NO<INF>X</INF> 
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 NO<INF>X</INF> 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.<SUP>11</SUP> 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.
---------------------------------------------------------------------------

    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 NO<INF>X</INF> allowances--each allowance representing a 
limited authorization to emit one ton of NO<INF>X</INF>--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 NO<INF>X</INF> allowances 
would be allocated to regulated sources in each State for each ozone 
season in the amount of the NO<INF>X</INF> budget set for the trading 
program in the State. States would have the responsibility for 
allocating allowances among regulated sources. The proposed 
NO<INF>X</INF> Budget Trading Rule establishes timing requirements for 
the submission of NO<INF>X</INF> allowance allocations to EPA by 
participating States for inclusion into the NO<INF>X</INF> 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 
NO<INF>X</INF> allowances to their sources covered by the 
NO<INF>X</INF> 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 NO<INF>X</INF> 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 NO<INF>X</INF> 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 NO<INF>X</INF> Budget Trading Program

    Market-based systems to control NO<INF>X</INF> 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) NO<INF>X</INF> 
Budget Program. Today's proposed NO<INF>X</INF> 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 NO<INF>X</INF> Budget Program
    The goals and implementation strategy of the OTC's NO<INF>X</INF> 
Budget Program are similar to those of the proposed transport rule and 
today's proposed NO<INF>X</INF> 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 NO<INF>X</INF> 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 NO<INF>X</INF> 
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 NO<INF>X</INF> 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 NO<INF>X</INF> 
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 NO<INF>X</INF> 
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 NO<INF>X</INF> allowances, and 
ultimately must hold allowances sufficient to cover all NO<INF>X</INF> 
emitted during the ozone season. Beginning in 1999, the total 
NO<INF>X</INF> emissions from regulated sources cannot exceed the 
number of allowances allocated in the OTR.
    In order to ensure that NO<INF>X</INF> emissions reductions are 
achieved and allowances are fungible, budget sources are required to 
monitor and report their NO<INF>X</INF> 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 
NO<INF>X</INF> 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 NO<INF>X</INF> allowances are not 
held, an automatic offset will be imposed during the following year's 
ozone season where an amount of NO<INF>X</INF> allowances will be 
deducted from the source in an amount equaling three NO<INF>X</INF> 
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 NO<INF>X</INF> 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 NO<INF>X</INF> 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 
NO<INF>X</INF> Budget Trading Program. The Trading and Incentives 
Workgroup was charged with designing market-based approaches to reduce 
NO<INF>X</INF> 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 NO<INF>X</INF> cap-
and-trade program prior to developing today's proposed NO<INF>X</INF> 
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 NO<INF>X</INF> 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 NO<INF>X</INF> 
Budget Trading Program development. To achieve the required 
NO<INF>X</INF> 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 NO<INF>X</INF> 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 NO<INF>X</INF> 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 NO<INF>X</INF> 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 NO<INF>X</INF> 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 NO<INF>X</INF> and sulfur oxides (SO<INF>X</INF>) 
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.<SUP>12</SUP> 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 SO<INF>X</INF> and NO<INF>X</INF>. 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 NO<INF>X</INF> emitters, the RECLAIM program generally 
requires stationary sources that emit ten or more tons of 
NO<INF>X</INF> 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 NO<INF>X</INF> 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. NO<INF>X</INF> Budget Trading Program

1. General Provisions
    Today's proposed NO<INF>X</INF> 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 NO<INF>X</INF> Budget 
Trading Rule includes Sections describing: To whom the NO<INF>X</INF> 
trading program would apply; the standard requirements for participants 
in the program (permitting, NO<INF>X</INF> 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 NO<INF>X</INF> Budget Trading Program, 
such as control period (the period beginning May 1 of each year and 
ending on September 30 of the same year), NO<INF>X</INF> Budget unit (a 
unit subject to the emissions limitation under the NO<INF>X</INF> 
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 NO<INF>X</INF> 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 NO<INF>X</INF> baseline emissions inventory and 
about 65 percent of the point source portion of the 2007 NO<INF>X</INF> 
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 NO<INF>X</INF> 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 
NO<INF>X</INF> 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 
NO<INF>X</INF> 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.
    <bullet> 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 NO<INF>X</INF> Budget 
Trading Program.
    <bullet> 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.
    <bullet> 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.<SUP>13</SUP>
---------------------------------------------------------------------------

    \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 NO<INF>X</INF> 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 NO<INF>X</INF> 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 <SUP>14</SUP>, 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 NO<INF>X</INF> allowances to 
NO<INF>X</INF> 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 NO<INF>X</INF> 
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 NO<INF>X</INF> 
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 NO<INF>X</INF> 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 NO<INF>X</INF> 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 NO<INF>X</INF> 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 NO<INF>X</INF> emission rate CEM and a 
flow CEM to determine NO<INF>X</INF> 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 NO<INF>X</INF> 
emission rate CEM and a fuel flow meter to determine NO<INF>X</INF> 
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 <SUP>15</SUP> 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 
NO<INF>X </INF>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 NO<INF>X</INF> 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 NO<INF>X</INF> 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 NO<INF>X</INF> 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 NO<INF>X</INF> 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 NO<INF>X</INF> 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 NO<INF>X</INF> 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 NO<INF>X</INF> emissions in comparison to the 
NO<INF>X</INF> emissions from the source categories purportedly 
included in the NO<INF>X</INF> 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 NO<INF>X</INF> 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 NO<INF>X</INF> 
mass emissions. Sources' compliance requirements could be streamlined 
significantly if they could meet their NSR offset obligations by 
participating in the NO<INF>X</INF> 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 
NO<INF>X</INF> 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 NO<INF>X</INF> 
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 NO<INF>X</INF> Budget Trading 
Program requirements for retired units. The purpose of this provision 
is to free retired NO<INF>X</INF> 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 NO<INF>X</INF> 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 NO<INF>X</INF> 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 
NO<INF>X</INF> allowances previously allocated or be allocated 
NO<INF>X</INF> allowances in the future depending on the allocation 
provisions adopted by the State where the retired unit is located. The 
number of future year NO<INF>X</INF> allowances that a retired unit 
would be allocated would be dependent on the

[[Page 25927]]

given State's allocation system. The NO<INF>X</INF> allowance 
allocations are discussed below in Section V.C.5 of this preamble.
    In order to resume operation without violating program 
requirements, the NO<INF>X</INF> AAR of the NO<INF>X</INF> 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 NO<INF>X</INF> 
budget units and their owners, operators, and NO<INF>X</INF> AARs must 
meet under the NO<INF>X</INF> 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, 
NO<INF>X</INF> 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 NO<INF>X</INF> 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 NO<INF>X</INF> 
limitation and, regardless of how many allowances a NO<INF>X</INF> 
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. NO<INF>X</INF> Authorized Account Representative
    40 CFR part 96 subpart B of today's proposed NO<INF>X</INF> Budget 
Trading Rule establishes the process for certifying the NO<INF>X</INF> 
AAR and describes his or her duties. A NO<INF>X</INF> AAR is the 
individual who is authorized to represent the owners and operators of 
each NO<INF>X</INF> budget unit at a NO<INF>X</INF> budget source in 
matters pertaining to the NO<INF>X</INF> Budget Trading Program. 
Because the NO<INF>X</INF> AAR is representing the owners and operators 
of all the NO<INF>X</INF> Budget units at a NO<INF>X</INF> Budget 
source, the NO<INF>X</INF> 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 NO<INF>X</INF> AAR's 
responsibilities include: the submission of permit applications to the 
permitting authority, submission of monitoring plans and certification 
applications, holding and transferring NO<INF>X</INF> 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 NO<INF>X</INF> AAR cannot always be 
available to perform his or her duties. Therefore, the rule proposes to 
allow for the appointment of one alternate NO<INF>X</INF> AAR 
(alternate NO<INF>X</INF> AAR) for a NO<INF>X</INF> budget source. The 
alternate NO<INF>X</INF> AAR would have the same authority and 
responsibilities as the NO<INF>X</INF> AAR. Therefore, unless expressly 
provided to the contrary, whenever the term ``NO<INF>X</INF> authorized 
account representative'' is used in the rule, it should be read to 
apply to the alternate NO<INF>X</INF> AAR as well. While the alternate 
NO<INF>X</INF> AAR would have full authority to act on behalf of the 
NO<INF>X</INF> AAR, all correspondence from EPA, including reports, 
would be sent only to the NO<INF>X</INF> AAR.
    Today's proposal requires the completion and submission of the 
account certificate of representation form in order to certify a 
NO<INF>X</INF> AAR for a NO<INF>X</INF> budget source and all 
NO<INF>X</INF> 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 NO<INF>X</INF> AAR name, the NO<INF>X</INF> AAR 
identification number (if already assigned), address, phone, fax, and 
e-mail (as well as similar information for the alternate NO<INF>X</INF> 
AAR, if applicable); the name of every owner and operator of the source 
and each NO<INF>X</INF> budget unit at the source; and certification 
language and signature of the NO<INF>X</INF> AAR and alternate, if 
applicable.
    In order to change the NO<INF>X</INF> AAR, alternate NO<INF>X</INF> 
AAR, or list of owners and operators, EPA is proposing that a new 
complete account certificate of representation be submitted. The EPA 
believes the NO<INF>X</INF> 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 NO<INF>X</INF> Budget 
permitting and to defer, whenever possible, to the permitting programs 
already established by the permitting authority. The proposed 
NO<INF>X</INF> Budget Trading Program regulations assume that the 
NO<INF>X</INF> budget permit would be a portion of a federally 
enforceable permit issued to the NO<INF>X</INF> 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 ``NO<INF>X</INF> budget permit'' throughout this preamble and the 
NO<INF>X</INF> Budget Trading Program regulations therefore refers to 
the NO<INF>X</INF> Budget Trading Program portion of the permit issued 
by the permitting authority to a NO<INF>X</INF> budget source.
    b. Title V/Non-Title V Permits. Although many of the NO<INF>X</INF> 
Budget sources that would participate in the NO<INF>X</INF> Budget 
Trading Program must apply for and receive a title V permit, this would 
not be the case for every NO<INF>X</INF> 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 NO<INF>X</INF> budget sources that are not 
major sources, the NO<INF>X</INF> Budget Trading Program would require 
only that a NO<INF>X</INF> budget source have a federally enforceable 
permit, rather than require that each NO<INF>X</INF> Budget source have 
a title V permit. The EPA believes that requiring all NO<INF>X</INF> 
budget sources to have a title V permit would be unduly burdensome and 
that proper implementation of a NO<INF>X</INF> 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 NO<INF>X</INF> 
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 NO<INF>X</INF> budget permit 
would be administered. For those sources not required to have a title V 
permit, the NO<INF>X</INF> Budget Trading Program attempts, wherever 
possible, to allow the permitting authority's non-title V permit 
regulations to govern how the NO<INF>X</INF> budget permit would be 
administered. Essentially, this would enable the NO<INF>X</INF> 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 NO<INF>X</INF> 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 NO<INF>X</INF> 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 
NO<INF>X</INF> budget units, of not requiring such units to obtain 
federally enforceable permits. Under this option, the State's 
NO<INF>X</INF> Budget Trading Rule would state that NO<INF>X</INF> 
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 NO<INF>X</INF> 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 NO<INF>X</INF> allowances each 
control period to cover NO<INF>X</INF> 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 NO<INF>X</INF> 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 NO<INF>X</INF> budget units (or what percent of States' 
NO<INF>X</INF> 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 NO<INF>X</INF> 
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 NO<INF>X</INF> 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. NO<INF>X</INF> Budget Permit Application Deadlines. The proposed 
rule sets the initial NO<INF>X</INF> 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 NO<INF>X</INF> Budget Trading Program, and therefore also the 
date by which initial NO<INF>X</INF> 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 NO<INF>X</INF> 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 NO<INF>X</INF> 
budget unit commences operation or from May 1, 2003. The NO<INF>X</INF> 
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 NO<INF>X</INF> budget permit 
application.
    d. NO<INF>X</INF> Budget Trading Program Permit Application. The 
NO<INF>X</INF> Budget Trading Program requires that a NO<INF>X</INF> 
budget permit application properly identify the source and include the 
standard requirements under proposed 40 CFR 96.6. The NO<INF>X</INF> 
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 NO<INF>X</INF> Budget Trading Program requirements into a 
NO<INF>X</INF> budget permit by including as part of such permit the 
NO<INF>X</INF> budget permit application submitted by the source. 
Directly incorporating the NO<INF>X</INF> budget permit application 
into the NO<INF>X</INF> 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 NO<INF>X</INF> 
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. NO<INF>X</INF> Budget Permit Issuance. As stated earlier, most 
of the procedures needed by a permitting authority to issue 
NO<INF>X</INF> 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 NO<INF>X</INF> 
Budget Trading Program permit regulations generally require use of the 
procedures under these other regulations and add some requirements such 
as NO<INF>X</INF> budget permit application submission and renewal 
deadlines, NO<INF>X</INF> budget permit application information 
requirements and permit content, and initial NO<INF>X</INF> budget 
permit effective dates.
    f. NO<INF>X</INF> Budget Permit Revisions. For revisions to the 
NO<INF>X</INF> budget permit, the NO<INF>X</INF> 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 NO<INF>X</INF> allowances is automatically incorporated in the 
NO<INF>X</INF> budget permit, and does not require a permit revision or 
reopening by the permitting authority. The NO<INF>X</INF> budget permit 
must, however, expressly state that each unit

[[Page 25929]]

must hold enough NO<INF>X</INF> allowances to account for 
NO<INF>X</INF> 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 
NO<INF>X</INF> budget permit each time a NO<INF>X</INF> 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 SO<INF>2 </INF>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 NO<INF>X</INF> Budget 
Trading Rule sets forth the requirements concerning certification by 
the NO<INF>X</INF> AAR at the end of each control period that the unit 
was in compliance with the emissions limitation and other requirements 
of the NO<INF>X</INF> Budget Trading Program. The NO<INF>X</INF> AAR 
must submit a compliance certification report for each NO<INF>X</INF> 
budget unit, by November 30 following the control period, to both the 
permitting authority and the Administrator. This report must identify 
the NO<INF>X</INF> budget unit and include a compliance certification 
statement. The compliance certification statement must indicate whether 
all of the applicable requirements of the NO<INF>X</INF> 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 NO<INF>X</INF> AAR to specify which allowances (by serial 
number) should be deducted from the NO<INF>X</INF> budget unit's 
compliance account and to specify the proportion of NO<INF>X</INF> 
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 NO<INF>X</INF> 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. NO<INF>X</INF> Allowance Allocations
    40 CFR part 96 subpart E of today's proposed model rule addresses 
the allocation of NO<INF>X</INF> allowances to NO<INF>X</INF> budget 
units. Within each participating State, the NO<INF>X</INF> Budget 
Trading Program would establish a State trading program budget (i.e., a 
cap of seasonal NO<INF>X</INF> emissions for all units included in the 
program) equal to a fixed total number of NO<INF>X</INF> allowances 
that each State allocates to its NO<INF>X</INF> 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 NO<INF>X</INF> allowances to the NO<INF>X</INF> 
budget units.
     a. Development of State Trading Program Budget. Today's proposal 
establishes in 40 CFR part 96 subpart E the total number of 
NO<INF>X</INF> tons for the NO<INF>X</INF> Budget Trading Program 
within a specific State. The proposed rule sets the State trading 
program budget at the level of NO<INF>X</INF> emissions apportioned by 
an approved SIP for the ozone transport rulemaking to the State's 
sources meeting the definition of ``NO<INF>X</INF> budget unit'' in the 
2007 statewide emissions budget. Sources meeting the definition of 
``NO<INF>X</INF> 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 
NO<INF>X</INF> tons apportioned to the NO<INF>X</INF> budget units. 
Therefore, a State may determine the number of NO<INF>X</INF> 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 NO<INF>X</INF> allowances that the State 
may allocate to the State's NO<INF>X</INF> budget units for any one 
control period.
    b. Timing Requirements. Today's proposed rule sets requirements for 
when a State would finalize NO<INF>X</INF> allowance allocations for 
each control period in the NO<INF>X</INF> 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 NO<INF>X</INF> 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 NO<INF>X</INF> allowances. The timing 
requirements would also contribute to the efficient administration of 
the NO<INF>X</INF> 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 NO<INF>X</INF> 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 NO<INF>X</INF> allowance allocations for the 
NO<INF>X</INF> 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 NO<INF>X</INF> 
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 
NO<INF>X</INF> allowance allocations would be periodically placed into 
the NATS for 5 to 10 control periods; to a single, permanent allocation 
where the NO<INF>X</INF> 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 NO<INF>X</INF> 
allowances to NO<INF>X</INF> 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 
NO<INF>X</INF> allowances based on this changing environment. Second, 
depending on the formula that is used to allocate the NO<INF>X</INF> 
allowances, trading programs that periodically update the allocations 
may provide an opportunity to reward energy efficiency improvements at 
specific NO<INF>X</INF> budget units. Incentives may be provided for 
energy efficiency improvements by rewarding NO<INF>X</INF> budget units 
that increase their production efficiency over time with a larger 
number of NO<INF>X</INF> allowances during the next allocation period. 
However, commenters also noted that allocation systems that are 
adjusted annually may restrict a NO<INF>X</INF> budget unit's ability 
to plan for compliance by creating uncertainty year to year about the 
amount of future allocations that the NO<INF>X</INF> budget unit would 
receive. In addition, annual allocations prevent a NO<INF>X</INF> 
budget unit from officially transferring future year NO<INF>X</INF> 
allowances because the NATS only contains the current year's 
NO<INF>X</INF> allowances under this type of system. These commenters 
generally favored an allocation system that periodically allocates 
NO<INF>X</INF> allowances for 5 to 10 control periods at a time.
    Other commenters noted the advantages of a single, permanent 
allocation where the NO<INF>X</INF> allowance allocations would be set 
only once at the beginning of the trading program. Permanent 
allocations provide a long planning horizon for the NO<INF>X</INF> 
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 
NO<INF>X</INF> budget unit's energy efficiency and require less 
resources to administer as compared to updating allocation systems. In 
a permanent allocation system, all NO<INF>X</INF> allowances are 
allocated to NO<INF>X</INF> budget units at the beginning of the 
trading program. New NO<INF>X</INF> budget units that begin operations 
after the allocation of NO<INF>X</INF> allowances would be required to 
obtain NO<INF>X</INF> 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 NO<INF>X</INF> allowances 
to new NO<INF>X</INF> 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 
NO<INF>X</INF> allowances for 5 to 10 years at a time. The proposed 
rule includes the following timing requirements for the allocation of 
NO<INF>X</INF> allowances: by September 30, 1999, the State would 
submit to EPA NO<INF>X</INF> 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 
NO<INF>X</INF> 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 NO<INF>X</INF> 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 
NO<INF>X</INF> budget units are always allocated 5 years worth of 
NO<INF>X</INF> allowances in the NATS. A second option, on which 
comment is also requested, is: By January 1, 2003, a State would submit 
to EPA NO<INF>X</INF> allowance allocations for the control periods in 
2008, 2009, 2010, 2011, and 2012. The State would maintain this 
schedule of submitting NO<INF>X</INF> allowance allocations for 5 
control periods by January 1 every five years after January 1, 2003. 
This option would ensure that the State's NO<INF>X</INF> budget units 
are allocated no less than 5 years, and as much as 10 years, worth of 
NO<INF>X</INF> 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 
NO<INF>X</INF> allowance allocations to EPA, EPA would allocate 
NO<INF>X</INF> allowances to NO<INF>X</INF> 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 NO<INF>X</INF> 
allowances to NO<INF>X</INF> budget units, which is discussed below. 
This provision is designed to ensure that all NO<INF>X</INF> budget 
units included in the NO<INF>X</INF> Budget Trading Program would 
receive NO<INF>X</INF> allowance allocations at the same time for each 
control period. The EPA solicits comment on this provision.

c. Options for NO<INF>X</INF> Allowance Allocation Recommendation

    i. Basis for Developing an Allocation Recommendation. The EPA 
proposes that the final NO<INF>X</INF> Budget Trading Rule include a 
recommended NO<INF>X</INF> allowance allocation. This was discussed at 
length at the public workshops. Three approaches to addressing 
NO<INF>X</INF> allowance allocations in the trading program were 
presented at the workshops. First, the rule could prescribe one method 
for allocating NO<INF>X</INF> allowances. States that choose to 
participate in the NO<INF>X</INF> Budget Trading Program would need to 
allocate NO<INF>X</INF> 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 NO<INF>X</INF> 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 NO<INF>X</INF> 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 
NO<INF>X</INF> 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 NO<INF>X</INF> 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 NO<INF>X</INF> 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 
NO<INF>X</INF> Budget Trading Program, EPA is proposing that the final 
rule contain a recommendation for how States may allocate 
NO<INF>X</INF> 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 
NO<INF>X</INF> 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. NO<INF>X</INF> 
allowances could be distributed to NO<INF>X</INF> 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 NO<INF>X</INF> 
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 NO<INF>X</INF> allowances: (1) The actual emissions (in tons 
of NO<INF>X</INF>) 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 NO<INF>X</INF> allowances based on a unit's actual 
NO<INF>X</INF> emissions was not generally recommended because it is 
regarded as providing a perverse incentive by rewarding more 
NO<INF>X</INF> allowances to units that have the greatest 
NO<INF>X</INF> 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.<SUP>17</SUP> 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 NO<INF>X</INF> 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 NO<INF>X</INF> 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 NO<INF>X</INF> 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 NO<INF>X</INF> 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 NO<INF>X</INF> 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 
NO<INF>X</INF> 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 NO<INF>X</INF> 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 
NO<INF>X</INF> 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 NO<INF>X</INF> 
allowances to NO<INF>X</INF> 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 NO<INF>X</INF> 
allowances as a set-aside for new NO<INF>X</INF> budget units for 
control periods for which the unit was not allocated NO<INF>X</INF> 
allowances, and (2) using either a fuel neutral or output neutral 
calculation to determine allocations for NO<INF>X</INF> 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 
NO<INF>X</INF> budget units (i.e., units that commence operation during 
or after the period on which general NO<INF>X</INF> 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 NO<INF>X</INF> allowances to set aside for new units. The 
remaining 98 percent of the NO<INF>X</INF> allowances are to be 
allocated to existing NO<INF>X</INF> 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 NO<INF>X</INF> 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 NO<INF>X</INF> 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 
NO<INF>X</INF> allowances equal to 2 percent of the NO<INF>X</INF> 
allowances in the State trading program budget <SUP>18</SUP>. 
NO<INF>X</INF> allowances in the allocation set-aside would be 
available to NO<INF>X</INF> 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 NO<INF>X</INF> allowance 
allocations are based. To receive NO<INF>X</INF> allowances from the 
allocation set-aside, the NO<INF>X</INF> AAR for a unit would submit to 
the State a NO<INF>X</INF> 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 NO<INF>X</INF> allowance allocations with 
existing NO<INF>X</INF> budget units. The NO<INF>X</INF> allowance 
request would be submitted prior to May 1 of the first control period 
for which NO<INF>X</INF> allowances are requested and after the date on 
which the State issues a permit to construct the NO<INF>X</INF> budget 
unit. The NO<INF>X</INF> AAR may not request an amount of 
NO<INF>X</INF> allowances for each control period that exceeds 0.15 lb/
mmBtu multiplied by the NO<INF>X</INF>

[[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.
---------------------------------------------------------------------------

    \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 NO<INF>X</INF> 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 
NO<INF>X</INF> allowances to new units requesting NO<INF>X</INF> 
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 NO<INF>X</INF> allowance 
requests. If the allocation set-aside for the control period for which 
NO<INF>X</INF> allowances are requested has an amount of NO<INF>X</INF> 
allowances not less than the number requested and verified by the 
State, the State would allocate the full (or adjusted) amount of 
NO<INF>X</INF> allowances requested to the NO<INF>X</INF> budget unit. 
If the set-aside for the control period for which NO<INF>X</INF> 
allowances are requested has a smaller amount of NO<INF>X</INF> 
allowances than the number requested and verified, the State would deny 
in part the request and only allocate the remaining number of 
NO<INF>X</INF> allowances in the set-aside to the NO<INF>X</INF> budget 
unit. Once the set-aside for a control period has been depleted of all 
NO<INF>X</INF> allowances, the State would not allocate any 
NO<INF>X</INF> allowances to additional units requesting NO<INF>X</INF> 
allowances for the control period. NO<INF>X</INF> budget units with 
NO<INF>X</INF> allowance requests that were denied in whole or part 
would be responsible for obtaining the necessary amount of 
NO<INF>X</INF> allowances from the NO<INF>X</INF> allowance market in 
order to demonstrate compliance with the provisions of the proposed 
rule. The State would act on all NO<INF>X</INF> allowance requests 
within 60 days upon receipt of the request and notify the 
NO<INF>X</INF> AAR that submitted the request and the EPA of the number 
of NO<INF>X</INF> allowances (if any) allocated for the control period. 
After September 30 of each year, the EPA would transfer NO<INF>X</INF> 
allowances remaining in the set-aside for the control period to the 
set-aside for the following control period.
    For new NO<INF>X</INF> budget units that have been allocated 
NO<INF>X</INF> allowances from the allocation set-aside, the EPA would 
deduct NO<INF>X</INF> 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 NO<INF>X</INF> allowances to existing units. Without 
the adjustment procedures, a new unit (e.g., a peaking unit) could be 
allocated NO<INF>X</INF> allowances assuming utilization far out of 
proportion to actual utilization and the set-aside could be 
insufficient to provide NO<INF>X</INF> allowances for all new units at 
such an allocation level.
    Under the actual utilization adjustment procedure, EPA would deduct 
a number of NO<INF>X</INF> allowances according to the following 
equation: NO<INF>X</INF> allowances deducted for actual utilization 
adjustment = (Number of NO<INF>X</INF> allowances allocated for control 
period)-((actual control period utilization (in mmBtu)  x  0.15 lb/
mmBtu)). The NO<INF>X</INF> allowances deducted must have the same or 
an earlier compliance use date as the year of the control period for 
which NO<INF>X</INF> 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 NO<INF>X</INF> 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 NO<INF>X</INF> AAR may identify the serial 
numbers of the NO<INF>X</INF> allowances to be deducted. In the absence 
of such identification, the EPA would deduct NO<INF>X</INF> allowances 
on a first-in, first-out basis. The EPA would transfer the 
NO<INF>X</INF> allowances deducted into the State's set-aside for the 
following control period.
    If additional NO<INF>X</INF> allowances are moved into a set-aside 
resulting from the transfer of NO<INF>X</INF> allowances from a 
previous year's set-aside or from the actual utilization adjustment, 
the State would allocate NO<INF>X</INF> allowances to those 
NO<INF>X</INF> allowance requests that were denied in whole or in part 
pursuant to the NO<INF>X</INF> allowance request provisions under this 
Section of the proposed rule. However, requests for NO<INF>X</INF> 
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 NO<INF>X</INF> allowances. The transparency of 
the first SO<INF>2</INF> 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 NO<INF>X</INF> allowances was discussed at the 
December public workshop. Commenters generally questioned the need for 
a price signal auction for NO<INF>X</INF> 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. NO<INF>X</INF> 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 
NO<INF>X</INF> 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 NO<INF>X</INF> 
allowances held by NO<INF>X</INF> budget units under the NO<INF>X</INF> 
Budget Trading Program, as well as those allowances held by other 
organizations or individuals. Specifically, the NATS would track the 
allocation of all NO<INF>X</INF> allowances, holdings of NO<INF>X</INF> 
allowances in accounts, deduction of NO<INF>X</INF> 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 NO<INF>X</INF> 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 NO<INF>X</INF> budget unit, 
and overdraft accounts are created for each source with two or more 
NO<INF>X</INF> 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 
NO<INF>X</INF> Budget Trading Program, EPA is proposing to establish 
compliance accounts for each NO<INF>X</INF> 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 
NO<INF>X</INF> allowances would be allocated). As for the deadline for 
transferring NO<INF>X</INF> allowances to cover emissions in the 
control period (i.e., the NO<INF>X</INF> allowance transfer deadline of 
midnight on November 30), each compliance account (supplemented as 
discussed below by an overdraft account) must hold sufficient 
NO<INF>X</INF> allowances to cover the NO<INF>X</INF> budget unit's 
NO<INF>X</INF> 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 NO<INF>X</INF> budget units, and represented by 
the source's NO<INF>X</INF> AAR. The NO<INF>X</INF> AAR may choose 
whether he or she wishes to utilize the account by transferring 
allowances into the account before the annual reconciliation process. 
NO<INF>X</INF> allowances transferred into the overdraft account for a 
NO<INF>X</INF> budget source by the NO<INF>X</INF> allowance transfer 
deadline would be available for deduction during annual reconciliation 
if a NO<INF>X</INF> budget unit at that source fails to hold sufficient 
NO<INF>X</INF> allowances to cover emissions in its compliance account. 
This is similar to the approach used in the OTC NO<INF>X</INF> Budget 
Program and provides additional flexibility for owners and operators in 
complying with the requirement to hold NO<INF>X</INF> allowances 
covering emissions. If the compliance account and the overdraft account 
together do not contain enough NO<INF>X</INF> allowances, then the unit 
would be out of compliance. The compliance account must be depleted of 
all NO<INF>X</INF> allowances before the overdraft account is utilized.
    The proposed rule would deduct NO<INF>X</INF> allowances from the 
overdraft account beginning with the unit having the lowest NATS 
account number. The unit that fails to hold sufficient NO<INF>X</INF> 
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 NO<INF>X</INF> allowances, such 
provisions would apply to the NO<INF>X</INF> allowances held in the 
overdraft accounts as well as those held in compliance accounts.
    Today's proposal allows the NO<INF>X</INF> AAR to identify specific 
serial numbers for deduction from a compliance account. In the absence 
of a specific identification of NO<INF>X</INF> allowances to be 
deducted, a FIFO (first-in, first-out) method would determine the order 
in which NO<INF>X</INF> allowances would be deducted. The proposal does 
not, however, allow for the identification of specific NO<INF>X</INF> 
allowances to be deducted from an overdraft account because 
NO<INF>X</INF> allowance deductions from the overdraft account would 
take place automatically, in a set order, after the NO<INF>X</INF> 
allowance transfer deadline has passed.
    c. Compliance. Once a control period has ended, NO<INF>X</INF> 
budget units would have a window of opportunity (i.e., until the 
NO<INF>X</INF> allowance transfer deadline of midnight on November 30) 
to evaluate their reported emissions and obtain any additional 
NO<INF>X</INF> allowances they may need to cover the emissions during 
the ozone season. On November 30 of each year, the NO<INF>X</INF> AAR 
must also submit a compliance certification report for each 
NO<INF>X</INF> budget unit. Should the NO<INF>X</INF> budget unit not 
obtain sufficient NO<INF>X</INF> allowances to offset emissions for the 
season, three NO<INF>X</INF> 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 NO<INF>X</INF> 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 NO<INF>X</INF> allowances (e.g., by NO<INF>X</INF> 
allowance brokers or owners of multiple NO<INF>X</INF> budget units). 
General accounts are currently used for SO<INF>2</INF> 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 NO<INF>X</INF> AAR name, phone, fax, and e-mail (as well as similar 
information for the Alternate NO<INF>X</INF> AAR, if applicable); 
NO<INF>X</INF> AAR mailing address; the names of all parties with an 
ownership interest with the respect to the NO<INF>X</INF> allowances in 
the account; and certification language and signatures of the 
NO<INF>X</INF> 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 NO<INF>X</INF> 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-NO<INF>X</INF> 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 
NO<INF>X</INF> 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 NO<INF>X</INF> 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 NO<INF>X</INF> 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 NO<INF>X</INF> 
allowances that could be used for compliance purposes, and therefore 
only to NO<INF>X</INF> 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 NO<INF>X</INF> 
allowances to cover emissions in the upcoming control period, the 1,000 
allowances would equate to 930 tons of NO<INF>X</INF> 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 
NO<INF>X</INF> 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 NO<INF>X</INF> 
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 NO<INF>X</INF> 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 NO<INF>X</INF> allowances. The 
longer the period of time allowed for early reductions and the less 
stringent the level at which NO<INF>X</INF> 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 NO<INF>X</INF> allowances available at 
the start of the program, there may be a need for management of the use 
of banked NO<INF>X</INF> 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 NO<INF>X</INF> 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 NO<INF>X</INF> 
Budget Trading Program would result in the automatic retirement of any 
NO<INF>X</INF> allowances not surrendered for compliance following each 
control period. Under this option, the only NO<INF>X</INF> 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 NO<INF>X</INF> 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 
NO<INF>X</INF> 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 NO<INF>X</INF> allowances 
because the volume of banked NO<INF>X</INF> 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 NO<INF>X</INF> 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 NO<INF>X</INF> allowance. The NO<INF>X</INF> 
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 NO<INF>X</INF> allowances awarded for early 
reductions come from the trading program budget, each State 
participating in the NO<INF>X</INF> 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 NO<INF>X</INF> 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 
NO<INF>X</INF> 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 NO<INF>X</INF> 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 NO<INF>X</INF> allowances awarded for early 
reductions. The shift of available NO<INF>X</INF> 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 
NO<INF>X</INF> 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 NO<INF>X</INF> 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 NO<INF>X</INF> allowances for early reductions under 
the NO<INF>X</INF> 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 NO<INF>X</INF> 
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 NO<INF>X</INF> 
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 NO<INF>X</INF> 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 NO<INF>X</INF> allowance 
set-aside to reward early reductions does not withdraw too many 
NO<INF>X</INF> allowances from the future trading program budget, and 
pose undue burden on sources in the program. Placing a limit on the 
number of NO<INF>X</INF> 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 NO<INF>X</INF> 
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 NO<INF>X</INF> allowances are 
withdrawn from the budget, since exceedance of the budget would still 
be quite possible due to the shift of available NO<INF>X</INF> 
allowances to the beginning of the program. As discussed above, a flow 
control management scenario, whereby the use of banked NO<INF>X</INF> 
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 NO<INF>X</INF> allowances to one for the current control 
period would be imposed on the use of some banked NO<INF>X</INF> 
allowances whenever the percentage of banked NO<INF>X</INF> allowances 
in the NO<INF>X</INF> 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 
NO<INF>X</INF> allowances. The proposed flow control management 
scenario is the same system used in the OTC's model rule to manage the 
use of banked NO<INF>X</INF> allowances. This system simply acts as a 
safeguard against excessive withdrawals of banked allowances in a given 
control period; if large amounts of banked NO<INF>X</INF> allowances 
are not used, it will not be invoked.
    These four factors together--the origin of the NO<INF>X</INF> 
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 NO<INF>X</INF> allowances--
together determine the impact of the award of early reduction credits 
on achievement and maintenance of the NO<INF>X</INF> 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 NO<INF>X</INF> budget source could over-control with respect 
to this preliminary level at one or more units and accrue 
NO<INF>X</INF> 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 NO<INF>X</INF> 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 NO<INF>X</INF> Budget 
Trading Program. Unlike an early reduction credit approach, a phased-in 
approach would not require applicants to demonstrate that 
NO<INF>X</INF> 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 NO<INF>X</INF> 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 NO<INF>X</INF> 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 NO<INF>X</INF> 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 NO<INF>X</INF> allowances used for 
compliance in the current control period whenever the percentage of 
banked allowances in the NO<INF>X</INF> 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 NO<INF>X</INF> allowances.
8. Allowance Transfers
    The EPA is proposing that once a NO<INF>X</INF> AAR is appointed 
and an account is established in the NATS, NO<INF>X</INF> 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 
NO<INF>X</INF> 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 NO<INF>X</INF> 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 NO<INF>X</INF> Budget Trading Program. 
The EPA is proposing that units subject to the NO<INF>X</INF> 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 NO<INF>X</INF> mass emissions (i.e., tons of 
NO<INF>X</INF> 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 NO<INF>X</INF> 
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 
NO<INF>X</INF> allowance (i.e., the authority to emit one ton of 
NO<INF>X</INF>) 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 NO<INF>X</INF> allowances can determine the 
value of what they are trading.
    The EPA believes that the NO<INF>X</INF> 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 NO<INF>X</INF> mass. One of the main advantages of using these 
provisions to support this program is that many of the NO<INF>X</INF> 
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 
NO<INF>X</INF> 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 NO<INF>X</INF> 
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 NO<INF>X</INF> 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 NO<INF>X</INF> 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 NO<INF>X</INF> 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 NO<INF>X</INF> 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 NO<INF>X</INF> 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 NO<INF>X</INF> mass 
emissions by monitoring NO<INF>X</INF> 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 NO<INF>X</INF> Budget Trading Program would be 
required to measure NO<INF>X</INF> emission rate using a NO<INF>X</INF> 
emission rate CEM consisting of a NO<INF>X</INF> concentration CEM and 
a diluent CEM (CO<INF>2</INF> or O<INF>2</INF> CEM) and measure heat 
input using a diluent CEM and a flow CEM. All gas and oil units covered 
by the NO<INF>X</INF> 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 NO<INF>X</INF> emission rate 
curves. Then based on hourly measurement of heat input from a fuel 
flowmeter and fuel sampling and analysis, the heat input versus 
NO<INF>X</INF> emission rate curves would be used to estimate the 
hourly NO<INF>X</INF> emission rate. This option for determining 
NO<INF>X</INF> 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 NO<INF>X</INF> mass. A unit 
that qualifies as a low mass emitting unit could use a default 
NO<INF>X</INF> emission rate and the unit's maximum rated hourly heat 
input to determine NO<INF>X</INF> 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 NO<INF>X</INF> 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 
NO<INF>X</INF> mass emissions. These include: an alternative way to 
measure NO<INF>X</INF> mass emissions using a NO<INF>X</INF> 
concentration CEM and a flow CEM, specific requirements for monitoring 
NO<INF>X</INF> emission rate at common stacks and heat input at common 
stacks and common fuel pipes, and the reporting of NO<INF>X</INF> 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 
NO<INF>X</INF> 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 NO<INF>X</INF> 
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 NO<INF>X</INF> 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 NO<INF>X</INF> 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 NO<INF>X</INF> 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 
NO<INF>X</INF> 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 
NO<INF>X</INF> mass. This would only be an issue if a unit shared a 
common stack with other units and chose to measure NO<INF>X</INF> 
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 NO<INF>X</INF> 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 NO<INF>X</INF> 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 
NO<INF>X</INF> allowances based on actual information on unit 
operation. The EPA has received comments that allocations of 
NO<INF>X</INF> 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 NO<INF>X</INF> allowances are reallocated on an 
ongoing basis (as is being proposed today) may decrease the incentives 
for reducing NO<INF>X</INF> 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 NO<INF>X</INF> allowances in 
the next NO<INF>X</INF> 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 NO<INF>X</INF> allowances. Since a 
decrease in the amount of fuel needed is generally accompanied by a 
decrease in NO<INF>X</INF> emissions, a unit increasing its efficiency 
would either have more NO<INF>X</INF> allowances to sell on the market 
or would need to purchase less NO<INF>X</INF> 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 SO<INF>2</INF>, mercury, 
and carbon dioxide (CO<INF>2</INF>).
    However, EPA is concerned that there may be some issues not yet 
fully addressed concerning allocation of NO<INF>X</INF> 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 NO<INF>X</INF> 
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 
NO<INF>X</INF> 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 NO<INF>X</INF> 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 
NO<INF>X</INF> budget by allowing those units, which may not otherwise 
be required to reduce NO<INF>X</INF> emissions for a State to meet its 
budget,

[[Page 25941]]

to opt in to the trading program and make incremental, lower-cost 
reductions. The NO<INF>X</INF> allowances freed up by the opt-in 
source's control action can be sold to other NO<INF>X</INF> budget 
units for their compliance with the NO<INF>X</INF> emission limitation. 
In general, units that opt in are treated like other NO<INF>X</INF> 
budget units and are subject to the same requirements to monitor, to 
hold allowances to account for emissions, and to have a NO<INF>X</INF> 
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 NO<INF>X</INF> Budget Trading Program. A State would account for 
the opt-in unit in the State's SIP by adding the opt-in unit's 
NO<INF>X</INF> emissions to the trading program budget in the SIP and 
subtracting the opt-in unit's NO<INF>X</INF> emissions from the part of 
the SIP not covered under the NO<INF>X</INF> Budget Trading 
Program.<SUP>19</SUP> 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.
---------------------------------------------------------------------------

    \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 NO<INF>X</INF> allowances to an opt-in unit on a year-by-year 
basis. An opt-in unit is required to monitor and report the 
NO<INF>X</INF> 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 
NO<INF>X</INF> 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 
NO<INF>X</INF> 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 NO<INF>X</INF> 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 NO<INF>X</INF> budget units.
    The EPA proposes to allocate NO<INF>X</INF> 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 NO<INF>X</INF> emissions. Such 
increases in emissions may occur if units outside the cap increase 
their utilization (and emissions) while NO<INF>X</INF> 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 NO<INF>X</INF> 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 NO<INF>X</INF> 
Budget Units. Today's proposal does not include special or simplified 
opt-in provisions for non-NO<INF>X</INF> budget units that share a 
common stack or common fuel pipe header with a NO<INF>X</INF> budget 
unit. Allowing these units to participate in the trading program may 
streamline the monitoring and reporting requirements for the 
NO<INF>X</INF> budget units. For example, if a non-NO<INF>X</INF> 
budget unit sharing a common stack with a NO<INF>X</INF> budget unit is 
opted in to the trading program, it may no longer be necessary to 
apportion common stack emissions between two units. The NO<INF>X</INF> 
AAR may simply elect the percentage of NO<INF>X</INF> 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 NO<INF>X</INF> Budget 
Program at any time, but a request to withdraw may be effective only on 
a date specified by the NO<INF>X</INF> 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 
NO<INF>X</INF> 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 NO<INF>X</INF> 
allowances to account for its NO<INF>X</INF> 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 
NO<INF>X</INF> emissions, since an opt-in unit could emit enough 
NO<INF>X</INF> to use up its NO<INF>X</INF> allowance allocation for 
the control period prior to the end of that control period, withdraw 
from the program, and continue to emit NO<INF>X</INF> after withdrawal 
during the control period. Such emissions would not be accounted for 
with the requisite surrender of NO<INF>X</INF> allowances required 
under the NO<INF>X</INF> Budget Program and could occur outside of a 
State's overall budget for NO<INF>X</INF>.
    If a NO<INF>X</INF> budget opt-in unit becomes a NO<INF>X</INF> 
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 NO<INF>X</INF> 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 NO<INF>X</INF> budget permit 
content requirements of 40 CFR 96.23 effective as of the date of the

[[Page 25942]]

change in status. The NO<INF>X</INF> 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 
NO<INF>X</INF> 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 
NO<INF>X</INF> budget units.
11. Program Audits
    The EPA would publish a report annually, commencing after the first 
year of compliance, that would contain, for each NO<INF>X</INF> budget 
unit, the control period NO<INF>X</INF> emissions and the number of 
NO<INF>X</INF> allowances deducted for all reasons. This would be done 
in order for States to track emissions and NO<INF>X</INF> 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 NO<INF>X</INF> 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 NO<INF>X</INF> 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 NO<INF>X</INF> 
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 NO<INF>X</INF> 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 NO<INF>X</INF> AARs, tracking all official 
transfers of NO<INF>X</INF> allowances, and using the end of control 
season emissions data and NO<INF>X</INF> 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 NO<INF>X</INF> allowance 
allocations consistent with a prescribed schedule and format. The 
NO<INF>X</INF> AARs for individual sources would have to provide EPA 
with information about all official NO<INF>X</INF> allowance transfers 
in a prescribed format. The NO<INF>X</INF> 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 NO<INF>X</INF> 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 NO<INF>X</INF> allowances to cover a unit's 
emissions for a control period, EPA would notify the State and would 
automatically deduct NO<INF>X</INF> 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 NO<INF>X</INF> Budget Trading Rule 
(40 CFR part 96). If a State chooses to implement the NO<INF>X</INF> 
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 NO<INF>X</INF> 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 NO<INF>X</INF> 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 NO<INF>X</INF> 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 NO<INF>X</INF> 
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 NO<INF>X</INF> 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 NO<INF>X</INF> 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 NO<INF>X</INF> 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 NO<INF>X</INF> 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 NO<INF>X</INF> Budget Trading 
Program by maintaining the ability for sources located in Maine, New 
Hampshire, and Vermont to trade NO<INF>X</INF> allowances with sources 
located in the other participating OTC States.
    b. Source Applicability. The source applicability criteria for 
today's proposed NO<INF>X</INF> 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 NO<INF>X</INF> 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 NO<INF>X</INF> Budget Trading Program.
2. Allocations
    Today's proposal establishes NO<INF>X</INF> allowances as the 
currency for the NO<INF>X</INF> Budget Program, and recommends a 
methodology for participating States to allocate NO<INF>X</INF> 
allowances among NO<INF>X</INF> 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 
NO<INF>X</INF> allowances allocated do not exceed the number of tons 
that the State apportions to NO<INF>X</INF> 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 NO<INF>X</INF> 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 NO<INF>X</INF> 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 NO<INF>X</INF> 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 
NO<INF>X</INF> Budget Trading Program.
4. Emissions Monitoring and Reporting
    The monitoring and reporting requirements in the proposed 
NO<INF>X</INF> 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 NO<INF>X</INF> 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 
NO<INF>X</INF> 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 NO<INF>X</INF> Budget Program, use of 
the revised 40 CFR part 75 would require few changes to address the 
NO<INF>X</INF> mass monitoring and reporting requirements in this 
proposal. However, for some sources that are only subject to the OTC 
NO<INF>X</INF> 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 NO<INF>X</INF> 
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 NO<INF>X</INF> 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 NO<INF>X</INF> 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 NO<INF>X</INF> Budget 
Program and the proposed NO<INF>X</INF> 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 NO<INF>X</INF> 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 NO<INF>X</INF> 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 NO<INF>X</INF> 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 NO<INF>X</INF> 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 NO<INF>X</INF> 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 NO<INF>X</INF> 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 NO<INF>X</INF> 
allowances elsewhere in the system to offset any new emissions. Those 
sources from whom NO<INF>X</INF> allowances are acquired must also hold 
sufficient NO<INF>X</INF> allowances to cover their emissions. 
Therefore, since the trading program budget would not be increased for 
sources seeking offsets, NO<INF>X</INF> 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 NO<INF>X</INF> 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 
NO<INF>X</INF> 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 NO<INF>X</INF> 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 NO<INF>X</INF> Budget Trading Rule to recognize and encourage 
the contribution that energy efficiency and renewables can make in 
meeting the NO<INF>X</INF> 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 NO<INF>X</INF> reduction 
strategy. Greater deployment of energy efficiency and renewables 
technologies cannot only be a cost-effective means of preventing 
emissions of NO<INF>X</INF>. It can also be a cost-effective way of 
preventing emissions of greenhouse gases, such as carbon dioxide 
(CO<INF>2</INF>), 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 NO<INF>X</INF> 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 NO<INF>X</INF> 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 NO<INF>X</INF> 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 NO<INF>X</INF> 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 NO<INF>X</INF> 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 NO<INF>X</INF> control 
methods, such as selective catalytic reduction (SCR) or selective non-
catalytic reduction (SNCR), can lower the overall compliance costs of 
meeting the NO<INF>X</INF> 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 NO<INF>X</INF> reduction strategy in the proposed 
NO<INF>X</INF> 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 NO<INF>X</INF> 
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 NO<INF>X</INF> budget, (2) promote energy efficiency and 
renewables as effective NO<INF>X</INF> and pollutant-reducing 
strategies through the accelerated adoption of such practices and 
technologies, and (3) reduce future CO<INF>2</INF>-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 NO<INF>X</INF> 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 NO<INF>X</INF> Budget 
Trading Program. The EPA continues to consider whether and how to 
develop an approach to include energy efficiency and renewables in the 
NO<INF>X</INF> 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 NO<INF>X</INF> Budget 
Trading programs.
<bullet> Issue (1) Rewarding Efficiency Improvements Above ``Business 
as Usual''
    In developing an approach for energy efficiency and renewables in 
the NO<INF>X</INF> 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 NO<INF>X</INF> 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 NO<INF>X</INF> 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 NO<INF>X</INF> 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 
NO<INF>X</INF> allowances. Under the third approach, the number of 
NO<INF>X</INF> allowances allocated to energy efficiency improvements 
likely to occur anyway is restricted to some portion (e.g., 50 percent) 
of the full number of NO<INF>X</INF> 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 NO<INF>X</INF> 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 
NO<INF>X</INF> 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 
NO<INF>X</INF> 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 NO<INF>X</INF> 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?
<bullet> 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 NO<INF>X</INF> 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 NO<INF>X</INF> 
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 NO<INF>X</INF> 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 
NO<INF>X</INF> budget for a State or across the region could be 
considered

    Note: these figures do not include a portion of the nonutility 
boiler NO<INF>X</INF> 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 
NO<INF>X</INF> 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 NO<INF>X</INF> Budget 
units. Other respondents to the December discussion paper remarked that 
an ``off-the-top'' scheme would allow too little certainty for 
NO<INF>X</INF> Budget units in planning for how to meet the 
NO<INF>X</INF> 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 NO<INF>X</INF> Budget Trading Program to award 
incremental energy efficiency projects that would not be undertaken 
without the availability of set-aside NO<INF>X</INF> 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 NO<INF>X</INF> budget

[[Page 25948]]

units about the number of non-set-aside NO<INF>X</INF> 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 
NO<INF>X</INF> rate that represents the average NO<INF>X</INF> 
emissions reductions expected for a kWh reduced. For this method, the 
rate could be based on one of three NO<INF>X</INF> rates: (1) The 
average NO<INF>X</INF> rate calculated by dividing the total 
NO<INF>X</INF> 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 
NO<INF>X</INF> rate calculated by multiplying the proposed ozone 
transport rulemaking NO<INF>X</INF> rate of 0.15 lbs per mmBtu by a 
system wide average heat rate in Btu per kWh; or (3) an average 
``marginal'' NO<INF>X</INF> rate in lbs per kWh representing the 
generation mix most likely to be backed out on the ``margin.'' This 
marginal NO<INF>X</INF> rate is calculated by dividing the difference 
in NO<INF>X</INF> 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 NO<INF>X</INF> 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 NO<INF>X</INF> reduction 
actually attributed to energy efficiency in an uncapped NO<INF>X</INF> 
environment. This method would likely result in different 
NO<INF>X</INF> factors for each State. The third method would be to 
develop measure-specific marginal NO<INF>X</INF> rates which would more 
accurately represent the load shape associated with particular energy 
efficiency measures (i.e., commercial lighting or industrial motors), 
or alternatively, NO<INF>X</INF> 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 NO<INF>X</INF> 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 NO<INF>X</INF> factors to be used in 
translating energy savings into NO<INF>X</INF> reductions and the 
corresponding NO<INF>X</INF> 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 NO<INF>X</INF> 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 NO<INF>X</INF> rate or the 
marginal NO<INF>X</INF> rate for their State or power pool that may be 
used for translating energy efficiency savings into tons of 
NO<INF>X</INF> reductions?
    Question 11. If a marginal NO<INF>X</INF> rate is not available or 
calculable and an average NO<INF>X</INF> 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?
<bullet> 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 NO<INF>X</INF>. Entities holding such NO<INF>X</INF> 
allowances for these purposes have a direct incentive to take actions 
that will lower their need for NO<INF>X</INF> allowances or free up 
NO<INF>X</INF> 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 NO<INF>X</INF> 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 NO<INF>X</INF> allowances, is it appropriate to 
limit eligibility to those entities that would not otherwise be holding 
NO<INF>X</INF> allowances for the purposes of being able to emit 
NO<INF>X</INF>? 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 NO<INF>X</INF> 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 
NO<INF>X</INF> allowances of less than one ton of NO<INF>X</INF> may be 
impractical because an allowance is defined as one ton of 
NO<INF>X</INF> emissions. It may be advisable to set a higher threshold 
of NO<INF>X</INF> reductions, such as five or ten tons or more, as a 
minimum for application. This would mean that an applicant for set-
aside NO<INF>X</INF> allowances would have to bring in energy 
efficiency and renewables projects that total no less than five or ten 
tons of NO<INF>X</INF> 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 NO<INF>X</INF> 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 NO<INF>X</INF> 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 NO<INF>X</INF> 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 NO<INF>X</INF> 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 NO<INF>X</INF> Budget Trading 
Program. Since the first year for the trading program is 2003, it may 
be possible to award NO<INF>X</INF> allowances for energy efficiency 
and renewables measures that are initiated and come on line between the 
finalization of the proposed NO<INF>X</INF> 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 NO<INF>X</INF> budget. In considering giving credit for early 
actions in the form of NO<INF>X</INF> 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 NO<INF>X</INF> 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 NO<INF>X</INF> 
allowances and how entities should apply. This concerns whether or not 
an end user may be awarded energy efficiency or renewables 
NO<INF>X</INF> 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 
NO<INF>X</INF> 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 NO<INF>X</INF> 
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 NO<INF>X</INF> 
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 NO<INF>X</INF> 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 NO<INF>X</INF> 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 NO<INF>X</INF> 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 NO<INF>X</INF> allowances necessary to 
cover the eligible applications for efficiency and renewables measures 
in a given period first, then allocating the balance of allowances to 
NO<INF>X</INF> budget units. However, the EPA is concerned that this 
method provides too little certainty to NO<INF>X</INF> 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?
<bullet> Issue (4) Persistence of Efficiency Award
    Because energy efficiency and renewables measures result in 
permanent improvements in energy use and NO<INF>X</INF> reductions, it 
may be appropriate to award energy efficiency and renewables 
NO<INF>X</INF> 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 
NO<INF>X</INF> allowances provides greater availability of such 
NO<INF>X</INF> 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 NO<INF>X</INF> Budget 
Trading Rule sets a five-year period as the duration of the initial 
allowance allocation to NO<INF>X</INF> 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 
NO<INF>X</INF> allowances?
<bullet> 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 
NO<INF>X</INF> reductions achieved, and that can be used in translating 
these savings into their associated NO<INF>X</INF> reductions for 
purposes of awarding NO<INF>X</INF> 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 
NO<INF>X</INF> 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 (SO<INF>2</INF>) allowances 
for savings produced by DSM measures. Although the CVP is 
comprehensive, this protocol may not be appropriate to EPA's purposes 
in a NO<INF>X</INF> 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/NO<INF>X</INF> 
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 NO<INF>X</INF> Rule

    On April 13, 1995, EPA promulgated NO<INF>X</INF> 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 NO<INF>X</INF> 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 NO<INF>X</INF> 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 NO<INF>X</INF> 
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 NO<INF>X</INF> 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 
NO<INF>X</INF> 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 
NO<INF>X</INF> emissions through cap-and-trade programs; and (ii) the 
establishment of the title IV Phase II NO<INF>X</INF> 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 
NO<INF>X</INF> limits are likely to face significant, additional 
NO<INF>X</INF> 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 NO<INF>X</INF> emission reductions exceeding those 
that would be required by utility boilers complying with title IV Phase 
II NO<INF>X</INF> limits, EPA believes that the cap-and-trade system 
should be relied on, in lieu of the title IV Phase II NO<INF>X</INF> 
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 NO<INF>X</INF> limit; only boilers with the same 
owner or operator may average their emissions and comply with a 
weighted average NO<INF>X</INF> limit under a NO<INF>X</INF> averaging 
plan.<SUP>20</SUP> Relief from the title IV Phase II NO<INF>X</INF> 
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 NO<INF>X</INF> control technology designed to meet the 
applicable standard NO<INF>X</INF> 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 NO<INF>X</INF> 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 NO<INF>X</INF> 
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 NO<INF>X</INF> reductions. Since alternative compliance 
will be allowed only if the necessary NO<INF>X</INF> 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 NO<INF>X</INF> 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 NO<INF>X</INF> 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 
NO<INF>X</INF> burner technology is available, and the resulting 
additional reductions are cost effective, represent a reasonable step 
toward achieving regional NO<INF>X</INF> 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, NO<INF>X</INF> 
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 NO<INF>X</INF> 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 NO<INF>X</INF> burners on Group 1 boilers. In setting 
the Group 2 limits, the Administrator relied in part on the additional 
NO<INF>X</INF> reductions that will result and determined that these 
reductions are cost effective, represent a reasonable step toward 
achieving necessary regional NO<INF>X</INF> 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 NO<INF>X</INF> 
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 NO<INF>X</INF> 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 NO<INF>X</INF> emission 
limits must be subject to either (i) a cap on total annual 
NO<INF>X</INF> emissions or (ii) two or more seasonal caps that 
together limit total annual NO<INF>X</INF> 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 
NO<INF>X</INF> 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 NO<INF>X</INF> limits for units in a 
given State will make compliance less cost effective by limiting the 
utility's ability to use NO<INF>X</INF> averaging plans to comply with 
the title IV NO<INF>X</INF> 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 
NO<INF>X</INF> (i.e., NO<INF>X</INF> allowances) to account for their 
NO<INF>X</INF> 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 NO<INF>X</INF> allowances.
    In addition, the units must be required to surrender allowances to 
account for any NO<INF>X</INF> 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 NO<INF>X</INF> 
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 SO<INF>2</INF> 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 
SO<INF>2</INF> 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 SO<INF>2</INF> allowance surrender to account 
for the emissions consequences of reduced utilization (60 FR 18462-63, 
1995).
    The NO<INF>X</INF> cap-and-trade program must include appropriate 
allowance surrender provisions to address this problem by requiring 
NO<INF>X</INF> allowance surrender to the extent necessary to account 
for the increased NO<INF>X</INF> 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 
NO<INF>X</INF> 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 
NO<INF>X</INF> allowance surrender provisions can be developed that are 
less complex than those in place for reduced utilization in the 
SO<INF>2</INF> 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 NO<INF>X</INF> 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 NO<INF>X</INF> 
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 NO<INF>X</INF> 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 NO<INF>X</INF> 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 NO<INF>X</INF> 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 
NO<INF>X</INF> 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 NO<INF>X</INF> 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 NO<INF>X</INF> 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 NO<INF>X</INF> 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'' <SUP>21</SUP>. 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 <SUP>22</SUP> (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 (km<SUP>2</SUP>) 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 <SUP>23</SUP> 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

    <bullet> Number of grid cells with a 1-hour daily maximum ozone 
concentrations >124 and >140 ppb,
    <bullet> ``Weighted sum of differences'' when the 2007 Base Case 
prediction is >124 ppb,
    <bullet> 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
    <bullet> 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

    <bullet> 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 
NO<INF>X</INF> 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:
    <bullet> the number of grid cells with 8-hour daily maximum ozone > 
84 ppb; and
    <bullet> 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 NO<INF>X</INF> 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 NO<INF>X</INF> 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 NO<INF>X                          
                                                   [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 NO<INF>X                           
                                                   [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 NO<INF>X                              
                                                   [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 
                       N0<INF>X 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
                                                      ==================================================================================================
NO<INF>X 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
                                    ============================================================================
NO<INF>x 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
                                           =============================================================================================================
NO<INF>X 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--# <greek-o><greek-ph> <greek-G><greek-r><greek-i><greek-d> <greek-PS><greek-e><greek-l><greek-l><greek-s> \ 140 <greek-p><greek-p><greek-b>                  
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
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<ls-thn-eq>=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 NO<INF>X</INF> 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 NO<INF>X</INF> 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 NO<INF>X</INF> 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 NO<INF>X</INF> 
Rule, today's supplemental proposal includes, in addition to provisions 
directly related to the NO<INF>X</INF> SIP call, a revision to the 40 
CFR Part 76, which implements the NO<INF>X</INF> 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 NO<INF>X</INF> 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 NO<INF>X</INF> SIP call. However, as noted in Section VI, 
Interaction with Title IV NO<INF>X</INF> Rule, today's supplemental 
proposal includes, in addition to provisions directly related to the 
proposed NO<INF>X</INF> SIP call, a revision to the 40 CFR Part 76, 
which implements the NO<INF>X</INF> 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 NO<INF>X</INF> 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 NO<INF>X</INF> control measures 
beginning with the compliance date for NO<INF>X</INF> 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 NO<INF>X</INF> 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 NO<INF>X</INF> 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 
NO<INF>X</INF>. 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 NO<INF>X</INF> 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 
(``NO<INF>X</INF> 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 NO<INF>X</INF> 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 NO<INF>X</INF> 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 NO<INF>X</INF> budget for a State listed in paragraph 
(c) of this section is defined as the total amount of NO<INF>X</INF> 
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 NO<INF>X</INF> 
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 NO<INF>X</INF> 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 
NO<INF>X</INF> 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 
NO<INF>X</INF> 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 
NO<INF>X</INF> budget, then those measures must either:
    (i) Impose a NO<INF>X</INF> mass emissions cap on each source;
    (ii) Impose a NO<INF>X</INF> emission rate limit on each source and 
assume maximum operating capacity for every such source for purposes of 
estimating mass NO<INF>X</INF> 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 NO<INF>X</INF> 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 NO<INF>X</INF> budget during the 2007 ozone season.
    (2) The demonstration must include the following:
    (i) Each revision must contain a detailed baseline inventory of 
NO<INF>X</INF> 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 NO<INF>X</INF> budget.
    (ii) Each revision must contain a summary of NO<INF>X</INF> mass 
emissions in 2007 projected to result from implementation of each of 
the new control measures and from all NO<INF>X</INF> sources together 
following implementation of such control measures. The summary must 
assume the same NO<INF>X</INF> 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 
NO<INF>X</INF> 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 NO<INF>X</INF> 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 NO<INF>X</INF> 
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 
NO<INF>X</INF> 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 NO<INF>x</INF> emissions.

    (a) For its transport SIP revision under section 51.121 of this 
part, each State must submit to EPA NO<INF>X</INF> emissions data as 
described in this section.
    (b) Each revision must provide for periodic reporting by the State 
of NO<INF>X</INF> 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 NO<INF>X</INF> emissions data from all of the following 
sources and source categories:
    (i) All NO<INF>X</INF> sources within the State which the State 
chooses to regulate specifically for the purpose of meeting the 
NO<INF>X</INF> budgets submitted under section 51.121(e)(4). This would 
include all NO<INF>X</INF> 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 NO<INF>X</INF> emissions data 
from all sources within the State.
    (3) Year 2007 reporting. Each plan must provide for reporting of 
year 2007 NO<INF>X</INF> 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 
NO<INF>X</INF> 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 
NO<INF>X</INF> or more per year. A non-mobile source which emits less 
NO<INF>X</INF> 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 NO<INF>X</INF> in Sec. 76.5, in 
lieu of the applicable emission limitations for NO<INF>X</INF> 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 
NO<INF>X</INF> 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 NO<INF>X</INF> emissions; or
    (B) Two or more seasonal caps that together limit total annual 
NO<INF>X</INF> emissions;
    (ii) May trade authorizations to emit NO<INF>X</INF> 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 
NO<INF>X</INF> 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 NO<INF>X</INF> to account 
for:
    (A) Any NO<INF>X</INF> emissions by such unit; and
    (B) Any NO<INF>X</INF> 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 NO<INF>X</INF> emissions under this 
paragraph (b)(1)(iii)(B) will not result in higher total NO<INF>X</INF> 
emissions from sources in the State or group of States or in other 
States; and
    (2)(i) Total annual NO<INF>X</INF> 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 NO<INF>X</INF> 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 NO<INF>X</INF> 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 NO<INF>X</INF> 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--NO<INF>X</INF> BUDGET TRADING PROGRAM

Subpart A--NO<INF>X</INF> 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 NO<INF>X</INF> Budget 
Sources

96.10  Authorization and responsibilities of the NO<INF>X</INF> 
authorized account representative.
96.11  Alternate NO<INF>X</INF> authorized account representative.
96.12  Changing the NO<INF>X</INF> authorized account 
representative, alternate NO<INF>X</INF> authorized account 
representative; changes in the owners and operators.
96.13  Account certificate of representation.
96.14  Objections concerning the NO<INF>X</INF> authorized account 
representative.

Subpart C--Permits

96.20  General NO<INF>X</INF> Budget permit requirements.
96.21  Submission of NO<INF>X</INF> Budget permit applications.
96.22  Information requirements for NO<INF>X</INF> Budget permit 
applications.
96.23  NO<INF>X</INF> Budget permit contents.
96.24  Effective date of initial NO<INF>X</INF> Budget permit.
96.25  NO<INF>X</INF> 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--NO<INF>X</INF> Allowance Allocations

96.40  State trading program budget.
96.41  Timing requirements for NO<INF>X</INF> allowance allocations.
96.42  NO<INF>X</INF> allowance allocations.

Subpart F--NO<INF>X</INF> Allowance Tracking System

96.50  NO<INF>X</INF> Allowance Tracking System accounts.
96.51  Establishment of accounts.
96.52  NO<INF>X</INF> Allowance Tracking System responsibilities of 
NO<INF>X</INF> authorized account representative.
96.53  Recordation of NO<INF>X</INF> allowance allocations.
96.54  Compliance.
96.55  Banking. [Reserved]
96.56  Account error.
96.57  Closing of general accounts.

Subpart G--NO<INF>X</INF> Allowance Transfers

96.60  Scope and submission of NO<INF>X</INF> 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  NO<INF>X</INF> authorized account representative.
96.83  Applying for NO<INF>X</INF> Budget opt-in permit.
96.84  Opt-in process.
96.85  NO<INF>X</INF> Budget opt-in permit contents.
96.86  Withdrawal from NO<INF>X</INF> Budget Trading Program.
96.87  Change in regulatory status.
96.88  NO<INF>X</INF> allowance allocations to opt-in units.

    Authority: 42 U.S.C. 7401, 7403, 7410, and 7601.

Subpart A--NO<INF>X</INF> 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 NO<INF>X</INF> 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 NO<INF>X</INF> 
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 NO<INF>X</INF> authorized account representative for a 
NO<INF>X</INF> Budget source or a group of identified NO<INF>X</INF> 
Budget sources who is authorized to represent the owners and operators 
of such source or sources and of the NO<INF>X</INF> Budget units at 
such source or sources with regard to matters under the NO<INF>X</INF> 
Budget Trading Program.
    Account number means the identification number given by the 
Administrator to each NO<INF>X</INF> 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 NO<INF>X</INF> 
allowances to be initially credited to a NO<INF>X</INF> 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 NO<INF>X</INF> 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 
NO<INF>X</INF> Budget unit under Sec. 96.4 on the date the unit 
commences commercial operation, the date the unit becomes a 
NO<INF>X</INF> 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 
NO<INF>X</INF> 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 NO<INF>X</INF> Budget unit under Sec. 96.4 on the date of 
commencement of operation, the date the unit becomes a NO<INF>X</INF> 
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 NO<INF>X</INF> Allowance Tracking System 
account, established by the Administrator for the NO<INF>X</INF> Budget 
unit under subpart F of this part, in which the NO<INF>X</INF> 
allowance allocations for the unit are initially recorded and in which 
are held NO<INF>X</INF> allowances available for use by the unit for a 
control period for the purpose of meeting the unit's NO<INF>X</INF> 
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 NO<INF>X</INF> Budget source's or a 
NO<INF>X</INF> Budget unit's compliance or noncompliance with this part 
and that is signed by the NO<INF>X</INF> authorized account 
representative in accordance with subpart B of this part.
    Compliance use date means the first control period for which a 
NO<INF>X</INF> allowance can be used for the purpose of meeting a 
unit's NO<INF>X</INF> 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 NO<INF>X</INF> 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 
NO<INF>X</INF> Budget unit during a control period that exceeds the 
NO<INF>X</INF> 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 NO<INF>X</INF> 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 NO<INF>X</INF> 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 CO<INF>2</INF>) or the minimum oxygen 
concentration (in percent O<INF>2</INF>).
    Maximum potential NO<INF>X</INF> 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 O<INF>2</INF>) or the minimum carbon dioxide 
concentration (in percent CO<INF>2</INF>), 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 NO<INF>X</INF> emissions limitation 
means, with regard to a NO<INF>X</INF> Budget opt-in source, the lowest 
NO<INF>X</INF> 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.
    NO<INF>X</INF> allowance means an authorization by the permitting 
authority or the Administrator under the NO<INF>X</INF> 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.
    NO<INF>X</INF> allowance deduction or deduct NO<INF>X</INF> 
allowances means the permanent withdrawal of NO<INF>X</INF> allowances 
by the Administrator from a NO<INF>X</INF> Allowance Tracking System 
compliance account or overdraft account to account for the number of 
tons of NO<INF>X</INF> emissions from a NO<INF>X</INF> 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.
    NO<INF>X</INF> allowances held or hold NO<INF>X</INF> allowances 
means the NO<INF>X</INF> allowances recorded by the Administrator, or 
submitted to the Administrator for recordation, in accordance with 
subpart G of this part, in a NO<INF>X</INF> Allowance Tracking System 
account.
    NO<INF>X</INF> Allowance Tracking System means the system by which 
the Administrator records allocations, deductions, and transfers of 
NO<INF>X</INF> allowances under the NO<INF>X</INF> Budget Trading 
Program.
    NO<INF>X</INF> Allowance Tracking System account means an account 
in the NO<INF>X</INF> Allowance Tracking System established by the 
Administrator for purposes of recording the allocation, holding, 
transferring, or deducting of NO<INF>X</INF> allowances.
    NO<INF>X</INF> 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 
NO<INF>X</INF> allowances may be submitted for recordation in a 
NO<INF>X</INF> Budget unit's compliance account, or the overdraft 
account of the source where the unit is located, in order to meet the 
unit's NO<INF>X</INF> Budget emissions limitation for the control 
period immediately preceding such deadline.
    NO<INF>X</INF> authorized account representative means, for a 
NO<INF>X</INF> Budget source or NO<INF>X</INF> Budget unit at the 
source, the natural person who is authorized by the owners and 
operators of the source and all NO<INF>X</INF> 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 
NO<INF>X</INF> 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 NO<INF>X</INF> allowances 
held in the general account.
    NO<INF>X</INF> Budget emissions limitation means the tonnage 
equivalent of the NO<INF>X</INF> allowances allocated to a 
NO<INF>X</INF> Budget unit for use in a control period adjusted, as of 
the NO<INF>X</INF> 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 NO<INF>X</INF> allowances available for 
compliance deductions for the unit for the control period in accordance 
with Sec. 96.54.
    NO<INF>X</INF> Budget opt-in permit means a NO<INF>X</INF> Budget 
permit covering a NO<INF>X</INF> Budget opt-in source.
    NO<INF>X</INF> Budget opt-in source means a unit that has been 
elected to become a NO<INF>X</INF> Budget unit under the NO<INF>X</INF> 
Budget Trading Program and whose opt-in permit has been issued and is 
in effect under subpart I of this part.
    NO<INF>X</INF> 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 NO<INF>X</INF> Budget Trading Program 
requirements applicable to a NO<INF>X</INF> Budget source, to each 
NO<INF>X</INF> Budget unit at the NO<INF>X</INF> Budget source, and to 
the owners and operators and the NO<INF>X</INF> authorized account 
representative of the NO<INF>X</INF> Budget source and each 
NO<INF>X</INF> Budget unit.
    NO<INF>X</INF> Budget source means a source that includes one or 
more NO<INF>X</INF> Budget units.
    NO<INF>X</INF> 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.
    NO<INF>X</INF> Budget unit means a unit that is subject to the 
NO<INF>X</INF> 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 NO<INF>X</INF> Budget permit under Sec. 96.83(a).
    Operator means any person who operates, controls, or supervises a 
NO<INF>X</INF> Budget unit, a NO<INF>X</INF> Budget source, or unit for 
which an application for a NO<INF>X</INF> 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 NO<INF>X</INF> Budget unit 
under the NO<INF>X</INF> Budget Trading Program through a final, 
effective NO<INF>X</INF> Budget opt-in permit under subpart I of this 
part.
    Overdraft account means the NO<INF>X</INF> Allowance Tracking 
System account, established by the Administrator under subpart F of 
this part, for each NO<INF>X</INF> Budget source where there are two or 
more NO<INF>X</INF> Budget units.
    Owner means any of the following persons:
    (1) Any holder of any portion of the legal or equitable title in a 
NO<INF>X</INF> Budget unit or in a unit for which an application for a 
NO<INF>X</INF> Budget opt-in permit under Sec. 96.83 is being or has 
been submitted; or
    (2) Any holder of a leasehold interest in a NO<INF>X</INF> Budget 
unit or in a unit for which an application for a NO<INF>X</INF> Budget 
opt-in permit under Sec. 96.83 is being or has been submitted; or

[[Page 25978]]

    (3) Any purchaser of power from a NO<INF>X</INF> Budget unit or 
from a unit for which an application for a NO<INF>X</INF> 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 NO<INF>X</INF> Budget 
unit or the unit for which an application for a NO<INF>X</INF> 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 NO<INF>X</INF> allowances held 
in the general account and who is subject to the binding agreement for 
the NO<INF>X</INF> authorized account representative to represent that 
person's ownership interest with respect to NO<INF>X</INF> 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 NO<INF>X</INF> 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 
NO<INF>X</INF> allowances, the movement of NO<INF>X</INF> allowances by 
the Administrator from one NO<INF>X</INF> 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 NO<INF>X</INF> allowances, 
the unique identification number assigned to each NO<INF>X</INF> 
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 NO<INF>X</INF> 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 
NO<INF>X</INF> tons apportioned to all NO<INF>X</INF> Budget units in a 
given State, in accordance with the NO<INF>X</INF> 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 NO<INF>X</INF> 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
CO<INF>2</INF>--carbon dioxide.
NO<INF>X</INF>--nitrogen oxides.
O<INF>2</INF>--oxygen.


Sec. 96.4  Applicability.

    The following units in a State shall be NO<INF>X</INF> Budget 
units, and any source that includes one or more such units shall be a 
NO<INF>X</INF> 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 NO<INF>X</INF> Budget unit, other 
than a NO<INF>X</INF> Budget opt-in source, that is permanently 
retired.
    (b)(1) Any NO<INF>X</INF> Budget unit, other than a NO<INF>X</INF> 
Budget opt-in source, that is permanently retired shall be exempt from 
the NO<INF>X</INF> 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 NO<INF>X</INF> 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 NO<INF>X</INF> 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 
NO<INF>X</INF> authorized account representative of the source submits 
a complete NO<INF>X</INF> 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 NO<INF>X</INF> 
authorized account representative of the source submits a complete 
NO<INF>X</INF> 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 
NO<INF>X</INF> authorized account representative of a unit exempt under 
this section shall comply with the requirements of the NO<INF>X</INF> 
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 NO<INF>X</INF> 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 NO<INF>X</INF> authorized account 
representative submits a NO<INF>X</INF> Budget permit application under 
paragraph (c)(2) of this section; or
    (B) The date on which the NO<INF>X</INF> authorized account 
representative is required under paragraph (c)(2) of this section to 
submit a NO<INF>X</INF> 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 NO<INF>X</INF> authorized account 
representative of each NO<INF>X</INF> Budget source and each 
NO<INF>X</INF> Budget unit at the source shall:
    (i) Submit to the permitting authority a complete NO<INF>X</INF> 
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 
NO<INF>X</INF> Budget permit application and issue or deny a 
NO<INF>X</INF> Budget permit.
    (2) The owners and operators of each NO<INF>X</INF> Budget source 
and each NO<INF>X</INF> Budget unit at the source shall have a 
NO<INF>X</INF> Budget permit issued by the permitting authority and 
operate the unit in compliance with such NO<INF>X</INF> Budget permit.
    (b) Monitoring requirements. (1) The owners and operators and, to 
the extent applicable, the NO<INF>X</INF> authorized account 
representative of each NO<INF>X</INF> Budget source and each 
NO<INF>X</INF> 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 NO<INF>X</INF> Budget emissions limitation under 
paragraph (c) of this section.
    (c) Nitrogen oxides requirements. (1) The owners and operators of 
each NO<INF>X</INF> Budget source and each NO<INF>X</INF> Budget unit 
at the source shall hold NO<INF>X</INF> allowances available for 
compliance deductions under Sec. 96.54, as of the NO<INF>X</INF> 
allowance transfer deadline, in the unit's compliance account and the 
source's overdraft account in an amount not less than the total 
NO<INF>X</INF> 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 
NO<INF>X</INF> Budget emissions limitation shall constitute a separate 
violation of this part, the Clean Air Act, and applicable State law.
    (3) A NO<INF>X</INF> 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) NO<INF>X</INF> allowances shall be held in, deducted from, or 
transferred among NO<INF>X</INF> Allowance Tracking System accounts in 
accordance with subparts E, F, G, and I of this part.
    (5) A NO<INF>X</INF> 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 
NO<INF>X</INF> allowance was allocated.
    (6) A NO<INF>X</INF> allowance allocated by the permitting 
authority under the NO<INF>X</INF> Budget Trading Program is a limited 
authorization to emit one ton of nitrogen oxides in accordance with the 
NO<INF>X</INF> Budget Trading Program. No provision of the 
NO<INF>X</INF> Budget Trading Program, the NO<INF>X</INF> Budget permit 
application, the NO<INF>X</INF> 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 NO<INF>X</INF> allowance allocated by the permitting 
authority or the Administrator under the NO<INF>X</INF> 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 
NO<INF>X</INF> allowance to or from a NO<INF>X</INF> 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 NO<INF>X</INF> 
Budget unit's NO<INF>X</INF> Budget permit by operation of law without 
any further review.
    (d) Excess emissions requirements. (1) The owners and operators of 
a NO<INF>X</INF> Budget unit that has excess emissions in any control 
period shall:
    (i) Surrender the NO<INF>X</INF> 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 NO<INF>X</INF> Budget source 
and each NO<INF>X</INF> 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 
NO<INF>X</INF> authorized account representative for the source and 
each NO<INF>X</INF> 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 NO<INF>X</INF> 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 NO<INF>X</INF> 
Budget Trading Program.
    (iv) Copies of all documents used to complete a NO<INF>X</INF> 
Budget permit application and any other submission under the 
NO<INF>X</INF> Budget Trading Program or to demonstrate compliance with 
the requirements of the NO<INF>X</INF> Budget Trading Program.
    (2) The NO<INF>X</INF> authorized account representative of a 
NO<INF>X</INF> Budget source and each NO<INF>X</INF> Budget unit at the 
source shall submit the reports and compliance certifications required 
under the NO<INF>X</INF> 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 NO<INF>X</INF> Budget Trading 
Program, a NO<INF>X</INF> 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 NO<INF>X</INF> 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 NO<INF>X</INF> Budget Trading Program that occurs 
prior to the date that the revision takes effect.
    (4) Each NO<INF>X</INF> Budget source and each NO<INF>X</INF> 
Budget unit shall meet the requirements of the NO<INF>X</INF> Budget 
Trading Program.
    (5) Any provision of the NO<INF>X</INF> Budget Trading Program that 
applies to a NO<INF>X</INF> Budget source (including a provision 
applicable to the NO<INF>X</INF> authorized account representative of a 
NO<INF>X</INF> Budget source) shall also apply to the owners and 
operators of such source and of the NO<INF>X</INF> Budget units at the 
source.
    (6) Any provision of the NO<INF>X</INF> Budget Trading Program that 
applies to a NO<INF>X</INF> Budget unit (including a provision 
applicable to the NO<INF>X</INF> authorized account representative of a 
NO<INF>X</INF> 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 NO<INF>X</INF> authorized account 
representative of one NO<INF>X</INF> Budget unit shall not be liable 
for any violation by any other NO<INF>X</INF> Budget unit of which they 
are not owners or operators or the NO<INF>X</INF> authorized account 
representative and that is located at a source of which they are not 
owners or operators or the NO<INF>X</INF> authorized account 
representative.
    (g) Effect on Other Authorities. No provision of the NO<INF>X</INF> 
Budget Trading Program, a NO<INF>X</INF> Budget permit application, a 
NO<INF>X</INF> 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 NO<INF>X</INF> authorized account 
representative of a NO<INF>X</INF> Budget source or NO<INF>X</INF> 
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 
NO<INF>X</INF> 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 
NO<INF>X</INF> 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 NO<INF>X</INF> 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--NO<INF>X</INF> Authorized Account Representative for 
NO<INF>X</INF> Budget Sources


Sec. 96.10  Authorization and responsibilities of the NO<INF>X</INF> 
authorized account representative.

    (a) Except as provided under Sec. 96.11, each NO<INF>X</INF> Budget 
source, including all NO<INF>X</INF> Budget units at the source, shall 
have one and only one NO<INF>X</INF> authorized account representative, 
with regard to all matters under the NO<INF>X</INF> Budget Trading 
Program concerning the source or any NO<INF>X</INF> Budget unit at the 
source.
    (b) The NO<INF>X</INF> authorized account representative of the 
NO<INF>X</INF> Budget source shall be selected by an agreement binding 
on the owners and operators of the source and all NO<INF>X</INF> Budget 
units at the source.
    (c) Upon receipt by the Administrator of a complete account 
certificate of representation under Sec. 96.13, the NO<INF>X</INF> 
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 NO<INF>X</INF> Budget source 
represented and each NO<INF>X</INF> Budget unit at the source in all 
matters pertaining to the NO<INF>X</INF> Budget Trading Program, not 
withstanding any agreement between the NO<INF>X</INF> authorized 
account representative and such owners and operators. The owners and 
operators shall be bound by any decision or order issued to the 
NO<INF>X</INF> authorized account representative by the permitting 
authority, the Administrator, or a court regarding the source or unit.
    (d) No NO<INF>X</INF> Budget permit shall be issued, and no 
NO<INF>X</INF> Allowance Tracking System account shall be established 
for a NO<INF>X</INF> Budget unit at a source, until the Administrator 
has received a complete account certificate of representation under 
Sec. 96.13 for a NO<INF>X</INF> authorized account representative of 
the source and the NO<INF>X</INF> Budget units at the source.
    (e) (1) Each submission under the NO<INF>X</INF> Budget Trading 
Program shall be submitted, signed, and certified by the NO<INF>X</INF> 
authorized account representative

[[Page 25981]]

for each NO<INF>X</INF> Budget source on behalf of which the submission 
is made. Each such submission shall include the following certification 
statement by the NO<INF>X</INF> authorized account representative: ``I 
am authorized to make this submission on behalf of the owners and 
operators of the NO<INF>X</INF> Budget sources or NO<INF>X</INF> 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 
NO<INF>X</INF> Budget source or a NO<INF>X</INF> 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 NO<INF>X</INF> authorized account representative.

    (a) An account certificate of representation may designate one and 
only one alternate NO<INF>X</INF> authorized account representative who 
may act on behalf of the NO<INF>X</INF> authorized account 
representative. The agreement by which the alternate NO<INF>X</INF> 
authorized account representative is selected shall include a procedure 
for authorizing the alternate NO<INF>X</INF> authorized account 
representative to act in lieu of the NO<INF>X</INF> 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 NO<INF>X</INF> 
authorized account representative shall be deemed to be a 
representation, action, inaction, or submission by the NO<INF>X</INF> 
authorized account representative.
    (c) Except in this section and Secs. 96.10(a), 96.12, 96.13, and 
96.51, whenever the term ``NO<INF>X</INF> authorized account 
representative'' is used in this part, the term shall be construed to 
include the alternate NO<INF>X</INF> authorized account representative.


Sec. 96.12  Changing the NO<INF>X</INF> authorized account 
representative alternate NO<INF>X</INF> authorized account 
representative; changes in the owners and operators.

    (a) Changing the NO<INF>X</INF> authorized account representative. 
The NO<INF>X</INF> 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 NO<INF>X</INF> 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 NO<INF>X</INF> authorized account representative and 
the owners and operators of the NO<INF>X</INF> Budget source and the 
NO<INF>X</INF> Budget units at the source.
    (b) Changing the alternate NO<INF>X</INF> authorized account 
representative. The alternate NO<INF>X</INF> 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 NO<INF>X</INF> 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 
NO<INF>X</INF> authorized account representative and the owners and 
operators of the NO<INF>X</INF> Budget source and the NO<INF>X</INF> 
Budget units at the source.
    (c) Changes in the owners and operators. (1) In the event a new 
owner or operator of a NO<INF>X</INF> Budget source or a NO<INF>X</INF> 
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 NO<INF>X</INF> authorized account representative 
and any alternate NO<INF>X</INF> 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 NO<INF>X</INF> Budget source or a NO<INF>X</INF> Budget unit, 
including the addition of a new owner or operator, the NO<INF>X</INF> 
authorized account representative or alternate NO<INF>X</INF> 
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 
NO<INF>X</INF> authorized account representative or an alternate 
NO<INF>X</INF> authorized account representative shall include the 
following elements in a format prescribed by the Administrator:
    (1) Identification of the NO<INF>X</INF> Budget source and each 
NO<INF>X</INF> 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 NO<INF>X</INF> 
authorized account representative and any alternate NO<INF>X</INF> 
authorized account representative.
    (3) A list of the owners and operators of the NO<INF>X</INF> Budget 
source and of each NO<INF>X</INF> Budget unit at the source.
    (4) The following certification statement by the NO<INF>X</INF> 
authorized account representative and any alternate NO<INF>X</INF> 
authorized account representative: ``I certify that I was selected as 
the NO<INF>X</INF> authorized account representative or alternate 
NO<INF>X</INF> authorized account representative, as applicable, by an 
agreement binding on the owners and operators of the NO<INF>X</INF> 
Budget source and each NO<INF>X</INF> Budget unit at the source. I 
certify that I have all the necessary authority to carry out my duties 
and responsibilities under the NO<INF>X</INF> Budget Trading Program on 
behalf of the owners and operators of the NO<INF>X</INF> Budget source 
and of each NO<INF>X</INF> 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 NO<INF>X</INF> authorized account 
representative and any alternate NO<INF>X</INF> 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 NO<INF>X</INF> 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 NO<INF>X</INF> authorized 
account representative shall affect any representation, action, 
inaction, or submission of the NO<INF>X</INF> authorized account 
representative or the finality of any decision or order by the 
permitting authority or the Administrator under the NO<INF>X</INF> 
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 
NO<INF>X</INF> authorized account representative, including private 
legal disputes concerning the proceeds of NO<INF>X</INF> allowance 
transfers.

Subpart C--Permits


Sec. 96.20  General NO<INF>X</INF> budget trading program permit 
requirements.

    (a) Each NO<INF>X</INF> Budget source shall have a federally 
enforceable permit, which shall include a NO<INF>X</INF> Budget permit, 
administered by the permitting authority.
    (1) For NO<INF>X</INF> Budget sources required to have a title V 
operating permit, the NO<INF>X</INF> 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 NO<INF>X</INF> Budget sources required to have a non-title 
V permit, the NO<INF>X</INF> 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 NO<INF>X</INF> Budget permit (including a draft or 
proposed NO<INF>X</INF> Budget permit, if applicable) shall contain all 
applicable NO<INF>X</INF> 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 NO<INF>X</INF> Budget permit applications.

    (a) Duty to apply. The NO<INF>X</INF> authorized account 
representative of any NO<INF>X</INF> Budget source with one or more 
NO<INF>X</INF> Budget units shall submit to the permitting authority a 
complete NO<INF>X</INF> Budget permit application under Sec. 96.22 by 
the applicable deadline in paragraph (b) of this section.
    (b)(1) For NO<INF>X</INF> Budget sources required to have a title V 
operating permit:
    (i) For any source, with one or more NO<INF>X</INF> Budget units 
under Sec. 96.4 that commence operation before January 1, 2000, the 
NO<INF>X</INF> authorized account representative shall submit a 
complete NO<INF>X</INF> Budget permit application under Sec. 96.22 
covering such NO<INF>X</INF> 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 NO<INF>X</INF> Budget unit under 
Sec. 96.4 that commences operation on or after January 1, 2000, the 
NO<INF>X</INF> authorized account representative shall submit a 
complete NO<INF>X</INF> Budget permit application under Sec. 96.22 
covering such NO<INF>X</INF> 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 NO<INF>X</INF> Budget unit commences operation.
    (2) For NO<INF>X</INF> Budget sources required to have a non-title 
V permit:
    (i) For any source, with one or more NO<INF>X</INF> Budget units 
under Sec. 96.4 that commence operation before January 1, 2000, the 
NO<INF>X</INF> authorized account representative shall submit a 
complete NO<INF>X</INF> Budget permit application under Sec. 96.22 
covering such NO<INF>X</INF> 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 NO<INF>X</INF> Budget unit under 
Sec. 96.4 that commences operation on or after January 1, 2000, the 
NO<INF>X</INF> authorized account representative shall submit a 
complete NO<INF>X</INF> Budget permit application under Sec. 96.22 
covering such NO<INF>X</INF> 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 NO<INF>X</INF> Budget unit commences operation.
    (c) Duty to Reapply. (1) For a NO<INF>X</INF> Budget source 
required to have a title V operating permit, the NO<INF>X</INF> 
authorized account representative shall submit a complete 
NO<INF>X</INF> Budget permit application under Sec. 96.22 for the 
NO<INF>X</INF> Budget source covering the NO<INF>X</INF> Budget units 
at the source in accordance with the permitting authority's title V 
operating permits regulations addressing operating permit renewal.
    (2) For a NO<INF>X</INF> Budget source required to have a non-title 
V permit, the NO<INF>X</INF> authorized account representative shall 
submit a complete NO<INF>X</INF> Budget permit application under 
Sec. 96.22 for the NO<INF>X</INF> Budget source covering the 
NO<INF>X</INF> 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 NO<INF>X</INF> Budget permit 
applications.

    A complete NO<INF>X</INF> Budget permit application shall include 
the following elements concerning the NO<INF>X</INF> Budget source for 
which the application is submitted, in a format prescribed by the 
permitting authority:
    (a) Identification of the NO<INF>X</INF> 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 NO<INF>X</INF> Budget unit at the 
NO<INF>X</INF> Budget source and whether it is a NO<INF>X</INF> 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 NO<INF>X</INF> Budget opt-in unit at the 
NO<INF>X</INF> Budget source, the following

[[Page 25983]]

certification statements by the NO<INF>X</INF> 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 NO<INF>X</INF> 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 NO<INF>X</INF> 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  NO<INF>X</INF> Budget permit contents.

    (a) Each NO<INF>X</INF> Budget permit (including any draft or 
proposed NO<INF>X</INF> Budget permit, if applicable) will contain, in 
a format prescribed by the permitting authority, all elements required 
for a complete NO<INF>X</INF> Budget permit application under 
Sec. 96.22 as approved or adjusted by the permitting authority.
    (b) Each NO<INF>X</INF> 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 NO<INF>X</INF> 
allowance to or from the compliance accounts of the NO<INF>X</INF> 
Budget units covered by the permit or the overdraft account of the 
NO<INF>X</INF> Budget source covered by the permit.


Sec. 96.24  Effective date of initial NO<INF>X</INF> budget permit.

    The initial NO<INF>X</INF> Budget permit covering a NO<INF>X</INF> 
Budget unit for which a complete NO<INF>X</INF> 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 NO<INF>X</INF> Budget unit 
commences operation, if the unit commences operation on or before May 1 
of that year;
    (c) The date on which the NO<INF>X</INF> 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 
NO<INF>X</INF> Budget unit commences operation, if the unit commences 
operation on or after October 1 of the year.


Sec. 96.25  NO<INF>X</INF> Budget permit revisions.

    (a) For a NO<INF>X</INF> Budget source with a title V operating 
permit, except as provided in Sec. 96.23(b), the permitting authority 
will revise the NO<INF>X</INF> Budget permit, as necessary, in 
accordance with the permitting authority's title V operating permits 
regulations addressing permit revisions.
    (b) For a NO<INF>X</INF> Budget source with a non-title V permit, 
except as provided in Sec. 96.23(b), the permitting authority will 
revise the NO<INF>X</INF> 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 NO<INF>X</INF> Budget units at a source are subject to the 
NO<INF>X</INF> Budget emissions limitation, the NO<INF>X</INF> 
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 NO<INF>X</INF> 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 NO<INF>X</INF> Budget emissions limitation for the 
control period covered by the report:
    (1) Identification of each NO<INF>X</INF> Budget unit;
    (2) At the NO<INF>X</INF> authorized account representative's 
option, the serial numbers of the NO<INF>X</INF> allowances that are to 
be deducted from each unit's compliance account under Sec. 96.54 for 
the control period;
    (3) At the NO<INF>X</INF> authorized account representative's 
option, for units sharing a common stack and having NO<INF>X</INF> 
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 NO<INF>X</INF> 
authorized account representative shall certify, based on reasonable 
inquiry of those persons with primary responsibility for operating the 
source and the NO<INF>X</INF> Budget units at the source in compliance 
with the NO<INF>X</INF> Budget Trading Program, whether each 
NO<INF>X</INF> 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 NO<INF>X</INF> Budget 
Trading Program applicable to the unit, including:
    (1) Whether the unit was operated in compliance with the 
NO<INF>X</INF> 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 NO<INF>X</INF> 
emissions to the unit, in accordance with subpart H of this part;
    (3) Whether all the NO<INF>X</INF> 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 NO<INF>X</INF> 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--NO<INF>X</INF> 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 
NO<INF>X</INF> emissions apportioned to the NO<INF>X</INF> Budget units 
under Sec. 96.4 in the State, as determined by the applicable, approved 
State implementation plan.


Sec. 96.41  Timing requirements for NO<INF>X</INF> allowance 
allocations.

    (a) By September 30, 1999, the permitting authority will submit to 
the Administrator the NO<INF>X</INF> 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 NO<INF>X</INF> allowance allocations in 
accordance with this paragraph (a), the Administrator will allocate 
NO<INF>X</INF> 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 
NO<INF>X</INF> 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 
NO<INF>X</INF> allowance allocations in accordance with this paragraph 
(b), the Administrator will allocate NO<INF>X</INF> 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  NO<INF>X</INF> allowance allocations.

    (a)(1) The heat input (in mmBtu) used for calculating 
NO<INF>X</INF> allowance allocations for each NO<INF>X</INF> Budget 
unit under Sec. 96.4 will be:
    (i) For a NO<INF>X</INF> 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 NO<INF>X</INF> 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 NO<INF>X</INF> 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 
NO<INF>X</INF> 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 NO<INF>X</INF> 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 NO<INF>X</INF> allowances equal to 98 
percent of the tons of NO<INF>X</INF> emissions in the State trading 
program budget under Sec. 96.40 in accordance with the following 
procedures:
    (1) The permitting authority will allocate NO<INF>X</INF> 
allowances to each NO<INF>X</INF> 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 NO<INF>X</INF> allowances 
allocated to all NO<INF>X</INF> 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 NO<INF>X</INF> emissions in the State trading 
program budget, the permitting authority will adjust the total number 
of NO<INF>X</INF> allowances allocated to all such NO<INF>X</INF> 
Budget units for the control period under paragraph (a)(1) of this 
section so that the total number of NO<INF>X</INF> allowances allocated 
equals 98 percent of the number of tons of NO<INF>X</INF> emissions in 
the State trading program budget. This adjustment will be made by: 
multiplying each unit's allocation by the total number of 
NO<INF>X</INF> allowances allocated under paragraph (a)(1) of this 
section divided by 98 percent of the number of tons of NO<INF>X</INF> 
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 NO<INF>X</INF> allowances to NO<INF>X</INF> 
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 NO<INF>X</INF> allowances equal to 2 percent of the tons of 
NO<INF>X</INF> emissions in the State trading program budget under 
Sec. 96.40.
    (2) The NO<INF>X</INF> authorized account representative of a 
NO<INF>X</INF> 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 NO<INF>X</INF> 
allowances for no more than five consecutive control periods under 
Sec. 96.41, starting with the control period during which the 
NO<INF>X</INF> Budget unit is projected to commence operation. The 
NO<INF>X</INF> allowance allocation request must be submitted prior to 
May 1 of the first control period for which the NO<INF>X</INF> 
allowance allocation is requested and after the date on which the 
permitting authority issues a permit to construct the NO<INF>X</INF> 
Budget unit.
    (3) In a NO<INF>X</INF> allowance allocation request under 
paragraph (c)(2) of this section, the NO<INF>X</INF> authorized account 
representative may request for a control period NO<INF>X</INF> 
allowances in an amount that does not exceed 0.15 lb/mmBtu multiplied 
by the NO<INF>X</INF> 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 
NO<INF>X</INF> allowances pursuant to, NO<INF>X</INF> 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 NO<INF>X</INF> 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 
NO<INF>X</INF> allowances are requested has an amount of NO<INF>X</INF> 
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 NO<INF>X</INF> allowances 
requested to the NO<INF>X</INF> Budget unit.
    (iii) If the allocation set-aside for the control period for which 
NO<INF>X</INF> allowances are requested has a smaller amount of 
NO<INF>X</INF> 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 
NO<INF>X</INF> allowances in the allocation set-aside to the 
NO<INF>X</INF> Budget unit.
    (iv) Once an allocation set-aside for a control period has been 
depleted of all NO<INF>X</INF> allowances, the permitting authority 
will deny, and will not allocate any NO<INF>X</INF> allowances pursuant 
to, any NO<INF>X</INF> allowance allocation requests under which 
NO<INF>X</INF> allowances

[[Page 25985]]

have not already been allocated for the control period.
    (5) Within 60 days of receipt of a NO<INF>X</INF> allowance 
allocation request, the permitting authority will take appropriate 
action under paragraph (c)(4) of this section and notify the 
NO<INF>X</INF> authorized account representative that submitted the 
request and the Administrator of the number of NO<INF>X</INF> 
allowances (if any) allocated for the control period to the 
NO<INF>X</INF> Budget unit.
    (6) After September 30 of each year, the Administrator will 
transfer any NO<INF>X</INF> 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 NO<INF>X</INF> 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 NO<INF>X</INF> allowances, in accordance with paragraph (c)(4) 
of this section, to any NO<INF>X</INF> allowance allocation requests 
that were originally denied in whole or in part. The permitting 
authority will notify the NO<INF>X</INF> authorized account 
representative that submitted the request and the Administrator of the 
number of NO<INF>X</INF> allowances (if any) allocated under this 
paragraph (c)(7).
    (d) For a NO<INF>X</INF> Budget unit that is allocated 
NO<INF>X</INF> allowances under paragraph (c) of this section for a 
control period, the Administrator will deduct NO<INF>X</INF> 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 NO<INF>X</INF> 
allowances to be deducted to account for the unit's actual utilization 
using the following formula, provided that the number of NO<INF>X</INF> 
allowances to be deducted shall be zero if the number calculated is 
less than zero:
    Unit's NO<INF>X</INF> allowances deducted for actual utilization = 
(Unit's NO<INF>X</INF> allowances allocated for control period)--
(Unit's actual control period utilization x 0.15 lb/mmBtu) where:
    ``Unit's NO<INF>X</INF> allowances allocated for control period'' 
is the number of NO<INF>X</INF> 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 NO<INF>X</INF> 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--NO<INF>X</INF> Allowance Tracking System


Sec. 96.50  NO<INF>X</INF> 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 NO<INF>X</INF> Budget unit 
and one overdraft account for each source with one or more 
NO<INF>X</INF> 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 NO<INF>X</INF> 
emissions, account for actual utilization, or offset excess emissions 
of NO<INF>X</INF> 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 NO<INF>X</INF> 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 
NO<INF>X</INF> 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 
NO<INF>X</INF> authorized account representative and any alternate 
NO<INF>X</INF> authorized account representative;
    (ii) At the option of the NO<INF>X</INF> authorized account 
representative, organization name and type of organization;
    (iii) A list of all persons subject to a binding agreement for the 
NO<INF>X</INF> 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 NO<INF>X</INF> 
authorized account representative and any alternate NO<INF>X</INF> 
authorized account representative: ``I certify that I was selected as 
the NO<INF>X</INF> authorized account representative or the 
NO<INF>X</INF> 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 NO<INF>X</INF> 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 NO<INF>X</INF> authorized account 
representative and any alternate NO<INF>X</INF> 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 NO<INF>X</INF> authorized account representative and any 
alternate NO<INF>X</INF> 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 NO<INF>X</INF> allowances held in 
the general account in all matters pertaining to the NO<INF>X</INF> 
Budget Trading Program, not withstanding any agreement between the 
NO<INF>X</INF> authorized account representative or any alternate 
NO<INF>X</INF> authorized account representative and such person. Any 
such person shall be bound by any order or decision issued to the 
NO<INF>X</INF> authorized account representative or any alternate 
NO<INF>X</INF> 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 NO<INF>X</INF> authorized 
account representative or the alternate NO<INF>X</INF> authorized 
account representative for the persons having an ownership interest 
with respect to NO<INF>X</INF> allowances held in the general account. 
Each such submission shall include the following certification 
statement by the NO<INF>X</INF> 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 NO<INF>X</INF> 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 NO<INF>X</INF> authorized account representative and one and 
only one alternate NO<INF>X</INF> authorized account representative who 
may act on behalf of the NO<INF>X</INF> authorized account 
representative. The agreement by which the alternate NO<INF>X</INF> 
authorized account representative is selected shall include a procedure 
for authorizing the alternate NO<INF>X</INF> authorized account 
representative to act in lieu of the NO<INF>X</INF> 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 
NO<INF>X</INF> authorized account representative shall be deemed to be 
a representation, action, inaction, or submission by the NO<INF>X</INF> 
authorized account representative.
    (4)(i) The NO<INF>X</INF> 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 NO<INF>X</INF> 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 
NO<INF>X</INF> authorized account representative and the persons with 
an ownership interest with respect to the allowances in the general 
account.
    (ii) The alternate NO<INF>X</INF> 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 NO<INF>X</INF> 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 NO<INF>X</INF> 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 NO<INF>X</INF> 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 NO<INF>X</INF> authorized 
account representative and any alternate NO<INF>X</INF> 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 NO<INF>X</INF> allowances in the 
general account, including the addition of persons, the NO<INF>X</INF> 
authorized account representative or alternate NO<INF>X</INF> 
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 NO<INF>X</INF> 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 NO<INF>X</INF> authorized account representative 
for a general account shall affect any representation, action, 
inaction, or submission of the NO<INF>X</INF> authorized account 
representative or the finality of any decision or order by the 
Administrator under the NO<INF>X</INF> 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 NO<INF>X</INF> authorized account 
representative for a general account, including private legal disputes 
concerning the proceeds of NO<INF>X</INF> 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  NO<INF>X</INF> Allowance Tracking System responsibilities 
of NO<INF>X</INF> authorized account representative.

    (a) Following the establishment of a NO<INF>X</INF> 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 NO<INF>X</INF> allowances in 
the account, shall be made only by the NO<INF>X</INF> authorized 
account representative for the account.
    (b) Authorized account representative identification. The 
Administrator will assign a unique identifying number to each 
NO<INF>X</INF> authorized account representative.


Sec. 96.53  Recordation of NO<INF>X</INF> allowance allocations.

    (a) The Administrator will record the NO<INF>X</INF> allowances for 
2003, 2004, 2005, 2006, and 2007 in the NO<INF>X</INF> Budget units' 
compliance accounts and the allocation set-asides, as allocated under 
subpart E of this part. The Administrator will also record the 
NO<INF>X</INF> allowances allocated under Sec. 96.88(a)(1) and (b) for 
each NO<INF>X</INF> Budget opt-in source in its compliance account.
    (b) Each year, after the Administrator has made all deductions from 
a NO<INF>X</INF> Budget unit's compliance account and the overdraft 
account pursuant to Sec. 96.54, the Administrator will record 
NO<INF>X</INF> 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 NO<INF>X</INF> 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 NO<INF>X</INF> allowances. When 
allocating NO<INF>X</INF> allowances to and recording them in an 
account, the Administrator will assign each NO<INF>X</INF> allowance a 
unique

[[Page 25987]]

identification number that will include digits identifying the year for 
which the NO<INF>X</INF> allowance is allocated.


Sec. 96.54  Compliance.

    (a) NO<INF>X</INF> allowance transfer deadline. The NO<INF>X</INF> 
allowances are available to be deducted for compliance with a unit's 
NO<INF>X</INF> Budget emissions limitation for a control period in a 
given year only if the NO<INF>X</INF> 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 
NO<INF>X</INF> allowance transfer deadline for that control period or 
are transferred into the compliance account or overdraft account by a 
NO<INF>X</INF> allowance transfer correctly submitted for recordation 
under Sec. 96.60 by the NO<INF>X</INF> allowance transfer deadline for 
that control period.
    (b) Deductions for compliance. (1) Following the recordation, in 
accordance with Sec. 96.61, of NO<INF>X</INF> 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 
NO<INF>X</INF> allowance transfer deadline for a control period, the 
Administrator will deduct NO<INF>X</INF> allowances available under 
paragraph (a) of this section to cover the unit's NO<INF>X</INF> 
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 NO<INF>X</INF> 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 NO<INF>X</INF> Allowance 
Tracking System account number and end with the unit having the 
compliance account with the highest NO<INF>X</INF> 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 NO<INF>X</INF> 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 NO<INF>X</INF> allowances deducted for the 
control period equals the number of tons of NO<INF>X</INF> 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 NO<INF>X</INF> allowances required for deduction to account 
for actual utilization under Sec. 96.42(d) for the control period; or
    (ii) Until no more NO<INF>X</INF> allowances available under 
paragraph (a) of this section remain in the respective account.
    (c)(1) Identification of NO<INF>X</INF> allowances by serial 
number. The NO<INF>X</INF> authorized account representative for each 
compliance account may identify by serial number the NO<INF>X</INF> 
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 
NO<INF>X</INF> allowances for a control period from the compliance 
account, in the absence of an identification or in the case of a 
partial identification of NO<INF>X</INF> 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 NO<INF>X</INF> 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 NO<INF>X</INF> 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 NO<INF>X</INF> 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 NO<INF>X</INF> 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 
NO<INF>X</INF> 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 NO<INF>X</INF> allowances, the Administrator will deduct the 
required number of NO<INF>X</INF> allowances, regardless of their 
compliance use date, whenever NO<INF>X</INF> 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 NO<INF>X</INF> 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 NO<INF>X</INF> 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 NO<INF>X</INF> authorized account representative of the 
units may identify the percentage of NO<INF>X</INF> allowances to be 
deducted from each such unit's compliance account to cover the unit's 
share of NO<INF>X</INF> 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 NO<INF>X</INF> allowances until the number of 
NO<INF>X</INF> allowances equals the identified percentage of the 
number of tons of NO<INF>X</INF> 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 NO<INF>X</INF> Allowance 
Tracking System account. Within 10 business days of making such 
correction, the Administrator will notify

[[Page 25988]]

the NO<INF>X</INF> authorized account representative for the account.


Sec. 96.57  Closing of general accounts.

    (a) The NO<INF>X</INF> 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 
NO<INF>X</INF> Allowance Tracking System and by correctly submitting 
for recordation under Sec. 96.60 an allowance transfer of all 
NO<INF>X</INF> allowances in the account to one or more other 
NO<INF>X</INF> 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 NO<INF>X</INF> allowances, the 
Administrator may notify the NO<INF>X</INF> authorized account 
representative for the account that the account will be closed and 
deleted from the NO<INF>X</INF> 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 NO<INF>X</INF> 
allowances into the account under Sec. 96.60 or a statement, in writing 
or in a format specified by the Administrator, submitted by the 
NO<INF>X</INF> authorized account representative demonstrating to the 
satisfaction of the Administrator good cause as to why the account 
should not be closed.

Subpart G--NO<INF>X</INF> Allowance Transfers


Sec. 96.60  Scope and submission of NO<INF>X</INF> allowance transfers.

    The NO<INF>X</INF> authorized account representatives seeking 
recordation of a NO<INF>X</INF> allowance transfer shall submit the 
transfer to the Administrator. To be considered correctly submitted, 
the NO<INF>X</INF> 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 NO<INF>X</INF> 
allowance to be transferred; and
    (c) The printed name and signature of the NO<INF>X</INF> authorized 
account representative of the transferror account and the date signed.


Sec. 96.61  EPA recordation.

    (a) Within 5 business days of receiving a NO<INF>X</INF> allowance 
transfer, except as provided in paragraph (b) of this section, the 
Administrator will record a NO<INF>X</INF> allowance transfer by moving 
each NO<INF>X</INF> 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 NO<INF>X</INF> allowance 
identified by serial number in the transfer; and
    (3) The transfer meets all other requirements of this part.
    (b) A NO<INF>X</INF> allowance transfer that is submitted for 
recordation following the NO<INF>X</INF> allowance transfer deadline 
and that includes any NO<INF>X</INF> allowances with a compliance use 
date that is prior to or the same as the year of the control period to 
which the NO<INF>X</INF> allowance transfer deadline applies will not 
be recorded until after completion of the process of recordation of 
NO<INF>X</INF> allowance allocations in Sec. 96.53(b).
    (c) Where a NO<INF>X</INF> 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 NO<INF>X</INF> 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 NO<INF>X</INF> authorized account representatives 
of both the transferror and transferee accounts.
    (b) Notification of non-recordation. Within 10 business days of 
receipt of a NO<INF>X</INF> 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 
NO<INF>X</INF> 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 
NO<INF>X</INF> 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 
NO<INF>X</INF> authorized account representative of a NO<INF>X</INF> 
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 ``NO<INF>X</INF> Budget 
unit,'' ``NO<INF>X</INF> 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 
NO<INF>X</INF> 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 NO<INF>X</INF> 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 NO<INF>X</INF> 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 NO<INF>X</INF> emission rate and heat 
input, starting on such date until all such certification tests are 
successfully completed, using either:
    (A) The maximum potential NO<INF>X</INF> 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 NO<INF>X</INF> 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 NO<INF>X</INF> 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 NO<INF>X</INF> 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 NO<INF>X</INF> 
emission rate and heat input, starting on such date until all such 
certification tests are successfully completed, using either:
    (A) The maximum potential NO<INF>X</INF> 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 NO<INF>X</INF> 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 NO<INF>X</INF> 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 NO<INF>X</INF> 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 NO<INF>X</INF> emission rate and heat 
input, starting on such date until all such certification tests are 
successfully completed, using either:
    (A) The maximum potential NO<INF>X</INF> 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 NO<INF>X</INF> 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 NO<INF>X</INF> 
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 NO<INF>X</INF> Budget unit shall 
operate the unit so as to discharge, or allow to be discharged, 
NO<INF>X</INF> 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 NO<INF>X</INF> 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 NO<INF>X</INF> 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 NO<INF>X</INF> 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 NO<INF>X</INF> 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 NO<INF>X</INF> 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 NO<INF>X</INF> 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 NO<INF>X</INF> Budget Trading 
Program.
    (2) For any additional NO<INF>X</INF> 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 NO<INF>X</INF> 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 NO<INF>X</INF> Budget unit that is subject to an 
acid rain emissions limitation shall meet the following initial 
certification and recertification procedures for any additional 
NO<INF>X</INF> 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 NO<INF>X</INF> 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 NO<INF>X</INF> 
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 NO<INF>X</INF> 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 NO<INF>X</INF> 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 NO<INF>X</INF> 
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 
NO<INF>X</INF> authorized account representative must submit the 
additional information required to complete the certification 
application. If the NO<INF>X</INF> 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 
NO<INF>X</INF> 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 NO<INF>X</INF> 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 NO<INF>X</INF> authorized account representative for a 
NO<INF>X</INF> 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 NO<INF>X</INF> 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 NO<INF>X</INF> 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 NO<INF>X</INF> 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 
NO<INF>X</INF> 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 NO<INF>X</INF> 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 NO<INF>X</INF> 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 NO<INF>X</INF> 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 
NO<INF>X</INF> 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 NO<INF>X</INF> 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 NO<INF>X</INF> 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 NO<INF>X</INF> emissions.
    (iv) The NO<INF>X</INF> 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 NO<INF>X</INF> authorized account representative of a 
NO<INF>X</INF> 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 NO<INF>X</INF> authorized account representative of a 
NO<INF>X</INF> 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 NO<INF>X</INF> authorized account representative of a 
NO<INF>X</INF> 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 NO<INF>X</INF> Budget unit 
under Sec. 96.4, and is operating, may qualify, under this subpart, to 
become a NO<INF>X</INF> Budget opt-in source. A unit that is a 
NO<INF>X</INF> 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 NO<INF>X</INF> Budget opt-in source.

[[Page 25992]]

Sec. 96.81  General.

    Except otherwise as provided in this part, a NO<INF>X</INF> Budget 
opt-in source shall be treated as a NO<INF>X</INF> Budget unit for 
purposes of applying subparts A through H of this part.


Sec. 96.82  NO<INF>X</INF> authorized account representative.

    A unit for which an application for a NO<INF>X</INF> Budget opt-in 
permit is being or has been submitted, or a NO<INF>X</INF> Budget opt-
in source, located at the same source as one or more NO<INF>X</INF> 
Budget units, shall have the same NO<INF>X</INF> authorized account 
representative as such NO<INF>X</INF> Budget units.


Sec. 96.83  Applying for NO<INF>X</INF> Budget opt-in permit.

    (a) Applying for initial NO<INF>X</INF> Budget opt-in permit. In 
order to apply for an initial NO<INF>X</INF> Budget opt-in permit, the 
NO<INF>X</INF> 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 NO<INF>X</INF> 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 NO<INF>X</INF> authorized account representative has 
been previously designated for the unit.
    (b) Duty to reapply. The NO<INF>X</INF> authorized account 
representative of a NO<INF>X</INF> Budget opt-in source shall submit a 
complete NO<INF>X</INF> Budget permit application under Sec. 96.22 to 
renew the NO<INF>X</INF> 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 NO<INF>X</INF> Budget 
opt-in permit for a unit for which an initial application for a 
NO<INF>X</INF> 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 NO<INF>X</INF> 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 NO<INF>X</INF> 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 NO<INF>X</INF> 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 
``NO<INF>X</INF> Budget unit'' prior to issuance of a NO<INF>X</INF> 
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 NO<INF>X</INF> emissions rate shall be calculated 
as the unit's total NO<INF>X</INF> 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 
NO<INF>X</INF> emissions rate for the unit under paragraph (c) of this 
section, the permitting authority will serve a draft NO<INF>X</INF> 
Budget opt-in permit on the NO<INF>X</INF> authorized account 
representative of the unit.
    (e) Confirmation of intention to opt-in. Within 20 days after the 
issuance of the draft NO<INF>X</INF> Budget opt-in permit, the 
NO<INF>X</INF> 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 
NO<INF>X</INF> 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 NO<INF>X</INF> Budget opt-in permit application.
    (f) Issuance of draft NO<INF>X</INF> Budget opt-in permit. If the 
NO<INF>X</INF> authorized account representative confirms the intention 
to opt in the unit under paragraph (e) of this section, the permitting 
authority will issue the draft NO<INF>X</INF> 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 NO<INF>X</INF> Budget opt-in 
permit for the unit, the permitting authority determines that the unit 
does not qualify as a NO<INF>X</INF> Budget opt-in source under 
Sec. 96.80, the permitting authority will issue a draft denial of a 
NO<INF>X</INF> Budget opt-in permit for the unit in accordance with 
Sec. 96.20.
    (h) Withdrawal of application for NO<INF>X</INF> Budget opt-in 
permit. A NO<INF>X</INF> authorized account representative of a unit 
may withdraw its application for a NO<INF>X</INF> Budget opt-in permit 
under Sec. 96.83 at any time prior to the issuance of the final 
NO<INF>X</INF> Budget opt-in permit. Once the application for a 
NO<INF>X</INF> Budget opt-in permit is withdrawn, a NO<INF>X</INF> 
authorized account representative wanting to reapply must submit a new 
application for a NO<INF>X</INF> Budget permit under Sec. 96.83.
    (i) Effective date. The effective date of the initial 
NO<INF>X</INF> Budget opt-in permit shall be May 1 of the first control 
period starting after the issuance of the initial NO<INF>X</INF> Budget 
opt-in permit by the permitting authority. The unit shall be a 
NO<INF>X</INF> Budget opt-in source and a NO<INF>X</INF> Budget unit as 
of the effective date of the initial NO<INF>X</INF> Budget opt-in 
permit.


Sec. 96.85  NO<INF>X</INF> Budget opt-in permit contents.

    (a) Each NO<INF>X</INF> Budget opt-in permit (including any draft 
or proposed NO<INF>X</INF> Budget opt-in permit, if applicable) will 
contain all elements required for a complete NO<INF>X</INF> Budget opt-
in permit application under Sec. 96.22 as approved or adjusted by the 
permitting authority.
    (b) Each NO<INF>X</INF> 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 NO<INF>X</INF> 
allowances to or from the compliance accounts of each NO<INF>X</INF> 
Budget opt-in source covered by the NO<INF>X</INF> Budget opt-in permit 
or the overdraft account of the NO<INF>X</INF> Budget source where the 
NO<INF>X</INF> Budget opt-in source is located.


Sec. 96.86  Withdrawal from NO<INF>X</INF> Budget Trading Program.

    (a) Requesting withdrawal. To withdraw from the NO<INF>X</INF> 
Budget Trading Program, the NO<INF>X</INF> authorized account 
representative of a NO<INF>X</INF> 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 NO<INF>X</INF> Budget opt-
in source covered by a request under paragraph (a) of this section may 
withdraw from the NO<INF>X</INF> Budget Trading Program and the 
NO<INF>X</INF> 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 NO<INF>X</INF> 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 NO<INF>X</INF> 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 
NO<INF>X</INF> Budget opt-in source's compliance account, or the 
overdraft account of the NO<INF>X</INF> Budget source where the 
NO<INF>X</INF> 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 
NO<INF>X</INF> Budget opt-in source's compliance account, or the 
overdraft account of the NO<INF>X</INF> Budget source where the 
NO<INF>X</INF> Budget opt-in source is located, NO<INF>X</INF> 
allowances equal in number to and with the same or earlier compliance 
use date as any NO<INF>X</INF> 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 NO<INF>X</INF> 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 NO<INF>X</INF> Budget opt-in source. The 
NO<INF>X</INF> authorized account representative for the NO<INF>X</INF> 
Budget opt-in source shall become the NO<INF>X</INF> authorized account 
representative for the general account.
    (c) A NO<INF>X</INF> Budget opt-in source that withdraws from the 
NO<INF>X</INF> Budget Trading Program shall comply with all 
requirements under the NO<INF>X</INF> Budget Trading Program concerning 
all years for which such NO<INF>X</INF> Budget opt-in source was a 
NO<INF>X</INF> 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 NO<INF>X</INF> allowances required), the permitting 
authority will issue a notification to the NO<INF>X</INF> authorized 
account representative of the NO<INF>X</INF> Budget opt-in source of 
the acceptance of the withdrawal of the NO<INF>X</INF> 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 NO<INF>X</INF> authorized account representative of 
the NO<INF>X</INF> Budget opt-in source that the NO<INF>X</INF> Budget 
opt-in source's request to withdraw is denied. If the NO<INF>X</INF> 
Budget opt-in source's request to withdraw is denied, the 
NO<INF>X</INF> Budget opt-in source shall remain subject to the 
requirements for a NO<INF>X</INF> 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 NO<INF>X</INF> Budget permit covering the 
NO<INF>X</INF> Budget opt-in source to terminate the NO<INF>X</INF> 
Budget opt-in permit as of the effective date specified under paragraph 
(d)(1) of this section. A NO<INF>X</INF> Budget opt-in source shall 
continue to be a NO<INF>X</INF> 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 NO<INF>X</INF> Budget opt-in 
source's request to withdraw, the NO<INF>X</INF> 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 NO<INF>X</INF> Budget Trading Program. 
Once a NO<INF>X</INF> Budget opt-in source withdraws from the 
NO<INF>X</INF> Budget Trading Program and its NO<INF>X</INF> Budget 
opt-in permit is terminated under this section, the NO<INF>X</INF> 
authority account representative may not submit another application for 
a NO<INF>X</INF> 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 NO<INF>X</INF> Budget opt-in permit became effective.


Sec. 96.87  Change in regulatory status.

    (a) Notification. When a NO<INF>X</INF> Budget opt-in source 
becomes a NO<INF>X</INF> Budget unit under Sec. 96.4, the 
NO<INF>X</INF> authorized account representative shall notify in 
writing the permitting authority and the Administrator of such change 
in the NO<INF>X</INF> 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 NO<INF>X</INF> Budget opt-in source becomes a NO<INF>X</INF> Budget 
unit under Sec. 96.4, the permitting authority will revise the 
NO<INF>X</INF> Budget opt-in source's NO<INF>X</INF> Budget opt-in 
permit to meet the requirements of a NO<INF>X</INF> Budget permit under 
Sec. 96.23 as of an effective date that is the date on which such 
NO<INF>X</INF> Budget opt-in source becomes a NO<INF>X</INF> Budget 
unit under Sec. 96.4.
    (ii)(A) The Administrator will deduct from the compliance account 
for the NO<INF>X</INF> Budget unit under paragraph (b)(1)(i) of this 
section, or the overdraft account of the NO<INF>X</INF> Budget source 
where the unit is located, NO<INF>X</INF> allowances equal in number to 
and with the same or earlier compliance use date as:
    (1) Any NO<INF>X</INF> allowances allocated to the NO<INF>X</INF> 
Budget unit (as a NO<INF>X</INF> Budget opt-in source) under Sec. 96.88 
for any control period after the last control period during which the 
unit's NO<INF>X</INF> Budget opt-in permit was effective; and
    (2) If the effective date of the NO<INF>X</INF> Budget permit 
revision under paragraph (b)(1)(i) of this section is during a control 
period, the NO<INF>X</INF> allowances allocated to the NO<INF>X</INF> 
Budget unit (as a NO<INF>X</INF> 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 NO<INF>X</INF> authorized account representative shall 
ensure that the compliance account of the NO<INF>X</INF> Budget unit 
under paragraph (b)(1)(i) of this section, or the overdraft account of 
the NO<INF>X</INF> Budget source where the unit is located, includes 
the NO<INF>X</INF> 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 NO<INF>X</INF> 
allowances, the Administrator will deduct the required number of 
NO<INF>X</INF> allowances, regardless of their compliance use date, 
whenever NO<INF>X</INF> allowances are recorded in either account.
    (iii) (A) For every control period during which the NO<INF>X</INF> 
Budget permit revised under paragraph (b)(1)(i) of this section is 
effective, the NO<INF>X</INF> Budget unit under paragraph (b)(1)(i) of 
this section will be treated, solely for purposes of NO<INF>X</INF> 
allowance allocations under Sec. 96.42, as a unit that commenced 
operation on the effective date of the NO<INF>X</INF> Budget permit 
revision under paragraph (b)(1)(i) of this section and will be 
allocated NO<INF>X</INF> allowances under Sec. 96.42.
    (B) Notwithstanding paragraph (b)(1)(iii)(A) of this section, if 
the effective date of the NO<INF>X</INF> Budget permit revision under 
paragraph (b)(1)(i) of this section is during a control period, the 
following number of NO<INF>X</INF> allowances will be allocated to the 
NO<INF>X</INF> Budget unit under paragraph (b)(1)(i) of this section 
under Sec. 96.42 for the control period: the number of NO<INF>X</INF> 
allowances otherwise allocated to the NO<INF>X</INF> 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 NO<INF>X</INF> authorized account representative of 
a NO<INF>X</INF> Budget opt-in source does not renew its NO<INF>X</INF> 
Budget opt-in permit under Sec. 96.83(b), the Administrator will deduct 
from the NO<INF>X</INF> Budget opt-in unit's compliance account, or the 
overdraft account of the NO<INF>X</INF> Budget source where the 
NO<INF>X</INF> Budget opt-in source is located, NO<INF>X</INF> 
allowances equal in number to and with the same or earlier compliance 
use date as any NO<INF>X</INF> allowances allocated to the 
NO<INF>X</INF> Budget opt-in source under Sec. 96.88 for any control 
period after the last control period for which the NO<INF>X</INF> 
Budget opt-in permit is effective. The NO<INF>X</INF> authorized 
account representative shall ensure that the NO<INF>X</INF> Budget opt-
in source's compliance account or the overdraft account of the 
NO<INF>X</INF> Budget source where the NO<INF>X</INF> Budget opt-in 
source is located includes the NO<INF>X</INF> allowances necessary for 
completion of such deduction. If the compliance account or overdraft 
account does not contain sufficient NO<INF>X</INF> allowances, the 
Administrator will deduct the required number of NO<INF>X</INF> 
allowances, regardless of their compliance use date, whenever 
NO<INF>X</INF> 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 NO<INF>X</INF> Budget 
opt-in source's compliance account. If any NO<INF>X</INF> allowances 
remain in the compliance account after completion of such deduction and 
any deduction under Sec. 96.54, the Administrator will close the 
NO<INF>X</INF> 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 NO<INF>X</INF> Budget opt-
in source. The NO<INF>X</INF> authorized account representative for the 
NO<INF>X</INF> Budget opt-in source shall become the NO<INF>X</INF> 
authorized account representative for the general account.


Sec. 96.88  NO<INF>X</INF> allowance allocations to opt-in units.

    (a) NO<INF>X</INF> allowance allocation. (1) By December 31 
immediately before the first control period for which the 
NO<INF>X</INF> Budget opt-in permit is effective, the permitting 
authority will allocate NO<INF>X</INF> allowances to the NO<INF>X</INF> 
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 NO<INF>X</INF> Budget opt-in permit is in effect, and 
December 31 of each year thereafter, the permitting authority will 
allocate NO<INF>X</INF> allowances to the NO<INF>X</INF> 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 NO<INF>X</INF> Budget 
opt-in source has an approved NO<INF>X</INF> Budget opt-in permit, the 
NO<INF>X</INF> Budget opt-in source will be allocated NO<INF>X</INF> 
allowances in accordance with the following procedures:
    (1) The heat input (in mmBtu) used for calculating NO<INF>X</INF> 
allowance allocations will be the lesser of:
    (i) The NO<INF>X</INF> Budget opt-in source's baseline heat input 
determined pursuant to Sec. 96.84(c); or
    (ii) The NO<INF>X</INF> 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 NO<INF>X</INF> allocations are being calculated.
    (2) The permitting authority will allocate NO<INF>X</INF> 
allowances to the NO<INF>X</INF> 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 NO<INF>X</INF> Budget opt-in source's baseline 
NO<INF>X</INF> emissions rate (in lb/mmBtu) determined pursuant to 
Sec. 96.84(c); or
    (ii) The most stringent State or Federal NO<INF>X</INF> emissions 
limitation applicable to the NO<INF>X</INF> Budget opt-in source during 
the control period.

[FR Doc. 98-11873 Filed 5-8-98; 8:45 am]
BILLING CODE 6560-50-P


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