[Federal Register Volume 63, Number 207 (Tuesday, October 27, 1998)]
[Rules and Regulations]
[Pages 57356-57538]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 98-26773]
[[Page 57355]]
_______________________________________________________________________
Part II
Environmental Protection Agency
_______________________________________________________________________
40 CFR Parts 51, 72, 75, and 96
Finding of Significant Contribution and Rulemaking for Certain States
in the Ozone Transport Assessment Group Region for Purposes of Reducing
Regional Transport of Ozone; Rule
Federal Register / Vol. 63, No. 207 / Tuesday, October 27, 1998 /
Rules and Regulations
[[Page 57356]]
ENVIRONMENTAL PROTECTION AGENCY
40 CFR Parts 51, 72, 75, and 96
[FRL-6171-2]
RIN 2060-AH10
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: Final rule.
-----------------------------------------------------------------------
SUMMARY: In accordance with the Clean Air Act (CAA), today's action is
a final rule to require 22 States and the District of Columbia to
submit State implementation plan (SIP) revisions to prohibit specified
amounts of emissions of oxides of nitrogen (NOX)--one of the
precursors to ozone (smog) pollution--for the purpose of reducing
NOX and ozone transport across State boundaries in the
eastern half of the United States.
Ground-level 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.
In today's action, EPA finds that sources and emitting activities
in each of the 22 States and the District of Columbia (23
jurisdictions) emit NOX in amounts that significantly
contribute to nonattainment of the 1-hour and 8-hour ozone national
ambient air quality standards (NAAQS), or will interfere with
maintenance of the 8-hour NAAQS, in one or more downwind States.
Further, by today's action, EPA is requiring each of the affected
upwind jurisdictions (sometimes referred to as upwind States) to submit
SIP revisions prohibiting those amounts of NOX emissions
which significantly contribute to downwind air quality problems. The
reduction of those NOX emissions will bring NOX
emissions in each of those States to within the resulting statewide
NOX emissions budget levels established in today's rule. The
23 jurisdictions are: Alabama, Connecticut, Delaware, District of
Columbia, Georgia, Illinois, Indiana, Kentucky, Massachusetts,
Maryland, Michigan, Missouri, North Carolina, New Jersey, New York,
Ohio, Pennsylvania, Rhode Island, South Carolina, Tennessee, Virginia,
West Virginia, and Wisconsin. These States will be able to choose any
mix of pollution-reduction measures that will achieve the required
reductions.
EFFECTIVE DATES: This rule is effective December 28, 1998. The
incorporation by reference of certain publications listed in the
regulations is approved by the Director of the Federal Register as of
December 28, 1998.
ADDRESSES: Dockets containing information relating to this rulemaking
(Docket No. A-96-56 and Docket No. A-9-35) are available for public
inspection at the Air and Radiation Docket and Information Center
(6102), 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.
FOR FURTHER INFORMATION CONTACT: General questions concerning today's
action should be addressed to Kimber S. 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; e-
mail: scavo.kimber@epa.gov. Please refer to SUPPLEMENTARY INFORMATION
below for a list of contacts for specific subjects described in today's
action.
SUPPLEMENTARY INFORMATION:
Availability of Related Information
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 notice of proposed
rulemaking for this final action, the supplemental notice of proposed
rulemaking, and associated documents are located at http://epa.gov/ttn/
oarpg/otagsip.html. Information related to Sections II, Weight of
Evidence Determination of Covered States, and IV, Air Quality
Assessment, can be obtained in electronic form from the following EPA
website: http://www.epa.gov/scram001/regmodcenter/t28.htm. Information
related to Section III, Determination of Budgets, may be found on the
following EPA website: http://www.epa.gov/capi. All information in
electronic form may also be found on diskettes that have been placed in
the docket to this rulemaking.
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 J. 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 and
questions concerning the Regulatory Impact Analysis (RIA), please
contact Scott Mathias, Office of Air Quality Planning and Standards,
Air Quality Strategies and Standards Division, MD-15, Research Triangle
Park, NC 27711, telephone (919) 541-5310.
Outline
I. Background
A. Summary of Rulemaking and Affected States
B. General Factual Background
C. Statutory and Regulatory Background
1. CAA Provisions
a. 1970 and 1977 CAA Amendments
b. 1990 CAA Amendments
2. Regulatory Structure
a. March 2, 1995 Policy
b. OTAG
[[Page 57357]]
c. EPA's Transport SIP Call Regulatory Efforts
d. Revision of the Ozone NAAQS
D. Section 126 Petitions
E. OTAG
F. Discussion of Comment Period and Availability of Key
Information
1. Request for Extension of the Comment Period
2. Request for Time to Conduct Additional Modeling
3. Availability of Key Information
4. Public Hearings
G. Implementation of Revised Air Quality Standards
H. Summary of Major Changes between Proposals and Final Rule
1. EPA's Analytical Approach (Section II.A)
2. Cost Effectiveness of Emissions Reductions (Section II.D)
3. Determination of Budgets (Section III)
4. NOX Control Implementation and Budget Achievement
Dates (Section V)
5. SIP Criteria (Section VI.A)
6. Emissions Reporting Requirements for States (Section VI.B)
7. NOX Budget Trading Program (Section VII)
8. Interaction with Title IV NOX Rule (Section VIII)
9. Administrative Requirements (Section X)
II. EPA's Analytical Approach
A. Interpretation of the CAA's Transport Provisions
1. Authority and Process for Requiring SIP Submissions under the
1-Hour Ozone NAAQS
a. Authority for Requiring SIP Submissions under the 1-Hour
NAAQS
b. Process for Requiring SIP Submissions under the 1-Hour NAAQS
2. Authority and Process for Requiring SIP Submissions under the
8-Hour Ozone NAAQS
a. Authority for Requiring SIP Submissions under the 8-Hour
NAAQS
b. Process for Requiring SIP Submissions under the 8-hour
Standard
3. Requirements of Section 110(a)(2)(D)
a. Summary
b. Determination of Meaning of ``Nonattainment'
c. Definition of Significant Contribution
d. Multi-factor Test for Determining Significant Contribution
e. Air Quality Factors
f. Determination of Highly Cost-effective Reductions and of
Budgets
g. Other Considerations in Determination of Significant
Contribution
h. Interfere with Maintenance
i. Dates
j. Downwind Areas' Control Obligations
k. Section 110(a)(2)(D) Caselaw
B. Alternative Interpretation of Section 110(a)(2)(D)
C. Weight-of-Evidence Determination of Covered States
1. Major Findings from OTAG-Related Technical Analyses
2. Summary of Notice of Proposed Rulemaking Weight-of-Evidence
Approach
a. Quantification of Contributions
b. Evaluation of 1-Hour and 8-Hour Contributions
c. Comments and Responses on Proposed Weight-of-Evidence
Approach to Significant Contribution
3. Analysis of State-specific Air Quality Factors
a. Overall Nature of Ozone Problem (``Collective Contribution'')
b. Extent of Downwind Nonattainment Problems
c. Air Quality Impacts of Upwind Emissions on Downwind
Nonattainment
4. Confirmation of States Making a Contribution to Downwind
Nonattainment
a. Analysis Approach
b. States Which Contain Sources That Significantly Contribute to
Downwind Nonattainment
c. Examples of Contributions From Upwind States to Downwind
Nonattainment
d. Conclusions From Air Quality Evaluation of Downwind
Contributions
5. States Not Covered by This Rulemaking
D. Cost Effectiveness of Emissions Reductions
1. Sources Included in the Cost-Effectiveness Determination
a. Electricity Generating Boilers and Turbines
b. Other Stationary Sources
2. Sources Not Included in the Cost-Effectiveness Determination
a. Area Sources
b. Small Point Sources
c. Mobile Sources
d. Other Stationary Sources
e. Conclusion
E. Other Considerations
1. Consistency of Regional Reductions with Attainment Needs of
Downwind Areas
a. General Discussion
b. 8-hour Nonattainment Problems
c. Commenters' Concerns
2. Equity Considerations
3. General Cost Considerations
4. Conclusion
III. Determination of Budgets
A. General Comments on the Base Emission Inventory
1. Quality
2. Availability
B. Electricity Generating Units (EGUs)
1. Base Inventory
2. Growth
a. Growth Rates
b. Use of IPM
c. Use of ``Corrected'' Growth Rates
3. Budget Calculation
a. Input vs. Output
b. Alternative Emission Limits
c. Consideration of the Climate Change Action Plan
C. Non-EGU Point Sources
1. Base Inventory
2. Growth
3. Budget Calculation
a. Proposed Control Assumptions
b. Small Source Exemption
c. Exemptions for Other Non-EGU Point Sources
d. Sources Without Adequate Control Information
e. Case-By-Case Analysis of Control Measures
f. Cost Effectiveness
g. Industrial Boiler Control Costs
h. Cement Manufacturing
i. Stationary Internal Combustion Engines
j. Industrial Boilers and Turbines
k. Municipal Waste Combustors (MWCs)
D. Highway Mobile Sources
1. Base Inventory
2. Growth
3. Budget Calculation
a. I/M Program Coverage
b. Emissions Cap
c. Tier 2 Standards
d. Low Sulfur Fuel
e. Conformity
E. Stationary Area and Nonroad Mobile Sources
1. Base Inventory
2. Growth
3. Budget Calculation
F. Other Budget Issues
1. Uniform vs. Regional Controls
2. Seasonal vs. Annual Controls
3. Full vs. Partial States
4. NOx Waivers
5. Recalculation of Budgets
6. Compliance Supplement Pool
a. Size of the Compliance Supplement Pool
b. State Distribution of the Compliance Supplement Pool
7. Banking
a. Banking Starting in 2003
b. Management of Banked Allowances
c. Early Reduction Credits
G. Final Statewide Budgets
1. EGU
a. Description of Selected Approach
b. Summary of Budget Component
2. Non-EGU Point Sources
a. Description of Selected Approach
b. Summary of Budget Component
3. Mobile and Area Sources
a. Description of Selected Budget Approach
b. Summary of Budget Component
4. Potential Alternatives to Meeting the Budget
5. Statewide Budgets
IV. Air Quality Assessment
A. Assessment of Proposed Statewide Budgets
B. Comments and Responses
C. Assessment of Alternative Control Levels
1. Scenarios Modeled
2. Emissions for Model Runs
3. Modeling Results
a. Impacts of Alternative Controls
b. Impacts of Upwind Controls on Downwind Nonattainment
c. Summary of Findings
V. NOx Control Implementation and Budget Achievement Dates
A. NOx Control Implementation Date
1. Practicability
a. Combustion Controls
b. Post-Combustion Controls
2. Relationship to SIP Submittal Date
3. Rationale
B. Budget Achievement Date
VI. SIP Criteria and Emissions Reporting Requirements
A. SIP Criteria
1. Schedule for SIP Revision
2. Approvability Criteria
a. Source Categories Subject to Additional Approvability
Criteria
[[Page 57358]]
b. Pollution Abatement Requirements
c. Monitoring Requirements
d. Approvability of Trading Program
3. Sanctions
4. FIPs
B. Emissions Reporting Requirements for States
1. Use of Inventory Data
2. Response to Comments
3. Final Rule
4. Data Elements to be Reported
5. 2007 Report
6. Ozone Season Reporting
7. Data Reporting Procedures
8. Confidential Data
C. Timeline
VII. NOX Budget Trading Program
A. General Background
B. NOX Budget Trading Program Rulemaking Overview
C. General Design of NOX Budget Trading Program
1. Appropriateness of Trading Program
2. Alternative Market Mechanisms
3. State Adoption of Model Rule
a. Process for Adoption
b. Model Rule Variations
4. Unrestricted Trading Market
a. Geographic Issues
b. Episodic Issues
D. Applicability
1. Core Sources
a. Commenters Who Felt the Core Group Should Not Be Changed
b. Commenters Who Felt the Core Group Should Be Expanded
c. Commenters Who Felt the Core Group Is Overly Inclusive
2. Mobile/Area Sources
3. Monitoring
a. Use of Part 75 to Ensure Compliance with the NOX
Budget Trading Program
b. Use of CEMS on Large Units
c. Commenters Who do not Believe that CEMS are Necessary
d. Issues Related to Monitoring and Reporting Needed to Support
a Heat Input Allocation Methodology
e. Amendments to Part 75
E. Emission Limitations/Allowance Allocations
1. Timing Requirements
2. Options for NOX Allowance Allocation Methodology
3. New Source Set-Aside
4. Optional NOX Allocation Methodology in Model Rule
F. Banking Provisions
1. Banking Starting in 2003
2. Management of Banked Allowances
3. Early Reduction Credits
4. Optional Methodology for Issuing Early Reduction Credits
5. Integrating the OTC Program with the NOX Budget
Trading Program's Banking Provisions
G. New Source Review
VIII. Interaction with Title IV NOX Rule
IX. Non-Ozone Benefits of NOX Emissions Decreases
A. Summary of Comments
B. Response to Comments
1. Drinking Water Nitrate
2. Eutrophication
3. Regulatory Impact Analysis
4. Justification for Rulemaking
X. Administrative Requirements
A. Executive Order 12866: Regulatory Impact Analysis
B. Regulatory Flexibility Act: Small Entity Impacts
C. Unfunded Mandates Reform Act
D. Paperwork Reduction Act
E. Executive Order 13045: Protection of Children from
Environmental Health Risks and Safety Risks
1. Applicability of E.O. 13045
2. Children's Health Protection
F. Executive Order 12898: Environmental Justice
G. Executive Order 12875: Enhancing the Intergovernmental
Partnerships
H. Executive Order 13084: Consultation and Coordination with
Indian Tribal Governments
I. Judicial Review
J. Congressional Review Act
K. National Technology Transfer and Advancement Act
Appendix A--Detailed Discussion of Changes to Part 75
CFR Revisions and Additions
Part 51
Sec. 51.121
Sec. 51.122
Part 72
Part 75
Part 96
I. Background
A. Summary of Rulemaking and Affected States
By notice of proposed rulemaking (NPR, proposal, or ``proposed SIP
call'') (62 FR 60318, November 7, 1997) and by supplemental notice
(SNPR or supplemental proposal) (63 FR 25902, May 11, 1998), EPA
proposed to find that NOX emissions from sources and
emitting activities (sources) in 23 jurisdictions (hereinafter also
referred to as States) will significantly contribute to nonattainment
of the 1-hour and 8-hour ozone NAAQS, or will interfere with
maintenance of the 8-hour NAAQS, in one or more downwind States
throughout the Eastern United States. The EPA based these proposals on
data generated by OTAG, public comments, and other relevant
information. Today's final action confirms that proposed finding. It
also requires, under CAA section 110(a)(1) and 110(k)(5), that the 23
jurisdictions adopt and submit SIP revisions that, in order to assure
that their SIPs meet the requirements of section 110(a)(2)(D)(i)(I),
contain provisions adequate to prohibit sources in those States from
emitting NOX in amounts that ``contribute significantly to
nonattainment in, or interfere with maintenance by,'' a downwind State.
The 23 jurisdictions are: Alabama, Connecticut, Delaware, District of
Columbia, Georgia, Illinois, Indiana, Kentucky, Massachusetts,
Maryland, Michigan, Missouri, North Carolina, New Jersey, New York,
Ohio, Pennsylvania, Rhode Island, South Carolina, Tennessee, Virginia,
West Virginia, and Wisconsin.
Each of these States and the District of Columbia is required to
adopt and submit by September 30, 1999, a SIP revision. The SIP
revision must contain measures that will assure that sources in the
State reduce their NOX emissions sufficiently to eliminate
the amounts of NOX emissions that contribute significantly
to nonattainment, or that interfere with maintenance, downwind. By
eliminating these amounts of NOX emissions, the control
measures will assure that the remaining NOX emissions will
meet the level identified in today's rule as the State's NOX
emissions budget. For simplicity, this final rule may refer to the
amounts that such SIP provisions must prohibit in order to meet the
statute as the ``significant amounts'' of NOX emissions.
After prohibiting these significant amounts of NOX, the
remaining amounts emitted by sources in the covered States will not
``significantly contribute to nonattainment, or interfere with
maintenance by,'' a downwind State, under section 110(a)(2)(D)(i)(I).
Section II.C, Weight-of-Evidence Determination of Covered States,
describes how EPA determined which States include sources that emit
NOX in amounts of concern (the ``covered'' States), and
Sections II.D, Cost Effectiveness of Emissions Reductions; II.E,
Comparison of Upwind and Downwind Costs; and III, Determination of
Budgets, describe how EPA determined the significant amounts of
emissions and the resulting statewide emissions budgets for the States
identified above. Section IV, Air Quality Assessment, discusses air
quality analyses conducted by EPA which help confirm the decisions and
requirements set forth in this rulemaking. Section V, NOX
Control Implementation and Budget Achievement Dates, primarily
discusses the dates by which (1) the States must submit SIP revisions
in response to today's action, (2) the sources must implement the
measures the States choose for the purpose of prohibiting the
significant amounts of NOX, and (3) the States are projected
to achieve the budget levels. Section VI, SIP Criteria and Emissions
Reporting Requirements, describes the SIP requirements themselves.
The SIP requirements permit each State to determine what measures
to adopt to prohibit the significant amounts and hence meet the
necessary emissions budget. Consistent with OTAG's recommendations to
achieve
[[Page 57359]]
NOX emissions decreases primarily from large stationary
sources in a trading program, EPA encourages States to consider
electric utility and large boiler controls under a cap-and-trade
program as a cost-effective strategy. The recommended cap-and-trade
program is described in more detail in Section VII, NOX
Budget Trading Program. The EPA also recognizes that promotion of
energy efficiency can contribute to a cost-effective strategy. In
Section VIII, Interaction with Title IV NOX rule, EPA
explains that it is not adopting proposed revisions to the title IV
NOX rule concerning the relationship between this rulemaking
and the title IV NOX rule. The remaining parts of today's
action include Section IX, Non-Ozone Benefits of NOX
Reductions, and Section X, Administrative Requirements.
The EPA also conducted a RIA which is available in the docket to
this rulemaking as a technical support document (TSD), entitled
``Regulatory Impact Analysis for the Regional NOX SIP Call''
(docket no. VI-B-09). A detailed explanation of how EPA calculated the
budgets is also available as a TSD entitled ``Development of Modeling
Inventory and Budgets for the Regional NOX SIP Call''
(docket no. VI-B-10). These two TSDs have been revised for the final
rulemaking. A detailed explanation of the air quality modeling analyses
is also available, entitled ``Air Quality Modeling Technical Support
Document for the Regional NOX SIP Call'' (docket no. VI-B-
11) for this final rulemaking. This preamble for today's notice
responds to some of the comments, but another document, entitled
``Response to Significant Comments on the Finding of Significant
Contribution and Rulemaking for Certain States in the OTAG Region for
Purposes of Reducing Regional Transport of Ozone,'' is included in the
docket (docket no. VI-C-01).
B. General Factual Background
In today's action, EPA takes a significant step toward reducing
ozone in the eastern half of the country. Ground-level ozone, the main
harmful ingredient in smog, is produced in complex chemical reactions
when its precursors, volatile organic compounds (VOC) and
NOX, react in the presence of sunlight. The chemical
reactions that create ozone take place while the pollutants are being
blown through the air by the wind, which means that ozone can be more
severe many miles away from the source of emissions than it is at the
source.
The science of ozone formation, transport, and accumulation is
complex. Ozone is produced and destroyed in a cyclical set of chemical
reactions involving NOX, VOC and sunlight. Emissions of
NOX and VOC are necessary for the formation of ozone in the
lower atmosphere. In part of the cycle of reactions, ozone
concentrations in an area can be lowered by the reaction of nitric
oxide with ozone, forming nitrogen dioxide; as the air moves downwind
and the cycle continues, the nitrogen dioxide forms additional ozone.
The importance of this reaction depends, in part, on the relative
concentrations of NOX, VOC and ozone, all of which change
with time and location.
At ground level, ozone can cause a variety of ill effects to human
health, crops and trees. Specifically, ground-level ozone has been
shown in clinical and/or epidemiologial studies to have the following
health effects:
Decreased lung function, primarily in children
active outdoors
Increased respiratory symptoms, particularly in
highly sensitive individuals
Hospital admissions and emergency room visits for
respiratory causes among children and adults with pre-existing
respiratory disease such as asthma
Inflammation of the lung
Possible long-term damage to the lungs or even
premature death.
The new 8-hour primary ambient air quality standard (62 FR 38856,
July 18, 1997) will provide increased protection to the public from
these health effects.
Each year, ground-level ozone above background is also responsible
for significant agricultural crop yield losses. Ozone also causes
noticeable foliar damage in many crops, trees, and ornamental plants
(i.e., grass, flowers, shrubs, and trees) and causes reduced growth in
plants. Studies indicate that current ambient levels of ozone are
responsible for damage to forests and ecosystems (including habitat for
native animal species).
As part of the efforts to reduce harmful levels of smog, EPA,
today, is establishing a requirement for certain States to revise their
SIPs in order to implement the necessary regional-scale reductions in
NOX emissions, and, thereby, reduce transported
NOX and ozone. Since air pollution travels across county and
State lines, it is essential for State governments and air pollution
control agencies to cooperate to solve the problem.
Currently, the following areas, impacted by the 23 jurisdictions
that are the subject of today's rulemaking, are designated
nonattainment areas for ozone under the 1-hour NAAQS:
Atlanta, GA
Baltimore, MD
Birmingham, AL
Boston-Lawrence-Worcester (eastern MA), MA-NH
Chicago-Gary-Lake County, IL-IN
Cincinnati-Hamilton, OH-KY
Door County, WI
Greater Connecticut
Kent & Queen Anne's Counties, MD
Lancaster, PA
Louisville, KY-IN
Manitowoc County, WI
Milwaukee-Racine, WI
Muskegon, MI
New York-Northern New Jersey-Long Island, NY-NJ-CT
Philadelphia-Wilmington-Trenton, PA-NJ-DE-MD
Pittsburgh-Beaver Valley, PA
Portland, ME
Portsmouth-Dover-Rochester, NH
Providence (All RI), RI
St. Louis, MO-IL
Springfield (western MA), MA
Washington, DC-MD-VA
These areas include many of the major urban centers in the eastern
half of the Nation. The combined population for these areas is
approximately 61.5 million. As described elsewhere, the reductions
called for in today's action will reduce ozone levels throughout these
areas.
Many more areas currently violate the 8-hour NAAQS. The EPA
estimates that a total population of approximately 73 million in the 23
jurisdictions live in counties for which air quality is monitored to be
in violation of that NAAQS. The reductions called for in today's action
will reduce ozone levels throughout these areas as well.
Moreover, as discussed below, many of these areas are expected to
be classified as ``transitional,'' which means, in most cases, that
they are expected to come into attainment solely as a result of the
reductions required by today's action. Thus, for those who live in
these areas, the reductions required under today's action, in-and-of-
themselves, are expected to mean the difference between unhealthful
ozone levels and acceptable ozone levels.
Please note that EPA will not designate ozone nonattainment areas
for the 8-hour NAAQS until 2000, and these designations will be based
on the data that are most recently available at that time.
C. Statutory and Regulatory Background
1. CAA Provisions
a. 1970 and 1977 CAA Amendments. For almost 30 years, Congress has
focused major efforts on curbing ground-level ozone. In 1970, Congress
amended the CAA to require, in title I, that EPA issue, and
periodically review
[[Page 57360]]
and if necessary revise, NAAQS for ubiquitous air pollutants (sections
108 and 109). Congress required the States to submit SIPs to attain and
maintain those NAAQS, and Congress included, in section 110, a list of
minimum requirements that SIPs must meet. Congress anticipated that
areas would attain the NAAQS by 1975.
In 1977, Congress amended the CAA by providing, among other things,
additional time for areas that were not attaining the ozone NAAQS to do
so, as well as by imposing specific SIP requirements for those
nonattainment areas. These provisions first required the designation of
areas as attainment, nonattainment, or unclassifiable, under section
107; and then required that SIPs for ozone nonattainment areas include
the additional provisions set out in part D of title I, as well as
demonstrations of attainment of the ozone NAAQS by either 1982 or 1987
(section 172).
In addition, the 1977 Amendments included two provisions focused on
interstate transport of air pollutants: the predecessor to current
section 110(a)(2)(D), which requires SIPs for all areas to constrain
emissions with certain adverse downwind effects; and section 126,
which, in general, authorizes a downwind State to petition EPA to
impose limits directly on upwind sources found to adversely affect that
State. Section 110(a)(2)(D), which is key to the present action, is
described in more detail below.
b. 1990 CAA Amendments. In 1990, Congress amended the CAA to better
address, among other things, continued nonattainment of the 1-hour
ozone NAAQS; the requirements that would apply if EPA revised the 1-
hour standard; and transport of air pollutants across State boundaries
(Pub. L. 101-549, Nov. 15, 1990, 104 Stat. 2399, 42 U.S.C., 7401-
7671q). Numerous provisions added, or revised, by the 1990 Amendments
are relevant to today's proposal.
(1) 1-Hour Ozone NAAQS. In the 1990 Amendments, Congress required
the States and EPA to review and, if necessary, revise the designation
of areas as attainment, nonattainment, and unclassifiable under the
ozone NAAQS in effect at that time, which was the 1-hour standard
(section 107(d)(4)). Areas designated as nonattainment were divided
into, primarily, five classifications based on air quality design
values (section 181(a)(1)). Each classification carries specific
requirements, including new attainment dates (sections 181-182). In
increasing severity of the air quality problem, these classifications
are marginal, moderate, serious, severe and extreme. The OTAG region
includes nonattainment areas of all classifications except extreme.
As amended in 1990, the CAA requires States containing ozone
nonattainment areas classified as moderate or above to submit several
SIP revisions at various times. One set of SIP revisions included
specified control measures, such as reasonably available control
technology (RACT) for existing VOC and NOX sources (section
182(b)(2), 182(f)). In addition, the CAA requires the reduction of VOC
in the amount of 15 percent by 1996 from a 1990 baseline (section
182(b)(1)). Further, for nonattainment areas classified as serious and
above, the CAA requires the reduction of VOC or NOX
emissions in the amount of 9 percent over each 3-year period from 1996
through the attainment date (the rate-of-progress (ROP) SIP
submittals), under section 182(c)(2)(B). In addition, the CAA requires
a demonstration of attainment, including air quality modeling, for the
nonattainment area (the attainment demonstration), as well as SIP
measures containing any additional reductions that may be necessary to
attain by the applicable attainment date (section 182(c)-(e)). The CAA
established November 15, 1994 as the required date for the ROP and
attainment demonstration SIP submittals for areas classified as serious
and above.1
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\1\ For moderate ozone nonattainment areas, the attainment
demonstration was due November 15, 1993 (section 182(b)(1)(A)),
except that if the State elected to conduct an urban airshed model,
EPA allowed an extension to November 15, 1994.
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(2) Revised NAAQS. Section 109(d) of the CAA requires periodic
review and, if appropriate, revision of the NAAQS. As amended in 1990,
the CAA further requires EPA to designate areas as attainment,
nonattainment, and unclassifiable under a revised NAAQS (section
107(d)(1); section 6103, Pub. L. 105-178). The CAA authorizes EPA to
classify areas that are designated nonattainment under the new NAAQS
and to establish for those areas attainment dates that are as
expeditiously as practicable, but not to exceed 10 years from the date
of designation (section 172(a)).
(3) General Requirements. The CAA continues, in revised form,
certain requirements, dating from the 1970 Amendments, which pertain to
all areas, regardless of their designation. All areas are required to
submit SIPs within certain timeframes (section 110(a)(1)), and those
SIPs must include specified provisions, under section 110(a)(2). In
addition, SIPs for nonattainment areas are generally required to
include additional specified control requirements, as well as controls
providing for attainment of any revised NAAQS and periodic reductions
providing ``reasonable further progress'' in the interim (section
172(c)).
(4) Provisions Concerning Transport of Ozone and Its Precursors.
The 1990 Amendments reflect general awareness by Congress that ozone is
a regional, and not merely a local, problem. As described above, ozone
and its precursors may be transported long distances across State lines
to combine with ozone and precursors downwind, thereby exacerbating the
ozone problems downwind. The phenomenon of ozone transport was not
generally recognized until relatively recently. Yet, ozone transport is
a major reason for the persistence of the ozone problem,
notwithstanding the imposition of numerous controls, both Federal and
State, across the country.
Section 110(a)(2)(D) provides one of the most important tools for
addressing the problem of transport. This provision, which applies by
its terms to all SIPs for each pollutant covered by a NAAQS, and for
all areas regardless of their attainment designation, provides that a
SIP must contain adequate provisions prohibiting its sources from
emitting air pollutants in amounts that will contribute significantly
to nonattainment, or interfere with maintenance, in one or more
downwind States.
Section 110(k)(5) authorizes EPA to find that a SIP is
substantially inadequate to meet any CAA requirement. If EPA makes such
a finding, it must require the State to submit, within a specified
period, a SIP revision to correct the inadequacy.
The CAA further addresses interstate transport of pollution in
section 126, which Congress revised slightly in 1990. Subsection (b) of
that provision authorizes each State (or political subdivision) to
petition EPA for a finding designed to protect that entity from upwind
sources of air pollutants.2
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\2\ In addition, section 115 authorizes EPA to require a SIP
revision when one or more sources within a State ``cause or
contribute to air pollution which may reasonably be anticipated to
endanger public health or welfare in a foreign country.''
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In addition, the 1990 Amendments added section 184, which
delineates a multistate ozone transport region (OTR) in the Northeast,
requires specific additional controls for all areas (not only
nonattainment areas) in that region, and establishes the Ozone
Transport Commission (OTC) for the purpose of recommending to EPA
regionwide controls affecting all areas in that region. At the same
time, Congress added section 176A, which authorizes
[[Page 57361]]
the formation of transport regions for other pollutants and in other
parts of the country.
2. Regulatory Structure
a. March 2, 1995 Policy. Notwithstanding significant efforts, the
States generally were not able to meet the November 15, 1994 statutory
deadline for the attainment demonstration and ROP SIP submissions
required under section 182(c). The major reason for this failure was
that at that time, States with downwind nonattainment areas were not
able to address transport from upwind areas. As a result, in a
memorandum from Mary D. Nichols, Assistant Administrator for Air and
Radiation, dated March 2, 1995, entitled ``Ozone Attainment
Demonstrations,'' (March 2, 1995 Memorandum or the Memorandum), EPA
recognized the efforts made by States and the remaining difficulties in
making the ROP and attainment demonstration submittals. The EPA
recognized that development of the necessary technical information, as
well as the control measures necessary to achieve the large level of
reductions likely to be required, had been particularly difficult for
the States affected by ozone transport.
Accordingly, as an administrative remedial matter, the Memorandum
indicated that EPA would establish new timeframes for SIP submittals.
The Memorandum indicated that EPA would divide the required SIP
submittals into two phases. Phase I generally consisted of (i) SIP
measures providing for ROP reductions due by the end of 1999, (ii) an
enforceable SIP commitment to submit any remaining required ROP
reductions on a specified schedule after 1996, and (iii) an enforceable
SIP commitment to submit the additional SIP measures needed for
attainment. Phase II consists of the remaining submittals, beginning in
1997.
The Phase II submittals primarily consisted of the remaining ROP
SIP measures, the attainment demonstration and additional rules needed
to attain, and any regional controls needed for attainment by all areas
in the region. The March 2, 1995 Memorandum indicated that the
attainment demonstration, target calculations for the post-1999 ROP
milestones, and identification of rules needed to attain and for post-
1999 ROP were due in mid-1997. To allow time for States to incorporate
the results of the OTAG modeling into their local plans, EPA extended
the mid-1997 submittal date to April 1998.3
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\3\ Guidance for Implementing the 1-hour Ozone and Pre-Existing
PM10 NAAQS, Memorandum from Richard D. Wilson, dated December 29,
1997.
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b. OTAG. In addition, the March 2, 1995 Memorandum called for an
assessment of the ozone transport phenomenon. The Environmental Council
of the States (ECOS) had recommended formation of a national work group
to allow for a thoughtful assessment and development of consensus
solutions to the problem. The OTAG was a partnership between EPA, the
37 easternmost States and the District of Columbia, industry
representatives, and environmental groups. The OTAG's air quality
modeling and recommendations formed the basis for today's action.
c. EPA's Transport SIP Call Regulatory Efforts. Shortly after OTAG
began its work, EPA began to indicate that it intended to issue a SIP
call to require States to implement the reductions necessary to address
the ozone transport problem. On January 10, 1997 (62 FR 1420), EPA
published a notice of intent that articulated this goal and indicated
that before taking final action, EPA would carefully consider the
technical work and any recommendations of OTAG. The EPA published the
NPR for the NOX SIP call by notice dated November 7, 1997
(62 FR 60319). The NPR proposed to make a finding of significant
contribution due to transported NOX emissions to
nonattainment or maintenance problems downwind and to assign
NOX emissions budgets for 23 jurisdictions. The EPA
published a supplemental notice of proposed rulemaking (SNPR) by notice
dated May 11, 1998 (63 FR 25902) which proposed a model NOX
budget trading program and State reporting requirements and provided
the air quality analyses of the proposed statewide NOX
emissions budgets. The EPA received approximately 700 comments on these
proposals. The comment periods are described in Section I.F, Discussion
of Comment Period and Availability of Key Information. Throughout the
course of the rulemaking, EPA has added information to the docket. By
notice dated August 24, 1998 (63 FR 45032), EPA published a notice of
availability listing the additional documents placed in the docket.
d. Revision of the Ozone NAAQS. On July 18, 1997 (62 FR 38856), EPA
issued its final action to revise the NAAQS for ozone. The EPA's
decision to revise the standard was based on the Agency's review of the
available scientific evidence linking exposures to ambient ozone to
adverse health and welfare effects at levels allowed by the pre-
existing 1-hour ozone standards. The 1-hour primary standard was
replaced by an 8-hour standard at a level of 0.08 parts per million
(ppm), with a form based on the 3-year average of the annual fourth-
highest daily maximum 8-hour average ozone concentration measured at
each monitor within an area. The new primary standard will provide
increased protection to the public, especially children and other at-
risk populations, against a wide range of ozone-induced health effects.
Health effects are described in paragraph I.B, General Factual
Background. The EPA retained the applicability of the 1-hour NAAQS for
existing nonattainment areas until such time as EPA determines that an
area has attained the 1-hour NAAQS (40 CFR 50.9(b)).
The pre-existing 1-hour secondary ozone standard was replaced by an
8-hour standard identical to the new primary standard. The new
secondary standard will provide increased protection to the public
welfare against ozone-induced effects on vegetation.
D. Section 126 Petitions
In a separate rulemaking, EPA is proposing action on petitions
submitted by eight northeastern States under section 126 of the CAA.
Each petition specifically requests that EPA make a finding that
NOX emissions from certain major stationary sources
significantly contribute to ozone nonattainment problems in the
petitioning State. The eight States are Connecticut, Massachusetts,
Maine, New Hampshire, New York, Pennsylvania, Rhode Island, and
Vermont.
Both the NOX SIP call and the section 126 petitions are
designed to address ozone transport through reductions in upwind
NOX emissions. However, the EPA's response to the section
126 petitions differs from EPA's action in the NOX SIP call
rulemaking in several ways. In today's NOX SIP call, EPA is
determining that certain States are or will be significantly
contributing to nonattainment or maintenance problems in downwind
States. The EPA is requiring the upwind States to submit SIP provisions
to reduce the amounts of each State's NOX emissions that
significantly contribute to downwind air quality problems. The States
will have the discretion to select the mix of control measures to
achieve the necessary reductions. By contrast, under section 126, if
findings of significant contribution are made for any sources
identified in the petitions, EPA would determine the necessary
emissions
[[Page 57362]]
limits to address the amount of significant contribution and would
directly regulate the sources. A section 126 remedy would apply only to
sources in States named in the petitions.
Based on the view that the SIP call and section 126 petitions are
both designed to achieve the same goal, several commenters urged EPA to
coordinate the two actions to the maximum extent possible. The EPA
agrees that the two actions are closely related and, therefore, should
be coordinated. This will help provide certainty for State and business
planning requirements. In addition, this coordination can help to
facilitate a trading program among sources in SIP call States that
choose to participate in the NOX trading program, and any
section 126 sources that would be subject to a Federal NOX
trading program.
The section 126 provisions require that any control remedy be
implemented within 3 years from the date of the finding that major
sources or a group of stationary sources emit or would emit in
violation of the relevant prohibition in section 110(a)(2)(D). Under
EPA's anticipated rulemaking schedule 4 on the petitions,
the compliance date for sources for which EPA makes such a finding
could be April 30, 2002; November 30, 2002; or May 1, 2003. Several
commenters expressed concern that the compliance deadline under section
126 was driving EPA's decision on the compliance deadline for the
NOX SIP call. Therefore, they believed that no changes would
be made in the proposed NOX SIP call deadline in response to
comments.
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\4\ The eight northeastern States that filed section 126
petitions also filed suit in the District Court for the Southern
District of New York, to compel EPA to take action on those
petitions within prescribed periods. State of Connecticut v.
Browner, No. 98-1376 (S.D.N.Y., filed Feb. 25, 1998). The EPA and
the eight northeastern States jointly filed a motion to enter a
consent order prescribing certain dates for EPA action.
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While EPA believes it is advantageous to coordinate the section 126
and NOX SIP call actions, EPA disagrees that this constrains
EPA from being responsive to public comments and considering
alternative compliance dates. See discussion below in Section V,
NOX Control Implementation and Budget Attainment Dates.
In the NOX SIP call NPR, EPA proposed that States be
required to submit SIPs within 12 months of the final SIP call. One
commenter asserted that the timing and terms of the rulemaking schedule
for the section 126 petitions precludes EPA from considering public
comments advocating different SIP due dates for the NOX SIP
call. The section 126 rulemaking schedule provides several options. One
option would allow findings on the petitions to be deferred pending
certain actions by the States and EPA on State submittals in response
to the NOX SIP call. The premise for the specified schedule
is that the SIP due date would be September 30, 1999 (i.e., roughly 12
months from signature of the notice on the final NOX SIP
call). As discussed below in Section VI, SIP Revision Criteria and
Schedule, EPA continues to believe 12 months is an appropriate
timeframe. However, had EPA determined that a longer timeframe for SIP
submittal was warranted, the section 126 rulemaking schedule would not
have restricted EPA from establishing a later due date.
One commenter supported the section 126 rulemaking schedule because
they thought it had the effect of using the SIP process rather than the
source-based petitions in that it provides an option of deferring
section 126 findings if EPA approves a State's NOX SIP.
Another commenter thought that the conditions for deferring section 126
findings were too stringent, and, therefore, section 126 would
inevitably be triggered prior to approval of any SIP provisions. This
issue is discussed in detail in Section II.A.2.c. in the NPR EPA just
issued on the section 126 petitions, which appears in the docket.
E. OTAG
As discussed in the proposed SIP call, OTAG completed the most
comprehensive analyses of ozone transport ever conducted. The EPA
participated extensively in this process. The EPA believes that the
OTAG process was successful and generated much useful technical and
modeling information on regional ozone transport. This information
provided EPA with the foundation for this rulemaking.
The EPA received numerous comments regarding the relationship
between the OTAG recommendations and EPA's proposed SIP call. Some
commenters asserted that the Agency's proposal was inconsistent with
the OTAG recommendations, while others believed that EPA used the
information and recommendations from OTAG appropriately. Primarily,
commenters stated that OTAG recommended a range of controls for utility
sources instead of a uniform level of control for all of the included
States.
The OTAG did recommend consideration of a range of controls, and
although it did not specifically recommend uniform controls across a
broad region, such a control scheme is within the range of its
recommendation. The EPA's action today is based on its consideration of
OTAG's recommendations, as well as information resulting from EPA's
additional work, and extensive public input generated through notice-
and-comment rulemaking. The EPA continues to believe, for reasons
explained in Section III.F.1, Uniform vs. Regional Controls, that
requiring NOX emissions reductions across the region in
amounts achievable by uniform controls is a reasonable, cost-effective
step to take at this time to mitigate ozone nonattainment in downwind
States for both the 1-hour and 8-hour standards.
Commenters also stated that EPA applied an electric utility control
level that was more stringent than the upper limit of the OTAG range of
utility controls. The OTAG recommended a range of utility controls that
falls between specific CAA-required controls and the less stringent of
85 percent reduction from the 1990 rate (lb/mmBtu), or 0.15 lb/mmBtu.
In determining the appropriate level of emissions reductions, EPA
considered what levels of NOX reductions could be obtained
by applying, to various source sectors, controls that are among the
most cost effective and feasible with today's proven pollution control
technologies. The EPA chose emissions reductions that are equivalent to
an emission limit from utilities of 0.15 lb/mmBtu. The EPA acknowledges
that this level may be more protective than the most protective level
contained in the OTAG recommendation in some cases, but, as discussed
below in Section IV, Air Quality Assessment, EPA believes that it
provides the most improvement in air quality while staying within the
bounds of the most highly cost-effective technology available. (Cost
effectiveness is discussed in Section II.D.) In addition, by relying on
actual 1995-1996 continuous emission monitoring data, rather than
relying on estimated 1990 emission data, this approach provides a more
accurate way of determining the States' budgets since it minimizes any
chances of over-or under-estimation of emissions.
Commenters asserted that OTAG recommended 12 months for additional
modeling--especially subregional modeling--before promulgating the SIP
call; and these commenters expressed concern that EPA did not provide
this amount of time following publication of the NPR. As discussed in
more detail in Section I.F, Discussion of Comment Period and
Availability of Key
[[Page 57363]]
Information, the Agency ultimately provided approximately 1 year from
the conclusion of OTAG for States and other members of the public to
complete and submit subregional and other types of modeling. The EPA
has considered this additional modeling in finalizing today's rule.
Some commenters stated that the goal of OTAG was to address
attainment of the ozone NAAQS. This is incorrect. The OTAG's goal was
to reduce ozone transport, which is one of the steps necessary to
enable attainment; the goal was not to recommend an overall strategy
that would yield attainment through regional measures alone. The OTAG
articulated its overall goal as follows:
* * * identify and recommend a strategy to reduce transported
ozone and its precursors which, in combination with other measures,
will enable attainment and maintenance of the national ambient ozone
standard in the OTAG region. A number of criteria will be used to
select the strategy including, but not limited to, cost
effectiveness, feasibility, and impacts on ozone levels.5
\5\ Ozone Transport Assessment Group Policy Paper approved by
the Policy Group on December 4, 1995.
It is also EPA's goal to ensure that sufficient regional reductions
are achieved to mitigate ozone transport in the eastern half of the
United States and thus, in conjunction with local controls, enable
nonattainment areas to attain and maintain the ozone NAAQS.
Commenters indicated that OTAG focused only on the 1-hour standard
nonattainment problem and did not assess compliance implications of the
8-hour standard. For this reason, according to commenters, EPA should
not base today's action on the nonattainment of the 8-hour NAAQS. It is
true that OTAG was established to address transport issues associated
with meeting the 1-hour standard. The EPA did not promulgate the 8-hour
standard until shortly after OTAG concluded; thus, OTAG did not
recommend strategies to address the 8-hour NAAQS. However, because EPA
had proposed an 8-hour standard, OTAG did examine the impacts of
different strategies on 8-hour average ozone predictions.
In light of OTAG's work and additional information, EPA is able to
assess ozone transport as it relates to the 8-hour NAAQS and to set
forth requirements as necessary to address the 8-hour standard in this
rulemaking. Ozone transport causes problems for downwind areas under
either the 1-hour or 8-hour standard. The regional reductions of
NOX that will be achieved through this SIP call for the 1-
hour NAAQS are key components for meeting the new 8-hour ozone standard
in a cost-effective manner. Therefore, EPA believes that the OTAG
recommendations for how to address ozone transport are valid for both
NAAQS.
Several commenters urged EPA to adopt and implement all Federal
measures identified in the OTAG recommendations.6 The Agency
is committed to continue implementing national control measures for
NOX, as recommended by OTAG. In addition, EPA has adopted
the following national measures for purposes of reducing VOC:
architectural and industrial maintenance coatings, consumer/commercial
products, and autobody refinishing. The EPA has made no decisions
regarding further VOC reductions beyond the reductions specified as
phase I in the OTAG recommendations.7
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\6\ The OTAG recommendations are located in Appendix B of the
November 7, 1997 NPR (62 FR 60376).
\7\ Letter to the Honorable Ken Calvert, Chairman, Subcommittee
on Energy and Environment, U.S. House of Representatives, from
Robert D. Brenner, Acting Deputy Assistant Administrator for Air and
Radiation, U.S. EPA, June 26, 1998, transmitting EPA's responses to
questions following the May 20, 1998 congressional hearing on EPA's
proposed rule on paints and coatings.
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Other more specific comments concerning the OTAG recommendations
will be addressed throughout this rulemaking as the issues are
discussed.
F. Discussion of Comment Period and Availability of Key Information
The EPA received numerous comments concerning the adequacy of the
comment period for the November 7, 1997 NPR and May 11, 1998 SNPR. Some
commenters remarked that the comment period for the NPR should be
extended to allow for development and review of technical information,
including inventory data, growth factors, and the resulting budget.
Commenters stated that the additional time was particularly necessary
for subregional air quality modeling, which is modeling designed to
isolate the impacts of emissions from a particular State or group of
States on downwind areas. Many specifically requested an additional 120
days, and one requested an additional 9 months. Some commenters
indicated that EPA did not incorporate their comments from the NPR into
the SNPR. Other commenters insisted that key information supporting the
rule is not publicly available. The EPA also received comments that
additional public hearings should be held in other locations of the
OTAG region.
1. Request for Extension of the Comment Period
The EPA allowed a 120-day public comment period for the November 7,
1997 NPR, which closed on March 9, 1998. By notice (63 FR 17349, April
9, 1998), EPA reopened the comment period for members of the public to
submit additional modeling analyses, as well as comments concerning the
implications that any additional modeling may have for the State NOx
budgets under consideration in the November 7, 1997 proposal. The
comment period was reopened through the end of the comment period on
the SNPR. The SNPR, which was published on May 11, 1998, allowed a
comment period until June 25, 1998. Thus, for most issues addressed in
the NPR, including air quality modeling issues, commenters received an
almost 8-month formal comment period. Indeed, many commenters had
access to the NPR immediately after October 10, 1997, when it was
signed and posted on an EPA website. The Agency also received a number
of comments after June 25, 1998, which were also reviewed and
considered in developing the final rule.
The EPA believes this additional opportunity for the public to
submit comments was reasonable. After March 9, 1998--the initial date
for close of the comment period on the NPR--EPA received numerous
comments on various issues raised in the NPR, including air quality
issues. Many of these comments were extensive, which indicates that
commenters received adequate time.
With respect to the concern that EPA did not incorporate comments
received on the NPR into the SNPR, it would not have been practical for
EPA to incorporate comments received on the NPR into the SNPR because
the SNPR was completed soon after the close of the comment period for
the NPR. In general, the SNPR addressed different aspects of the rule
than the NPR, and one of the purposes of the SNPR was to take comment
on several new issues, as noted above. The EPA has addressed comments
on both the NPR and SNPR in today's action.
The major issues raised in the comments are responded to throughout
the preamble of this final rule. A comprehensive summary of all
significant comments, along with EPA's response to the comments which
have not been responded to in the preamble (Response to Comments), can
be found in the docket for this rulemaking (Docket No. A-96-56).
[[Page 57364]]
2. Request for Time to Conduct Additional Modeling
The OTAG Policy Group, at its June 3, 1997 meeting, recommended
that States have the opportunity to conduct additional local and
subregional modeling and air quality analyses, as well as to develop
and propose appropriate levels and timing of controls. The EPA received
numerous comments related to OTAG's recommendation. The commenters
requested that the Agency give States more time to conduct this
additional modeling so that EPA could more accurately assess each
State's contribution to downwind nonattainment.
The EPA signed the NPR on October 10, 1997, and posted it on a
website at that time, although it was not published in the Federal
Register until November 7, 1997. As noted above, EPA reopened the
comment period through June 25, 1998 for submittal of additional air
quality modeling runs. In effect, this has extended the amount of time
for modeling analyses to over a year from the date OTAG submitted its
recommendations, and to over 8 months from the signature date for the
NPR. By the close of the comment period on June 25, 1998, EPA had
received numerous comments containing new and extensive air quality
modeling studies. Accordingly, EPA believes that commenters received
adequate time.
3. Availability of Key Information
A number of commenters asserted that EPA failed to make publicly
available key information, such as modeling and emissions inventory
data. Specifically, commenters stated that they did not have access to
the emissions data on which EPA based the air quality modeling for the
NPR. In addition, according to some commenters, several models used by
EPA and OTAG are proprietary models and have not been generally
available to the public.
In Section III.A.2, Availability, the Agency discusses the
availability of emissions inventory data to the public.
The OTAG and EPA conducted air quality modeling runs to determine
the level of contribution from emissions in upwind areas to ozone
nonattainment in downwind areas. Some of this modeling employed UAM-
V.8 The UAM-V has generally been available to the public for
the purpose of analyzing information relevant to today's rulemaking.
State and local agencies, as well as utility companies and other
stakeholders, have had access to licenses to use UAM-V.
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\8\ Variable-Grid Urban Airshed Model.
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Commenters objected that they were obliged either to purchase
licenses for use of the UAM-V model or to employ as a contractor the
model owner, and that these financial constraints restricted their
access to the model. Because this model has, in general, been privately
developed, EPA believes that reasonable fees for its use should be
expected. The EPA did not receive information indicating that the
associated expenses were other than reasonable. To the extent that
commenters experienced delays in obtaining the UAM-V model, EPA
believes that the extensions of the comment period resulted in adequate
time for comment. In any event, any commenter who was not able to gain
access in the timeframe desired was able to use a comparable model,
such as the Comprehensive Air Quality Model with Extensions (CAMx),
which is not proprietary. For the purpose of responding to public
comments, EPA is considering all information based on CAMx and similar
models.
The Agency made available additional modeling runs used to
determine emissions changes, costs and cost effectiveness for
electricity generating units (EGUs). These runs were placed on the IPM
Analyses web site at www.epa.gov/capi, with links to EPA's Office of
Air and Radiation Policy and Guidance web site.
On August 10, the EPA placed in the docket and made available on
the web site, modeling analyses and other information supporting
today's action. As noted above, by notice dated August 24, 1998 (63 FR
45032), EPA published a notice of availability which stated that
throughout the course of the rulemaking, EPA had placed information in
the docket or made it available on various web sites. This information
included inventory data and additional modeling runs. By placing those
materials in the docket and informing the public of their availability,
EPA provided 4-6 weeks for review and comment by the public. The EPA
did receive comments concerning this information from the Utility Air
Regulatory Group on September 9, and EPA is responding to those
comments in the Response To Comments document. The EPA notes that the
additional modeling analyses were performed in response to comments
received on the NPR urging EPA to conduct State-by-State modeling. The
Agency does not believe it is required to provide for additional
comment on every action it takes in response to comment, particularly
where, as here, the new information confirms the Agency's proposed
conclusions. Therefore, the Agency did not further extend the comment
period.
4. Public Hearings
The Agency conducted two hearings in Washington, DC, including a 2-
day hearing on February 3-4, 1998 for the NPR, and a 1-day hearing on
May 29, 1998 for the SNPR. Some commenters believe that additional
public hearings should have been held in other locations in the OTAG
region. The EPA believes these hearings provided reasonable opportunity
for oral comment on the proposed rulemaking given the timeframes
associated with this rulemaking. Therefore, the Agency did not schedule
any additional hearings. The public also had an opportunity to submit
written testimony within approximately 30 days after each hearing date.
G. Implementation of Revised Air Quality Standards
On July 18, 1997, EPA published its final rule for strengthening
the NAAQS for ozone by establishing an 8-hour standard (62 FR 38856).
Current monitoring data indicate that many areas in the East, Midwest
and South violate the 8-hour NAAQS. Along with areas violating the 1-
hour NAAQS, areas violating the 8-hour NAAQS are also affected by the
transport of ozone across the East. The regional NOX
reduction strategy finalized in today's action will provide a mechanism
to achieve reductions that will assist States in attaining and
maintaining this revised standard. In fact, the regional reductions
alone should be enough to enable the vast majority of the new counties
violating the 8-hour NAAQS that are located in States throughout the
East to attain the revised 8-hour standard.\9\
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\9\ In the NPR (62 FR 60318, 60363), EPA provided estimates of
the number of counties expected to attain as a result of the
NOX SIP call. The EPA will update this list in the coming
months. The updated estimates of which counties will attain will be
based on more current air quality data and on the State-by-State
emissions budgets contained in today's final rule.
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On July 16, 1997, President Clinton issued a directive on the
implementation of the revised air quality standards. This
implementation policy was described in the NPR (62 FR 60318, 60362-64).
The EPA received numerous comments on this implementation policy and on
EPA's plan to create a transitional classification\10\ for 8-hour ozone
nonattainment areas that meet certain
[[Page 57365]]
criteria. Since these comments concern implementation efforts for the
revised 8-hour ozone standard and do not relate directly to the
NOX SIP call on which EPA is taking final action in this
rulemaking, EPA is not responding in detail to the comments. The EPA
will address implementation of the revised standard separately. In
August 1998, EPA issued proposed guidance for public comment to explain
the implementation policy in further detail and to provide details on
SIP requirements for transitional areas (63 FR 45060, August 24, 1998).
The EPA expects to finalize the August 1998 draft guidance, as well as
guidance for areas other than transitional, by December 1998.\11\
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\10\ The ``transitional classification'' EPA intends for 8-hour
ozone nonattainment areas is further discussed in the NPR (62 FR
60318, 60363).
\11\ For a complete listing of the guidance and other actions
EPA plans to issue to implement the revised ozone and PM NAAQS, see
a table on EPA's implementation website: http://
ttnwww.rtpnc.epa.gov/implement/actions.htm.
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H. Summary of Major Changes Between Proposals and Final Rule
This summary describes the major changes that have occurred since
the NPR and SNPR in each of the following sections of today's final
rule.
1. EPA's Analytical Approach (Section II.A)
The NPR proposed two interpretations for the section
110(a)(2)(D)(i)(I) provisions concerning the ``significant
contribution'' test. Under the first, EPA would examine certain factors
relating to level of emissions and their ambient impact to determine
whether to make a finding that all of the emissions from a particular
State's sources contribute significantly to nonattainment or
maintenance problems downwind. If EPA made such a finding, then EPA
would examine certain cost factors to determine the extent to which the
SIP for the State must mitigate (reduce) its emissions. Under the
second interpretation, EPA would examine all of those factors
together--level of emissions, ambient impact, and costs--to determine
whether to make the finding with respect to a specified amount of
emissions. If EPA made the finding, then it would require the SIP to
eliminate that amount. In today's final rule, EPA is adopting the
second interpretation. The EPA indicates, however, that it would adopt
the same rule if it were instead implementing the first interpretation.
2. Cost Effectiveness of Emissions Reductions (Section II.D.)
The methodology of determining cost effectiveness has not
changed. For all sources, the inventory and as a result, the source-
specific costs, in some cases, have changed. This results in a
different overall budget level and a different overall cost-
effectiveness value. For the non-EGUs, while the methodology has not
changed, the analysis focuses on large non-EGU sources. The methodology
in the NPR focused on all non-EGU sources.
3. Determination of Budgets (Section III.)
For EGU, the EPA maintained the approach to use the
higher, by State, of 1995 or 1996 heat input data to calculate baseline
heat input rates for the NFR, and added 577 smaller units to the State
budget inventories which had erroneously been omitted from the NPR.
These units included electricity generating sources of 25 megawatts
(MW) or less of electrical output and additional units not affected
under the Acid Rain Program. Additional controls are not assumed for
these sources, but they are added to the budget at baseline levels. The
Agency has decided to use State-specific growth factors derived from
application of the IPM using the 1998 Base Case and chose to retain the
0.15 lbs/mmBtu as the assumed uniform control level for EGU budget
emissions determination.
The EPA examined alternatives that focus on non-EGU point
source reductions from the largest source categories, and within each
of these categories assumed controls that would result in a regionwide
average cost effectiveness less than $2000/ton. The resulting budget
assumes the emissions reductions from large non-EGU sources that are
among the most cost effective to control and does not include
reductions from smaller sources and sources that, as a group, are not
quite as cost effective or efficient to control, or are already covered
by other Federal measures. As a result, this final rule assumes, for
purposes of calculating the State NOX budgets, the following
emissions decreases from uncontrolled levels for the large (generally
greater than 250 mmBtu or 1 ton/day non-EGU sources (no emission
reductions are assumed for the smaller sources):
--Non-EGU boilers and turbines--60 percent decrease.
--Stationary internal combustion engines--90 percent decrease.
--Cement manufacturing plants--30 percent decrease.
It should be noted that point sources with capacities less than 250
mmBtu/hr but with emissions greater than 1 ton/day are not treated
differently from sources with capacities greater than 250 mmBtu/hr for
purposes of calculating the budget. This is a change from the NPR which
included RACT controls on units with capacities less than 250 mmBtu/hr
and emissions greater than 1 ton/day (see Section III.G.2.a). As under
the proposal, the rule allows States to choose control measures other
than the EPA-assumed controls to meet the numerical budgets.
The EPA has implemented the following changes that the
Agency proposed in the NPR for calculating baseline NOX
emissions from highway vehicles. A 1995 baseline is used for the final
rule in place of the 1990 baseline used in the NPR. The Highway
Performance and Monitoring System data were used to estimate States'
1995 vehicle miles traveled (VMT) by vehicle category, except in those
cases where EPA accepted revisions offered in the comments. Today's
action includes those mobile source reductions which EPA has determined
are appropriate to implement on a national basis, and which have been
promulgated in final form or are expected to be promulgated in final
form before States are required to comply with their budgets. The
highway vehicle budget components include the emission reductions
resulting from implementation of the National Low Emitting Vehicle
(NLEV) program, including the phase-in schedule agreed to by the
States, automobile manufacturers, and EPA. The highway budget
components do not include the effect of Tier 2 light-duty vehicle and
truck standards and any associated fuel standards since these standards
have not yet been proposed. The extent of the reformulated gasoline
(RFG) and inspection and maintenance (I/M) programs was not assumed to
change beyond that assumed for the NPR, except for those States that
were able to demonstrate that the NPR's modeling assumptions did not
conform to the State's SIP and did not reflect CAA requirements.
The EPA has chosen to retain the 1990 baseline inventories
for nonroad mobile sources presented in the NPR for today's action,
with additional changes made in response to public comments. The
control strategies assumed for calculating the nonroad and stationary
area source budget components have not changed from the SNPR.
4. NOX Control Implementation and Budget Achievement Dates
(Section V)
The EPA proposed that the SIP revisions require full
implementation of the necessary State measures by September 2002 and
took comment on a range of dates from September 2002 through September
2004. Based on
[[Page 57366]]
public comments and feasibility analyses conducted by EPA, the Agency
is requiring an implementation date of May 1, 2003. The Agency is also
providing some compliance flexibility to States for the 2003 and 2004
ozone seasons by establishing State compliance supplement pools. This
is described in Section III.F.6.
5. SIP Criteria (Section VI.A)
The Agency has determined that the additional SIP
approvability criteria, as proposed in the SNPR, should apply not only
when States choose to regulate EGUs (63 FR 25912), but also when States
choose to regulate large steam-producing units (i.e., combustion
turbines and combined cycle systems with a capacity greater than 250
mmBtu/hr).
The Agency proposed revisions to part 51 requiring
continuous emissions monitoring systems (CEMS) on all large electrical
generating and steam-producing sources which States elect to subject to
emissions reduction requirements in response to this rulemaking. The
EPA took comment on requiring that, if a State chooses to regulate
these sources to meet the SIP call, the SIP must require these sources
to use the NOX mass monitoring provisions of part 75,
subpart H, to demonstrate compliance with applicable emissions control
requirements. After considering comments, the Agency is requiring that,
in these circumstances, the SIP specify that large sources comply with
the monitoring provisions of part 75, subpart H, which includes non-
CEMS monitoring options for units that are infrequently operated or
units that have low mass emissions.
6. Emissions Reporting Requirements for States (Section VI.B)
The proposed rule required that States report full-year,
as well as ozone-season, emissions from all sources for the triennial
inventories commencing with year 2002 emissions and the 2007 inventory,
and for those sources for which reports had to be submitted annually
starting with year 2003 emissions. The final rule requires only ozone-
season emissions reporting for all sources.
In the SNPR, the EPA proposed, for purposes of reporting
requirements, to define a point source as a non-mobile source which has
NOX emissions of 100 tons/year or greater. Under today's
action, States have the option of establishing a smaller emission
threshold than 100 tons/year of NOX emissions in defining
point source. This will allow the definition of point source to remain
consistent with current definitions in local areas.
7. NOX Budget Trading Program (Section VII.)
For States that choose to participate in the
NOX Budget Trading Program, the preamble clarifies the
intent of the model rule and identifies areas of the rule where States
have flexibility to include variations in their State rules.
In the SNPR, the Agency solicited comment on a range of
options for incorporating banking into the trading program. After
considering these comments, the Agency is including banking provisions
in the final rule. The provisions allow for unlimited banking starting
in 2003 and includes a flow control mechanism to limit the emissions
variability associated with banking.
One of the banking approaches presented in the SNPR
included the option for sources to generate and use early reduction
credits. Consistent with the provisions of the NOX SIP call
which provide for State compliance supplement pools, the final rule
allows States to issue early reduction credits for certain
NOX emissions reductions achieved between September 30, 1999
and May 1, 2003.
The final rule clarifies the timing requirements for State
submission of allowance allocations to EPA and, as proposed, lays out
an allocation approach. Each State remains free to adopt the final
rule's allocation approach or adopt an allocation scheme of its own,
provided it meets the specified timing requirements, requires new
sources to hold allowances, and does not allocate more allowances than
are available in the State trading budget.
8. Interaction with Title IV NOX Rule (Section VIII.)
In the SNPR, EPA proposed revisions to part 76 addressing
the interaction between title IV and the NOX SIP call. In
this final rule, EPA explains that the Agency is not adopting any of
the proposed revisions to part 76.
9. Administrative Requirements (Section X.)
NPR Section VIII, Regulatory Analyses, has been replaced
in the final rule by Section X.A, Executive Order 12866: Regulatory
Impacts Analysis. The new final rule Section X.A indicates that EPA has
prepared a RIA for the final rule and cites the cost and benefit
estimates from that analysis.
The final rule adds several Sections under X,
Administrative Requirements, that were absent from the NPR. These
include: Paperwork Reduction Act; Executive Order 13045: Protection of
Children from Environmental Health Risks and Safety Risks; Executive
Order 12898: Environmental Justice; Executive Order 12875: Enhancing
the Intergovernmental Partnerships; Executive Order 13084: Consultation
and Coordination with Indian Tribal Governments; Judicial Review; and
Congressional Review Act. These new Sections provide a more
comprehensive summary of the Acts and Executive Orders that could apply
to the final rule. Each Section identifies the requirements of the
relevant Act or Executive Order, indicates EPA's interpretation of
whether the Act or Executive Order actually applies to this rulemaking,
and, if so, indicates how the Agency has addressed the Act or Executive
Order.
II. EPA's Analytical Approach
A. Interpretation of the CAA's Transport Provisions
As indicated in the NPR, 62 FR 60323, the primary statutory basis
for today's action is the ``good neighbor'' provision of section
110(a)(2)(D)(i)(I), under which, in general, each SIP is required to
include provisions assuring that sources within the State do not emit
pollutants in amounts that significantly contribute to nonattainment or
maintenance problems downwind. This statutory requirement applies to
SIPs under both the 1-hour ozone NAAQS and the 8-hour ozone NAAQS.
1. Authority and Process for Requiring SIP Submissions Under the 1-Hour
Ozone NAAQS
a. Authority for Requiring SIP Submissions under the 1-Hour NAAQS.
Each State is currently required to have in place a SIP that implements
the 1-hour ozone NAAQS for areas to which that standard still applies.
In the NAAQS rulemaking, EPA determined that the 1-hour NAAQS would
cease to apply to areas that EPA determines have air quality in
attainment of that NAAQS (40 CFR 50.9(b)). In two recent rulemakings,
EPA identified numerous areas of the country to which the 1-hour NAAQS
no longer applies. ``Final Rule: Identification of Ozone Areas
Attaining the 1-Hour Standard and to Which the 1-Hour Standard is No
Longer Applicable,'' (63 FR 31014, June 5, 1998); ``Final Rule:
Identification of Additional Ozone Areas Attaining the 1-Hour Standard
and to Which the 1-Hour Standard is No Longer Applicable,'' (63 FR
27247, July 22, 1998).
The 1-hour NAAQS remains applicable to areas whose air quality
continues to monitor nonattainment. As noted above in Section I.B,
General
[[Page 57367]]
Factual Background, these include many major urban areas in the eastern
half of the United States. States that contain these areas remain
responsible for meeting CAA requirements applicable to those areas for
the purpose of attaining the 1-hour NAAQS. For example, States are
responsible for attainment demonstrations for areas designated
nonattainment and classified as moderate or higher.
By the same token, States that are upwind of these areas are
responsible to meet the ``good neighbor'' requirements of section
110(a)(2)(D). This responsibility is not alleviated simply because, for
areas other than the current nonattainment areas, the 8-hour NAAQS has
replaced the 1-hour NAAQS.
b. Process for Requiring SIP Submissions under the 1-Hour NAAQS. As
explained in the NPR, the appropriate route for EPA to require SIP
submissions under section 110(a)(2)(D)(i)(I) with respect to the 1-hour
standard is issuance of a ``SIP call'' under section 110(k)(5).\12\
Section 110(k)(5) authorizes EPA to find that a SIP is substantially
inadequate to meet a CAA requirement and to require (``call for'') the
State to submit, within a specified period, a SIP revision to correct
the inadequacy. Specifically, section 110(k)(5) provides, in relevant
part:
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\12\ As discussed in the NPR and in greater detail further
below, the basis for requiring a transport-related SIP revision for
the 8-hour standard is the requirement in section 110(a)(1) that
States submit SIPs meeting the requirements of section 110(a)(2)
within 3 years (or an earlier date established by EPA) of
promulgation of a new or revised NAAQS. This is discussed in further
detail below.
Whenever the Administrator finds that the applicable
implementation plan for any area is substantially inadequate to
attain or maintain the relevant [NAAQS], to mitigate adequately the
interstate pollutant transport described in section 176A or section
184, or to otherwise comply with any requirement of this Act, the
Administrator shall require the State to revise the plan as
necessary to correct such inadequacies. The Administrator shall
notify the State of the inadequacies, and may establish reasonable
deadlines (not to exceed 18 months after the date of such notice)
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for the submission of such plan revisions.
By today's action, EPA is determining that the SIPs for the
specified jurisdictions are substantially inadequate to comply with the
requirements of section 110(a)(2)(D)(i)(I) because the relevant SIPs do
not contain adequate provisions prohibiting their sources from emitting
amounts of NOX emissions that contribute significantly to
nonattainment in downwind areas that remain subject to the 1-hour
NAAQS. Based on these determinations, EPA is requiring the identified
States to submit SIP revisions containing adequate provisions to limit
emissions to the appropriate amount.
If a State does not submit the required SIP provisions in response
to this SIP call, EPA will issue a finding that the State failed to
make a required SIP submittal under section 179(a). This finding has
implications for sanctions as well as for EPA's promulgation of Federal
implementation plans (FIPs). Sanctions and FIPs are discussed in
Section VI, SIP Criteria and Emissions Reporting Requirements.
(1) Commenters' Arguments Concerning the Transport Provisions.
Commenters argued that EPA does not have unilateral authority to issue
a SIP call under section 110(k)(5) to require States to remedy SIPs
that do not meet the requirements of section 110(a)(2)(D). The
commenters noted that when Congress amended the CAA in 1990, Congress
provided that the sole authority for EPA and States to address
interstate transport of pollution is through transport commissions. In
support, the commenters state that Congress: (i) Added sections 176A
and 184, which authorize the establishment of transport regions and the
formation of transport commissions; (ii) revised section 110(k)(5) to
refer to those transport provisions; and (iii) revised section
110(a)(2)(D)(i) to require that SIP provisions designed to eliminate
interstate pollutant transport be consistent with other CAA
requirements. According to the commenters, these provisions, read as a
whole, mandate that if EPA believes that a transport problem exists,
EPA's sole recourse is to form a transport region under sections 176A
and/or 184; EPA may issue a SIP call to mandate compliance with section
110(a)(2)(D)(i) only in response to a recommendation of the transport
region. The commenters also claim that this scheme is sensible because
it provides a consensual forum for States to address interstate
pollution rather than allowing unilateral action on the part of EPA or
a State.
The EPA disagrees with the commenters' conclusion that these
statutory provisions make clear that EPA cannot require a State to
address interstate transport without first establishing a transport
commission and in the absence of a recommendation from the transport
commission. There is no language of limitation in sections 110(a)(2)(D)
or (k)(5), or 176A, or 184. Nor is there any support in the legislative
history for such a narrow reading of the statute. Moreover, under the
commenters' interpretation, the CAA Amendments of 1990 have placed
greater constraints on States' and EPA's ability to address the
interstate transport of pollution. Such an interpretation would be
inconsistent with the overall purpose of the CAA to ensure healthful
air. Thus, EPA believes that the transport provisions were added as an
additional tool to address interstate transport but were not intended
to preclude other methods of addressing interstate pollution than prior
to passage of the amendments.
Under the 1990 Amendments, Congress recognized the growing evidence
that ozone and its precursors can be transported over long distances
and that the control of transported ozone was a key to achieving
attainment of the ozone standard across the nation (Cong. Rec. S16903
(daily ed. Oct. 27, 1990) (statement of Sen. Mitchell); S16970
(conference report) S16986-87 (statement of Sen. Lieberman)). Thus, in
1990, Congress added a new mechanism to address interstate transport.
Specifically, Congress enacted sections 176A and 184, which provide a
mechanism for States to work together to address the interstate
transport problem. However, by their terms, these sections simply
provide authority for EPA to designate transport regions and establish
transport commissions. There is nothing in the language of these
provisions that indicates that they supersede the other statutory
mechanisms for addressing interstate transport, or that they now
provide the sole mechanism for resolving interstate pollution
transport.
Moreover, although Congress expressly added these two provisions
through the 1990 Amendments, Congress did not in any way limit section
110(a)(2)(D), which requires States to address interstate transport in
their SIPs. The addition of the language providing that States' actions
under section 110(a)(2)(D) be ``consistent with [title I] of the Act''
cannot be read to limit the controls States may adopt to meet section
110(a)(2)(D) to those recommended by a transport
commission.13 After all, the transport region provisions are
only two of many provisions in title I. Rather, this
[[Page 57368]]
language concerning consistency should be read as clarifying that any
section 110(a)(2)(D) requirement must be consistent with other
provisions of title I. Similarly, this language makes explicit that SIP
revisions required in accordance with the procedures of the transport
provisions would meet the requirements of section 110(a)(2)(D)(i).
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\13\ Taken to its logical conclusion, the commenters' argument
would mean that States are precluded from submitting a section
110(a)(2)(D) SIP unless it reflects measures recommended through the
transport commission process. The EPA does not believe that Congress
would first establish a specific mandate (to submit a SIP to address
interstate transport) and then limit it in such a cryptic fashion.
If Congress intended section 110(a)(2)(D) SIPs to only reflect
transport commission recommendations, Congress could have
specifically referenced sections 176A and 184 in section
110(a)(2)(D), rather than generally providing that SIPs be
``consistent'' with title I of the CAA.
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Furthermore, it is significant that Congress did not in any sense
bind EPA's ultimate discretion to determine whether State plans
appropriately address interstate transport. Under sections 176A and
184, the States may only make recommendations to EPA. Thus, under the
transport provisions, as well as the general SIP requirements of
section 110(a)(2), EPA must ultimately decide whether the SIP meets the
applicable requirements of the CAA. If, as the commenters contend, EPA
is limited to calling on States to address interstate transport only by
strategies recommended by the State, then EPA would be precluded from
ensuring that States address interstate transport. For example, EPA
could establish a transport commission but the commission could fail to
make recommendations or make insufficient recommendations. (Section
176A provides that transport commissions may make recommendations to
EPA only by ``majority vote of all members'' other than those
representing EPA.) Such a reading of the statute would be absurd in
light of the growing recognition at the time of the 1990 Amendments
that transport is a real threat to the primary purpose of title I of
the CAA--attainment of the NAAQS.
By the same token, in amending section 110(k)(5) in the 1990
Amendments, Congress did not add anything that explicitly provides
that, in the case of interstate transport, section 110(k)(5) would
apply only when EPA approved (or substituted measures for) a transport
commission's recommendations. The reference in section 110(k)(5) to the
transport provisions of sections 176A and 184 does not preclude EPA's
use of the SIP call provision to call on States to ensure their SIPs
meet the requirements of section 110(a)(2)(D)(i). Section 110(k)(5)
also provides for EPA to call on States ``to otherwise comply with
requirements of this Act;'' among the requirements in chapter I of the
CAA is the requirement in section 110(a)(2)(D). The reference in
section 110(k)(5) to the transport provisions simply makes explicit
that EPA may employ section 110(k)(5) for the additional purpose of
requiring SIPs to include the control measures as recommended by
transport commissions and approved by EPA under the transport
provisions.
Moreover, there is no indication in the legislative history of the
1990 Amendments that Congress intended the sections 176A and 184
transport provisions to supersede the section 110(k)(5) SIP call
mechanism for ensuring compliance with section 110(a)(2)(D)(i). Reading
the transport provisions to supersede the SIP call mechanism would
constitute a significant change from the CAA as it read prior to the
1990 Amendments. Even if the statute is ambiguous as to whether the
transport provisions supersede the SIP call mechanism--and EPA believes
the statute is clear that the transport provisions do not supersede--
congressional silence would suggest that Congress did not intend such a
significant change (See generally Harrison v. PPG Industries, Inc., 446
U.S. 578, 602, 100 S.Ct. 1889, 1902, 64 L.Ed.2d 525 (1980) (Rehnquist,
J., dissenting), cited with approval in Chisom v. Roemer, 501 U.S. 380,
396 n. 23, 111 S.Ct. 2354, 2364 n. 23, 115 L.Ed.2d 348 (1991)).
Finally, the commenter asserts that EPA's interpretation of the CAA
to allow a SIP call in the absence of a transport commission
recommendation reads out of the CAA the consensual transport commission
procedures under sections 176A and 184. This is simply not true. The
EPA interprets the transport commission process to be one tool to
assess and address interstate transport. In fact, the Northeast Ozone
Transport Commission, under section 184, has been active since
enactment of the 1990 Amendments. In 1995, EPA approved a
recommendation of that commission (60 FR 4712 14). Transport
commissions remain a viable means for dealing with interstate
transport. Furthermore, contrary to the general implication of the
commenter's remark, the OTAG process, though not a formal transport
commission, provided an opportunity not only for Federal and State
governments to assess jointly the transport issue, but also involved
industry, environmental groups and others. The EPA based its SIP call
on information developed through OTAG, as well as additional analyses
performed by the Agency and information submitted by a variety of
groups during the comment period on the proposed rule. Thus, the OTAG
process contained consensual elements.
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\14\ In Commonwealth of Virginia v. EPA, 108 F.3d 1397 (D.C.
Cir. 1997), the court vacated EPA's SIP call in response to the
Northeast Ozone Transport Commission's recommendation on the basis
that the EPA could not require States to adopt a specific control
measure under its section 110(k)(5) authority and that, in any
event, EPA could not require States to adopt stricter motor vehicle
emission standards under either section 110(k)(5) or section 184.
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(2) Commenters' Arguments Concerning the Virginia case. Under one
of the approaches described in the proposed rule, EPA proposed to
determine, for each of various upwind States, the aggregate ``amounts''
of air pollutants (NOX) that contribute significantly to
nonattainment, and that, therefore must be prohibited by the various
SIPs. The NOX emissions budget for each State is an
expression of the amount of NOX emissions that would remain
after the State prohibits the amount that contributes significantly to
downwind nonattainment. In the final rule issued today, EPA has
continued this approach, establishing emissions budgets for each of the
23 jurisdictions based on required reductions. This determination is an
important step toward assuring that overall air quality standards are
met downwind.
Commenters argue that even if EPA has authority to call on States
to address interstate transport, EPA does not have the authority under
section 110(a)(2)(D) to mandate that upwind States limit NOX
emissions to specified amounts. Rather, according to this view, EPA's
authority is limited to determining that the upwind States' SIPs are
inadequate, and generally requiring the upwind States to submit SIP
revisions to correct the inadequacies. The upwind States would then,
according to this view, submit a SIP revision that implements what the
upwind States determine to be the appropriate amount of NOX
reductions. If EPA believes that those amounts are too small to correct
the inadequacy, EPA could disapprove the SIP revisions.
Proponents of this view rely on the recent decision in Virginia v.
EPA, 108 F.3d 1397, 1406-10 (D.C. Cir. 1997) (Virginia) (citing Train
v. NRDC), in which the court vacated EPA's SIP call on the basis that
through it, EPA gave States no choice but to adopt the California low
emission vehicle (LEV) program. The court found that the language in
section 110(k)(5) that provides EPA with the authority to call on a
State to revise its SIP ``as necessary'' to correct a substantial
inadequacy did not change the longstanding precept that States have the
primary authority for determining the mix of control measures needed to
attain the NAAQS.
The EPA disagrees that the CAA prohibits EPA from establishing an
emissions budget through a SIP call requiring upwind States to prohibit
emissions that contribute significantly to downwind nonattainment.
Section
[[Page 57369]]
110(a)(2)(D) is silent regarding whether States or EPA are to determine
the level of emission reductions necessary to mitigate significant
contribution. The caselaw cited by the commenters only provides that
States are primarily responsible for determining the mix of control
measures--not the aggregate emission reduction levels that are
necessary. Moreover, Train v. NRDC, which underlies the Virginia
court's decision, relied on section 107(a) of the CAA, which specifies
only that each State is primarily responsible for determining a control
strategy to attain the NAAQS ``within such State.''
Section 110(a)(2)(D) does not provide who--EPA or the States--is to
determine the level of emission reductions necessary to address
interstate transport. As quoted above, section 110(a)(2)(D)(i)(I)
requires that SIPs contain ``adequate provisions prohibiting * * *
[sources] from emitting any air pollutant in amounts which will
contribute significantly to nonattainment'' downwind. Nor does this
provision indicate the criteria for determining the ``amounts'' of
pollutants that contribute significantly to nonattainment downwind. Nor
does this provision indicate the process for determining those
``amounts,'' including whether EPA or the States should carry out this
responsibility. 15 Under Chevron U.S.A., Inc. v. Natural
Resources Defense Council, 468 U.S. 1227, 105 S.Ct. 28, 82 L.Ed.2d 921
(1984) (Chevron), because the statute does not answer these specific
issues, EPA has discretion to provide a reasonable interpretation.
---------------------------------------------------------------------------
\15\ The EPA is not contending that the ``as necessary''
language in section 110(k)(5) provides the basis for EPA's authority
to identify the emissions budget for upwind States.
---------------------------------------------------------------------------
Neither the decision in Virginia, nor the body of caselaw upon
which it relies, addresses this issue. Rather, these cases address
solely the division between the States and EPA regarding the initial
identification of control measures necessary to attain the ambient air
quality standards. The issue before the court in Virginia was whether
EPA had offered States a choice in selecting control measures or
instead had mandated the adoption of a specific control measure.
Relying on Train v. NRDC, 421 U.S. 60, 95 S.Ct. 1470, 43 L.Ed.2d 731
1975), the Virginia court found that under title I of the CAA, EPA is
required to establish the overall air quality standards, but the States
are primarily responsible for determining the mix of control measures
needed to meet those standards and the sources that must implement
controls, as well as the applicable level of control for those sources.
The EPA must then review the State's determination only to the extent
of assuring that the overall air quality standards are met. If EPA
determines that the SIP's mix of control measures does not result in
achieving the overall air quality standards, EPA is required to
disapprove the SIP and promulgate a FIP, under which EPA selects the
sources for emissions reductions (Virginia, 108 F.3d at 1407-08, citing
Train v. NRDC, 421 U.S. 60, 95 S.Ct. 1470, 43 L.Ed.2d 731 (1975); Union
Electric Co. v. EPA, 427 U.S. 246, 96 S.Ct. 2518, 49 L.Ed.2d 474
(1976)). This line of cases, which focuses on the selection of
controls, does not address whether EPA or the States--in the first
instance--should determine the aggregate amount of reductions necessary
to address interstate transport.
Moreover, NRDC v. Train addresses State plans for purposes of
intrastate emissions planning. In determining that States have the
primary authority for determining the control measures needed to attain
the standard, the court relied on section 107(a) of the CAA, which
provided (and still provides) that:
Each State shall have the primary responsibility for assuring
air quality within the entire geographic area comprising such State
by submitting an implementation plan which will specify the manner
in which national primary and secondary ambient air quality
standards will be achieved and maintained within each air quality
region in such State.''
(421 U.S. at 64, 95 S.Ct at 1474-75 (emphasis added)).
Thus, the underlying support for the court's determination in Train
v. NRDC applies only where a State is determining the mix of controls
within its boundaries, not to the broader task of determining the
aggregate emissions reductions needed in conjunction with emissions
reductions from a number of other States in order to address the impact
of transported pollution on downwind States. 16
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\16\ The court's decision in Train v. NRDC appears to rely on
the plain language of the statute in holding that a State is
primarily responsible for determining the mix of control measures
necessary to demonstrate attainment within that State's borders. The
court in Virginia appears to adopt this ``plain meaning''
interpretation without addressing that the language in section
107(a) applies only to intrastate issues. This issue is not relevant
in the present case, however, since States are free to decide the
mix of control measures under today's final action.
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Although the cases to date have not addressed directly whether it
is the province of EPA or the States to determine the aggregate amounts
of emissions to be prohibited (and hence, the amounts that may remain--
i.e., the emissions budgets), EPA believes it reasonable to interpret
the ambiguity in section 110(a)(2)(D)(i)(I) to include this
determination among EPA's responsibilities, particularly in the current
circumstances. Determining the overall level of air pollutants allowed
to be emitted in a State is comparable to determining overall standards
of air quality, which the courts have recognized as EPA's
responsibility, and is distinguishable from determining the particular
mix of controls among individual sources to attain those standards,
which the caselaw identifies as a State responsibility. In Train, a
State was required to assure that its own air quality attained overall
air quality standards and to implement emissions controls to do so.
Under these circumstances, the court clarified that while the
responsibility for determining the overall air quality standards was
EPA's, the responsibility for determining the specific mix of controls
designed to achieve that air quality was the State's. By comparison, as
stated earlier, a transport case, under section 110(a)(2)(D)(i), does
not concern any requirement of the upwind State to assure that its own
air quality attains overall air quality standards. Rather, a transport
case concerns the upwind State's requirement to assure that its
emissions are reduced to a level that will not contribute significantly
to nonattainment downwind. Determining this overall level of reductions
for the upwind State is analogous to determining overall air quality
standards, and, thus, should be the responsibility of EPA.
Once EPA determines the overall level of reductions (by assigning
the aggregate amounts of emissions that must be eliminated to meet the
requirements of section 110(a)(2)(D)), it falls to the State to
determine the appropriate mix of controls to achieve those reductions.
Unlike the regulation at issue in Virginia, today's regulation
establishing emission budgets for the States does not limit the States
to one set of emission controls. Rather, the States will have
significant discretion to choose the appropriate mix of controls to
meet the emissions budget. The EPA has based the aggregate amounts to
be prohibited on the availability of a subset of cost-effective
controls that are among the most cost effective available. As explained
elsewhere in this final rule and the NPR, the State may choose from a
broader menu of cost-effective, reasonable alternatives, including some
(e.g., vehicle inspection and maintenance programs and reformulated
[[Page 57370]]
gasoline) that may even be more advantageous in light of local
concerns.
The task of determining the reductions necessary to meet section
110(a)(2)(D) involves allocating the use of the downwind States' air
basin. This area is a commons in the sense that the contributing State
or States have a greater interest in protecting their local interests
than in protecting an area in a downwind State over which they do not
have jurisdiction and for which they are not politically accountable.
Thus, in general, it is reasonable to assume that EPA may be in a
better position to determine the appropriate goal, or budget, for the
contributing States, while leaving to the contributing States'
discretion to determine the mix of controls to make the necessary
reductions.
The EPA's decision to assign the budgets in the final rule is
particularly reasonable. Today's rulemaking involves almost half the
States in the Nation, and although these States participated in OTAG
beginning more than 3 years ago, they still have not agreed on whether
particular upwind States should be treated as having sources whose
emissions contribute significantly to downwind nonattainment, what the
aggregate level of emissions reductions should be, or what the State-
by-State reductions should be. The sharply divergent positions taken by
the States in their comments on the NPR and SNPR raise doubts that
those disagreements could ever be resolved by consensus. It is most
efficient--indeed necessary--for the Federal government to establish
the overall emissions levels for the various States. This is
particularly true for an interstate pollution problem such as the one
being dealt with in this action where the downwind areas at issue are
affected by pollution coming from several States and the actions taken
by each of the concerned States could have an effect on the appropriate
action to be taken by another State. For example, if EPA did not
specify the emissions to be prohibited from each of the various States
affecting New York City, each of those States might claim it could
reduce its emissions less provided other States did more. Or, a State
close to New York might assert that it could just as effectively deal
with its contribution to New York through additional VOC, rather than
NOX, reductions and submit a section 110(a)(2)(D) SIP based
on a VOC-control rather than NOX-control strategy. These
choices, however, even assuming they were valid, necessarily relate to
the choices that would need to be made by the other upwind States
(e.g., Pennsylvania's choice of a VOC-dominated 110(a)(2)(D) control
strategy to deal with its contribution to New York could affect what
Ohio or New Jersey would need to do to deal with their own
contributions by lowering the overall level of NOX
reductions being obtained throughout the pertinent region). Where many
States are involved and the choices of each individual State could
affect the choices and decisions of the other States the need for
initial federal action is manifest. The EPA's action to determine the
amount of NOX emissions that each of the States must
prohibit in this widespread geographic area is needed to enable the
States to decide expeditiously how to achieve those reductions in an
efficient manner that will not undermine the actions of another State.
By notifying each State in advance of its reduction requirements, EPA
enables each State to develop its plan with full knowledge of the
amount and kind of reductions that must be achieved both by itself and
other affected States. The EPA's action provides the minimum framework
necessary for a multi-state solution to a multi-state problem while
preserving the maximum amount of state flexibility in terms of the
specific control measures to be adopted to achieve the needed emission
reductions. The reasonableness of EPA's approach to the interstate
ozone transport problem was recently recognized by a US Court of
Appeals in the context of upholding EPA's redesignation of the
Cleveland ozone nonattainment area to attainment in light of EPA's
approach to the regional transport problem. In the course of doing so
the court rejected the contention that a separate analysis of the
current adequacy of the Cleveland SIP under section 110(a)(2)(D) was
required as a prerequisite to redesignation. The court, after
describing the November 7, 1997 proposed SIP call and the path EPA was
on to deal with this multi-state regional problem, upheld EPA's
redesignation and stated that ``[w]e find that the EPA's approach to
the regional transport problem is reasonable and not arbitrary or
capricious.'' Southwestern Pennsylvania Growth Alliance v. Browner, 144
F.3d 984, 990 (6th Cir. 1998).
As noted above, commenters have argued that if EPA determines to
issue any SIP call, the SIP call must be more general (i.e., one that
simply requires revised SIPs from upwind areas) and not specify the
amounts of NOX emissions that those areas must prohibit.
However, if EPA issued a general SIP call and an upwind State responded
by submitting an inadequate SIP revision, EPA would disapprove that
SIP, and in the disapproval rulemaking, EPA would be obliged to justify
why the submitted SIP was unacceptable. Without determining an
acceptable level of NOX reductions, the upwind State would
not have guidance as to what is an acceptable submission. The EPA's
determination, as part of the issuance of the SIP call, of the amounts
of NOX emissions the SIPs must prohibit obviously provides
for more efficient and smooth-running administrative processes at both
the State and Federal levels. For the same reasons that EPA believes it
is appropriate for the Agency to establish the emissions budgets under
the authority of section 110(a)(2)(D) and (k)(5), EPA believes that it
is necessary to do so through a rule under the general rulemaking
authority of section 301(a). Setting such a rule is necessary, as a
practical matter, for the Administrator's effective implementation of
section 110(a)(2)(D). See NRDC v. EPA, 22 F.3d 1125, 1146-48. Without
such a rule the States could be expected to submit SIPs reflecting
their conflicting interests, which could result in up to 23 separate
SIP disapproval rulemakings in which EPA would need to define the
requirements that each of those States would need to meet in their
later, corrective SIPs. That in turn would trigger a new round of SIP
rulemakings to judge those corrective SIPs. The delay attendant to that
process would thwart timely attainment of the ozone standards.
2. Authority and Process for Requiring SIP Submissions under the 8-Hour
Ozone NAAQS
a. Authority for Requiring SIP Submissions under the 8-Hour NAAQS.
(1) SIP Submissions Under CAA Section 110(a)(1). In the NPR and SNPR,
EPA proposed to require the 23 upwind jurisdictions to submit SIP
revisions to reduce emissions that exacerbate ozone problems in
downwind States under the 8-hour ozone NAAQS, as well as the 1-hour
NAAQS. The EPA recognized that under the 8-hour NAAQS, areas have not
yet been designated as attainment, nonattainment, or unclassifiable,
and are not yet required to have SIPs in place. Even so, EPA proposed
that upwind areas be required to submit SIPs meeting the requirements
of section 110(a)(2)(D)(i)(I) with respect to the 8-hour NAAQS.
In today's action, EPA is confirming its view that it has authority
under the 8-hour NAAQS to require SIP submittals under section
110(a)(2)(D)(i)(I) to reduce NOX emissions by the prescribed
amounts. Section 110(a)(1) provides, in relevant part--
[[Page 57371]]
Each State shall * * * adopt and submit to the Administrator,
within 3 years (or such shorter period as the Administrator may
prescribe) after the promulgation of a national primary ambient air
quality standard (or any revision thereof) * * * a plan which
provides for implementation, maintenance, and enforcement of such
primary standard in each (area) within such State.
Section 110(a)(2) provides, in relevant part--
Each implementation plan submitted by a State under this Act
shall be adopted by the State after reasonable notice and public
hearing. Each such plan shall [meet certain requirements, including
those found in section 110(a)(2)(D)].
The provisions of section 110(a)(1) and (a)(2) apply by their terms
to all areas, regardless of whether they have been designated as
attainment, nonattainment, or unclassifiable under section 107. The
plain meaning of these provisions, read together, is that SIP revisions
are required under the revised NAAQS within 3 years of the date of
revision, or earlier if EPA so requires, and that those SIP revisions
must meet the requirements of section 110(a)(2), including subparagraph
(D).
That the SIP submission requirements of section 110(a)(1) are
triggered by the promulgation of a new or revised NAAQS is made even
clearer by comparing section 172(b), which applies by its terms only to
areas that have been designated nonattainment under section 107.
Section 172(b) provides, in relevant part--
At the time the Administrator promulgates the designation of any
area as nonattainment with respect to a [NAAQS] under section 107(d)
* * *, the Administrator shall establish a schedule according to
which the State containing such area shall submit a plan or plan
revision * * * meeting the applicable requirements of subsection (c)
of this section and section 110(a)(2) * * * Such schedule shall at a
minimum, include a date or dates, extending no later than 3 years
from the date of the nonattainment designation, for the submission
of a plan or plan revision * * * meeting the applicable requirements
of subsection (c) of this section and section 110(a)(2) * * *
Section 172(b) establishes the schedule for submissions due with
respect to nonattainment areas under sections 172(c) and 110(a)(2). The
section 172(c) requirements apply only with respect to areas designated
nonattainment.17
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\17\ As quoted above, section 172(b) refers to ``applicable
requirements of * * * section 110(a)(2).'' This reference appears to
mean those requirements of section 110(a)(2) that either (i) relate
to all SIP submissions, such as the requirement for reasonable
notice and public hearing in the language at the beginning of
section 110(a)(2); or (ii) relate particularly to SIP submissions
required for nonattainment areas, but that have not yet been
submitted by the State.
---------------------------------------------------------------------------
In the NPR, EPA proposed that section 110(a)(1) mandates SIP
submissions meeting the requirements of section 110(a)(2)(D) and
provides full authority for EPA to establish a submission date within 3
years of the July 18, 1997 8-hour ozone NAAQS promulgation date (62 FR
38856 (NAAQS rulemaking): 62 FR 60325 (NOx SIP call NPR)). The EPA
further asserted in the NPR that EPA has the authority to establish
different submittal schedules for different parts of the section
110(a)(1) SIP revision, and that EPA may require the section
110(a)(2)(D) submittal first so that upwind reductions may be secured
at an earlier stage in the regional SIP planning process (62 FR 60325).
Subsections (ii) and (iii) of this section further elaborates on the
reasoning underlying EPA's decision to retain its proposal to require
SIP submissions under section 110(a)(2)(D) for the 8-hour standard.
(2) Commenters and the Definition of ``Nonattainment.'' Commenters
challenged several aspects of EPA's proposal to evaluate the
contribution of upwind areas under the 8-hour NAAQS. Commenters
asserted that section 110(a)(2)(D)(i) applies to constrain emissions
from upwind sources only with respect to downwind areas that are
designated nonattainment. According to these commenters, until EPA
designates areas nonattainment under the 8-hour NAAQS, EPA has no
authority to require SIP submissions, under section 110(a)(1), from
upwind areas with respect to the 8-hour NAAQS. One commenter pointed
out that the new source review requirements and ozone nonattainment
requirements enacted in the 1990 Amendments apply only to areas
designated nonattainment.
The EPA disagrees with this comment. Section 110(a)(2)(D)(i)(I)
provides that a SIP must prohibit emissions that ``contribute
significantly to nonattainment in * * * any other State.''
18 The provision does not, by its terms, indicate that this
downwind ``nonattainment'' must already have been designated under
section 107 as a nonattainment ``area.'' If the provision were to
employ the term ``area'' in conjunction with the term
``nonattainment,'' then it would have to be interpreted to apply only
to areas designated nonattainment. Other provisions of the CAA do
employ the term ``area'' in conjunction with ``nonattainment,'' and
these provisions clearly refer to areas designated nonattainment (e.g.,
sections 107(d)(1)(A)(i), 181(b)(2)(A), 211(k)(10)(D)). Similarly, the
provisions to which the commenter appeared to refer--section 172(b)/
172(c)(5) (new source review) and section 181(a)(1)/182 (classified
ozone nonattainment area requirements)--by their terms apply to a
nonattainment ``area.'' In contrast, section 110(a)(2)(D) refers to
only ``nonattainment,'' not to a nonattainment ``area.''
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\18\ Section 110(a)(2)(D)(i)(I) further provides that a SIP must
prohibit emissions that ``interfere with maintenance by * * * any
other State.''
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By the same token, section 176A(a) authorizes EPA to establish a
transport region whenever ``the Administrator has reason to believe
that the interstate transport of air pollutants from one or more States
contributes significantly to a violation of a [NAAQS] in one or more
other States.'' This reference to ``a violation of a [NAAQS]'' makes
clear that EPA is authorized to form a transport region when an upwind
State contributes significantly to a downwind area with nonattainment
air quality, regardless of whether the downwind area is designated
nonattainment. The EPA believes that section 110(a)(2)(D) should be
read the same way in light of the parallels between section
110(a)(2)(D) and section 176A(a). Both provisions address transport and
both are triggered when emissions from an upwind area ``contribute
significantly'' downwind. It seems reasonable to apply a consistent
approach to the type of affected downwind area, which would mean
interpreting the term ``nonattainment'' in section 110(a)(2)(D) as
synonymous with the phrase ``a violation of a [NAAQS]'' in section
176A(a). The CAA contains other provisions, as well, that refer to the
factual, air quality status of a particular area as opposed to its
designation status. These provisions include, among others, (i)
sections 172(c)(2) and 171(1), the reasonable further progress
requirement, which requires nonattainment SIPs to provide for ``such
annual incremental reductions in emissions * * * as * * * may * * * be
required * * * for the purpose of ensuring attainment of the [NAAQS]''
(emphasis added); and (ii) section 182(c)(2), the attainment
demonstration requirement, which mandates a ``demonstration that the
[SIP] * * * will provide for attainment of the [NAAQS]'' (emphasis
added). The emphasized terms clearly refer to air quality status. In a
series of notices in the Federal Register, EPA relied on these
references to air quality status in determining that areas seeking to
redesignate from nonattainment to attainment did not need to complete
ROP SIPs or attainment demonstrations--even though those requirements
generally applied to areas
[[Page 57372]]
designated nonattainment--as long as the air quality for those
redesignating areas was, in fact, in attainment. See ``State
Implementation Plans; General Preamble for the Implementation of Title
I of the Clean Air Act Amendments of 1990; Proposed Rule,'' 57 FR
13498, 13564 (April 16, 1992); ``Determination of Attainment of Ozone
Standard for Salt Lake and Davis Counties, Utah, and Determination
Regarding Applicability of Certain Reasonable Further Progress and
Attainment Demonstration Requirements: Direct Final Rule,'' 60 FR
30189, 30190 (June 8, 1995); and ``Determination of Attainment of Ozone
Standard for Salt Lake and Davis Counties, Utah, and Determination
Regarding Applicability of Certain Reasonable Further Progress and
Attainment Demonstration Requirements: Final Rule,'' 60 FR 36723, 36724
(July 18, 1995). The EPA's interpretation was upheld by the Court of
Appeals for the 10th Circuit, in Sierra Club v. EPA, 99 F.3d 1551, 1557
(10th Cir. 1996).
Accordingly, EPA believes it clear that the reference in section
110(a)(2)(D)(i)(I) to ``nonattainment'' refers to air quality, not
designation status. The EPA believes this matter is clearly resolved by
reference to the terms of the provision itself, so that under the first
step of the Chevron analysis, no further inquiry is needed. If,
however, it were concluded that the provision is ambiguous on this
point, then EPA believes that, under the second step in the Chevron
analysis, EPA should be given deference for any reasonable
interpretation. Interpreting ``nonattainment'' to refer to air quality
is reasonable for the reasons described above.19
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\19\ Similarly, EPA believes that the term ``maintenance'' in
another clause of section 110(a)(2)(D)(i)(I) refers to air quality
status as well. This clause includes only the term ``maintenance,''
and does not include the term ``area.''
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The structure of the schedules for requiring SIP submissions and
designating areas nonattainment provides support for EPA's
interpretation. As noted above, section 110(a)(1) requires States to
submit SIPs covering all their areas--regardless of whether designated,
or how designated-- within 3 years of a NAAQS revision and requires
that those SIPs include provisions meeting the requirements of section
110(a)(2)(D).20 When a new or revised NAAQS is promulgated,
section 107(d)(1) authorizes a process of up to 3 years for
designations. States must recommend designations within one year of
promulgation of a new or revised NAAQS and EPA must designate areas
within 2 years of promulgation; EPA may take up to 3 years to designate
areas if insufficient information prevents designations within 2 years.
In the case of the 8-hour ozone NAAQS, Congress provided specific
legislation for designations (Pub. L. 105-178 Sec. 6103). Under this
new legislation, States are provided 2 years to make recommendations
and EPA must designate areas within 1 year of the time State
recommendations are due. Because of this legislation, designations must
occur 3 years following promulgation of the NAAQS (July 2000). The EPA
believes that it is not sensible to interpret the term
``nonattainment'' in section 110(a)(2)(D)(i)(I) to refer to
nonattainment designations because those designations may not be made
until 3 years after the promulgation of a new or revised NAAQS, and the
section 110(a)(2)(D) submittals are due within 3 years.
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\20\ See ``Re-issue of the Early Planning Guidance for the
Revised Ozone and Particulate Matter (PM) National Ambient Air
Quality Standards (NAAQS),'' memorandum from Sally L. Shaver, dated
June 16, 1998.
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Further, interpreting the reference to ``nonattainment'' as a
reference to air quality, and not designation, is consistent with the
air quality goals of section 110(a)(2)(D) and the CAA as a whole. In
the present case, it is clear from air quality monitoring and modeling
that large areas of the eastern part of the United States are in
violation of the 8-hour NAAQS, and it is also clear from air quality
modeling studies that NOX emissions from sources in upwind
States contribute to those air quality violations. The EPA currently
has available all the information that it needs to determine whether
upwind States should be required to revise their SIPs to implement
appropriate reductions in NOX emissions. The designation
process will clarify the precise boundaries of the downwind areas, but
because ozone is a regional phenomenon, information as to the precise
boundaries of the downwind areas is not necessary to implement the
requirements of section 110(a)(2)(D)(i). As a result, no air quality
purpose will be served by waiting until the downwind areas are
designated nonattainment.
On the contrary, taking action now is necessary to protect public
health. As described in Section I.G., the regional NOX
reductions required under today's action will allow numerous areas
currently in violation of the 8-hour NAAQS to attain that standard. For
the millions of people living in those areas, today's action will
advance the date by which these areas will meet the revised ozone
standard. Taking action now is particularly important because one of
the sub-population groups at higher risk to ozone health effects is
children who are active and spend more time outdoors during the summer
months when ozone levels are elevated.
(3) EPA's Authority to Require Section 110(a)(2)(D) Submissions in
Accordance with section 110(a)(1). Commenters argue that sections
110(a)(1), (a)(2), and 172(b) should be read so that only requirements
under section 110(a)(2) that are unrelated to nonattainment are due
under the section 110(a)(1) timetable. These commenters contend that
requirements under section 110(a)(2) that are related to
nonattainment--including section 110(a)(2)(D)--are due under the
section 172(b) timetable, that is, within 3 years of the designation of
areas as nonattainment. In support, these commenters rely on language
in section 110(a)(1) indicating that the submissions are for plans for
air quality regions ``within such State.'' Finally, certain commenters
cite as further support for their position the definition of the term
``nonattainment'' as found in section 107(d)(1)(A), claiming that the
definition includes interstate transport areas.
As noted above, section 110(a)(1) provides that States must submit
SIP revisions providing ``for the implementation, maintenance and
enforcement'' of the NAAQS in each area of the State within 3 years (or
a shorter time prescribed by the Administrator) following promulgation
of a new or revised NAAQS. Section 110(a)(2) then sets forth the
applicable elements of a SIP. These provisions apply to all areas
within the State, regardless of designation. Section 172(b) establishes
a SIP submission schedule for nonattainment areas. It provides that at
the time EPA designates areas as nonattainment, EPA shall establish a
SIP submission schedule for the submission of a SIP meeting the
requirements of section 172(c).
While EPA agrees that there is overlap between the submission
requirements under sections 110(a)(1)-(2) and 172(c), EPA believes that
the plain language of section 110(a)(1)-(2) authorizes EPA to require
the section 110(a)(2)(D) SIPs on the schedule described today, and that
there is nothing to the contrary in section 172. Sections 110(a)(2) and
172 contain cross-references to each other.21
[[Page 57373]]
These cross-references indicate that under certain circumstances, the
section 110(a)(2)(D) submittal may be required under section 110(a)(1);
and under other circumstances, the section 110(a)(2)(D) submittal may
be required under section 172(b). These cross-references are
particularly relevant with respect to nonattainment areas, which are
subject to both sections 110(a) (1) and (2) and 172. In the current
situation, EPA believes that it is appropriate to require the
submissions to meet section 110(a)(2)(D) in accordance with the
schedule in section 110(a)(1) rather than under the schedule for
nonattainment areas in section 172(b).22
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\21\ Section 110(a)(2)(D) provides that areas designated
nonattainment must submit SIPs in accordance with ``part D'' (which
includes section 172). Section 172(b) requires EPA to establish a
schedule for designated nonattainment areas to meet the requirements
of sections 172(c) and 110(a)(2); section 172(c)(7) requires that
nonattainment SIPs shall meet the requirements of section 110(a)(2).
\22\ In other situations, EPA has indicated that certain
elements of section 110(a)(2) would be better addressed in
accordance with the timeframe established in section 172. See e.g.,
60 FR 12492, 12505 (March 7, 1995) Proposed Requirements for
Implementation Plans and Ambient Air Quality Surveillance for Sulfur
Oxides (Sulfur Dioxide) National Ambient Air Quality Standard.
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The EPA has provided that, for the revised ozone and particulate
matter NAAQS, States must assess their section 110 SIPs by July 18,
2000 to ensure that they adequately provide for implementing the
revised standards. See Re-issue of the Early Planning Guidance for the
Revised Ozone and Particulate Matter (PM) National Ambient Air Quality
Standards (NAAQS), memorandum from Sally L. Shaver, dated June 16,
1998. The EPA recognized that the section 110 SIP should generally be
sufficient to address the revised NAAQS. However, the Agency noted
three areas that the States particularly needed to assess, including
whether the SIP adequately addressed section 110(a)(2)(D). The EPA also
provided that the States should submit revisions to address section
110(a)(2)(D) on the timeframe established by the final NOX
SIP call, when issued. The submittal date that EPA has specified in the
final NOX SIP call rule is consistent with both the Early
Planning Guidance and with section 110(a)(1) and (2) of the CAA.
The EPA acknowledges that it has not historically required an
affirmative submission under section 110(a)(2)(D), applicable to
specific sources of emissions, in response to the promulgation of a new
or revised NAAQS. In part, this is because sufficient technical
information was not available to determine which sources ``contribute
significantly'' to nonattainment in a downwind area. In the absence of
such a determination, States were unable to regulate sources under this
provision in any meaningful way. However, based on the many analyses
performed over the last several years, EPA believes that there is now
affirmative information regarding significant contribution to ozone
violations in the eastern portion of the country; in light of that
evidence, it would not be appropriate to defer action under section
110(a)(2)(D) until a later time.
Moreover, as noted above, the section 172(c) SIP submissions apply
only to areas designated nonattainment. Specifically, section 172(b)
provides that ``[a]t the time'' EPA designates an area as
nonattainment, EPA shall set a schedule ``according to which the State
containing such area shall submit'' SIPs. Section 171(2) provides
further clarification by providing that for purposes of part D of title
I of the CAA (CAA sections 171-193) ``[t]he term `nonattainment area'
means, for any air pollutant, an area which is designated
`nonattainment' with respect to that pollutant within the meaning of
section 107(d).'' By its terms then, section 172 does not apply to
areas designated attainment or unclassifiable (even if such areas are
not attaining the standard) or for areas not yet designated. Thus,
section 110(a)(1) provides the only submission schedule for areas not
designated nonattainment. For those areas, the commenters' argument
that section 172(b) should establish the timetable for section
110(a)(2)(D)(i) SIPs clearly fails. Since certain portions of the 23
jurisdictions covered by this rule likely will not be designated
nonattainment for the 8-hour standard, EPA believes that the section
110(a)(1) schedule is the only schedule (and thus is the reasonable
schedule) to follow for purposes of the SIP call.
Furthermore, contrary to the commenters' assertions, the definition
of nonattainment does not broadly include areas that contribute to
nonattainment in a downwind State. The definition of nonattainment
includes areas that have monitored violations of the standard and areas
that ``contribute to ambient air quality in a nearby area'' that is
violating the standard (section 107(d)(1)(A)(i) (emphasis added)).
Thus, only ``nearby'' areas that contribute to violations of a standard
will be included in the nonattainment designation; areas contributing
to longer-range transport will not be designated nonattainment based
solely on that longer-range transport. Therefore, they will not be
subject to section 172(c) requirements and timing.
The commenters argue that EPA's position that section 110(a)(1)
governs the section 110(a)(2)(D) SIP submittal schedule leads to the
absurd result that upwind areas will be required to submit SIPs dealing
with their contribution to a nonattainment problem downwind before the
downwind area will be required to submit SIPs under section 172(b). The
commenters explain that section 110(a)(2) requires SIP submittals on a
faster timetable (within 3 years from the date of promulgation or
revision of a NAAQS) than section 172(b) (within 3 years from the date
of designation as nonattainment). The commenters also contend that
section 107 provides that States have the primary responsibility for
ensuring attainment within their boundaries; only after a State
implements all statutorily required and necessary measures can it
pursue reductions in other areas through a SIP call or section 126. The
commenters contend that the SIP call is contrary to the plain language
of section 107 and congressional intent because it would require upwind
areas to implement controls before the downwind area has implemented
all statutorily required or necessary controls.
While it is true that plans to meet the emissions budget for the
SIP call will be due prior to nonattainment designations and attainment
plans for areas designated nonattainment for the 8-hour standard, EPA
does not consider this result to be absurd in the present case.
The CAA, at least since its amendment in 1970, has required States
to regulate ozone. For more than the past 25 years, States have focused
on the adoption and implementation of local controls for the purpose of
bringing nonattainment areas into attainment. Thus, historically, the
downwind nonattainment areas have borne the brunt of the control
obligations through the implementation of local controls. In
comparison, areas in attainment of the NAAQS, but upwind of
nonattainment areas, have not been required to implement controls
designed to ameliorate the air quality problems experienced by their
downwind neighbors.
Since the CAA Amendment of 1977, designated nonattainment areas
have been subject to specific local control obligations, such as
vehicle I/M and, for stationary sources, the requirement to implement
RACT. The CAA Amendments of 1990 tightened these control obligations
for many areas. Moderate, serious, severe and extreme areas were
required to reduce emissions by 15 percent between 1990 and 1996. In
addition, each serious, severe and extreme area is required to achieve
9 percent reductions over the succeeding 3 year periods until the area
attains the
[[Page 57374]]
standard. Additional requirements, such as the use of RFG and the use
of vapor recovery devices on gasoline pumps, are also required for
certain areas (see generally, CAA section 182 and, e.g., section
211(k)). Thus, downwind areas with nonattainment problems under the 1-
hour NAAQS are under current obligations to submit SIP revisions
containing local control measures for that standard. For these areas,
local reductions needed to meet the 1-hour standard are already
occurring and will be achieved prior to or on the same schedule as
reductions States may require in response to the SIP call.
Furthermore, in many of the downwind areas, States have been taking
action to reduce ozone levels for many years in order to meet the 1-
hour ozone NAAQS. Although the fact that the 8-hour ozone NAAQS is a
new form of the ozone standard, however, should not obscure the fact
that the downwind States have been making efforts to reduce ozone
levels for decades. The EPA believes that the history of implementation
by downwind areas of ozone pollution controls further mitigates the
commenters' argument that it is absurd to require upwind areas to
implement controls in advance of downwind attainment demonstrations
under the 8-hour NAAQS.23
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\23\ Although the SIP call will provide a benefit to a wide
number of areas, the focus of the SIP call is to reduce boundary
conditions for a number of areas that will have difficulty attaining
either the 1-hour or 8-hour standard (or both) without the benefit
of reductions from outside the nonattainment area. Based on current
monitoring data and modeling, EPA predicts that there will be a
number of areas that are meeting the 1-hour standard that will be
designated nonattainment for the 8-hour standard. The EPA further
predicts that many of these areas will come back into attainment due
solely to the emission reductions achieved by the NOX SIP
call. However, this incidental benefit--which likely will occur
without the need for local emission reductions--does not preclude
EPA from requiring the SIP call reductions, which are needed to help
other more seriously polluted areas that have long-standing
pollution problems.
---------------------------------------------------------------------------
Moreover, virtually all of the downwind States affected by today's
rulemaking, due to 8-hour ozone nonattainment or maintenance problems,
are themselves upwind contributors to problems further downwind, and,
thus, are subject to the same requirements as the States further
upwind.24 The reductions these downwind States must
implement due to their additional role as upwind States will help
reduce their own 8-hour ozone problems on the same schedule as
emissions reductions for the upwind States. Accordingly, for the most
part, this rulemaking does not require upwind areas to take action in
advance of any action by downwind areas to ameliorate the downwind
problems.
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\24\ Maine, New Hampshire, and Vermont are the only downwind
States that are not subject to today's action.
---------------------------------------------------------------------------
Finally, even if EPA were requiring upwind States to take action to
reduce downwind nonattainment and maintenance in advance of action by
the downwind States, this would simply require upwind areas to take the
first step by developing SIPs to eliminate their significant
contribution to the downwind problem. The downwind areas will be
required to take the next step by developing SIPs that address their
share. Generally, an agency may resolve a problem (in this case,
downwind nonattainment) on a step-by-step basis (see e.g., Group
Against Smog and Pollution, Inc. v. EPA, 665 F.2d 1284, 1291-92 (D.C.
Cir. 1981)).
A commenter has observed that under section 110(a)(1), EPA may
authorize section 110(a)(2) submittals as late as 3 years after
revision of a NAAQS, which, in this case, would run until July 2000.
The Early Planning Guidance, described above, indicates that States are
allowed until July 2000 to make submissions concerning other elements
of section 110(a)(2). However, as described elsewhere, EPA has
determined that the section 110(a)(2)(D) submittals should be submitted
by the end of September 1999 to assure that the required NOX
reductions will be implemented as expeditiously as practicable, which
EPA has determined is no later than the May 1 start of the 2003 ozone
season (see Section V, below).
Citing section 107(a) of the CAA, the commenters assert that the
CAA requires downwind areas to fully adopt and implement all
statutorily required or necessary measures before EPA can require
upwind areas to control emissions. Section 107 provides that States
shall have the primary responsibility for assuring air quality within
the State by submitting a plan that specifies how the NAAQS will be
achieved and maintained in the State. The commenters attempt to read
this statement regarding a State's authority to choose the mix of
control measures within State boundaries as barring the control of
emissions from upwind States.
This provision may be read as focusing on the State-Federal balance
in controlling criteria pollutants, such as ozone, not any upwind-
State, downwind-State balance. The provision indicates that although
EPA may promulgate Federal measures that provide reductions to help
States reach attainment, States bear the ultimate responsibility for
assuring attainment. Further, this provision may be read to indicate
that States may choose the mix of controls to reach attainment within
their own boundaries. Nothing in this provision purports to address the
need for upwind controls. By comparison, section 110(a)(2)(D)
affirmatively requires States to submit a SIP prohibiting emissions
that significantly contribute to downwind nonattainment or interfere
with maintenance of the NAAQS. Thus, the statute, read as a whole,
contemplates that interstate transport will be addressed as part of the
downwind States' attainment responsibilities. Indeed, determining the
upwind area's share of the problem is necessary in order for downwind
attainment planning. In the absence of the upwind reductions that will
be achieved, the downwind area would be required to submit an
attainment plan to demonstrate attainment regardless of cost and
without benefit of the reduction of upwind emissions that significantly
contribute to nonattainment. In light of the statute as a whole, it is
absurd to argue that Congress intended downwind areas to reduce
emissions at any cost while upwind sources that significantly
contribute to that nonattainment remain unregulated. Congress attempted
to balance responsibilities, providing that States could choose the mix
of controls within the State's borders (CAA section 107(a)) and are
ultimately responsible for assuring attainment, but also recognizing
that emissions reductions from upwind States may be needed for
attainment (CAA section 110(a)(2)(D)(i)).
b. Process for Requiring SIP Submissions under the 8-Hour Standard.
The time by which the section 110(a)(2)(D) SIP revision under the 8-
hour NAAQS must be submitted is governed by section 110(a)(1), which
requires the SIP revision to be ``adopt[ed] and submit[ed] to the
Administrator, within 3 years (or such shorter period as the
Administrator may prescribe) after the promulgation of a [NAAQS] (or
any revision thereof) . . . .'' In the NPR, EPA indicated that the SIP
revision would be due by the end of September 1999, which EPA expected
to be 12 months from the date of completing today's final rule. In
today's action, EPA is confirming that the SIP revision will be due
September 30, 1999, for the reasons described below in Section VI.A.1,
Schedule for SIP Revision.
3. Requirements of Section 110(a)(2)(D)
a. Summary. Today's action is driven by the requirements of CAA
section 110(a)(2)(D). This provides that each SIP must--
[[Page 57375]]
* * * contain adequate provisions--(I) prohibiting, consistent
with the provisions of this title, any source or other type of
emissions activity within the State from emitting any air pollutant
in amounts which will--(I) contribute significantly to nonattainment
in, or interfere with maintenance by, any other State with respect
to any such national primary or secondary ambient air quality
standard * * *
According to section 110(a)(2)(D), the SIP for each area,
regardless of its designation as nonattainment or attainment (including
unclassifiable), must prohibit sources within the area from emitting
air pollutants in amounts that will ``contribute significantly'' to
``nonattainment'' in a downwind State, or that ``interfere with
maintenance'' in a downwind State.
b. Determination of Meaning of ``Nonattainment'' (1) Geographic
Scope. In determining the meaning and scope of section 110(a)(2)(D), it
is useful first to determine the geographic scope of ``nonattainment''
downwind.
At proposal, EPA stated that it--
* * * proposes to interpret this term to refer to air quality
and not to be limited to currently-designated nonattainment areas.
Section 110(a)(2)(D) does not refer to ``nonattainment areas,''
which is a phrase that EPA interprets to refer to areas that are
designated nonattainment under * * * section 107(d)(1)(A)(I) * * * .
Rather, the provision includes only the term `nonattainment' and
does not define that term. Under these circumstances, EPA has
discretion to give the term a reasonable definition, and EPA
proposes to define it to include areas whose air quality currently
violates the NAAQS, and will likely continue [to violate in the
future], regardless of the designation of those areas * * *
(62 FR 60324).
To determine whether areas would continue to violate in the future,
EPA proposed to take into account the reductions that would result from
current CAA control requirements (apart from controls that may be
required under section 110(a)(2)(D)). To take these reductions into
account, EPA determined whether the area would be in nonattainment in
the future based on air quality modeling that assumed CAA-mandated
reductions and that accounted for growth. If an area would reach
attainment based on required controls, EPA would not view that area as
having a nonattainment problem to which any upwind areas may be
considered to contribute.
As explained earlier, in today's action, EPA has determined that
for purposes of the 8-hour NAAQS, the reference to ``nonattainment''
should be defined as EPA proposed. Thus, in determining whether an
upwind area contributes significantly to ``nonattainment'' downwind,
EPA would evaluate downwind areas for which monitors indicate current
nonattainment, and air quality models indicate future nonattainment,
taking into account CAA control requirements and growth.
For the 1-hour standard, EPA proposed to define nonattainment to
include all grid cells within a county when a monitor in that county
indicated nonattainment. Upon further study, EPA found that in some
instances, a metropolitan area may consist of numerous counties, only a
few of which contain monitors indicating nonattainment. The EPA
recognizes that under the 1-hour NAAQS, nonattainment boundaries are
generally used to describe the area with the nonattainment problem;
accordingly, EPA believes that this geographic vicinity offers an
appropriate indication of an area that may be expected to have
nonattainment air quality. The EPA predicts that many 1-hour
nonattainment areas that currently monitor nonattainment somewhere
within the area will remain in nonattainment in 2007, in some cases
because of predicted violations in counties that currently monitor
attainment. The EPA believes that the entire area should be considered
to be in nonattainment until all monitors in the area indicate
attainment of the NAAQS. Thus, in today's action, EPA used the
designated nonattainment area in determining the downwind nonattainment
problem.25
---------------------------------------------------------------------------
\25\ It should be reiterated that EPA relied on the designated
area solely as a proxy to determine which areas have air quality in
nonattainment. This proxy is readily available under the 1-hour
NAAQS because areas have long been designated nonattainment. The
EPA's reliance on designated nonattainment areas for purposes of the
1-hour NAAQS does not indicate that the reference in section
110(a)(2)(D)(i)(I) to ``nonattainment'' should be interpreted to
refer to areas designated nonattainment.
---------------------------------------------------------------------------
As noted above, commenters disagreed with EPA's view that the term
``nonattainment'' covers areas with air quality that is currently in
nonattainment, regardless of designation. The EPA's response to those
comments is also set forth above.
(2) 2007 Projection Year. In the NPR, EPA indicated that it would
adopt the year 2007 as the year for determining whether areas achieved
their required NOX budget levels. Accordingly, in
determining whether downwind areas should be considered to be, and
remain in, ``nonattainment,'' EPA would model their air quality in
2007, based on the implementation of CAA required controls by that
date, and growth in emissions--generally due to economic growth and
greater use of vehicles--by that date. At proposal, EPA adopted this
same approach with respect to both the 1-hour and the 8-hour NAAQS (62
FR 60325). The EPA is continuing this approach.
c. Definition of Significant Contribution. As indicated in the NPR,
neither the CAA nor its legislative history provides meaningful
guidance for interpreting the term ``contribute significantly'' under
section 110(a)(2)(D)(i)(I).
(1) ``Contribute.'' The initial step in defining the ``contribute
significantly'' term is to determine the meaning of the term
``contribute.'' In the NPR, EPA stated that it believes this term
should be defined broadly, so that emissions ``contribute'' to
nonattainment downwind if they have an impact on nonattainment downwind
(62 FR 60325). Air quality modeling indicated that emissions from the
upwind States clearly impact downwind nonattainment problems; as a
result, EPA generally folded this step of determining whether sources
``contribute'' to nonattainment downwind into the step of determining
whether that contribution is ``significant,'' discussed below.
In addition, section 110(a)(2)(D)(i)(I) requires the SIP to
prohibit amounts of emissions ``which will contribute significantly * *
*'' (emphasis added). The EPA believes that the term ``will'' means
that SIPs are required to eliminate the appropriate amounts of
emissions that presently, or that are expected in the future,
contribute significantly to nonattainment downwind.
Because ozone is a secondary pollutant formed as a result of
complex chemical reactions involving numerous sources, it is not
possible to determine the downwind impact on each individual source. In
addition, ozone generally results from the contributions of numerous
sources. As indicated in the NPR:
[U]nhealthful levels of ozone result from emissions of
NOX and VOCs from thousands of stationary sources and
millions of mobile sources [and consumer products and other sources]
across a broad geographic area. Each source's contribution is a
small percentage of the overall problem; indeed, it is rare for
emissions from even the largest single sources to exceed one percent
of the inventory of ozone precursors even for a single metropolitan
area. Under these circumstances, even complete elimination of any
given source's emissions may well have no measurable impact in
ameliorating the nonattainment problem. Rather, attainment requires
controls on numerous sources across a broad area. Ozone is a
regional scale
[[Page 57376]]
problem that requires regional scale reductions
(62 FR 60326).
Accordingly, EPA has adopted a ``collective contribution'' approach
to determining whether sources ``contribute'' to nonattainment
downwind: EPA determines the impact downwind of emissions in the
aggregate from a particular geographic region. If the aggregated
emissions are considered to contribute to nonattainment downwind, then
all of the emissions in that region should be considered as
contributors to that nonattainment problem. In today's action, EPA is
continuing the same interpretation of the term ``contribute,'' for the
reasons just described.
(2) ``Significantly''. (a) Notice of Proposed Rulemaking. In the
NPR, EPA proposed a ``weight-of-evidence,'' or multi-factor, approach
for determining whether a contribution is ``significant.''
The EPA proposed two separate interpretations for the term
``contribute significantly,'' which had implications as to which
factors were to be considered in what parts of the analysis. Under the
first interpretation, significant contribution is determined with
reference to--
* * * factors concerning amounts of emissions and their ambient
impact, including the nature of how the pollutant is formed, the
level of emissions and emissions density (defined as amount of
emissions per square mile) in the particular upwind area, the level
of emissions in other upwind areas, the amount of contribution to
ozone in the downwind area from the upwind areas, and the distance
between the upwind sources and the downwind nonattainment problem.
Under this approach, when emissions and ambient impact reach a
certain level, as assessed by reference to the factors identified
above, those emissions would be considered to ``contribute
significantly'' to nonattainment.
(62 FR 60325).
Under this interpretation, after identifying amounts of emissions
that constitute a significant contribution, EPA then determines the
amount of emissions reductions necessary to adequately mitigate these
contributions. This determination entails--
* * * [e]valuation of the costs of available measures for
reducing upwind emissions * * * as well as to the extent known (at
least qualitatively), the relative costs of, amounts of reductions
from, and ambient impact of measures available in the downwind
areas.
Id.
Under the second interpretation, EPA considers all of the factors
under both the significant contribution prong and the mitigation prong
of the first interpretation, and, once EPA determines an amount of
emissions that does significantly contribute to downwind nonattainment,
then EPA would determine that the SIP must contain provisions adequate
to prohibit that amount of emissions. Id. at 60325-26.
(b) Today's Action. The EPA has determined that the second
interpretation should be used; that is, that the determination of
significant contribution includes both air quality factors relating to
amounts of upwind emissions and their ambient impact downwind, as well
as cost factors relating to the costs of the upwind emissions
reductions. Once an amount of emissions is identified in an upwind
State that contributes significantly to a nonattainment problem
downwind, or interferes with maintenance downwind, the SIP must include
provisions to eliminate that amount of emissions.
To reiterate, section 110(a)(2)(D)(i)(I) provides that the SIP must
``prohibit[]'' sources from ``emitting any air pollutant in amounts
which will contribute significantly to nonattainment in, or interfere
with maintenance by, any other State.'' The term ``prohibit'' is
defined as ``to forbid by authority'' or ``prevent,'' or ``preclude.''
``The American Heritage Dictionary of the English Language'' (3d ed.
1992, 1448). The EPA believes that the term ``prohibit'' means that
SIPs must eliminate those amounts of emissions determined to contribute
significantly to nonattainment or interfere with maintenance downwind.
Moreover, EPA believes that whether emissions ``contribute
significantly'' depends on a multifactor test, as described below.
Thus, section 110(a)(2)(D)(i)(I) does not require the elimination of
all upwind source emissions that impact downwind air quality problems,
but only those amounts of emissions that, based on a multi-factor test,
significantly contribute to downwind air quality problems.
d. Multi-factor Test for Determining Significant Contribution. In
the NPR, EPA proposed a multi-factor test for determining whether
emissions from an upwind State contribute significantly to a
nonattainment or maintenance problem downwind. The EPA received
numerous comments on the factors. Based on the comments and EPA's
further analysis, EPA, in today's action, is continuing the multi-
factor approach, with some refinements in response to comments, with
respect to the factors EPA considered and the manner in which EPA
considered them.
In determining whether emissions from upwind States affected by
today's action contribute significantly to downwind nonattainment or
maintenance problems, EPA specifically considered the following factors
with respect to each such upwind State. These factors were the primary
components in EPA's consideration.
The overall nature of the ozone problem (i.e.,
``collective contribution'')
The extent of the downwind nonattainment problems to
which the upwind State's emissions are linked, including the ambient
impact of controls required under the CAA or otherwise implemented in
the downwind areas
The ambient impact of the emissions from the upwind
State's sources on the downwind nonattainment problems
The availability of highly cost effective control
measures for upwind emissions.
The first three of these factors are related to air quality; the
fourth is related to costs.
In addition, EPA generally reviewed several other considerations
before concluding that upwind emissions contribute significantly to
downwind nonattainment. The EPA did not consider it necessary, or did
not have adequate information, to apply each of these factors with
specificity with respect to each upwind State's emissions. In addition,
in some instances, EPA did not have quantitative information to assess
certain of these factors, and instead relied on qualitative
information. These considerations were secondary aspects of EPA's
analysis. They include:
The consistency of the regional reductions with the
attainment needs of the downwind areas with nonattainment problems
The overall fairness of the control regimes required of
the downwind and upwind areas, including the extent of the controls
required or implemented by the downwind and upwind areas
General cost considerations, including the relative
cost-effectiveness of additional downwind controls compared to upwind
controls
All of these factors and considerations are described in the
following sections.
e. Air Quality Factors. As noted above, EPA specifically considered
three air quality factors with respect to each upwind State, which
factors, in conjunction with the cost factor discussed in the next
section, were the primary components in EPA's consideration:
The overall nature of the ozone problem (i.e.,
``collective contribution'')
The extent of the downwind nonattainment problems to
which the upwind State's emissions are linked,
[[Page 57377]]
including the ambient impact of controls required under the CAA or
otherwise implemented in the downwind areas
The ambient impact of the emissions from the upwind
State's sources on the downwind nonattainment problems
(1) Collective Contribution. As indicated elsewhere, ozone
generally results from the collective contribution of emissions from
numerous sources over a large geographic area. For example, for urban
nonattainment areas under the 1-hour NAAQS, the downwind sources,
comprise numerous stationary sources as well as mobile on-road sources,
mobile off-road sources, and consumer and commercial products. Further,
additional contributions are made by numerous upwind States, both
adjacent to and further away from the nonattainment area itself. The
fact that virtually every nonattainment problem is caused by numerous
sources over a wide geographic area is a factor suggesting that the
solution to the problem is the implementation over a wide area of
controls on many sources, each of which may have a small or
unmeasureable ambient impact by itself.
(2) Extent of Downwind Nonattainment Problems, Including Ambient
Impact of Required Controls. In determining whether a downwind area has
a nonattainment problem under the 1-hour standard to which an upwind
area may be determined to be a significant contributor, EPA determined
whether the downwind area currently has a nonattainment problem, and
whether that area area would continue to have a nonattainment problem
as of the year 2007 assuming that in that area, all controls
specifically required under the CAA were implemented, and all required
or otherwise expected Federal measures were implemented. If, following
implementation of such required CAA controls and Federal measures, the
downwind area would remain in nonattainment, then EPA considered that
area as having a nonattainment problem to which upwind areas may be
determined to be significant contributors.
Thus, this analytical approach assumes that downwind areas
implement all required controls and receive the benefit of reductions
from Federal measures, and yet have a residual nonattainment problem
(prior to the implementation of the regional reductions required by
today's action). The fact that a nonattainment problem persists,
notwithstanding fulfillment of CAA requirements by the downwind
sources, is a factor suggesting that it is reasonable for the upwind
sources to be part of the solution to the ongoing nonattainment
problem.
The EPA undertook a comparable analysis with respect to the 8-hour
NAAQS. That is, the major urban areas in the northeast, midwest, and
south that are violating the 8-hour NAAQS are designated nonattainment
under the 1-hour NAAQS as well. After these areas are designated
nonattainment under the 8-hour NAAQS, they will become subject to the
control requirements of section 172(c). However, for these areas, the
section 172(c) requirements do not, by their terms, impose any specific
controls other than what these areas have already implemented to
fulfill the requirements under section 182 attendant to their
designation and classification under the 1-hour NAAQS. Accordingly, the
same air quality modeling analyses that shows residual nonattainment
for at least one of the urban areas linked to each upwind State under
the 1-hour standard shows residual nonattainment for those areas under
the 8-hour NAAQS. Indeed, modeling analyses relied on for today's
action indicate residual nonattainment for the major urban areas even
after the implementation of regional reductions comparable to those
required today.26
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\26\ The presence of residual nonattainment in major urban areas
after their implementation of specifically required CAA controls
supports the regional reductions required under today's action.
Those regional reductions allow the major urban areas to progress
towards attainment under the 8-hour NAAQS, and, at the same time,
significantly ameliorate the nonattainment problems under the 8-hour
NAAQS for numerous other areas. In fact, EPA projections indicate
that numerous areas with nonattainment problems will achieve
attainment of the 8-hour NAAQS as a result of the regional
reductions.
---------------------------------------------------------------------------
(3) Ambient Impact of Emissions from the Upwind Sources. In today's
action, EPA examined the impact of numerous upwind States on numerous
downwind areas with nonattainment problems.
Under the 1-hour NAAQS, EPA conducted various air quality modeling
analyses that examined the impact of emissions from sources in each
upwind State on ozone levels in downwind nonattainment areas, in light
of the impact of emissions from sources in other upwind States on the
downwind area's nonattainment problem. The EPA assessed the frequency
and magnitude of each upwind State's contribution to downwind
nonattainment problems. Some of the modeling analyses also permitted
determining the magnitude of the average contribution and the peak
contribution from each upwind State, as well as the percentage of each
upwind State's contribution to the downwind nonattainment problem.
The EPA determined that for each upwind State affected by today's
action, its contribution to a downwind nonattainment problem, in
conjunction with the contribution from other upwind States, comprised a
relatively large percentage of the nonattainment problem. The EPA
further determined that, in this context, the impacts from each
affected upwind State's NOX emissions are sufficiently large
and/or frequent so that the amounts of that State's emissions should be
considered to be significant contributions, depending on the cost
factor and other relevant considerations. For most upwind States, EPA
conducted two types of modeling--UAM-V and CAMx--that isolated the
impact of emissions from the upwind State alone on downwind
nonattainment.
The EPA also conducted much the same analysis to determine the
impact of emissions from each upwind State on ozone levels in downwind
States under the 8-hour NAAQS. Because nonattainment problems under the
8-hour NAAQS are widespread, and because EPA has not designated
individual nonattainment areas, EPA focused this part of its inquiry on
the upwind State's impact on the entire downwind State.
The EPA's analysis under both the 1-hour and 8-hour NAAQS led EPA
to conclude that, in light of both the collective contribution nature
of the ozone problem, and the fact that downwind areas continue to
suffer a nonattainment problem even after implementation of all
required CAA measures and Federal measures, emissions from each of the
affected upwind States have a sufficiently large and/or frequent
ambient impact such that those emissions contribute significantly to
nonattainment downwind, depending on the availability of highly cost-
effective measures and on other considerations discussed below.
f. Determination of Highly Cost-effective Reductions and of
Budgets. After determining the degree to which NOX
emissions, as a whole from the particular upwind States, contribute to
downwind nonattainment or maintenance problems, EPA then determined
whether any amounts of the NOX emissions may be eliminated
through controls that, on a cost-per-ton basis, may be considered to be
highly cost effective. By examining the cost effectiveness of recently
promulgated or proposed NOX controls, EPA determined that an
average of approximately $2,000 per ton removed
[[Page 57378]]
is highly cost effective. The EPA then determined a set of controls on
NOX sources that would cost no more than an average of
$2,000 per ton reduced. Specifically, EPA determined that one set of
these controls would include a cap-and-trade program for (i)
electricity generating boilers and turbines larger than 25 Mwe (``large
EGUs''), and (ii) large non-electricity generating industrial boilers
and turbines (``large non-EGU boilers and turbines''). The application
of an emission rate of 0.15 lb/mmBtu and 1995-1996 utilization for EGUs
and 60 percent for large non-EGUs to the emissions projected to occur
in 2007 including growth and CAA measures, led to the determination of
the amounts to be reduced. The remaining amount is a State's budget.
The EPA further determined that additional highly cost-effective
controls are also available for cement manufacturing sources and
internal combustion engines. On the basis of reasonable assumptions
concerning growth to the year 2007, EPA then determined the amounts of
emissions from these source categories that would be eliminated with
those controls.
The EPA further determined that there were no other controls on
other NOX sources that qualify as highly cost effective
(although several controls are reasonably cost-effective).
On the basis of the determinations just described for the various
source categories, EPA determined an amount of NOX emissions
that may be eliminated through these highly cost-effective measures.
Because EPA had also determined that the NOX emissions from
the affected upwind States have a large and/or frequent impact on
downwind nonattainment or maintenance problems, EPA concludes that the
amount of NOX emissions from those States that can be
eliminated through application of highly cost-effective control
measures contributes significantly to nonattainment or maintenance
problems downwind.
Under section 110(a)(2)(D)(i)(I), the SIP must include ``adequate
provisions prohibiting'' sources from emitting these ``amounts.''
Because no highly cost-effective controls are available to eliminate
the remaining amounts of NOX emissions, EPA concludes that
those emissions do not contribute significantly to downwind
nonattainment or maintenance problems. As indicated below and in
Section III, there are cost-effective alternatives available to States
that choose not to adopt all of the highly cost-effective measures on
which EPA based its selection of the significant amounts of
NOX emissions.
To implement EPA's determinations, each affected upwind State is
required to submit for EPA approval SIP controls projected to be
sufficient, by the year 2007, to eliminate the amount of NOX
emissions in the State that EPA determined contributes significantly to
nonattainment. The EPA determined this amount of reductions, for each
affected upwind State, as follows: EPA first determined the amount of
NOX emissions in that State by the year 2007, based on
assumptions concerning both growth and emissions controls that are
required under the CAA or that will be implemented due to Federal
actions (the ``2007 base case''). Second, EPA applied the control
measures identified as highly cost effective to the 2007 base case
amount for the appropriate source categories. The amount of
NOX emissions remaining in the State after application of
controls to the affected source categories constitutes the 2007 budget.
The difference between the 2007 base case and the 2007 budget is the
amount of NOX emissions in that State by the year 2007 that
EPA has determined to contribute significantly to nonattainment and
that, therefore, the SIPs must prohibit.
The upwind State's SIP revision due in response to today's action
must provide controls that, on the basis of the same assumptions
(including concerning growth) made by EPA in determining the budget,
would limit NOX emissions in the year 2007 to no more than
the 2007 budget. The State has full discretion in selecting the
controls, so that it may choose any set of controls that would assure
achievement of the budget.
As EPA stated in the NPR:
States are not constrained to adopt measures that mirror the
measures EPA used in calculating the budgets. In fact, EPA believes
that many control measures not on the list relied upon to develop
EPA's proposed budgets are reasonable--especially those, like
enhanced vehicle inspection and maintenance programs, that yield
both NOX and VOC emissions reductions.[ 27]
Thus, one State may choose to primarily achieve emissions reductions
from stationary sources while another State may focus emission
reductions from the mobile source sector.
\27\ As indicated in the NPR, EPA considers that measures may be
reasonable in light of their reduction of VOC and NOX
emissions, even though their cost-effectiveness in terms of cost per
NOX emissions removed is relatively high (62 FR 60346-
48).
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(62 FR 60328).
The EPA believes that its overall approach derives further support
from the mandate in section 110(a)(2)(D) that each SIP include
provisions prohibiting ``any source or other type of emissions activity
within the State from emitting any air pollutant in amounts' that
adversely affect downwind areas. The phrase ``any source or other type
of emissions activity'' may be interpreted to require that the SIP
regulate all sources of emissions to assure that the total amount of
emissions generated within the State does not adversely affect downwind
areas. By its terms, the phrase covers all emitters of any kind because
every emitter--stationary, mobile, or area--may be considered a
``source or other type of emissions activity.'' This interpretation is
consistent with the legislative history of the phrase. Prior to the CAA
Amendments of 1990, the predecessor to section 110(a)(2)(D), which was
section 110(a)(2)(E), referred to ``any stationary source within the
State.'' In the 1990 Amendments, Congress revised the phrase to read as
it currently does. A Committee Report explained, ``Where prohibitions
in existing section 110(a)(2)(E) apply only to emissions from a single
source, the amendment includes ``any other type of emissions
activity,'' which makes the provision effective in prohibiting
emissions from, for example, multiple sources, mobile sources, and area
sources.'' V Leg. Hist. 8361, S. Rep. No. 228, 101st Cong., 1st Sess.
21 (1989).
For reasons explained below, if an upwind State chooses to achieve
all or a portion of the required reductions from large EGUs or large
non-EGU boilers and turbines, then the SIP must include a mass
emissions limitation for those sources computed with reference to
certain growth assumptions and the emission rate limits chosen by the
State. The EPA recommends that this mass limitation, or cap, be
accompanied by a trading program. Any such cap-and-trade program must
be established by May 1, 2003. If the State chooses to achieve all or a
portion of the required reductions from other sources, then the State
must implement controls, by the year 2003, on those other sources that
are projected to achieve the required level of reductions, based on
certain assumptions (including growth), in the year 2007. The controls
on these other sources may be rate-based, and no emissions cap on them
is required. By the year 2007, any applicable mass emissions limitation
for large EGUs or large non-EGU boilers and turbines must continue to
be met, and any applicable controls on other sources must continue to
be implemented. The amount of the 2007 overall budget is used to
compute the level of controls that would result in the appropriate
amount of emissions reductions, given assumptions concerning, for
example,
[[Page 57379]]
growth. To this extent, the 2007 overall budget is an important
accounting tool. However, the State is not required to demonstrate that
it has limited its total NOX emissions to the budget
amounts. Thus, the overall budget amount is not an independently
enforceable requirement.
g. Other Considerations in Determination of Significant
Contribution. The EPA reviewed several other considerations in support
of its determination that the specified amounts of emissions from the
affected upwind States contribute significantly to nonattainment
downwind.
(1) Consistency of Regional Reductions with Downwind Attainment
Needs. The EPA conducted modeling analyses of emission reductions of
virtually the same magnitude as the regional reductions required under
today's action. Although the impact on any downwind ozone problem of
each upwind State's emissions reductions alone may be relatively small,
the impact of those reductions, when combined with the reductions from
the other States, is substantial. Based on this modeling, EPA
determined that the regional reductions allow downwind nonattainment
areas under the 1-hour NAAQS to make appreciable progress towards
attainment. The EPA further determined that under the 8-hour NAAQS,
many areas with nonattainment problems are expected to reach attainment
based solely on the regional reductions, and that other (primarily
urban) areas would benefit from the regional reductions but are
expected to experience residual nonattainment. EPA further determined
that none of the upwind States affected by today's action are affected
by ``overkill,'' that is, required reductions that are more than
necessary to ameliorate downwind nonattainment in every downwind area
affected by that upwind State.
(2) Fairness. The EPA also considered the overall fairness of the
control regimes required of the downwind and upwind areas, including
the extent of the controls required or implemented by the downwind and
upwind areas. Most broadly, EPA believes that overall notions of
fairness suggest that upwind sources which contribute significant
amounts to the nonattainment problem should implement cost-effective
reductions. When upwind emitters exacerbate their downwind neighbors'
ozone nonattainment problems, and thereby visit upon their downwind
neighbors additional health risks and potential clean-up costs, EPA
considers it fair to require the upwind neighbors to reduce at least
the portion of their emissions for which highly cost-effective controls
are available.
In addition, EPA recognizes that in many instances, areas
designated as nonattainment under the 1-hour NAAQS have incurred ozone
control costs since the early 1970s. Moreover, virtually all components
of their NOx and VOC inventories are subject to SIP-required or Federal
controls designed to reduce ozone. Furthermore, these areas have
complied with almost all of the specific control requirements under the
CAA, and generally are moving towards compliance with their remaining
obligations. The CAA's sanctions and FIP provisions provide assurance
that these remaining controls will be implemented. By comparison, many
upwind States in the midwest and south have had fewer nonattainment
problems and have incurred fewer control obligations.
(3) General Cost Considerations. The EPA also considered the fact
that in general, areas that currently have, or that in the past have
had, nonattainment problems under the 1-hour NAAQS, or that are in the
Northeast Ozone Transport Region (OTR), have already incurred ozone
control costs. The controls already implemented in these areas tend to
be among the less expensive of available controls. As described in more
detail below, EPA has determined that, in general, the next set of
controls identified as available in the downwind nonattainment areas
under the 1-hour NAAQS would cost approximately $4,300 per ton removed.
By comparison, EPA has determined that the cost of the regional
reductions required today would approximate $1,500 per ton removed.
Thus, it appears that the upwind reductions required by today's action
are more cost-effective per ton removed than reductions in the downwind
nonattainment areas. Moreover, under the 1-hour NAAQS, the reductions
required from each upwind State, in conjunction with reductions from
other upwind States, result in ambient improvement in at least several
downwind areas with nonattainment problems.
The EPA did not have available, and was not presented with,
meaningful quantitative information indicating the cost-effectiveness
of the regional reductions required today in light of their ambient
impact downwind (e.g., the cost of emissions reductions per ppb
improvement in ambient ozone levels in a downwind nonattainment area).
This lack of information limited the extent to which EPA could rely on
this consideration in making its determinations.
The various considerations just discussed point in the same
direction as the other factors described above concerning air quality
and costs. These factors and considerations lead EPA to conclude that
the amounts of each upwind State's emissions that may be eliminated
through highly cost-effective measures contribute significantly to
nonattainment or maintenance problems downwind.
h. Interfere with Maintenance. Once a nonattainment area has
attained the NAAQS, it is required to maintain that standard (e.g.,
sections 107(d)(3)(E)(iv), 110(a)(1)). Section 110(a)(2)(D)(i)(I) also
requires that SIPs contain adequate provisions prohibiting amounts of
emissions that ``interfere with maintenance by * * * any [downwind]
State.'' The EPA explained and applied this requirement in the NPR as
follows:
This [interfere-with-maintenance] requirement * * * does not, by
its terms, incorporate the qualifier of ``significantly.'' Even so,
EPA believes that for present purposes, the term ``interfere''
should be interpreted much the same as the term ``contribute
significantly,'' that is, through the same weight-of-evidence
approach.
With respect to the 1-hour NAAQS, the ``interfere-with-
maintenance'' prong appears to be inapplicable. The EPA has
determined that the 1-hour NAAQS will no longer apply to an area
after EPA has determined that the area has attained that NAAQS.
Under these circumstances, emissions from an upwind area cannot
interfere with maintenance of the 1-hour NAAQS.
With respect to the 8-hour NAAQS, the ``interfere-with-
maintenance'' prong remains important. After an area has reached
attainment of the 8-hour NAAQS, that area is obligated to maintain
that NAAQS. (See sections 110(a)(1) and 175A.) Emissions from
sources in an upwind area may interfere with that maintenance.
The EPA proposes to apply much the same approach in analyzing
the first component of the ``interfere-with-maintenance'' issue,
which is identifying the downwind areas whose maintenance of the
NAAQS may suffer interference due to upwind emissions. The EPA has
analyzed the ``interfere-with-maintenance'' issue for the 8-hour
NAAQS by examining areas whose current air quality is monitored as
attaining the 8-hour NAAQS [or which have no current air quality
monitoring], but for which air quality modeling shows nonattainment
in the year 2007. This result is projected to occur, notwithstanding
the imposition of certain controls required under the CAA, because
of projected increases in emissions due to growth in emissions
generating activity. Under these circumstances, emissions from
upwind areas may interfere with the downwind area's ability to
attain. Ascertaining the impact on the downwind area's air quality
of the upwind area's emissions aids in determining whether the
upwind emissions interfere with maintenance
[[Page 57380]]
(62 FR 60326).
In today's action, EPA is taking the same positions with respect to
the interfere-with-maintenance test as described in the NPR. Because
EPA generally interprets the ``interfere-with-maintenance'' test the
same as the ``contributes-significantly-to-nonattainment'' test, for
purposes of convenience, in this final rule, EPA sometimes refers to
``contributes-significantly-to-nonattainment'' to refer to both tests.
i. Dates. In today's action, EPA is determining that SIP
submissions required under this rulemaking must be submitted by
September 30, 1999 (see Section VI.A.1, Schedule for SIP Revision).
Further, in today's action, EPA is requiring that SIP controls
required today must be implemented by no later than May 1, 2003, and
they must achieve reductions computed with reference to an overall
budget amount determined as of September 30, 2007 (see Section V,
NOX Control Implementation and Budget Achievement Dates).
j. Downwind Areas' Control Obligations. Commenters have argued that
under the CAA, downwind States must implement additional controls
before EPA may require controls in upwind States. Commenters base this
argument in part on the provisions of CAA section 107(a), which
provides,
Each State shall have the primary responsibility for assuring
air quality within the entire geographic area comprising such State
by submitting an implementation plan for such State which will
specify the manner in which [NAAQS] will be achieved and maintained
within each air quality control region in such State.
Commenters further note that downwind States must implement
additional reductions (beyond those specifically required by the CAA
28) as needed to attain, under section 182(b)(1)(A)(i) and
182(c)(2)(A). The commenters add that section 179(d)(2) is a generally
applicable provision that limits the stringency of required controls to
what is feasible. The commenters read these provisions together to
conclude that downwind States must first implement all feasible control
measures in an effort to reach attainment, and only after EPA
determines that such States have done so but have not reached
attainment may EPA require upwind contributors to implement controls.
The commenters further observe that some of the downwind States in the
Northeast have not implemented all feasible SIP measures.
---------------------------------------------------------------------------
\28\ Reductions specifically required by the CAA include, for
example, the 3 percent-per-year ROP reductions required of ozone
nonattainment areas classified as serious or higher, under section
182(c)(2)(B).
---------------------------------------------------------------------------
The EPA disagrees with this legal analysis. The provision in
section 107(a) that accords to States the primary responsibility for
the air quality of their air basins, in essence provides the underlying
rationale for the requirement of States to submit SIP revisions that
meet CAA requirements. This phrase clarifies that the requirement of
assuring attainment does not fall, in the first instance, on EPA. This
provision does not have implications for apportioning responsibility
between the downwind State and upwind States for contributions from
upwind States. Downwind States would still carry the primary
responsibility of assuring clean air even after the upwind contributors
have revised their SIPs to meet the requirements of section
110(a)(2)(D).
Furthermore, EPA disagrees that section 179(d)(2) has any
application to today's rulemaking. That provision in essence provides a
general rule that if a nonattainment area fails to attain by its
attainment date, EPA may require the State to implement reasonable
controls that can be ``feasibly implemented.'' This requirement is not
relevant to today's rulemaking, which addresses the requirements under
section 110(a)(2)(D)(i)(I) that SIPs include provisions eliminating
amounts of emissions from their sources that contribute significantly
to downwind nonattainment.
In addition, the requirement of downwind States to implement
reductions beyond minimum CAA requirements if needed for attainment
does not place the burden of implementing those reductions, in the
first instance, on the downwind States. This requirement should be read
to go hand-in-hand with the section 110(a)(2)(D) requirement that
upwind States include SIP provisions that prohibit their sources from
emitting air pollutants in amounts that ``significantly contribute'' to
downwind nonattainment. In today's action, EPA is promulgating criteria
for interpreting section 110(a)(2)(D) to take into account downwind
attainment needs.
As a practical matter, EPA has reviewed the status of Northeast
States' efforts to comply with the requirements of the 1990 CAA
Amendments and has found that these States have complied with the vast
majority of the SIP submission requirements. Even so, EPA is well aware
that some of the States have not made certain required submissions.
29-30 However, EPA sees no basis in section 110(a)(2)(D) to
mandate that downwind areas complete their SIP planning and
implementation before upwind areas are required to begin that process.
Upwind areas have been subject to the requirements of section
110(a)(2)(D)--in some form--since the predecessor to this provision was
added in the 1977 CAA Amendments. The EPA has determined, through air
quality modeling, that even after the downwind States fulfill their
prescribed CAA requirements, they will have areas expected to remain in
nonattainment. Under these circumstances, the downwind areas continue
to constitute areas with air quality in ``nonattainment'' under section
110(a)(2)(D). As a result, upwind areas with emissions in amounts that
``significantly contribute'' to the nonattainment air quality downwind
are subject to control requirements whether or not the downwind areas
they affect have met all of their planning obligations.
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\29-30\ If downwind areas fail to meet their planning
obligations, they are subject to sanctions (See Section VI, below.
As EPA noted in the NPR, 62 FR 60322-23, in some instances, States
in the Northeast failed to submit all of their required SIP
revisions or other commitments under Phase 1 of the March 2, 1995
Memorandum and as a result, EPA initiated the sanctions process by
starting sanctions clocks. In general, those States have since made
the required Phase 1 submissions, and EPA terminated the sanctions
process by stopping the clocks.
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k. Section 110(a)(2)(D) Caselaw. In the NPR, EPA noted that prior
to the CAA Amendments of 1990, EPA had issued several rulemakings under
section 110(a)(2)(E), the predecessor to section 110(a)(2)(D), and
section 126 that addressed the issue of significant contribution in the
context of pollutant transport. In those rulemakings, EPA generally
applied a multi-factor test to determine whether the emissions from the
sources in question constituted a signficant contribution to downwind
jurisdictions. In each instance, EPA concluded that the emissions at
issue from the upwind sources were not demonstrated to impact downwind
air quality in a manner that would constitute significant contribution.
Several of these determinations resulted in judicial challenges, but in
each instance the courts upheld the Agency's determination of no
significant contribution. The EPA indicated in the NPR that the prior
rulemakings and the related court holdings, provide limited precedents
for today's action. The EPA noted that these decisions have limited
relevance because they involved different facts and circumstances,
including different pollutants, different
[[Page 57381]]
upwind sources, and different downwind effects.
Several commenters asserted that these prior rulemakings and cases
are relevant to today's action, and compel EPA to conclude that the
emissions from the upwind States affected by today's action do not
contribute significantly to downwind nonattainment or maintenance
problems. The EPA disagrees that these earlier determinations are
controlling and that these earlier determinations are inconsistent with
today's action. The EPA responds to these comments in detail in the
Response to Comment document.
B. Alternative Interpretation of Section 110(a)(2)(D)
As discussed above, in the NPR EPA advanced an alternative
interpretation of section 110(a)(2)(D) (62 FR 60327). Under this
alternative interpretation, EPA would determine the level of emissions
that significantly contribute to nonattainment downwind based on
factors relating to the entire amount of upwind emissions from a
particular upwind State and their ambient impact downwind. The EPA
would then determine what emissions reductions must be required to
adequately mitigate that significant contribution based on factors
relating to cost effectiveness of reductions and attainment needs
downwind.
The EPA continues to believe that this alternative interpretation
remains a permissible interpretation of the statute for the reasons
described in the NPR (62 FR 60327). In any event, it should be noted
that for purposes of today's action, EPA finds no practical difference
between the requirements that would result from the interpretation of
section 110(a)(2)(D) adopted today and those that would result from the
alternative interpretation described in the NPR. That is, even under
the alternative interpretation, today's rulemaking would contain the
same findings and require the same SIP revisions as under the
interpretation adopted today (62 FR 60327).
C. Weight-of-Evidence Determination of Covered States
As discussed above, EPA applied a multi-factor approach to identify
the amounts of NOX emissions that contribute significantly
to nonattainment. The EPA evaluated three air quality factors for each
upwind jurisdiction (hereafter referred to as ``States'' or ``upwind
States'') to determine whether each has emissions whose contributions
to downwind nonattainment problems are large and/or frequent enough to
be of concern. Further, for those States whose emissions are large and/
or frequent enough to be of concern, EPA applied highly cost-effective
controls to determine the amount of NOx in upwind States
which significantly contributes to nonattainment in, or interferes with
maintenance by, a downwind State. The EPA also generally reviewed
several other considerations before drawing final conclusions. Even
though the actual finding of significant contribution applies only to
the portion of a State's emissions for which EPA has identified highly
cost-effective controls, for ease of discussion, the term
``significant'' (or like term) is used in the discussion in this
section to characterize the emissions of each upwind State that make a
large and/or frequent contribution to nonattainment in downwind States
sufficient to warrant eliminating a portion of its emissions equivalent
to what can be removed through those controls.
The purpose of this section is to describe the technical analyses
performed by EPA to (a) quantify the air quality contributions from
emissions in each upwind State on both 1-hour and 8-hour nonattainment,
as well as 8-hour maintenance, in each downwind State, and (b)
determine whether these contributions are significant.
In the proposed weight-of-evidence approach, EPA specifically
applied several factors to each upwind State, as discussed in Section
II.A.3.c, Definition of Significant Contribution. These factors
include:
The overall nature of ozone problem (i.e., ``collective
contribution'');
The extent of the downwind nonattainment problems to which
the upwind State's emissions are linked, including the ambient impact
of controls required under the CAA or otherwise implemented in the
downwind areas; and
The ambient impact of the emissions from the upwind
State's sources on the downwind nonattainment problems.
As part of the analysis of these factors, EPA considered the
findings from OTAG's technical analyses, as well as the findings from a
number of other studies performed by OTAG participants independent of
OTAG. The major findings from these analyses are described below. This
is followed by an overview of the approach used by EPA in the proposal
for considering the above factors to identify States that make a
significant contribution to downwind nonattainment. The comments and
EPA's response to comments on EPA's weight-of-evidence proposal are
then discussed. Following that discussion, the results of additional
State-by-State UAM-V modeling and State-by-State CAMX
31 source apportionment modeling performed by EPA in
response to comments are summarized.32 The EPA's analysis of
the modeling results in terms of the significance of the contributions
of upwind States to downwind nonattainment is presented in Section
II.C.4, Confirmation of States Making a Significant Contribution to
Downwind Nonattainment.
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\31\ Comprehensive Air Quality Model with Extensions.
\32\ The UAM-V and CAMX models are described in the
Air Quality Modeling TSD.
---------------------------------------------------------------------------
1. Major Findings From OTAG-Related Technical Analyses
The major findings from the air quality and modeling analyses by
OTAG and individual OTAG participants that are most relevant to today's
rulemaking are as follows:
several different scales of transport (i.e., intercity,
intrastate, interstate, and inter-regional) are important to the
formation of high ozone in many areas of the East;
emissions reductions in a given multistate region/
subregion have the most effect on ozone in that same region/subregion;
emissions reductions in a given multistate region/
subregion also affect ozone in downwind multistate regions/subregions;
downwind ozone benefits decrease with distance from the
source region/subregion (i.e., farther away, less effect);
downwind ozone benefits increase as the size of the upwind
area being controlled increases, indicating that there is a cumulative
benefit to extending controls over a larger area;
downwind ozone benefits increase as upwind emissions
reductions increase (the larger the upwind reduction, the greater the
downwind benefits);
a regional strategy focusing on NOX reductions
across a broad portion of the region will help mitigate the ozone
problem in many areas of the East;
both elevated and low-level NOX reductions
decrease ozone concentrations regionwide;
there are ozone benefits across the range of controls
considered by OTAG; the greatest benefits occur with the most emissions
reductions; there was no ``bright line'' beyond which the benefits of
emissions reductions diminish significantly;
even with the large ozone reductions that would occur if
the most
[[Page 57382]]
stringent controls considered by OTAG were implemented, there may still
remain high concentrations in some portions of the OTAG region; and a
regional NOX emissions reduction strategy coupled with local
NOX and/or VOC reductions may be needed to enable attainment
and maintenance of the NAAQS in this region.
The above findings provide technical evidence that transport within
portions of the OTAG region results in large contributions from upwind
States to ozone in downwind areas, and that a regionwide approach to
reduce NOX emissions is an effective way to address these
interstate contributions.
2. Summary of Notice of Proposed Rulemaking Weight-of-Evidence Approach
The EPA relied on OTAG data to develop the information necessary to
evaluate the weight-of-evidence factors identified above. These data
include emissions (tons) and emission density (tons per square mile),
air quality analyses, trajectory, wind vector, and ``ozone cloud''
analyses, and subregional zero-out modeling. In brief, EPA's proposed
approach was as follows:
the OTAG transport distance scale was applied to identify,
based on the meteorological potential for transport, which States may
contribute to ozone in downwind States;
the results of the OTAG subregional modeling runs
(described below) were used to quantify the extent to which each
subregion contributes to downwind nonattainment for the 1-hour and/or
8-hour NAAQS;
the OTAG 2007 Base Case NOX emissions and
emissions density were used to identify States which emit large amounts
of NOX and/or have a high density of NOX
emissions compared to other States in the OTAG region and, therefore,
have NOX emissions which may be great enough to contribute
to downwind nonattainment; and the OTAG 2007 Base Case NOX
emissions were also used to translate the findings from the subregional
modeling to a State-by-State basis.
a. Quantification of Contributions. As part of OTAG's assessment of
transport, a series of model runs were performed to examine the impacts
of emissions from each of 12 multistate subregions on ozone in downwind
areas. The locations of these subregions are shown in Figure II-1.
[GRAPHIC] [TIFF OMITTED] TR27OC98.000
In each subregional model run, all manmade emissions were removed
from one upwind subregion and the model was run for the OTAG July 1988
and 1995 episodes. The ``parts per billion (ppb)'' differences in ozone
between each subregional zero-out run compared to the corresponding
2007 Base Case run were used to quantify the air quality impacts of the
subregion on nonattainment downwind.
In the proposed NOX SIP call, EPA considered areas as
``nonattainment'' if air quality monitoring indicates that the area is
currently measuring nonattainment and if air quality modeling indicates
future nonattainment, taking into account CAA control requirements and
growth. In this regard, areas were considered nonattainment for the 1-
hour NAAQS if
[[Page 57383]]
they had 1994-1996 \33\ monitoring data indicating measured 1-hour
violations and 2007 Base Case 1-hour predictions >=125 ppb. Areas were
considered to be nonattainment for the 8-hour NAAQS if they had 1994-
1996 monitoring data indicating measured 8-hour violations and 2007
Base Case 8-hour predictions >=85 ppb. The inconsistency between the
form of the 8-hour NAAQS, which considers 3 years of data for
determining the average of the fourth-highest 8-hour daily maximum
concentration at a monitor, and the limited predictions available from
the OTAG episodes introduced a complication to the analysis of 8-hour
contributions. It was not possible to use the model predictions in a
way that explicitly matched the form of the 8-hour NAAQS. Instead, an
analysis of seasonal and episodic ozone measurements was performed in
an attempt to link 8-hour measured concentrations during the OTAG
episodes to the form of the 8-hour NAAQS, as closely as possible. The
results of that analysis indicated that the 3-episode average of the
second highest 8-hour ozone concentrations measured during the OTAG
1991, 1993, and 1995 episodes corresponded best, overall, to the 3-year
average of the fourth highest 8-hour daily ambient data. However, since
OTAG subregional modeling was only available for the 1988 and 1995
episodes, EPA used the concentrations during these two episodes in
calculating average second high 8-hour concentrations.\34\
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\33\ Data for 1994-1996 were used because these were the most
recent quality-assured data available at the time the analysis was
performed.
\34\ In response to comments, EPA has reexamined the method for
relating 8-hour model predictions during the OTAG episodes to the
form of the 8-hour NAAQS. This is discussed further in Section
II.C.2.c, Comments and Responses on the Proposed Weight of Evidence
Approach to Significant Contribution.
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b. Evaluation of 1-Hour and 8-Hour Contributions. In the proposal,
EPA summarized the ``ppb'' contributions to downwind nonattainment from
each subregion in terms of both the frequency and the magnitude of the
downwind impacts over specific concentration ranges (e.g., 2 to 5 ppb,
5 to 10 ppb, 10 to 15 ppb, etc.). The results indicate that, in
general, large contributions to downwind nonattainment occur on
numerous occasions. Although the level of downwind contribution varies
from subregion to subregion, a consistent pattern is apparent for both
1-hour nonattainment and 8-hour nonattainment. Specifically, the
results of the subregional modeling indicate that emissions from States
in subregions 1 through 9 produce large 1-hour and 8-hour contributions
downwind in terms of the magnitude and frequency, including geographic
extent, of the downwind impacts. In addition, nonattainment areas
within many States in the OTAG region receive large and/or frequent
contributions from emissions in these subregions. The EPA proposed to
find that most of the States whose emissions are wholly or partially
contained within one or more of these subregions (i.e., Alabama,
Connecticut, Delaware, Georgia, Illinois, Indiana, Kentucky, Maryland,
Michigan, Missouri, New Jersey, New York, North Carolina, Ohio,
Pennsylvania, South Carolina, Tennessee, Virginia, West Virginia, and
Wisconsin, as well as the District of Columbia) are making a
significant contribution to downwind nonattainment. In addition to the
ambient impact demonstrated by the subregional modeling, this proposed
finding was based on a determination that:
OTAG strategy modeling and non-OTAG modeling indicate that
NOX emissions reductions across these States would produce
large reductions in 1-hour and 8-hour ozone concentrations across broad
portions of the region including 1-hour and 8-hour nonattainment areas;
these States are upwind from nonattainment areas within
the 1- to 2-day distance scale of transport;
these States form a contiguous area of manmade emissions
covering most of the core portion of the OTAG region;
11 of the States that are wholly within subregions 1
through 9 have a relatively high level of NOX emissions from
sources in their States; these States are ranked in the top 50 percent
of all States in the region in terms of total NOX emissions
and/or have NOX emissions exceeding 1000 tons per day;
States wholly within subregions 1 through 9 with lesser
emissions have a relatively high density of NOX emissions;
for the seven States that are only partially contained in
one of subregions 1 through 9, the State total NOX
emissions, as well as each State's contribution to NOX
emissions in the subregions in which they are located, indicate that
six of the States each have: NOX emissions that are more
than 10 percent of the total NOX emissions in one of these
subregions, NOX emissions in the top 50 percent among all
States, and/or a majority of its NOX emissions within one of
these subregions.
For the New England States that were not included in any of the
OTAG zero-out subregions, EPA found that two of these States (i.e.,
Massachusetts and Rhode Island) have a high density of NOX
emissions. Also, the trajectory and wind vector analyses indicated that
these States are immediately upwind of nonattainment areas in other
States.
For the nine States in the OTAG region which are wholly within
subregions 10, 11, and 12 (i.e., Florida, Kansas, Louisiana, Minnesota,
Nebraska, North Dakota, Oklahoma, South Dakota, and Texas), and for
Arkansas, Iowa, and Mississippi, EPA proposed that emissions from each
of these States should be considered not to significantly contribute to
downwind nonattainment. These States are further discussed below in
Section II.C.5, States Not Covered by this Rulemaking.
c. Comments and Responses on Proposed Weight-of-Evidence Approach
to Significant Contribution. The EPA received a number of comments on
various elements of the proposed weight-of-evidence approach. In
addition, EPA received new modeling and analyses performed by
commenters which address the issue of significant contribution. The
following is a summary of the major comments received by EPA and the
responses to these comments. Additional comments and EPA's response to
these comments are provided in the Response to Comment document.
Comment: Some commenters stated that it was inappropriate to use a
weight-of-evidence approach to determine the significance of upwind
emissions on downwind nonattainment. Rather, it was argued that EPA
should use a specific ``bright line'' criterion. Other commenters
supported the weight-of-evidence approach.
Response: The magnitude and frequency of contributions from an
upwind State to downwind nonattainment depend on the extent of the
nonattainment problem in the downwind area, the emissions in the
downwind area, the emissions in the upwind State, the distance between
the upwind State and the downwind area, and weather conditions (i.e.,
winds and temperatures which favor ozone formation and transport).
Because these factors vary in a complex way across the OTAG region, it
is not possible to develop a single bright line test for significance
that will be applicable and appropriate for all potential upwind-State-
to-downwind-area linkages. Therefore, EPA believes that it is more
appropriate to use a weight-of-evidence approach to account for all of
these factors than establishing a bright line criterion.
Comment: Some commented that EPA should not use the trajectory,
wind vector, and ``ozone cloud'' analyses as a
[[Page 57384]]
basis for determining significant contribution because these techniques
indicate air movement and do not account for ozone formation and
depletion due to photochemical reactions and other processes. Other
commenters argued in favor of using this information as means of
linking upwind States with downwind nonattainment.
Response: The EPA agrees that information from such techniques
should not be used as the sole basis for finding that certain upwind
States significantly contribute to nonattainment in specific downwind
States. However, EPA believes that it is important to consider the
``movement'' of ozone and/or precursors as part of the air quality
evaluation of contributions from upwind States. This factor is
incorporated into the air quality models used by EPA for this
rulemaking. The inclusion of this information, in conjunction with
numerous other air quality factors in the models, provides for a more
technically robust analysis than can be provided by the trajectory,
ozone cloud, and wind vector analyses alone.
Comment: A number of commenters stated that CAA section
110(a)(2)(D) requires a State-by-State demonstration that emissions
within an upwind State make a significant contribution to nonattainment
in another State and thus, EPA's proposed approach of using subregional
(i.e., multistate) modeling, together with each upwind State's
NOX emissions, to establish these linkages is legally
flawed. These commenters argued that section 110(a)(2)(D) requires
``each implementation plan submitted by a State'' to contain provisions
that prohibit any source or other type of emissions activity ``within
the State'' from emitting air pollutants in amounts that contribute
significantly to a downwind nonattainment problem. The commenters
concluded that these provisions require, as a matter of technical
procedure, that EPA must base its determination that emissions from a
particular State significantly contribute to nonattainment downwind on
a technical analysis of that particular State's emissions. According to
the commenters, section 110(a)(2)(D) by its terms, prohibits EPA from
making that technical determination by examining the impact of
emissions from a group of States on a downwind nonattainment problem,
and then extrapolating from that information to determine whether
emissions from each State within that group should be considered to
make a significant contribution.
As a technical matter, these commenters argue that if emissions
from more than one State are lumped together in assessing the
contribution to a downwind State, there is no way to determine the
amount of emissions in each contributing State that must be reduced.
The commenters argue that the only way to establish specific upwind
State to downwind State linkages is through air quality modeling on a
State-by-State basis. Further, the commenters contend that once an area
beyond a particular State's boundaries is modeled, there is no way of
knowing how much farther upwind to go in terms of defining a source
area. In order to address these issues, many commenters stated that EPA
must do State-by-State zero-out UAM-V modeling and/or State-by-State
source apportionment modeling using the CAMx model to determine
downwind contributions from upwind States.
Response: On the legal issue, EPA disagrees that the above-
referenced provisions of section 110(a)(2)(D), by their terms, mandate
the technical procedure for EPA to make the determination of
significant contribution. These provisions simply indicate that EPA
must make that determination on a SIP-by-SIP basis, that is, for EPA to
issue a SIP call with respect to a particular State, EPA must determine
that the provisions of that SIP fail to adequately control emissions
from sources within the State. However, these provisions do not mandate
any particular technical procedure for making that determination. As a
result, EPA may employ any technical procedure that is sufficiently
accurate. As discussed below, EPA believes that its subregional
approach is sufficiently accurate to justify the SIP call. However, in
response to this and other comments, EPA did conduct State-by-State
modeling. The results of this modeling, as discussed below, confirm the
results of the subregional modeling.
On the technical issue, EPA used the subregional modeling as part
of the proposed approach because OTAG had developed and relied on this
modeling as part of its analysis to quantify the impacts of manmade
emissions in upwind areas on ozone in downwind areas. In addition, in
conjunction with other information, EPA believes that it is possible to
make rational extrapolations from the subregional results in order to
draw conclusions as to the contribution of individual States. The EPA
believes that it is credible to use NOx emissions in each
State, along with the subregional modeling results, in the
determination of significance in view of the results of OTAG modeling
which indicate that, in addition to local emissions, the level of ozone
in a downwind State is directly related to the magnitude of
NOx emissions in upwind areas and the proximity of the
upwind area to the downwind State. A more detailed discussion of the
technical validity of the subregional modeling is contained in the
Response to Comment Document.
The EPA recognizes that State-by-State modeling would provide some
additional precision to the magnitude and frequency of individual
State-to-State contributions. In response to the recommendations for
additional modeling, EPA performed both State-by-State UAM-V zero-out
modeling and State-by-State CAMx source apportionment modeling for many
of the upwind States in the OTAG region which were proposed as
significant contributors. The EPA's analysis of the contributions to
downwind nonattainment using the State-by-State modeling confirms the
overall finding, based on the proposed subregional modeling, that the
23 jurisdictions identified in the proposal significantly contribute to
nonattainment in downwind States. Specifically, the subregional
modeling indicates that manmade emissions from sources in subregions 1
through 9 make large and/or frequent contributions to 1-hour and 8-hour
nonattainment in specific downwind States. The EPA's analysis of the
State-by-State modeling demonstrates that each of the 23 upwind
jurisdictions identified through subregional modeling significantly
contribute to nonattainment in specific downwind States. In addition,
the results of the State-by-State modeling show that the specific
upwind-State-to-downwind-nonattainment linkages indicated by the
subregional modeling are confirmed overall by the State-by-State
modeling. The State-by-State modeling analyses are summarized below and
more fully documented in the Air Quality Modeling TSD.
Comment: The EPA received comments that zero-out modeling
introduces sharp spatial changes in emissions and pollutants along the
edges of the zero-out area. The commenters contend that this is not
credible and provides an incorrect assessment of transport.
Response: The EPA disagrees with this comment, as discussed in the
Response to Comments document. Also, as indicated above, in response to
other comments, EPA has performed CAMx source apportionment modeling
which does not use a zero-out technique for quantifying ozone
contributions from upwind States. In general, EPA has found that the
source apportionment technique and zero-out modeling
[[Page 57385]]
provide consistent information on the relative contribution of upwind
States to downwind nonattainment. In cases where the two techniques do
not provide consistent results, the source apportionment technique
tends to indicate larger contributions than the zero-out modeling. The
differences between these two modeling techniques are described further
in the Air Quality Modeling TSD.
Comment: Some comments referenced a study which analyzed the
``noise'' (i.e., uncertainty) in the UAM-V modeling system. This study
purports to show that the contributions from some States EPA proposed
as significant are within the ``noise'' of the model.
Response: This study focuses on model uncertainty by varying many,
but not all, inputs to the model. The study does not contend that the
inputs selected by OTAG are incorrect, but rather that there may be
other plausible values for these inputs. The results indicate that
there is a range of uncertainty in predicted ozone associated with the
range of possible values for the particular inputs studied by the
commenter. The study does not indicate that there is any bias in the
model's predictions (i.e., there is no indication that the predictions
are too high or too low). The specific values for the inputs being used
by EPA in its air quality modeling are the same values that were used
by OTAG. These values were selected by the OTAG Regional and Urban
Scale Modeling Work Group, which included experts in air quality
modeling from the public and private sector, in conjunction with the
model's developers, Systems Application International. The predictions
from OTAG's model runs using these same input values were evaluated
against ambient measurements and found by OTAG to provide acceptable
results. The EPA continues to believe that the specific inputs selected
by OTAG are technically sound and the modeling results are credible. A
further discussion of EPA's response to this comment is in the Response
to Comments document.
Comment: Several commenters stated that emissions from large point
sources of NOx in specific States do not contribute
significantly to downwind nonattainment.
Response: As discussed in Section II.A.3.c, Definition of
Significant Contribution, under EPA's collective contribution approach,
if emissions in the aggregate from a particular geographic region or
State are found to contribute significantly to nonattainment downwind,
then the emissions in that region or State are considered to be
significant contributors to that nonattainment problem. Moreover, EPA
treats emissions as ``contributing significantly'' only to the extent
they may be eliminated through highly cost-effective reductions. Thus,
if all emissions from a State, when considered in the aggregate, are
found to contribute significantly to nonattainment downwind, and if
there are highly cost-effective controls for NOx emissions
from sources in the upwind State, then the amount of NOx
emissions from these sources that can be eliminated with such controls
are considered to be making a significant contribution. The amount of
emissions determined through this approach to make a significant
contribution may be relatively small, compared to the upwind State's
entire inventory; and the ambient impact downwind of eliminating that
amount may be relatively small as well. However, this small impact does
not mean that the emissions themselves are not significant insofar as
their contribution to nonattainment downwind. Further, as discussed in
Section IV, Air Quality Assessment, when the amount of emissions
required to be eliminated from upwind States are combined and modeled
collectively, their ambient impact downwind is larger.
Comment: One commenter provided a recommendation for dealing with
the concern that the spatial resolution of meteorological inputs to the
air quality model may be too coarse to require that predicted
exceedences correspond exactly with a county violating the NAAQS. The
commenter's recommendations were to base the selection of 1-hour
nonattainment receptors on model predicted exceedences in either (a)
all counties within the metropolitan statistical area containing the
nonattainment area or (b) all counties comprising the designated 1-hour
nonattainment area.
Response: The EPA believes that the appropriate way to address this
issue is to use all counties comprising the designated 1-hour
nonattainment area. That is, all counties in a designated 1-hour
nonattainment area should be considered as possible nonattainment
receptors for the purposes of evaluating contributions to nonattainment
under the 1-hour NAAQS. The EPA recognizes that not all counties within
a designated nonattainment area have monitors, and that some counties
may have monitors that indicate attainment in that county. Even so, EPA
recognizes that under the 1-hour NAAQS, nonattainment boundaries are
generally used to describe an area with the nonattainment problem.
Thus, EPA believes that this geographic vicinity offers the best
indication of an area that may be expected to have nonattainment air
quality somewhere within its boundaries. The EPA believes that it is
appropriate to include all counties in the designated nonattainment
area because the entire nonattainment area is responsible for meeting
the 1-hour NAAQS, even if only one monitor measures nonattainment at
any one time. As noted elsewhere, EPA predicts that many 1-hour
nonattainment areas that currently monitor nonattainment somewhere
within the area will remain in nonattainment in 2007, in some cases
because of predicted violations in counties that currently monitor
attainment. The EPA believes that the entire area should be considered
to be in nonattainment until all monitors in the area indicate
attainment of the NAAQS. Thus, in today's rulemaking, EPA used the
designated 1-hour nonattainment area in selecting the receptors to be
used to evaluate impacts on downwind nonattainment problems.
Comment: Several commenters questioned the validity of EPA's
approach of using the 3-episode average of the second highest 8-hour
daily maximum concentration to represent the form of the 8-hour NAAQS
(i.e., the 3-year average of the fourth highest 8-hour daily maximum
values at a monitor 35). Commenters expressed the concern
that the average second high may not be representative for all areas
across the OTAG domain. However, none of the commenters provided any
suggested alternatives to EPA's approach.
---------------------------------------------------------------------------
\35\ For the purposes of discussion in this Section, these
values are referred to as ``design'' values.
---------------------------------------------------------------------------
Response: The analysis performed by EPA to establish a relationship
between the air quality during the OTAG episodes and the form of the 8-
hour NAAQS was based upon an analysis of 3 years of monitoring data
compared to monitoring data during the OTAG episodes. In response to
comments, EPA performed an analysis to determine how the predicted
average second high 8-hour values, as well as several alternative 8-
hour values, compared to ambient 8-hour design values, based on 1994 to
1996 measured data. Based on this analysis, EPA determined that,
overall, the model-predicted average second high values underestimate
the corresponding ambient design values for those counties in the OTAG
domain with 1994-1996 ambient values >=85 ppb. In addition to the
average second high, EPA also compared six other measures of 8-hour
model predictions to ambient design values. The six other measures
include the highest, second
[[Page 57386]]
highest, third highest, and fourth highest ozone predictions across the
July 1991, 1993, and 1995 episodes; the 3-episode average of the
highest concentrations; and the 3-episode average of the highest,
second highest, and third highest concentrations. The EPA also
developed the same measures using model predictions from all 4 episodes
for comparison to the ambient design values. The results indicate that
none of the alternative measures provides a universal best match to
ambient 8-hour design values in all States. Each of the indicators
overestimates values in some areas and underestimates values in other
areas to a varying extent. Furthermore, the best representation of 8-
hour design values using predictions from the OTAG episodes varies from
State to State. Given that the predicted average second high
underestimates ambient 8-hour design values and that none of the other
8-hour indicators examined by EPA provides a ``best'' match to ambient
values in all cases, EPA has decided to analyze the contributions to 8-
hour nonattainment problems using all 8-hour predictions >=85 ppb. The
EPA believes that this approach is appropriate given that EPA is using
modeling results for the 8-hour NAAQS merely as an indicator of the
likelihood that areas that currently monitor violations of the 8-hour
NAAQS will continue to be nonattainment for the 8-hour NAAQS and/or
have 8-hour maintenance problems in 2007.36 Thus, the air
quality analysis of 8-hour contributions, described below, focuses on
all 8-hour values >=85 ppb.
---------------------------------------------------------------------------
\36\ Similarly, the EPA is also using 1-hour model predictions
>=125 ppb as an indicator that areas currently designated
nonattainment for the 1-hour NAAQS will continue to be nonattainment
for the 1-hour NAAQS in 2007.
---------------------------------------------------------------------------
Comment: Several commenters submitted new State-by-State zero-out
modeling using UAM-V and CAMx source apportionment modeling
purporting to show that contributions from particular upwind States are
insignificant.
Response: The EPA reviewed the commenters' modeling to determine
and assess (a) the technical aspects of the models that were applied;
(b) the types of episodes modeled; (c) the methods for aggregating,
analyzing, and presenting the results; (d) the completeness and
applicability of the information provided; and (e) whether the
technical evidence supports the arguments made by the commenters.
Overall, the modeling submitted by commenters is viewed by EPA as
generally technically credible, although not complete in all cases. The
EPA's ability to fully evaluate and utilize the modeling submitted by
commenters was hampered in some cases because only limited information
on the results was provided. For example, a commenter may have provided
results for only 1 or 2 days in an episode, or for only one of several
episodes with no information presented on the results for the remaining
days or episodes that were modeled. As another example, results were
presented for only the peak ozone day in an episode while greater
contributions may have been predicted on other high ozone days of the
episode. For some of the modeling, the information was only presented
in graphical form which made the results difficult to evaluate in a
quantitative way. Also, in some cases the model predictions were only
presented as episode composite values without information on peak
contributions. The EPA's full assessment of the modeling submitted by
commenters is provided in the Response to Comments document.
In light of the absence of complete information in the modeling
provided by commenters and other comments calling for State-by-State
analyses, EPA decided to perform additional air quality modeling of the
type submitted by commenters in order to consider all of the data
resulting from such model runs. The EPA modeling includes State-by-
State zero-out modeling using UAM-V and State-by-State CAMx
source apportionment modeling.
EPA conducted further analysis of other factors included in the
multi-factor approach for significant contribution. The results of
EPA's consideration of these factors and EPA's modeling are described
next.
3. Analysis of State-specific Air Quality Factors
a. Overall Nature of Ozone Problem (``Collective Contribution'').
As described above, EPA believes that each ozone nonattainment problem
at issue in today's rulemaking is the result of emissions from numerous
sources over a broad geographic area. The contribution from sources in
an upwind State must be evaluated in this context. This ``collective
contribution'' nature of the ozone problem supports the proposition
that the solution to the problem lies in a range of controls covering
sources in a broad area, including upwind sources that cause a
substantial portion of the ozone problem. This upwind share is
typically caused by NOx emissions from sources in numerous States.
States adjacent to the State with the nonattainment problem generally
make the largest contribution, but States further upwind, collectively,
make a contribution that constitutes a large percentage in the context
of the overall problem. As an example to illustrate the overall nature
of the ozone problem, EPA discusses below the ozone problem in the New
York City nonattainment area.
b. Extent of Downwind Nonattainment Problems. For each downwind
area to which an upwind State may be linked, EPA also examined the
extent of the downwind nonattainment problem, including the air quality
impacts of controls required in downwind areas under the CAA, as well
as of controls required or implemented on a national basis. As
indicated elsewhere, EPA determined that a downwind area should be
considered ``nonattainment'' for purposes of section 110(a)(2)(D)(i)(I)
under the 1-hour NAAQS if the area currently (as of the 1994-96 time
period) has nonattainment air quality 37 and if the area is
modeled to have nonattainment air quality in the year 2007, after
implementation of all measures specifically required of the area under
the CAA as well as implementation of Federal measures required or
expected to be implemented by that date. The EPA determined that each
such downwind area had a residual nonattainment problem even after
implementation of all these control measures. The presence of residual
nonattainment is a factor that supports the need to reduce emissions
from upwind sources to allow further progress towards
attainment.38 As an example, the residual nonattainment for
the New York City area is discussed in more detail below.
---------------------------------------------------------------------------
\37\ As explained elsewhere, for the 1-hour standard, EPA based
its determination as to the boundaries of the area with air quality
violating the NAAQS on the boundaries of the area designated as
nonattainment.
\38\ Indeed, the modeling relied on in today's action indicates
that many downwind nonattainment areas carry a residual
nonattainment problem even after implementation of regional
reductions by all the States affected by today's action. Although
not essential to EPA's conclusions, the presence of this
nonattainment problem even after implementation of regional
controls, based on the modeling used in today's rulemaking,
indicates that even further reductions, regionally or locally, would
be needed to assure attainment in those downwind areas.
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[[Page 57387]]
c. Air Quality Impacts of Upwind Emissions on Downwind
Nonattainment. As indicated above, in response to comments, additional
air quality modeling was performed by EPA to confirm the proposed
approach which relied on subregional modeling to quantify the impacts
of emissions from upwind States on nonattainment in downwind areas. The
additional modeling consisted of State-by-State zero-out modeling using
UAM-V and State-by-State source apportionment modeling using the CAMx
Anthropogenic Precursor Culpability Assessment (APCA)
technique.39 A description of these models is contained in
the Air Quality Modeling TSD. Both models are currently being used by
the scientific and regulatory community for air quality assessments.
The EPA is not aware of any information that would indicate that either
model provides more credible predictions than the other. Each modeling
technique (i.e., zero-out and source apportionment) provides a
different technical approach to quantifying the downwind impact of
emissions in upwind States. The zero-out modeling analysis provides an
estimate of downwind impacts by comparing the model predictions from a
Base Case run to the predictions from a run in which the Base Case
manmade emissions are removed from a specific State. In contrast, the
source apportionment modeling quantifies downwind impacts by tracking
formation, chemical transformation, depletion, and transport of ozone
formed from emissions in an upwind source area and the impacts that
ozone has on nonattainment in downwind areas. The EPA ran both models
for all four OTAG episodes (i.e., July 1-11, 1988; July 13-21, 1991;
July 20-30, 1993; and July 7-18, 1995) using the 2007 SIP Call Base
Case emissions. The development of emissions for this Base Case
scenario are described in Section IV, Air Quality Assessment.
---------------------------------------------------------------------------
\39\ For ease of discussion, EPA is using the term ``UAM-V'' to
refer to the UAM-V State-by-State zero-out modeling and the term
``CAMx'' to refer to the CAMx source apportionment modeling.
---------------------------------------------------------------------------
The EPA selected several metrics in order to evaluate the downwind
contributions from emissions in upwind States. The metrics were
designed to provide information on the three fundamental factors for
evaluating whether emissions in an upwind State make large and/or
frequent contributions to downwind nonattainment. These factors are (a)
the magnitude of the contribution, (b) the frequency of the
contribution, and (c) the relative amount of the contribution. The
magnitude of contribution factor refers to the actual amount of
``ppbs'' of ozone contributed by emissions in the upwind State to
nonattainment in the downwind area. The frequency of the contribution
refers to how often the contributions occur and how extensive the
contributions are in terms of the number of grids in the downwind area
that are affected by emissions in the upwind State. The relative amount
of the contribution is used to compare the total ``ppb'' contributed by
the upwind State to the total ``ppb'' of nonattainment in the downwind
area.
As indicated above, two modeling techniques (i.e., UAM-V zero-out
and CAMx source apportionment) were used for the State-by-State
evaluation of contributions. The EPA developed metrics for both
modeling techniques for each of the three factors. However, because of
the differences between the two techniques, some of the metrics used
for the UAM-V modeling and the CAMx modeling are different. The
specific UAM-V and CAMx metrics and how they relate to the three
factors used for the evaluation of contributions are described below.
The EPA examined the contributions from upwind States to downwind
nonattainment for several types of nonattainment receptors.
Nonattainment receptors for the 1-hour analysis include those grid
cells that (a) are associated with counties designated as nonattainment
for the 1-hour NAAQS and (b) have 1-hour Base Case model predictions
>=125 ppb. These grid cells are referred to as ``designated plus
modeled'' nonattainment receptors. Using these receptors, the metrics
were calculated for each 1-hour nonattainment area as well as for each
State. To calculate the metrics by State, all of the 1-hour
nonattainment receptors in that State were pooled
together.40 Table II-1 lists the 1-hour nonattainment areas
that were considered in this analysis, along with the State(s) in which
the nonattainment area is located. In addition to the areas listed in
Table II-1, EPA also evaluated the contributions of upwind States to
ozone concentrations over Lake Michigan because modeled air quality
over the lake can be indicative, under certain weather conditions, of
air quality in portions of the States surrounding the
lake.41
---------------------------------------------------------------------------
\40\ For ease of discussion in this Section, the 1-hour
nonattainment areas and the set of nonattainment receptors pooled
over an entire State are referred to as downwind areas.
\41\ High measured ozone concentrations in portions of Illinois,
Indiana, Michigan, and Wisconsin near the shoreline of Lake Michigan
are often associated with weather conditions which cause ozone
precursor pollutants to be blown offshore over the lake during the
morning, where they can form high ozone concentrations which then
return onshore during ``lake breeze'' wind flows in the afternoon.
Because the size of the grid cells used in the OTAG modeling is
relatively large compared to the spatial scale of the lake breeze,
the high ozone concentrations predicted over the lake may not be
blown back onshore in the model. Since high concentrations over the
lake do, in reality, impact air quality along the shoreline of one
or more of these States, the EPA believes that it is appropriate to
use predicted contributions to ozone over Lake Michigan as a
surrogate for contributions to any one of the surrounding States
(i.e., Illinois, Indiana, Michigan, and Wisconsin).
Table II-1.--1-Hour Nonattainment Areas Evaluated
------------------------------------------------------------------------
Nonattainment area State(s)
------------------------------------------------------------------------
Atlanta...................... Georgia.
Baltimore.................... Maryland.
Birmingham................... Alabama.
Boston/Portsmouth 1.......... Massachusetts, New Hampshire.
Chicago/Milwaukee 2.......... Illinois, Indiana, Wisconsin.
Cincinnati................... Kentucky, Ohio.
Greater Connecticut.......... Connecticut.
Louisville................... Indiana, Kentucky.
Memphis...................... Mississippi, Tennessee.
New York City................ Connecticut, New Jersey, New York.
Philadelphia................. Delaware, Maryland, New Jersey,
Pennsylvania.
Pittsburgh................... Pennsylvania.
Portland..................... Maine.
Rhode Island................. Rhode Island.
Southwestern Michigan 3...... Michigan.
[[Page 57388]]
St. Louis.................... Illinois, Missouri.
Washington, DC............... District of Columbia, Maryland, Virginia.
Western Massachusetts........ Massachusetts.
------------------------------------------------------------------------
\1\ For the purposes of this analysis EPA has combined the Greater
Boston nonattainment area which includes portions of Massachusetts and
New Hampshire, with the Portsmouth, New Hampshire nonattainment area
into a single downwind nonattainment receptor area.
\2\ For the purposes of this analysis EPA has combined the 1-hour
nonattainment counties that are along the shoreline of Lake Michigan
in the States of Illinois, Indiana, and Wisconsin into a single
downwind nonattainment receptor area.
\3\ For the purposes of this analysis EPA has combined the 1-hour
nonattainment counties that are along the shoreline of Lake Michigan
in the State of Michigan into a single downwind nonattainment receptor
area.
For the 8-hour analysis, nonattainment receptors are those grid
cells that (a) are associated with counties currently violating the 8-
hour NAAQS (based on 1994-1996 data) and (b) have 8-hour Base Case
model predictions >=85 ppb. These grid cells are referred to as
``violating plus modeled'' nonattainment receptors. The metrics for the
8-hour contribution analyses were calculated on a State-by-State basis
by pooling together the ``violating plus modeled'' receptors in a
State.
(1) UAM-V State-by-State Modeling. In the UAM-V zero-out model runs
all manmade emissions in a given upwind State were removed from the
Base Case scenario. Each zero-out scenario was run for all 4 episodes
and the ozone predictions in downwind States were then compared to
those from the Base Case run in order to quantify the downwind impacts
of emissions from the upwind State (i.e., the State in which the
manmade emissions were removed). The EPA performed zero-out runs for
the following set of States:
Alabama, Georgia, Illinois, Indiana, Kentucky,
Massachusetts, Michigan, Missouri, North Carolina, Ohio, South
Carolina, Tennessee, Virginia, West Virginia, and Wisconsin.
Zero-out modeling for Massachusetts was performed because this
State was the only State in the Northeast with relatively large
NOX emissions that was not included in any of the OTAG
subregional modeling. The other States listed above were selected for
zero-out modeling in order to respond to comments that emissions in all
or portions of each of these States do not contribute significantly to
downwind nonattainment.
The EPA analyzed the model-predicted ozone concentrations from the
zero-out runs using the four metrics described below. The results for
these metrics are too voluminous to include in the notice in their
entirety. The full set of results is contained in the Air Quality
Modeling TSD. Each metric was calculated using 1-hour daily maximum
concentrations >=125 ppb as well as 8-hour daily maximum concentrations
>=85 ppb. Model predictions from all 4 episodes were used for
calculating the metrics.42
---------------------------------------------------------------------------
\42\ Model predictions from the first few days of each episode
are considered ``ramp-up'' days and were excluded from the analysis,
following the procedures adopted by OTAG. The ramp-up days include
the first 3 days of the July 1988, 1991, and 1995 episodes and the
first 2 days of the July 1993 episode.
---------------------------------------------------------------------------
UAM-V Metric 1: Exceedences. This metric is the total number of
predicted concentrations exceeding the NAAQS (i.e. 1-hour values >=125
ppb and 8-hour values >=85 ppb) within the downwind area. In
calculating this metric, EPA summed the number of occurrences of values
above the applicable standard (i.e., 1-hour or 8-hour) for all
nonattainment receptors within the downwind area. For example, in
Downwind Area #1 there are five 1-hour ``designated plus modeled''
nonattainment receptors. For this downwind area, the Base Case value
for Metric 1 is calculated by first counting the number of days, across
all four episodes, that had 1-hour daily maximum values >=125 ppb at
each of the five receptors. The result is the total number of
exceedences at each receptor over all days in all four episodes. The
total number of exceedences at each receptor is then summed across all
five receptors to produce the total number of exceedences in Downwind
Area #1, which is the value for Metric 1 for this area.
UAM-V Metric 2: Ozone Reduced--ppb. This metric shows the magnitude
and frequency of the ``ppb'' impacts from each upwind State on ozone
concentrations in each downwind area. These impacts are quantified by
calculating the difference in ozone concentrations between the zero-out
run and the Base Case. The results are then tabulated in terms of the
number of ``impacts'' within six concentration ranges: >=2 to 5 ppb,
>=5 to 10, >=10 to 15, >=15 to 20, >=20 to 25, and >=25 ppb. The
impacts for 1-hour daily maximum values and 8-hour daily maximum values
are determined by tallying the total ``number of days and grid cells''
>=125 ppb or >=85 ppb that receive contributions within the
concentration ranges. In the analysis of contributions, as described
below, the data from Metric 2 are used in conjunction with Metric 1 to
determine the percent of the exceedences in the downwind area that
receive contributions of >=2 ppb, >= 5 ppb, >=10, ppb, etc. The maximum
``ppb'' impact within the downwind area is also calculated.
UAM-V Metric 3: Total ppb Reduced. This metric quantifies the total
ppb contributed in the downwind area from an upwind State, not
including that portion of the contribution that occurs below the level
of the NAAQS. For 1-hour concentrations, Metric 3 is calculated by
taking the difference between the Base Case predictions in each
nonattainment receptor and either (a) the corresponding value in the
zero-out run, or (b) 125 ppb, whichever is greater (i.e., 125 ppb or
the prediction in the zero-out run). The Base Case vs. zero-out
differences are summed over all days and across all nonattainment
receptors in the downwind area. The calculation of this metric is
illustrated by the following example. If the Base Case 1-hour daily
maximum ozone prediction is 150 ppb and the corresponding value from
the zero-out run is 130 ppb, then the difference used in this metric is
20 ppb. However, if the value from the zero-out run is 115 ppb, then
the difference used in this metric is 25 ppb (i.e., 150 ppb-125 ppb,
because 115 ppb is less than 125 ppb).
For analyzing the contributions using Metric 3, the values of this
metric are compared to the total amount of ozone above the NAAQS (i.e.,
125 ppb, 1-hour or 85 ppb, 8-hour) in the Base Case. This baseline
measure of the ``total amount of nonattainment'' (i.e., the total
``ppb'' of ozone that is above the NAAQS) is calculated by summing the
``ppb'' values in the Base Case that are above the level of the NAAQS.
The total contribution from an upwind State to a particular downwind
area calculated by Metric 3 is expressed in relation to the
[[Page 57389]]
amount that the downwind area is in nonattainment. For example, if
Upwind State #1 contributes a total of 50 ppb >=125 ppb to Downwind
Area #2 and the total Base Case ozone >=125 ppb in Downwind Area #2 is
500 ppb, then the contribution from Upwind State #1 (i.e., 50 ppb) to
Downwind Area #2 is equivalent to 10 percent of Downwind Area #2's
nonattainment problem (i.e., 50 ppb divided by 500 ppb, times 100).
UAM-V Metric 4: Population-Weighted Total ppb Reduced. This metric
is similar to the ``Total ppb Reduced'' metric except that the
calculated contributions are weighted by (i.e., multiplied by)
population. In calculating this metric, the ``ppb'' contributions are
determined for each nonattainment receptor, then summed across all
nonattainment receptors in a particular downwind area. During this
calculation, the population in the nonattainment receptor is multiplied
by the total contribution in that receptor (i.e., grid cell) and then
this value is added to the corresponding values for the other receptors
in the downwind area. The results for this metric are expressed
relative to the population-weighted Base Case amount similar to the
approach followed with Metric 3, as described above.
(2) CAMx Source Apportionment Modeling. In the CAMx modeling, the
source apportionment technique was used to calculate the contributions
from upwind States to ozone concentrations above the NAAQS in downwind
areas. Due to computational constraints, it was not possible for EPA to
treat each State in the OTAG region as a separate source area. Several
of the smaller States in the Northeast were grouped together as were
seven States in the far western portion of the region. The following
States were treated as individual source areas:
Alabama, Florida, Georgia, Illinois, Indiana, Iowa,
Kentucky, Louisiana, Maine, Massachusetts, Michigan, Mississippi,
Missouri, New Jersey, New York, North Carolina, Ohio, Pennsylvania,
South Carolina, Tennessee, Texas, Virginia, West Virginia, and
Wisconsin.
The following States were grouped together:
Connecticut and Rhode Island were combined; Maryland,
Delaware and the District of Columbia were combined; New Hampshire and
Vermont were combined; and Arkansas was combined with the portions of
Oklahoma, Kansas, Minnesota, Nebraska, North Dakota, and South Dakota
that lie within the OTAG region.
The contributions from each of these source areas to downwind
nonattainment were evaluated using four metrics. As indicated above,
the CAMx metrics are calculated for the same types of nonattainment
receptors as the UAM-V zero-out metrics. The CAMx metrics are
calculated in a way that is different from the metrics used for the
zero-out runs in large part because of the differences between the two
techniques. The zero-out modeling calculates contributions using the
difference in predictions between two model runs (i.e., a Base Case and
a State-specific zero-out run). In contrast, the CAMx source
apportionment technique calculates contributions by internally tracking
ozone formed from emissions in each source area. In raw form, the
source apportionment technique produces a ``ppb'' contribution from
each source area to hourly ozone in each receptor grid cell. The
individual hourly ``ppb'' contributions were treated in the way
described below to calculate 1-hour and 8-hour values for the four
metrics. The approach was based on recommendations to EPA by Environ,
the developers of CAMx. For 1-hour concentrations the metrics are
calculated based on contributions to all hourly predictions >=125 ppb.
For 8-hour concentrations, the metrics are calculated based on the
contribution to every 8-hour period in a day with an average
concentration >=85 ppb. In order to provide a link to the way 1-hour
and 8-hour concentrations were treated for the zero-out runs, EPA also
calculated the CAMx metrics for 1-hour daily maximum values >=125 ppb
and 8-hour daily maximum values >=85 ppb. 43 The full set of
results for all of the CAMx metrics is contained in the Air Quality
Modeling TSD.
---------------------------------------------------------------------------
\43\ As described in the Air Quality Modeling TSD, the metrics
calculated using the hourly contributions >= 125 ppb are consistent
with the metrics calculated using 1-hour daily maximum contributions
>= 125 ppb. Similarly, the metrics calculated using all 8-hour
periods >= 85 ppb are consistent with the metrics calculated using
8-hour daily maximum values >= 85 ppb.
---------------------------------------------------------------------------
The CAMx Metrics 1 and 2 provide information on the magnitude and
frequency of contributions in a form that is similar to UAM-V Metrics 1
and 2.
CAMx Metric 3: Highest Daily Average Contribution. This metric is
the highest daily average ozone ``ppb'' contribution from each upwind
source area to each downwind nonattainment receptor area over all days
modeled in all four episodes. The following example illustrates how
this metric is calculated for 1-hour ozone concentrations. Similar
procedures are followed for calculating this metric for 8-hour
concentrations. First, the hourly ``ppb'' contributions from a
particular upwind source area to each nonattainment receptor in a
downwind area are summed across all receptors in the downwind area.
This total daily contribution is then divided by the number of hours
and grid cells >=125 ppb in the downwind area to determine the daily
average ``ppb'' contribution. This calculation is performed on a day by
day basis for each day in the 4 episodes. After the average
contributions are calculated for each day, the highest daily average
value across all episodes is selected for analysis. In addition, the
highest daily average contribution is expressed as a percent of the
downwind area's average ozone >=125 ppb. That is, the highest daily
average ``ppb'' contribution is divided by the average of the ozone
concentrations >=125 ppb on that day (i.e., the day on which the
highest average ppb contribution occurred). For example, if the highest
daily average contribution from an upwind State to nonattainment
downwind is 15 ppb and the average of the hourly ozone values >=125 ppb
on this day in the downwind area is 150 ppb, then the 15 ppb
contribution, expressed as a percent, is 10 percent.
CAMx Metric 4: Percent of Total Manmade Ozone Contribution. This
metric represents the total contribution from emissions in an upwind
State relative to the total ozone for all hours above the NAAQS in the
downwind area. This metric, which is referred to as the ``average
contribution,'' is calculated for each episode as well as for all four
episodes combined. The following example is used to illustrate how this
metric is calculated for a single episode for a particular downwind
area. In step 1, all predicted Base Case hourly values >=125 ppb in the
downwind area are summed over all nonattainment receptors and all days
in an episode. In step 2, the ``ppb'' contributions from a source area
to this downwind area are summed over all nonattainment receptors in
the downwind area and all days in the episode to yield a total ppb
contribution. The total contribution calculated in Step 2 is then
divided by the total ozone >=125 ppb in the downwind area to produce
the fraction of ozone >=125 ppb in the downwind area that is due to
emissions from the upwind source area. This fraction is multiplied by
100 to express the result as a percent.
4. Confirmation of States Making a Significant Contribution to Downwind
Nonattainment
In the proposal, EPA made findings of significant contribution
based on a
[[Page 57390]]
weight-of-evidence approach that included consideration of air quality
contributions based on subregional modeling. As discussed in section
II.C.2, Summary of Notice of Proposed Rulemaking Weight-of-Evidence
Approach, EPA believes that the subregional modeling provides an
adequate independent basis for determining which States contribute
significantly to downwind nonattainment. The evaluation of the State-
by-State modeling confirms the overall findings that were based on the
subregional modeling and provides more refined information regarding
the impacts of specific upwind States on nonattainment in individual
downwind areas. This State-by-State modeling is discussed in more
detail below.
a. Analysis Approach. The EPA has analyzed the results of the
State-by-State UAM-V zero-out modeling and the State-by-State CAMx
source apportionment modeling for each of the 23 jurisdictions for
which this modeling is available.44 Both UAM-V and CAMx
modeling results are available for fifteen States (i.e., Alabama,
Georgia, Illinois, Indiana, Kentucky, Massachusetts, Michigan,
Missouri, North Carolina, Ohio, South Carolina, Tennessee, Virginia,
West Virginia, and Wisconsin). For an additional eight States (i.e.,
Connecticut, Delaware, the District of Columbia, Maryland, New Jersey,
New York, Pennsylvania, and Rhode Island), CAMx modeling is available.
Also, as noted above in Section II.C.3, State-by-State Air Quality
Modeling, Connecticut and Rhode Island were combined as a single source
area, and Maryland, the District of Columbia, and Delaware were also
combined as a single source area. Because the NOX emissions
and/or NOX emissions density is large in each jurisdiction
within both of these combined source areas, EPA believes that the
downwind contributions from these combined source areas can be
attributed to each jurisdiction within the source area.
---------------------------------------------------------------------------
\44\ The approach for dealing with the 15 States in the OTAG
domain which were not proposed to make a significant contribution to
downwind nonattainment are discussed below in Section II.C.5, States
Not Covered by this Rulemaking.
---------------------------------------------------------------------------
For the 1-hour NAAQS, EPA evaluated downwind impacts in two ways
using the factors described in Section II.C.3, State-by-State Air
Quality Modeling. First, EPA evaluated the contributions from each
upwind State to nonattainment in each downwind State. Second, the EPA
evaluated the contributions from each upwind State to nonattainment in
each downwind 1-hour nonattainment area. In downwind States which only
contain a single intrastate nonattainment area (e.g., Atlanta), the
results of the downwind State and downwind nonattainment area analyses
are the same because the same nonattainment receptors are used in both
cases. For the 8-hour NAAQS, EPA evaluated the contributions from
upwind States to 8-hour nonattainment in each downwind State.
The EPA used the following process in determining whether a
particular upwind State contributes significantly to 1-hour
nonattainment in an individual downwind area. First, EPA reviewed the
extent of the nonattainment problem in the downwind area using ambient
design values and model predictions of future ozone concentrations
after the application of (a) 2007 Base Case controls, (b) additional
local NOX reductions, and (c) regional reductions
(additional local plus upwind NOX reductions).45
As indicated above, EPA determined that each downwind area had a
residual nonattainment problem even after implementation of the control
measures in the 2007 Base Case.
---------------------------------------------------------------------------
\45\ Scenarios (b) and (c) refer to the runs used to assess
transport as described in Section IV.
---------------------------------------------------------------------------
Second, using the information from CAMx Metric 4 46, EPA
reviewed (a) the relative portion of the ozone problem in each downwind
area that is due to ``local'' emissions (i.e., emissions from the
entire State or States in which the downwind area is located), (b) the
total contribution from all upwind emissions (i.e., the sum of the
contributions from manmade emissions in all upwind States, combined),
and (c) the contribution from manmade emissions in individual upwind
States. The local versus upwind contributions for each downwind area
are provided in the Air Quality Modeling TSD. The EPA analyzed this
information to determine whether upwind emissions are an important part
of the downwind areas' nonattainment problem. In general, the data
indicate that, although a substantial portion of the 1-hour
nonattainment problem in many of the downwind areas is due to local
emissions, a substantial portion of the nonattainment problem is also
due to emissions from upwind States. In addition, for most upwind-
State-to-downwind-area linkages there is no single upwind State that
makes up all of the upwind contribution. Rather, the total contribution
for all upwind States combined is comprised of individual contributions
from a number of upwind States many of which are relatively similar in
magnitude such that there is no ``bright line'' which distinguishes
between the contributions from most of the individual upwind States.
---------------------------------------------------------------------------
\46\ This information represents the average contributions
across all four episodes. In addition to the four-episode average
contribution, EPA also examined the highest single-episode average
contribution from each upwind State to each downwind area.
---------------------------------------------------------------------------
Third, EPA determined whether each individual upwind State
significantly contributes to nonattainment in a particular downwind
area using the UAM-V and CAMx metrics to evaluate three aspects, or
factors of the contribution.47 These factors include the
magnitude, frequency, and relative amount of the contribution. The
specific UAM-V and CAMx metrics which correspond to each of the factors
are identified in Table II-2. As indicated in the table, there is at
least one metric from each modeling technique that corresponds to each
of the three factors.
---------------------------------------------------------------------------
\47\ The factors used to interpret the metrics should not be
confused with the multi-factor approach used to identify the amounts
of NOX emissions that contribute signficantly to
nonattainment.
Table II-2.--Metrics Associated With Each Contribution Factor
------------------------------------------------------------------------
Factor UAM-V CAMx
------------------------------------------------------------------------
Magnitude of Contribution... Maximum ``ppb'' Maximum ``ppb''
contribution Contribution
(Metric 2) (Metric 2); and
Highest Daily
Average
Contribution
(Metric 3).
Frequency of Contribution... Number and percent Number and percent
of exceedences with of exceedences with
contributions in contributions in
various various
concentration concentration
ranges (Metric 1 ranges (Metric 1
and 2) and 2).
Relative Amount of Total ``ppb'' Four-episode average
Contribution. contribution percent
relative to the contribution from
total ``ppb'' that the upwind State to
the downwind area nonattainment in
is above the NAAQS the downwind area
(Metric 3); and (Metric 4); and
Total population- Highest single-
weighted ``ppb'' episode average
contribution percent
relative to the contribution from
total population- the upwind State to
weighted ``ppb'' nonattainment in
that the downwind the downwind area
area is above the (Metric 4).
NAAQS (Metric 4)
------------------------------------------------------------------------
[[Page 57391]]
It should be noted that the relative contributions of individual
upwind States to a particular downwind area add up to 100 percent for
the CAMx 4-episode average percent contribution. However, this is not
the case for the CAMx highest single-episode average percent
contribution since the value from one upwind State can occur in a
different episode than the value from another upwind State for the same
downwind area. In addition, it should be noted that UAM-V Metrics 3 and
4 are used in combination to express the total contribution above the
NAAQS relative to the total amount that the downwind area is above the
NAAQS. The values for each of these metrics also do not add up to 100
percent when considering contributions from multiple upwind States to
an individual downwind area.
The EPA compiled the UAM-V and CAMx metrics by downwind area in
order to evaluate the contributions to downwind nonattainment. The data
on 1-hour and 8-hour contributions were compiled and analyzed
separately. The data were reviewed to determine how large of a
contribution a particular upwind State makes to nonattainment in each
downwind area in terms of the magnitude of the contribution and the
relative amount of the total contribution. The data were also examined
to determine how frequently the contributions occur.
The first step in evaluating this information was to screen out
linkages for which the contributions were very low, as described in the
Air Quality Modeling TSD. The finding of significance for linkages that
passed the initial screening criteria was based on EPA's technical
assessment of the values for the three contribution factors. Each
upwind State that had large and/or frequent contributions to the
downwind area, based on these factors, is considered as contributing
significantly to nonattainment in the downwind area. The EPA believes
that each of the factors provides an independent legitimate measure of
contribution. However, there had to be multiple factors that indicate
large and/or frequent contributions in order for the linkage to be
significant. In this regard, the finding of a significant contribution
for an individual linkage was not based on any single factor.
For many of the individual linkages the factors yield a consistent
result (i.e., either large and/or frequent contributions or small and/
or infrequent contributions). In some cases, however, not all of the
factors are consistent. For upwind-downwind linkages in which some of
the factors indicate high and/or frequent contributions while other
factors do not, EPA considered the overall number and magnitude of
those factors that indicate large and/or frequent contributions
compared to those factors that do not. Based on an assessment of all
the factors in such cases, EPA determined that the upwind State
contributes significantly to nonattainment in the downwind area if on
balance the factors indicate large and/or frequent contributions from
the upwind State to the downwind area.
The EPA's evaluation of the contributions to 1-hour nonattainment
in New York City is presented as an example to illustrate this process.
The New York City area, which consists of portions of New York, New
Jersey, and Connecticut, is designated as a severe nonattainment area
under the 1-hour NAAQS. The ambient 1-hour design value in New York
City, based on 1994 through 1996 monitoring data is 144 ppb. During the
four OTAG episodes, 39 percent of the days are predicted to have 1-hour
exceedences in 2007 after the implementation of all CAA controls and
Federal measures.48 Moreover, EPA's air quality modeling of
the benefits of regional NOX strategies, as described in
Section IV, Air Quality Assessment, indicates that there would still be
exceedences of the 1-hour NAAQS remaining in New York City even with
eliminating the significant amounts of emissions required by this
NOX SIP Call.
---------------------------------------------------------------------------
\48\ This is further described in the Air Quality Modeling TSD.
---------------------------------------------------------------------------
In the assessment of contributions to New York City, EPA examined
the local versus upwind contributions to 1-hour nonattainment in this
area, as shown in Table II-3. Local emissions in the New York City
nonattainment area are spread among numerous stationary sources, area
sources, highway sources, and nonroad sources, each of which
contributes only a very small, indeed sometimes immeasurable, amount to
New York City's ozone nonattainment problem. Combined, these emissions
result in approximately 55 percent of the New York City area's ozone
problem. Emissions from States upwind of New York, New Jersey, and
Connecticut, on average across all four episodes, contribute 45 percent
of the nonattainment problem in New York City is due to. However, no
single State stands out as contributing most of the total upwind
contribution. The biggest single contributor is Pennsylvania (18
percent) followed by Maryland/Washington, DC/Delaware (5 percent). The
total contribution from all Northeast States is 23 percent. A similar
amount (22 percent) of the total contribution is due to emissions in
those States outside the Northeast. The data in Table II-3 indicate
that 19 percent of the 22 percent is fairly evenly divided among ten
States, whose contributions range from 1 percent (6 States) to 4
percent (Ohio and Virginia). The remaining 3 percent (i.e., 19 percent
vs 22 percent) is from States that each contribute less than 1 percent,
on average. The highest single-episode contributions from States upwind
of the Northeast range from 1 percent (Tennessee) to 8 percent
(Virginia). In general, the contribution data in Table II-3 indicate
that a substantial amount of New York City's nonattainment problem is
due to the collective contribution from emissions in a number of upwind
States both within and outside the northeast. That these upwind
contributions are a meaningful part of New York City's nonattainment
problem is particularly evident in light of the fact that the
contribution to the problem made by New York City itself is comprised
of the collective contribution of numerous sources.
Table II-3.--Percent Contribution From Upwind States to 1-Hour Nonattainment in New York City \1\
----------------------------------------------------------------------------------------------------------------
Percent of
total manmade Highest single-
Downwind area: New York City emissions over episode percent
4 episodes contribution
-------------------------------------------------------------------------------------------------------\2\------
Amount due to ``Local'' Emissions \3\.......................................... 55 \4\NA
Total Amount from all ``Upwind'' States........................................ 45 NA
Contributions from Individual Upwind States.................................... .............. ...............
PA............................................................................. 18 19
MD/DC/DE....................................................................... 5 6
[[Page 57392]]
OH............................................................................. 4 6
VA............................................................................. 4 8
WV............................................................................. 3 7
IL............................................................................. 2 3
IN............................................................................. 1 2
KY............................................................................. 1 3
MI............................................................................. 1 4
MO............................................................................. 1 2
NC............................................................................. 1 2
TN............................................................................. 1 1
Total Amount from All Other States, combined................................... 3 NA.
----------------------------------------------------------------------------------------------------------------
\1\ These values are based on CAMx Metric 3 calculated across all 4 episodes.
\2\ These values are based on CAMx Metric 3 calculated for each episode individually. These values do not add up
to 100 percent.
\3\ 3. Total contribution from the State(s) in which the Nonattainment area is located.
\4\ 4. Not applicable.
The extent of New York City's nonattainment problem and the nature
of the contributions from upwind States were considered in determining
whether the values of the metrics indicate large and/or frequent
contributions for individual upwind States. Specifically, additional
controls beyond the local and upwind NOX reductions which
are part of the regional NOX strategy may be needed to solve
New York City's 1-hour nonattainment problem. Also, the total
contribution from all upwind States is large and there is no single
State or small number of States which comprise this total upwind
portion. In this regard, the contributions to New York City from some
States may not appear to be individually ``high'' amounts. However, (as
described below) these contributions, when considered together with the
contributions from other States (i.e., the collective contribution)
produce a large total contribution to nonattainment in New York City.
The EPA evaluated the magnitude, frequency, and relative amount of
contribution from emissions in individual upwind States to determine
which States contribute significantly to 1-hour nonattainment in New
York City. The UAM-V and CAMx metrics which quantify each upwind
State's contribution to New York City for each of the three factors are
provided in the Air Quality Modeling TSD and described below.
Examination of the values for these metrics indicates that the upwind
States can be divided into three general groups, based on the
magnitude, frequency, and relative amount of contribution. The first
group contains those upwind States for which the UAM-V and CAMx metrics
all clearly indicate a significant contribution to 1-hour nonattainment
in New York City. The second group contains those States for which the
CAMx and UAM-V metrics are not quite as consistent, but overall the
metrics indicate a significant contribution to 1-hour nonattainment in
New York City.49 The third group contains those States for
which the CAMx and UAM-V metrics clearly indicate that the impacts do
not make a significant contribution to New York City.
---------------------------------------------------------------------------
\49\ For New York City, each of the ``Group 2'' States were
found to make a significant contribution. However, this was not the
case for all of the Group 2 linkages in other nonattainment areas.
For example, the contribution from Kentucky to Philadelphia and the
contribution from Tennessee to Baltimore were Group 2 situations in
which EPA determined that the contributions were not significant.
---------------------------------------------------------------------------
Group 1 Upwind States:
The CAMx and UAM-V metrics all clearly indicate that emissions from
Maryland/Washington, DC/Delaware, Ohio, Pennsylvania, Virginia, and
West Virginia make large and/or frequent contributions to 1-hour
nonattainment in New York City. For Pennsylvania the magnitude of
contribution, as indicated by the highest daily average contribution
(CAMx Metric 3), is 25 ppb and the relative amount of contribution is
18 percent (CAMx Metric 4). For the other upwind areas, the magnitude
of the contributions range from 9 ppb to 15 ppb (CAMx Metric 3, highest
daily average contributions) with contributions in the range of 5 ppb
to 10 ppb--from Ohio, Virginia, and West Virginia (UAM-V Metric 2,
maximum ``ppb'' contribution). In terms of the frequency of the
contribution, 7 percent to 11 percent of the total number of grid-hours
>=125 ppb in New York City receive contributions of 10 ppb from each of
these States (CAMx Metric 1 and 2). Also, the relative amounts of the
contribution are in the range of 6 percent to 8 percent (CAMx Metric 4,
highest single-episode average percent contribution) and the total
contribution from each of three States (i.e., Ohio, Virginia, and West
Virginia) is large compared to the total amount of nonattainment,
ranging from 8 percent to 11 percent (UAM-V Metric 3).
Group 2 Upwind States:
The CAMx and UAM-V metrics are somewhat less consistent on the
extent of contributions from each of 5 States: Kentucky, Illinois,
Indiana, Michigan, and North Carolina. None of the metrics for either
model indicate extremely low or extremely high contributions. Rather,
for these States most of the metrics indicate relatively high
contributions while a few metrics indicate relatively low
contributions. The rationale used by EPA for evaluating the
contributions from these States involved comparing and contrasting each
piece of data for these States on an individual ``upwind State-by-
upwind State'' basis and as a group (i.e., for all 5 States, together)
in order to weigh the relative magnitude and frequency of the
contributions for making a determination of significance.
UAM-V Metrics--For each of these 5 States the ``weakest'' factor is
the magnitude contribution (UAM-V Metric 2) in that the highest
contributions are in the range of 2 to 5 ppb. The other UAM-V Metrics,
however, indicate that the contributions from each State are of a
larger frequency and relative amount. Specifically, four of these
States (Kentucky, Indiana, Illinois, and
[[Page 57393]]
Michigan) each contribute 2 to 5 ppb to as many as 3 percent to 4
percent of the exceedences in New York City (UAM-V Metrics 1 and 2).
While North Carolina contributes to somewhat fewer exceedences (2
percent), this slight weakness is out-weighed by the relative amount of
contribution (UAM-V Metrics 3 and 4) which indicates that the total
contribution from North Carolina alone is equivalent to 3 percent of
the total ``ppb'' >=125 ppb and 4 percent of the population-weighted
``ppb'' >=125 ppb in New York City. For Indiana, Illinois, and Michigan
the relative amount of contribution (UAM-V Metrics 3 and 4) is also
relatively high and ranges from 3 percent to 5 percent. The relative
amount of contribution from Kentucky is somewhat weaker at 2 percent.
CAMx Metrics--For Illinois, all of the CAMx metrics indicate
relatively large and/or frequent contributions, as described below. For
Kentucky, Indiana, Michigan, and North Carolina the magnitude of
contribution is large, as indicated by the maximum contribution which
ranges from 6 ppb (Indiana) to 11 ppb (North Carolina). Also, the
highest daily average contribution from Kentucky, Michigan, and North
Carolina are all in the range of 5 ppb to 7 ppb. In terms of the
frequency of contribution, Indiana and North Carolina contribute in the
range of 5 ppb to 10 ppb to 3 percent and 6 percent of the exceedences,
respectively, in New York City. For Kentucky, Indiana, Michigan, and
North Carolina the relative amounts of contribution is somewhat mixed
in that the 4-episode average percent contribution is only 1 percent,
but the highest single-episode average percent contributions are higher
at 2 percent from both Indiana and North Carolina, 3 percent from
Kentucky, and 4 percent from Michigan (CAMx Metric 4).
Overall contributions considering UAM-V and CAMx Metrics--
Considering the CAMx and UAM-V metrics, as described below, the
majority of the contribution factors indicate that, overall, each of
the Group 2 States contributes significantly to 1-hour nonattainment in
New York City.
Kentucky--
Metrics indicating relatively high and/or frequent contributions:
--Magnitude of Contribution: the maximum contribution from CAMx is 9
ppb (CAMx Metric 2) and highest daily average contribution is 7 ppb
(CAMx Metric 3);
--Frequency of Contribution: 4 percent of the exceedences receive
contributions of more than 2 ppb (UAM-V Metrics 1 and 2); and
--Relative Amount of Contribution: the highest single-episode average
contribution is 3 percent (CAMx Metric 4).
Metrics indicating relatively low and/or infrequent contributions:
--Magnitude of Contribution: the maximum contribution from UAM-V is 2
ppb; and
--Relative Amount of Contribution: the 4-episode average percent
contribution is 1 percent (CAMx Metric 4).
Indiana--
Metrics indicating relatively high and/or frequent contributions:
--Magnitude of Contribution: the maximum ``ppb'' contribution is 6 ppb
(CAMx Metric 2);
--Frequency of Contribution: 4 percent of the exceedences receive
contributions of more than 2 ppb (UAM-V Metrics 1 and 2) ; and
--Relative Amount of Contribution: the total ``ppb'' contribution is
equivalent to 3 percent of total amount of nonattainment (UAM-V Metric
3).
Metrics indicating relatively low and/or infrequent contributions:
--Magnitude of Contribution: the maximum contribution from is 2 ppb
(UAM-V Metric 2); and
--Relative Amount of Contribution: the 4-episode average percent
contribution is 1 percent (CAMx Metric 4).
Illinois--
Metrics indicating relatively high and/or frequent contributions:
--Magnitude of Contribution: the maximum contribution is 8 ppb (CAMx
Metric 2); the highest daily average contribution is 6 ppb;
--Frequency of Contribution: 3 percent of the exceedences receive
contributions of more than 2 ppb; and
--Relative Amount of Contribution: the highest single-episode average
contribution is 3 percent (CAMx Metric 4); the total ``ppb''
contribution is equivalent to 3 percent of total amount of
nonattainment.
Metrics indicating relatively low and/or infrequent contributions:
--Magnitude of Contribution: the maximum contribution from UAM-V is 2
ppb.
Michigan--
Metrics indicating relatively high and/or frequent contributions:
--Magnitude of Contribution: the maximum contribution is 7 ppb (CAMx
Metric 2); the highest daily average contribution is 5 ppb (CAMx Metric
3);
--Frequency of Contribution: 3 percent of the exceedences receive
contributions of more than 2 ppb (UAM-V Metrics 1 and 2); and
--Relative Amount of Contribution: the highest single-episode average
contribution is 4 percent (CAMx Metric 4); the total ``ppb''
contribution is equivalent to 3 percent of the total amount of
nonattainment.
Metrics indicating relatively low and/or infrequent contributions:
--Magnitude of Contribution: the maximum contribution from UAM-V is 2
ppb
--Frequency of Contribution: 1 percent of the exceedences receive
contributions of 5 ppb or more (CAMx Metrics 1 and 2); and
--Relative Amount of Contribution: the 4-episode average percent
contribution is 1 percent (CAMx Metric 4).
North Carolina--
Metrics indicating relatively high and/or frequent contributions:
--Magnitude of Contribution: the maximum contribution is 11 ppb (CAMx
Metric 2); the highest daily average contribution is 6 ppb (CAMx Metric
3);
--Frequency of Contribution: 6 percent of exceedences receive
contributions of 5 ppb or more (CAMx Metrics 1 and 2); and
--Relative Amount of Contribution: the total ``ppb'' contribution is
equivalent to 3 percent of total amount of nonattainment.
Metrics indicating relatively low and/or infrequent contributions:
--Relative Amount of Contribution: the 4-episode average percent
contribution is 1 percent (CAMx Metric 4).
Group 3 Upwind States: The CAMx and UAM-V metrics clearly indicate
that the emissions from the following States do not make large and/or
frequent contributions to 1-hour nonattainment in New York City:
Alabama, Georgia, Massachusetts, Missouri, South Carolina, Tennessee,
and Wisconsin. The rationale for this conclusion is as follows:
--Magnitude of Contribution: all of these upwind States individually
contribute less than 2 ppb to 1-hour daily maximum exceedences in New
York City (UAM-V Metric 2); the highest daily average contribution was
1 ppb or less from Alabama, Georgia, and Massachusetts, and 2
[[Page 57394]]
ppb from South Carolina, Tennessee, and Wisconsin (CAMx Metric 3); and
--Relative Amount of Contribution: the 4-episode average contributions
from Alabama, Georgia, Massachusetts, South Carolina, and Wisconsin are
less than 1 percent (CAMx Metric 4); the total contributions from
Missouri and Tennessee are each equivalent to 1 percent of the total
amount of nonattainment in New York City (UAM-V Metric 3).
Based on the preceding evaluation, EPA believes that emissions in
each of the following twelve jurisdictions contribute significantly to
1-hour nonattainment in the New York City nonattainment area: the
District of Columbia, Delaware, Illinois, Indiana, Kentucky, Maryland,
Michigan, North Carolina, Ohio, Pennsylvania, Virginia, and West
Virginia.
b. States Which Contain Sources That Significantly Contribute to
Downwind Nonattainment. The results of EPA's assessment of the State-
by-State UAM-V and CAMx modeling confirms the findings based on
subregional modeling that the 23 jurisdictions contribute large and/or
frequent amounts to downwind nonattainment under both the 1-hour and 8-
hour NAAQS and forms an independent basis for those findings. The
specific upwind States which significantly contribute to nonattainment
in specific downwind States are listed in Tables II-4 and II-5 for the
1-hour NAAQS and Table II-6 and Table II-7 for the 8-hour NAAQS. The
information on the 1-hour contribution linkages are presented by upwind
State in Table II-4 and by downwind State in Table II-5. In Table II-4
the upwind States are each listed in the first column and the downwind
States to which each upwind State contributes significantly are listed
in the second column. In Table II-5, the same information is presented
by downwind State. In this table, each downwind State is listed in the
first column and the upwind States that contribute to that downwind
State are listed in the second column. The 8-hour contribution linkages
are presented by upwind State in Table II-6 and by downwind State in
Table II-7.
Table II-4.--Downwind States for Which Upwind States Contain Sources
That Contribute Significantly to 1-Hr Nonattainment \1\
------------------------------------------------------------------------
Upwind state Downwind states
------------------------------------------------------------------------
Alabama...................... GA, IL*, IN*, MI*, TN, WI*.
Connecticut.................. ME, MA, NH.
Delaware..................... CT, ME, MA, NH*, NJ, NY, PA, RI, VA.
District of Columbia......... CT, ME, MA, NH*, NJ, NY, PA, RI, VA.
Georgia...................... AL, TN.
Illinois..................... CT*, IN, MD, NJ*, NY, MI, MO, WI*.
Indiana...................... CT*, DE*, DC*, IL*, KY, MD, NJ*, NY, MI,
OH, VA*, WI*.
Kentucky..................... AL, CT*, DC*, GA, IL*, IN, MD, MI*, NJ,
NY, MO, OH, VA, WI*.
Maryland..................... CT, ME, MA, NH*, NJ, NY, PA, RI, VA.
Massachusetts................ ME, NH.
Michigan..................... CT, DC*, MD, NJ, NY, VA*.
Missouri..................... IL, IN, MI, WI*.
New Jersey................... CT, ME, MA, NH, NY, PA, RI.
New York..................... CT, ME, MA, NH, NJ, RI.
North Carolina............... CT*, DC*, GA, KY, MD, NJ, NY, OH, PA,
VA*.
Ohio......................... CT, DE, DC*, KY, MD, MA, NH*, NJ, NY, PA,
RI, VA.
Pennsylvania................. CT, DE, DC, ME, MD, MA, NH, NJ, NY, RI,
VA.
Rhode Island................. ME, MA, NH.
South Carolina............... AL, GA, TN.
Tennessee.................... AL, GA, IL*, IN, KY, MI*, OH, WI*.
Virginia..................... CT, DE, DC, KY*, MD, MA, NH*, NJ, NY, PA,
RI.
West Virginia................ CT, DE, DC, MD, MA, NJ, NY, PA, RI, VA.
Wisconsin.................... IL*, IN*, MI* .
------------------------------------------------------------------------
\1\ States marked with an asterisk (*) are included because they are
part of an interstate nonattainment area that receives a contribution
from the upwind State. New Hampshire is included because it is part of
the combined Boston/Portsmouth area; Connecticut and New Jersey are
included because they are part of the New York City area; Kentucky is
included because it is part of the Cincinnati area; Delaware is
included because it is part of the Philadelphia area; Illinois is
included because it is part of the St. Louis area; Illinois, Indiana,
Michigan, and Wisconsin are included because they are part of the Lake
Michigan area; and Maryland, Virginia, and the District of Columbia
are included because they are part of the Washington, DC area.
Table II-5.--Upwind States that Contain Sources that Contribute
Significantly to 1-Hr Nonattainment in Downwind States \1\
------------------------------------------------------------------------
Downwind state Upwind states
------------------------------------------------------------------------
Alabama...................... GA, KY, SC, TN.
Connecticut.................. DE, DC, IL*, IN*, KY*, MD, MI*, NJ, NY,
NC*, OH, PA, VA, WV.
Delaware..................... IN*, OH, PA, VA, WV.
District of Columbia......... IN*, KY*, MI*, NC*, OH*, PA, VA, WV.
Georgia...................... AL, KY, NC, SC, TN.
Illinois..................... AL*, IN*, KY*, MO, TN*, WI*.
Indiana...................... AL*, IL, KY, MO, TN, WI*.
Kentucky..................... IN, NC, OH, TN, VA*.
Maine........................ CT, DE, DC, MD, MA, NJ, NY, PA, RI.
Maryland..................... IL, IN, KY, MI, NC, OH, PA, VA, WV.
Massachusetts................ CT, DE, DC, MD, NJ, NY, OH, PA, RI, VA,
WV.
Michigan..................... AL*, IL, IN, KY*, MO, TN*, WI*.
Missouri..................... IL, KY.
[[Page 57395]]
New Hampshire................ CT, DC*, DE*, MD*, MA, NJ, NY, OH*, PA,
RI, VA*.
New Jersey................... DE, DC, IL*, IN*, KY, MD, MI, NY, NC, OH,
PA, VA, WV.
New York..................... DE, DC, IL, IN, KY, MD, MI, NJ, NC, OH,
PA, VA, WV.
Ohio......................... IN, KY, TN, NC.
Pennsylvania................. DE, DC, MD, NJ, NC, OH, VA, WV.
Rhode Island................. DE, DC, MD, NJ, NY, OH, PA, VA, WV.
Tennessee.................... AL, GA, SC.
Virginia..................... DE, DC, IN*, KY, MD, MI*, NC*, OH, PA,
WV.
Wisconsin.................... AL*, IL*, IN*, KY*, MO*, TN* .
------------------------------------------------------------------------
\1\ Upwind States marked with an asterisk (*) are considered to
significantly contribute to the downwind State because they contribute
to an interstate nonattainment area that includes part of the downwind
State. New Hampshire is included in the Boston/Portsmouth area;
Connecticut and New Jersey are included in the New York City area;
Kentucky is included in the Cincinnati area; Delaware is included in
the Philadelphia area; Illinois is included in the St. Louis area;
Illinois, Indiana, Michigan, and Wisconsin are included in the Lake
Michigan area; and Maryland and Virginia are included in the
Washington, DC area.
Table II-6.--Downwind States to Which Sources in Upwind States
Contribute Significantly for the 8-hour Standard
------------------------------------------------------------------------
Upwind state Downwind states
------------------------------------------------------------------------
Alabama...................... GA, IL, IN, KY, MI, MO, NC, OH, PA, SC,
TN, VA.
Connecticut.................. ME, MA, NH, RI.
Delaware..................... CT, ME, MA, NH, NJ, NY, PA, RI, VA.
District of Columbia......... CT, ME, MD, MA, NH, NJ, NY, PA, RI, VA.
Georgia...................... AL, IL, IN, KY, MI, MO, NC, SC, TN, VA.
Illinois..................... AL, CT, DC, DE, IN, KY, MD, MI, MO, NJ,
NY, OH, PA, RI, TN, WV, WI.
Indiana...................... DE, IL, KY, MD, MI, MO, NJ, NY, OH, PA,
TN, VA, WV, WI.
Kentucky..................... AL, DC, DE, GA, IL, IN, MD, MI, MO, NJ,
NY, NC, OH, PA, SC, TN, VA, WV, WI.
Maryland..................... CT, DE, DC, ME, MA, NH, NJ, NY, PA, RI,
VA.
Massachusetts................ ME, NH
Michigan..................... CT, DC, DE, MD, MA, NJ, NY, OH, PA, WV.
Missouri..................... IL, IN, KY, MI, OH, PA, TN, WI.
New Jersey................... CT, ME, MA, NH, NY, PA, RI.
New York..................... CT, ME, MA, NH, NJ, PA, RI.
North Carolina............... AL, CT, DE, GA, IN, KY, ME, MD, MA, NJ,
NY, OH, PA, RI, SC, TN, VA, WV.
Ohio......................... CT, DC, DE, IN, KY, MD, MA, MI, NJ, NY,
NC, PA, RI, TN, VA, WV.
Pennsylvania................. CT, DC, DE, ME, MD, MA, NH, NJ, NY, OH,
RI, VA.
Rhode Island................. ME, MA, NH.
South Carolina............... AL, GA, IN, KY, NC, TN, VA.
Tennessee.................... AL, DC, DE, GA, IL, IN, KY, MD, MI, MO,
NC, OH, PA, SC, VA, WV, WI.
Virginia..................... CT, DE, DC, ME, MD, MA, NJ, NY, NC, OH,
PA, RI, SC, WV.
West Virginia................ CT, DC, DE, IN, KY, MD, MA, NJ, NY, NC,
OH, PA, RI, SC, TN, VA.
Wisconsin.................... MI.
------------------------------------------------------------------------
Table II-7.--Upwind States that Contain Sources that Contribute
Significantly to 8-hour Nonattainment in Downwind States.
------------------------------------------------------------------------
Downwind state Upwind states
------------------------------------------------------------------------
Alabama...................... GA, IL, KY, NC, SC, TN.
Connecticut.................. DE, DC, IL, MD, MI, NJ, NY, NC, OH, PA,
VA, WV.
District of Columbia......... IL, KY, MD, MI, OH, PA, TN, VA, WV.
Delaware..................... IL, IN, KY, MI, NC, OH, PA, TN, VA, WV.
Georgia...................... AL, KY, NC, SC, TN.
Illinois..................... AL, GA, IN, KY, MO, TN.
Indiana...................... AL, GA, IL, KY, MO, NC, OH, SC, TN, WV.
Kentucky..................... AL, GA, IL, IN, MO, NC, OH, SC, TN, WV.
Maine........................ CT, DE, DC, MD, MA, NJ, NY, NC, PA, RI,
VA
Maryland..................... DC, IL, IN, KY, MI, NC, OH, PA, TN, VA,
WV.
Massachusetts................ CT, DE, DC, MD, MI, NJ, NY, NC, OH, PA,
RI, VA, WV.
Michigan..................... AL, GA, IL, IN, KY, MO, OH, TN, WI.
Missouri..................... AL, GA, IL, IN, KY, TN.
New Hampshire................ CT, DE, DC, MD, MA, NJ, NY, PA, RI.
New Jersey................... DE, DC, IL, IN, KY, MD, MI, NC, NY, OH,
PA, VA, WV.
New York..................... DE, DC, IL, IN, KY, MD, MI, NC, NJ, OH,
PA, VA, WV.
North Carolina............... AL, GA, KY, OH, SC, TN, VA, WV.
Ohio......................... AL, IL, IN, KY, MI, MO, NC, PA, TN, VA,
WV.
Pennsylvania................. AL, DE, DC, IL, IN, KY, MD, MI, MO, NJ,
NY, NC, OH, TN, VA, WV.
Rhode Island................. CT, DE, DC, IL, MD, NJ, NY, NC, OH, PA,
VA, WV.
[[Page 57396]]
South Carolina............... AL, GA, KY, NC, TN, VA, WV.
Tennessee.................... AL, GA, IL, IN, KY, MO, NC, OH, SC, WV.
Virginia..................... AL, DE, DC, GA, IN, KY, MD, NC, OH, PA,
SC, TN, WV.
West Virginia................ IL, IN, KY, MI, NC, OH, TN, VA.
Wisconsin.................... IL, IN, KY, MO, TN.
------------------------------------------------------------------------
c. Examples of Contributions From Upwind States to Downwind
Nonattainment. A full discussion of EPA's analysis supporting the
determination that specific upwind States contribute significantly to
individual downwind States under the 1-hour and 8-hour NAAQS is
provided in the Air Quality Modeling TSD. Examples of the types of
contributions which link individual upwind States to downwind areas are
provided below for the 1-hour NAAQS for the 23 upwind jurisdictions.
--Alabama's Contribution to 1-Hour Nonattainment in Atlanta
Magnitude of Contribution: The maximum contribution is 39 ppb (CAMx
Metric 2); the highest daily average contribution is 31 ppb (CAMx
Metric 3).
Frequency of Contribution: Alabama contributes at least 10 ppb to
12 percent of the 1-hr exceedences (UAM-V Metrics 1 and 2).
Relative Amount: The total contribution from Alabama is equivalent
to 14 percent of the total amount >=125 ppb in Atlanta (UAM-V Metric
3); Alabama contributes 8 percent of the total manmade ppb >= 125 ppb
in Atlanta (CAMx Metric 4; 4-episode average percent contribution).
--Connecticut/Rhode Island's Contribution to 1-Hour Nonattainment in
Western Massachusetts
Magnitude of Contribution: The maximum contribution is 61 ppb (CAMx
Metric 2); the highest daily average contribution is 50 ppb (CAMx
Metric 3).
Frequency of Contribution: Connecticut/Rhode Island contribute at
least 10 ppb to 100 percent of the 1-hr exceedences (CAMx Metrics 1 and
2).
Relative Amount: Connecticut/Rhode Island contribute 35 percent of
the total manmade ppb >= 125 ppb in Western Massachusetts (CAMx Metric
4; 4-episode average percent contribution).
--Georgia's Contribution to 1-Hour Nonattainment in Birmingham
Magnitude of Contribution: The maximum contribution is 51 ppb (CAMx
Metric 2); the highest daily average contribution is 24 ppb (CAMx
Metric 3).
Frequency of Contribution: Georgia contributes at least 10 ppb to
11 percent of the 1-hr exceedences (UAM-V Metrics 1 and 2).
Relative Amount: The total contribution from Georgia is equivalent
to 12 percent of the total amount >=125 ppb in Birmingham (UAM-V Metric
3); Georgia contributes 3 percent of the total manmade ppb >= 125 ppb
in Birmingham (CAMx Metric 4; 4-episode average percent contribution).
--Illinois's Contribution to 1-Hour Nonattainment in New York City
Magnitude of Contribution: The maximum contribution is 8 ppb (CAMx
Metric 2); the highest daily average contribution is 6 ppb (CAMx Metric
3).
Frequency of Contribution: Illinois contributes at least 5 ppb to
20 percent of the 1-hr exceedences (CAMx Metrics 1 and 2).
Relative Amount: The total contribution from Illinois is equivalent
to 3 percent of the total amount >=125 ppb in New York City (UAM-V
Metric 3); Illinois contributes 3 percent of the total manmade ppb >=
125 ppb in New York City (CAMx Metric 4; single highest episode percent
contribution).
--Indiana's Contribution to 1-Hour Nonattainment in Baltimore
Magnitude of Contribution: The maximum contribution is 8 ppb (CAMx
Metric 2); the highest daily average contribution is 6 ppb (CAMx Metric
3).
Frequency of Contribution: Indiana contributes at least 5 ppb to 26
percent of the 1-hr exceedences (CAMx Metrics 1 and 2).
Relative Amount: The total contribution from Indiana is equivalent
to 4 percent of the total amount >=125 ppb in Baltimore (UAM-V Metric
3); Indiana contributes 3 percent of the total manmade ppb >= 125 ppb
in New York City (CAMx Metric 4; single highest episode percent
contribution).
--Kentucky's Contribution to 1-Hour Nonattainment in Baltimore
Magnitude of Contribution: The maximum contribution is 9 ppb (CAMx
Metric 2); the highest daily average contribution is 8 ppb (CAMx Metric
3).
Frequency of Contribution: Kentucky contributes at least 5 ppb to
24 percent of the 1-hr exceedences (CAMx Metrics 1 and 2).
Relative Amount: The total contribution from Kentucky is equivalent
to 3 percent of the total amount >=125 ppb in Baltimore (UAM-V Metric
3); Kentucky contributes 5 percent of the total manmade ppb >= 125 ppb
in Baltimore (CAMx Metric 4; single highest episode percent
contribution).
--Maryland/District of Columbia/Delaware's Contribution to 1-Hour
Nonattainment in New York City
Magnitude of Contribution: The maximum contribution is 50 ppb (CAMx
Metric 2); the highest daily average contribution is 15 ppb (CAMx
Metric 3).
Frequency of Contribution: Maryland/District of Columbia/Delaware
contribute at least 10 ppb to 14 percent of the 1-hr exceedences and at
least 5 ppb to 38 percent of the 1-hr exceedences (CAMx Metrics 1 and
2).
Relative Amount: Maryland/District of Columbia/Delaware contribute
5 percent of the total manmade ppb >= 125 ppb in New York City (CAMx
Metric 4; 4-episode average percent contribution).
--Massachusetts' Contribution to 1-Hour Nonattainment in Portland, ME
Magnitude of Contribution: The maximum contribution is 79 ppb (CAMx
Metric 2); the highest daily average contribution is 67 ppb (CAMx
Metric 3).
Frequency of Contribution: Massachusetts contributes at least 10
ppb to 100 percent of the 1-hr exceedences (UAM-V Metrics 1 and 2).
Relative Amount: The total contribution from Massachusetts is
equivalent to 100 percent of the total amount >=125 ppb in Portland, ME
[[Page 57397]]
(UAM-V Metric 3); Massachusetts contributes 56 percent of the total
manmade ppb >= 125 ppb in Portland, ME (CAMx Metric 4; 4-episode
average percent contribution).
--Michigan's Contribution to 1-Hour Nonattainment in Baltimore
Magnitude of Contribution: The maximum contribution is 9 ppb (CAMx
Metric 2); the highest daily average contribution is 8 ppb (CAMx Metric
3).
Frequency of Contribution: Michigan contributes at least 5 ppb to 7
percent of the 1-hr exceedences (CAMx Metrics 1 and 2).
Relative Amount: The total contribution from Michigan is equivalent
to 5 percent of the total amount >=125 ppb in Baltimore (UAM-V Metric
3); Michigan contributes 5 percent of the total manmade ppb >= 125 ppb
in Baltimore (CAMx Metric 4; single highest episode percent
contribution).
--Missouri's Contribution to 1-Hour Nonattainment over Lake Michigan
Magnitude of Contribution: The maximum contribution is 19 ppb (CAMx
Metric 2); the highest daily average contribution is 12 ppb (CAMx
Metric 3).
Frequency of Contribution: Missouri contributes at least 10 ppb to
66 percent of the 1-hr exceedences (CAMx Metrics 1 and 2).
Relative Amount: The total contribution from Missouri is equivalent
to 22 percent of the total amount >=125 ppb over Lake Michigan (UAM-V
Metric 3); Missouri contributes 9 percent of the total manmade ppb >=
125 ppb over Lake Michigan (CAMx Metric 4; 4-episode average percent
contribution).
--New Jersey's Contribution to 1-Hour Nonattainment in Western
Massachusetts
Magnitude of Contribution: The maximum contribution is 30 ppb (CAMx
Metric 2); the highest daily average contribution is 23 ppb (CAMx
Metric 3).
Frequency of Contribution: New Jersey contributes at least 10 ppb
to 100 percent of the 1-hr exceedences (CAMx Metrics 1 and 2).
Relative Amount: New Jersey contributes 16 percent of the total
manmade ppb >= 125 ppb in Western Massachusetts (CAMx Metric 4; 4-
episode average percent contribution).
--New York's Contribution to 1-Hour Nonattainment in Western
Massachusetts
Magnitude of Contribution: The maximum contribution is 25 ppb (CAMx
Metric 2); the highest daily average contribution is 23 ppb (CAMx
Metric 3).
Frequency of Contribution: New York contributes at least 10 ppb to
100 percent of the 1-hr exceedences (CAMx Metrics 1 and 2).
Relative Amount: New York contributes 18 percent of the total
manmade ppb >= 125 ppb in Western Massachusetts (CAMx Metric 4; 4-
episode average percent contribution).
--North Carolina's Contribution to 1-Hour Nonattainment in Philadelphia
Magnitude of Contribution: The maximum contribution is 10 ppb (CAMx
Metric 2); the highest daily average contribution is 9 ppb (CAMx Metric
3).
Frequency of Contribution: North Carolina contributes at least 2
ppb to 4 percent of the 1-hr exceedences (UAM-V Metrics 1 and 2).
Relative Amount: The total contribution from North Carolina is
equivalent to 4 percent of the total amount >=125 ppb in Philadelphia
(UAM-V Metric 3); North Carolina contributes 2 percent of the total
manmade ppb >= 125 ppb in Philadelphia (CAMx Metric 4; single highest
episode percent contribution).
--Ohio's Contribution to 1-Hour Nonattainment in Baltimore
Magnitude of Contribution: The maximum contribution is 13 ppb (CAMx
Metric 2); the highest daily average contribution is 12 ppb (CAMx
Metric 3).
Frequency of Contribution: Ohio contributes at least 5 ppb to 51
percent of the 1-hr exceedences (CAMx Metrics 1 and 2).
Relative Amount: The total contribution from Ohio is equivalent to
11 percent of the total amount >=125 ppb in Baltimore (UAM-V Metric 3);
Ohio contributes 4 percent of the total manmade ppb >= 125 ppb in
Baltimore (CAMx Metric 4; 4-episode average percent contribution).
--Pennsylvania's Contribution to 1-Hour Nonattainment in Greater
Connecticut
Magnitude of Contribution: The maximum contribution is 28 ppb (CAMx
Metric 2); the highest daily average contribution is 23 ppb (CAMx
Metric 3).
Frequency of Contribution: Pennsylvania contributes at least 10 ppb
to 60 percent of the 1-hr exceedences and at least 5 ppb to 98 percent
of the 1-hr exceedences (CAMx Metrics 1 and 2).
Relative Amount: Pennsylvania contributes 10 percent of the total
manmade ppb >= 125 ppb in Greater Connecticut (CAMx Metric 4; 4-episode
average percent contribution).
--South Carolina's Contribution to 1-Hour Nonattainment in Atlanta
Magnitude of Contribution: The maximum contribution is 24 ppb (CAMx
Metric 2); the highest daily average contribution is 23 ppb (CAMx
Metric 3).
Frequency of Contribution: South Carolina contributes at least 5
ppb to 6 percent of the 1-hr exceedences (UAM-V Metrics 1 and 2).
Relative Amount: The total contribution from South Carolina is
equivalent to 4 percent of the total amount >=125 ppb in Atlanta (UAM-V
Metric 3); South Carolina contributes 2 percent of the total manmade
ppb >= 125 ppb in Atlanta (CAMx Metric 4; single highest episode
percent contribution).
--Tennessee's Contribution to 1-Hour Nonattainment Over Lake Michigan
Magnitude of Contribution: The maximum contribution is 12 ppb (CAMx
Metric 2); the highest daily average contribution is 11 ppb (CAMx
Metric 3).
Frequency of Contribution: Tennessee contributes at least 5 ppb to
14 percent of the 1-hr exceedences (UAM-V Metrics 1 and 2).
Relative Amount: The total contribution from Tennessee is
equivalent to 6 percent of the total amount >=125 ppb over Lake
Michigan (UAM-V Metric 3); Tennessee contributes 10 percent of the
total manmade ppb >= 125 ppb over Lake Michigan (CAMx Metric 4; single
highest episode percent contribution).
--Virginia's Contribution to 1-Hour Nonattainment in New York City
Magnitude of Contribution: The maximum contribution is 25 ppb (CAMx
Metric 2); the highest daily average contribution is 11 ppb (CAMx
Metric 3).
Frequency of Contribution: Virginia contributes at least 10 ppb to
11 percent of the 1-hr exceedences and at least 5 ppb to 36 percent of
the 1-hr exceedences (CAMx Metrics 1 and 2).
Relative Amount: The total contribution from Virginia is equivalent
to 11 percent of the total amount >=125 ppb in New York City (UAM-V
Metric 3); Virginia contributes 4 percent of the
[[Page 57398]]
total manmade ppb >= 125 ppb in New York City (CAMx Metric 4; 4-episode
average percent contribution).
--West Virginia's Contribution to 1-Hour Nonattainment in New York City
Magnitude of Contribution: The maximum contribution is 14 ppb (CAMx
Metric 2); the highest daily average contribution is 10 ppb (CAMx
Metric 3).
Frequency of Contribution: West Virginia contributes at least 5 ppb
to 9 percent of the 1-hr exceedences and at least 2 ppb to 28 percent
of the 1-hr exceedences (UAM-V Metrics 1 and 2).
Relative Amount: The total contribution from West Virginia is
equivalent to 9 percent of the total amount >=125 ppb in New York City
(UAM-V Metric 3); West Virginia contributes 7 percent of the total
manmade ppb >= 125 ppb in New York City (CAMx Metric 4; single highest
episode percent contribution).
--Wisconsin's Contribution to 1-Hour Nonattainment Over Lake Michigan
Magnitude of Contribution: The maximum contribution is 43 ppb (CAMx
Metric 2); the highest daily average contribution is 8 ppb (CAMx Metric
3).
Frequency of Contribution: Wisconsin contributes at least 10 ppb to
11 percent of the 1-hr exceedences (CAMx Metrics 1 and 2).
Relative Amount: Wisconsin contributes 4 percent of the total
manmade ppb >= 125 ppb over Lake Michigan (CAMx Metric 4; 4-episode
average percent contribution).
d. Conclusions From Air Quality Evaluation of Downwind
Contributions. As indicated above, EPA is following a multi-step
approach for determining whether emissions from an upwind State
significantly contribute to nonattainment downwind. The first step
involves an air quality evaluation to determine whether the air quality
factors, and particularly the extent of the downwind contributions from
emissions in the upwind State, indicate that those contributions are
large and/or frequent enough to be of concern under the 1-hour and/or
8-hour NAAQS. The second step, as described below, employs a cost-
effectiveness analysis to determine which of the upwind emissions may
be eliminated through highly cost-effective controls. Any emissions
that may be so eliminated are considered to be emissions that
significantly contribute to nonattainment downwind. Finally, to confirm
that the emissions considered to significantly contribute, taken as a
whole, have a meaningful impact on nonattainment in downwind areas, EPA
modeled the air quality effects of eliminating that amount of emissions
(see Section IV, Air Quality Assessment, below).
The EPA's conclusions from the first step in this process, the air
quality evaluation, is that emissions from sources in each of the 23
jurisdictions listed below make a significant contribution to
nonattainment downwind for both the 1-hour and 8-hour NAAQS and
interfere with maintenance of the 8-hour NAAQS. This determination was
based on two independent sets of analyses, each of which EPA believes
provides an independent basis for these conclusions. These two
independent analyses are (1) subregional modeling using UAM-V, and (2)
State-by-State modeling using CAMx and UAM-V. For the subregional
modeling, EPA examined the frequency and magnitude of the impacts from
each subregion along with State emissions data and other air quality
information to evaluate the contributions from upwind States to
nonattainment in downwind areas. For the UAM-V and CAMx State-by-State
techniques, a number of measures of ozone contribution, or metrics,
were used to assess, from several perspectives, the air quality effect
of contributions from sources in different upwind States.
The EPA weighed the results of its analysis of these several air
quality metrics to determine which upwind States contain sources whose
emissions contribute significantly to downwind nonattainment or
maintenance problems. By examining the results of several air quality
metrics, EPA assured that no one metric determined whether a State
contains sources whose emissions contribute to downwind air quality
problems. Rather, the determination of whether an upwind State
contained sources whose emissions contribute significantly to a
downwind nonattainment problem was based on the extent of the
contributions reflected by multiple metrics. The EPA concluded that
each set of modeling (i.e., subregional and State-by-State) when
considered independently under EPA's weight-of-evidence approach
provides a sound technical basis for finding that NOX
emissions from sources in the following 23 jurisdictions make a
significant contribution to nonattainment of the 1-hour and 8-hour
NAAQS in, or interfere with maintenance of the 8-hour NAAQS by, one or
more downwind States:
Alabama
Connecticut
Delaware
District of Columbia
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
The remaining 15 OTAG States not covered by this final rule are
discussed below.
5. States Not Covered by This Rulemaking
In Section VI of the NPR, EPA proposed to find that emissions from
sources in the following 15 States in the OTAG region do not
significantly contribute to downwind nonattainment under the 1-hour or
8-hour ozone NAAQS, or interfere with maintenance under the 8-hour
NAAQS: Arkansas, Florida, Iowa, Kansas, Louisiana, Maine, Minnesota,
Mississippi, North Dakota, Nebraska, New Hampshire, Oklahoma, South
Dakota, Texas, Vermont (62 FR 60369). The EPA received comments on this
section of the NPR and has recently conducted some additional CAMx
analyses.50 The CAMx modeling suggested that further
analysis using UAM-V State-by-State modeling would be warranted in
order to have a set of information comparable to that for other States
that are subject to this rule. In today's rulemaking, EPA is taking no
action on whether emissions from sources in these 15 States do or do
not contribute significantly to downwind nonattainment, or interfere
with maintenance downwind, under either NAAQS. Thus, by today's
rulemaking, EPA is not requiring these 15 States to submit SIP
revisions providing for NOX emissions controls to meet a
statewide NOX emissions budget; nor is EPA determining that
these States will not be required to make these SIP submissions in the
future. The EPA is continuing to review available information on the
downwind impacts of these States, including comments submitted on the
NPR. In addition, EPA plans to conduct State-by-State modeling to
determine whether a SIP revision under section 110(a)(2)(D)(i)(I)
should be required from any of these States in the future.
[[Page 57399]]
The EPA intends to begin this modeling in the fall of 1998.
---------------------------------------------------------------------------
\50\ See ``Notice of Availability'' 63 FR 45032 (August 24,
1998).
---------------------------------------------------------------------------
As discussed in the NPR (62 FR 60318 at 60370), EPA reiterates that
these 15 States may need to cooperate and coordinate SIP development
activities with other States that are subject to today's action. Also,
States with interstate nonattainment areas for the 1-hour standard and/
or the new 8-hour standard should cooperate in reducing emissions to
mitigate local-scale interstate transport problems (e.g., transport
from one State in a multi-state urban nonattainment area to another
State in that area) to provide for attainment in the nonattainment area
as a whole. The EPA encourages the 15 States to conduct additional
analyses on ozone transport recommended by the OTAG Policy Group, which
indicated that these States, ``* * * will, in cooperation with EPA,
periodically review their emissions, and the impact of increases, on
downwind nonattainment areas and, as appropriate, take steps necessary
to reduce such impacts including appropriate control measures.''
51
---------------------------------------------------------------------------
\51\ OTAG Recommendation: Utility NOX Controls,
approved by the Policy Group, June 3, 1997.
---------------------------------------------------------------------------
Comment: A number of commenters supported the proposal to exclude
the proposed States, either in general or for specific States. Others
opposed the proposal in general, or for specific States.
Response: Because EPA is taking no action on the 15 States at this
time, EPA will not respond to comments concerning these States at this
time. As discussed above, EPA intends to continue to review ambient air
quality data, air quality modeling results, and other technical
information on the downwind contribution from all States not found to
be significant contributors in today's action.
Comment: Several commenters stated that if EPA revisits which
States should be included in the rulemaking, EPA must reopen the public
comment period.
Response: The EPA agrees. Because today's action does not propose a
change from the NPR concerning which States should be covered, no new
comment period is needed at this time. As EPA noted in the NPR, if
results from additional modeling and technical analyses indicate that
States other than the 22 States (and the District of Columbia) that are
the subject of today's action should be required to submit a SIP
revision under section 110(a)(2)(D)(i)(I), EPA will publish a new NPR
as to any such States and provide an additional comment period. As also
stated in the NPR, in 2007, EPA will reassess transport in the full
OTAG region to evaluate the effectiveness of the regional
NOX measures and the need, if any, for additional regional
controls.
D. Cost Effectiveness of Emissions Reductions
As discussed above, in today's action, EPA considers control costs
in determining whether, and the extent to which, upwind emissions
contribute significantly to nonattainment, or interfere with
maintenance downwind. The EPA considers cost factors in conjunction
with other factors generally related to levels of emissions.
1. Sources Included In the Cost-Effectiveness Determination
This subsection describes the rationale used to determine the cost
effectiveness of emissions reductions measures. The EPA evaluates the
relative costs of the available control measures using average cost
effectiveness, measured as dollars per ton of NOX reduced
relative to a baseline, to identify those emissions reductions that are
``highly cost-effective.'' In performing this evaluation, EPA considers
the cost savings of a regionwide NOX emissions trading
system for large electricity generating boilers and turbines (i.e.,
boilers and turbines serving a generator larger than 25 MWe). As
described in this section, EPA has determined that these emissions
reductions are highly cost effective on a regionwide basis.
To assure equity among the various source categories and the
industries they represent, EPA considered the cost effectiveness of
controls for each source category separately throughout the SIP call
region. Sources are combined into a common source category if they
serve the same general industry (e.g., boilers and turbines that are
used by the electricity generation industry are combined in the same
category). In general, this means that the sources in the same source
category share the same six-digit source code classification (SCC). One
exception is in the case of boilers and turbines which are combined and
then separated into (1) a category of boilers and turbines serving
generators that produce electricity for sale to the grid; or (2) a
category of boilers and turbines that exclusively generate steam and/or
mechanical work (e.g., provide energy to an industrial pump), or
produce electricity primarily for internal use and not for sale. The
EPA believes that this categorization better reflects the industrial
sectors served.
For each source category, the required emission levels (in tons per
ozone season) were determined based on the application of
NOX controls that achieve the greatest feasible emissions
reduction while still falling within a cost-per-ton-reduced range that
EPA considers to be highly cost-effective (hereinafter also referred to
as ``highly cost-effective'' measures). Marginal or incremental costs
of control are additional cost-effective measures that may provide
important information about alternatives. In particular, incremental
cost-effectiveness helps to identify whether a more stringent control
option imposes much higher costs relative to the average cost per ton
for further control. The use of an average cost-effectiveness measure
may not fully reveal costly incremental requirements where control
options achieve large reductions in emissions (relative to the
baseline).
In this rulemaking, EPA has chosen to focus on an average cost-
effectiveness measure in identifying highly cost-effective control
options for several reasons. Since EPA's determination for the core
group of sources is based on the adoption of a broad-based trading
program, average cost-effectiveness serves as an adequate measure
across sources because sources with high marginal costs will be able to
take advantage of this program to lower their costs. In addition,
average cost-effectiveness estimates are readily available for other
recently adopted NOX control measures.
The EPA examined a representative sample of potentially available
controls. NOX controls for this rulemaking were considered
highly cost-effective for the purposes of reducing ozone transport to
the extent they achieve the greatest feasible emissions reduction but
still cost no more than $2,000 per ton of ozone season NOX
emissions removed (in 1990 dollars), on average, for each source
category. The discussion below further describes the basis for this
cost amount and the techniques used for each category. Many may
consider certain controls that cost more than $2,000 per ton of
NOX reduced to be reasonably cost-effective in reducing
ozone transport or in achieving attainment with the ozone NAAQS in
specific nonattainment areas; however, EPA has determined to focus
today's rulemaking on only highly cost-effective reductions. In the
future, as EPA continues to consider the impact of ozone transport and
the most effective ways to assure downwind attainment, EPA may
reconsider whether State NOX budget levels should be lowered
to reflect application of additional controls
[[Page 57400]]
that, although more expensive, are nevertheless cost-effective. In
addition, as discussed below, in determining whether to assume
reductions from source categories with only a few sources or relatively
small emissions, EPA considered administrative efficiency in developing
conclusions about whether to assume emissions reductions for these
sources.
In determining the cost of NOX reductions by large
electricity generating units (EGUs), EPA assumed an emissions trading
system. As discussed in Section IV below, EPA evaluated and compared
the likely air quality impacts of this rulemaking with and without a
regionwide NOX emissions trading system for electricity
generating sources. This analysis shows that a regionwide trading
program causes no significant adverse air quality impacts. Because such
a program would result in significant cost savings, EPA's cost-
effectiveness determination for large electricity generating boilers
and turbines assumes that each State will adopt the lowest cost
approach, i.e., the States will elect to include these sources in a
regionwide NOX emissions trading program. However, States
retain the option of choosing other, perhaps more expensive, approaches
to achieving the necessary reductions. For non-EGU sources in the core
group of the trading program, EPA used a least cost method which is
equivalent to an assumption of an intrastate trading program. Inclusion
of these sources in a regionwide trading program would provide further
cost savings. For other source categories for which EPA identified
highly cost-effective controls (i.e., internal combustion engines and
cement manufacturing), EPA assumed source-specific controls. However, a
State may choose to include such categories in the trading program and
realize further cost savings.
For the purposes of this rulemaking, EPA considers the following
sizes of point sources to be large: (1) electricity generating boilers
and turbines serving a generator greater than 25 MWe; or (2) other
point sources with a heat input greater than 250 mmBtu/hr or which emit
more than one ton of NOX per average summer day.
In the NPR, EPA based the cost-effectiveness determination on
NOX emissions controls that are available and of comparable
cost to other recently undertaken or planned NOX measures.
Table 1 provides a reference list of measures that EPA and States have
recently undertaken to reduce NOX and their average annual
costs per ton of NOX reduced. Most of these measures fall
below $2,000 per ton. With few exceptions, the average cost-
effectiveness of these measures is representative of the average cost-
effectiveness of the types of controls EPA and States have needed to
adopt most recently because their previous planning efforts have
already taken advantage of opportunities for even cheaper controls. The
EPA believes that the cost-effectiveness of measures that EPA or States
have adopted, or proposed to adopt, forms a good reference point for
determining which of the available additional NOX control
measures can most easily be implemented by upwind States whose
emissions impact downwind nonattainment problems.
Table 1.--Average Cost-effectiveness of NOX Control Measures Recently
Undertaken
[1990 dollars]
------------------------------------------------------------------------
Cost
per ton
Control measure of NOX
Removed
------------------------------------------------------------------------
NOX RACT....................................................... 150-1,3
00
Phase II Reformulated Gasoline................................. \52\ 4,
100
State Implementation of the Ozone Transport Commission
Memorandum of Understanding................................... 950-1,6
00
New Source Performance Standards for Fossil Steam Electric
Generation Units.............................................. 1,290
New Source Performance Standards for Industrial Boilers........ 1,790
------------------------------------------------------------------------
\52\ Average cost representing the midpoint of $2,180 to $6,000 per ton.
This cost represents the projected additional cost of complying with
the Phase II RFG NOX standards, beyond the cost of complying with the
other standards for Phase II RFG.
The Federal Phase II RFG costs presented in Table 1 are not
strictly comparable to the other costs cited in the table. Federal
Phase II RFG will provide large VOC reductions in addition to
NOX reductions. Federal RFG is required in nine cities with
the nation's worst ozone nonattainment problems; other nonattainment
areas have chosen to opt into the program as part of their attainment
strategy. The mandated areas and those areas in the OTAG region that
have chosen to opt into the program are areas where significant local
reductions in ozone precursors are needed; such areas may value RFG's
NOX and VOC reductions differently for their local ozone
benefits than they would value NOX reductions from RFG or
other programs for ozone transport benefits.
Commenters on the proposal generally agreed with basing the cost-
effectiveness determination on the cost effectiveness of other recently
undertaken measures. Therefore, EPA has considered controls with an
average cost-effectiveness less than $2,000 per ton of NOX
removed to be highly cost effective and has calculated the amounts of
emissions that States must prohibit based on application of these
controls. Some commenters believed that a more appropriate measure of
cost effectiveness was incremental--instead of average--dollars per ton
of NOX removed. Other commenters believed that a more
appropriate measure was dollars per ppb of ozone removed from a
nonattainment area. The EPA continues to depend on regionwide average
dollars per ton of NOX removed when evaluating what control
measures are highly cost-effective for the purposes of this rulemaking.
Table 2 summarizes the control options investigated for each source
category and the resulting average, regionwide cost effectiveness.
[[Page 57401]]
Table 2.--Average cost Effectiveness of Options Analyzed \53\
[1990 dollars in 2007]
----------------------------------------------------------------------------------------------------------------
Source category
----------------------------------------------------------------------------------------------------------------
Average Cost-effectiveness ($/ozone season ton) for each
control option
-----------------------------------------------------------------
Boilers and Turbines Generating Electricity... 0.20 lb/mmBtu....... 0.15 lb/mmBtu....... 0.12 lb/mmBtu.
$1,263.............. $1,468.............. $1,760.
Boilers and Turbines not Generating 50% reduction....... 60% reduction....... 70% reduction.
Electricity.
$1,235.............. $1,467.............. $2,140.
Other Stationary Sources \54\................. $3,000/ton maximum $4,000/ton maximum $5,000/ton maximum
per source. per source. per source.
Cement Manufacturing.......................... $1,458.............. $1,458.............. $1,458
Glass Manufacturing........................... $2,020.............. $2,339.............. $4,758.
Incinerators.................................. $2,118.............. $2,118.............. $2,118.
Internal Combustion Engines................... $1,213.............. $1,213.............. $1,215.
Process Heaters............................... $2,860.............. $2,896.............. $2,896.
----------------------------------------------------------------------------------------------------------------
\53\ The cost-effectiveness values in Table 2 are regionwide averages. The cost-effectiveness values represent
reductions beyond those required by Title IV or Title I RACT, where applicable.
\54\ For cement manufacturing, incinerators, internal combustion engines and process heaters, the table
indicates that the same control technology (at the same cost) would be selected whether the cost ceiling for
each source is $3,000, $4,000, or $5,000 per ton; thus the average cost-effectiveness number for these source
categories is the same in each column. For glass manufacturing, the table indicates that additional emissions
reductions would be obtained from more effective and more costly control technologies as the cost ceiling
increase.
The following discussion explains the controls determined by EPA to
be highly cost-effective for each source category.
The EPA has analyzed the implications of each State limiting
trading within its borders compared to entering into a common trading
program with all other States, provided that States choose to control
EGUs at an average level of 0.15 lb/mmBtu. In the case of intrastate
trading, EPA found that the average cost per ton of the resulting ozone
season NOX reduction was about $1,499 per ton. This result
from the IPM model was for all the States together considering changes
in dispatch and other aspects of the future operation of the nation's
power system. Individual State results were not provided by the model.
As explained below, EPA expects that individual State cost per ton
results are likely to be fairly close to this collective result.
For a regionwide budget based on 0.15 lb/mmBtu, EPA's analyses
suggest that whether (1) there were individual State trading programs,
or (2) a single regionwide trading program, all States experienced a
substantial reduction in summer NOX emissions from Base Case
emissions levels. For this to occur, there have to be similar
opportunities throughout the SIP call region for highly cost-effective
reductions to occur at EGUs. If this were not true, EPA would have
found, in the case where there is a single trading program across the
entire SIP call region, that some States reduce a much greater share of
their NOX emissions than other States do. The fact that
there are similar opportunities for NOX reductions in each
of the States indicates that if there were individual State trading
programs in place they would each generally have an average cost
effectiveness for reducing ozone season NOX emissions that
is fairly close to the cost effectiveness of trading programs in other
States. Therefore, each State is generally likely to have an average
cost effectiveness of about $1,550 per ton, the amount we found in the
results of the IPM model run for a scenario where each State ran its
own trading program.
a. Electricity Generating Boilers and Turbines. For EGUs larger
than 25 MWe, the control level was determined by applying a uniform
NOX emissions rate regionwide. The cost-effectiveness for
each control level was determined using the IPM. Details regarding the
methodologies used can be found in the Regulatory Impact Analysis of
this rulemaking. Table 2 summarizes the control levels and resulting
cost-effectiveness of three options analyzed.
A regionwide level of 0.20 lb/mmBtu was rejected because though it
resulted in an average cost effectiveness of less than $2,000 per ton,
the air quality benefits were less than those for the 0.15 lb/mmBtu
level which was also less than $2,000 per ton. The results suggest that
a regionwide level of 0.15 lb/mmBtu should be assumed for this source
category when calculating the amount of emissions that should be
considered significant and therefore prohibited in each covered State.
This control level has an average cost-effectiveness of $1,468 per
ozone season ton removed. This amount is consistent with the range for
cost-effectiveness that EPA has derived from recently adopted (or
proposed to be adopted) control measures. As discussed later in this
preamble, EPA has determined that EGU sources are fully capable of
implementing this level of control by May 1, 2003.
The EPA estimates that a control level based on 0.12 lb/mmBtu, has
a cost effectiveness of $1,760 per ozone season ton removed, which is
within the upper range of cost effectiveness. This estimate is based on
the Agency's best estimates of several key assumptions on the
performance of pollution control technologies and electricity
generation requirements in the future which the Agency thoroughly
researched over the last two years. Given that the cost per ton
estimate for 0.12 lb/mmBtu trading is much closer to $2,000 than the
0.15 lb/mmBtu trading, EPA is not as confident about the robustness of
the results. Also, although EPA is very comfortable that a 0.15 lb/
mmBtu trading program beginning in 2003 will not lead to installation
of SCR technology at a level and in a manner that will be difficult to
implement or result in reliability problems for electric power
generation, the Agency's level of comfort is not as high in considering
0.12 lb/mmBtu-based trading.55 With a strong need to
implement a program by 2003 that is recognized by the States as
practical, necessary, and broadly accepted as highly cost effective,
the Agency has decided to base the
[[Page 57402]]
emissions budgets for EGUs on a 0.15 lb/mmBtu trading level of control.
---------------------------------------------------------------------------
\55\ For reasons explained in Section V., below, EPA has
determined that May 1, 2003 is the earliest practicable date for
achieving the level of emissions reductions EPA selected, and
therefore is the appropriate date for achieving these reductions in
light of the CAA's attainment date requirements.
---------------------------------------------------------------------------
It should be noted that the cost-effectiveness values for EGUs were
calculated using a slightly older version of the final EGU inventory.
Changes made to the inventory and growth assumptions resulted in
decreasing the final regionwide allowable emission level for EGUs,
under the 0.15 option, to 543,825 tons per year from 563,785 tons per
year. Reducing the allowable regionwide emissions increased the average
cost-effectiveness value of the 0.15 option from $1,468/ton, to $1,503/
ton.
b. Other Stationary Sources. The appropriate cost-effective control
level for large non-EGU source categories was determined by evaluating
various regulatory alternatives. For industrial boilers and turbines
(i.e., boilers and turbines greater than 250 mm/Btu per hour or with
NOX emissions greater than 1 tpd), the control level was
determined by applying a uniform percent reduction regionwide in
increments of 10 percent. For all other stationary sources, the control
level was determined by applying source-category-specific cost-
effectiveness thresholds, because trading was not assumed to be readily
available for these source categories. Details regarding the
methodologies used are in the Regulatory Impact Analysis. Table 2
summarizes the control levels and resulting cost-effectiveness for each
option under each category.
Further, for large non-EGUs, the cost-effectiveness determination
includes estimates of the additional emissions monitoring costs that
sources would incur in order to participate in a trading program. Some
non-EGUs already monitor their emissions. In the NPR, EPA had not
included monitoring costs in the cost-effectiveness determination
because such costs had not been estimated at that time. Since then, EPA
has evaluated monitoring system costs. These costs are defined in terms
of dollars per ton of NOX removed so that they can be
combined with the cost-effectiveness figures related to control costs.
Since monitoring costs do not vary with the level of control, the cost
per ton for monitoring varies in accordance with the amount of control
being required. For purposes of this analysis, the level of control was
assumed to be the level of control used to calculate the budget.
Monitoring costs varied from about $150 to $400 per ton of
NOX removed, depending on the type of source category.
The EPA, therefore, determines that: (1) For large non-electricity-
generating industrial boilers and turbines, a control level
corresponding to 60 percent reduction from baseline levels is highly
cost-effective (this percent reduction corresponds to a regionwide
control level of about 0.17 lb/mmBtu); and (2) for large internal
combustion engines and cement manufacturing sources, a control level
corresponding to the application of NOX reduction technology
costing no more than $5,000/ton for each source is, on average, highly
cost effective. As indicated in Table 2 and described in detail in the
RIA, these control levels are associated with a cost effectiveness of
approximately $1,467/ton for boilers and turbines, $1,458/ton for
cement manufacturing, and $1,215/ton for internal combustion engines.
This results in an average emissions reduction from uncontrolled
emissions of 90 percent for internal combustion engines and 30 percent
for cement manufacturing sources. The EPA notes that States may include
these source categories in the model NOX budget trading
program, further assuring that each source would be able to cost-
effectively meet its reduction requirements. The EPA determined that
controlling glass manufacturing sources, incinerators, and process
heaters was not highly cost-effective because all the options analyzed
for these source categories cost more than $2,000 per ton of
NOX removed. Thus, no additional controls are assumed for
these sources when determining the significant amounts that must be
reduced in each State.
2. Sources Not Included In the Cost-effectiveness Determination
For the following groups of sources, EPA is determining that no
additional control measures or levels of control should be assumed in
this rulemaking, for the reasons described.
a. Area Sources. In the NPR, EPA noted that control levels for area
sources (i.e., sources other than mobile or point sources) could not be
determined based on available information concerning applicable control
technologies. Comments to the NPR did not identify specific
NOX control technologies that were both technologically
feasible and highly cost-effective. Because EPA has no new information
on applicable control technologies for area sources, no additional
control level is assumed for these sources in this rulemaking. Further
discussion concerning area sources can be found in Section III, below,
of this preamble.
b. Small Point Sources. For the purposes of this rulemaking, EPA
considers the following sizes of point sources to be small: (1)
Electricity generating boilers and turbines serving a generator 25 MWe
or less, and (2) other point sources with a heat input of 250 mmBtu/hr
or less and which emit less than one ton of NOX per average
summer day. In the NPR, EPA stated that the collective emissions from
small sources were relatively small (in the context of this rulemaking)
and the administrative burden, to the States and regulated entities, of
controlling such sources was likely to be considerable. As a result, in
the NPR, EPA proposed not to assume reductions from these sources in
establishing the State budgets.
Comments to the NPR did not identify specific approaches that would
result in significant emission reductions and be administratively
efficient in controlling these sources. On the contrary, many comments
encouraged EPA to exclude small point sources from any budget
calculations for this rulemaking.
Therefore, in today's action, EPA is not assuming additional
control levels for these sources. Further discussion concerning small
point sources may be found in section III, below, of this preamble.
c. Mobile Sources. In the NPR, EPA noted that it could not identify
any additional NOX controls that States could implement for
mobile or nonroad sources beyond those already reflected in the
proposed State NOX budgets that were both technologically
feasible and cost-effective, relative to point sources covered by this
rule, for the purposes of reducing NOX. Several commenters
stated that the EPA should require States to implement additional
reductions for mobile sources. However, these commenters did not
identify specific, new, technologically feasible mobile source
NOX controls that were highly cost-effective by the
standards of today's action. The EPA has re-examined the availability
of mobile source control measures available to States, as discussed in
more detail in sections III.D. and III.E. below, and has not identified
any such controls that are both technologically feasible and highly
cost-effective for NOX control. Therefore, the States' final
NOX budgets promulgated in today's action do not assume
implementation of additional highway or nonroad mobile source controls
or expansion of existing controls beyond those described in the NPR.
Further discussion concerning mobile sources, including the national
measures EPA has assumed for purposes of today's rule, can be found in
Section III, Determination of Budgets.
d. Other stationary sources. The EPA does not assume, in this
rulemaking, any additional control measures or
[[Page 57403]]
lower emissions levels for municipal waste combustors because these
combustors are already being controlled through MACT regulations.
Moreover, no additional control measures were assumed for source
categories with relatively small NOX emissions (e.g., iron
and steel mills, nitric acid manufacturing sources, space heaters, lime
kilns, recovery plants, and engine test facilities). Further discussion
concerning why controls were not assumed for these source categories
may be found in Section III of this preamble.
e. Conclusion. The above discussion described the controls for
various source categories that EPA considers to be highly cost-
effective. The next step in the process is to determine the amounts of
NOX emissions that would be eliminated by applying these
highly cost-effective controls to the respective source categories. The
EPA considers those emissions to be the amounts that contribute
significantly to nonattainment in, or interfere with maintenance by,
downwind States. By assuming that reductions of this magnitude should
occur, EPA determined the resulting State-specific ``budget.'' Section
III, Determination of Budgets describes the process EPA used to
determine each State's budget and discusses comments received on the
NPR.
E. Other Considerations
As described above, EPA determined the amount of emissions that
significantly contribute to downwind nonattainment from sources in a
particular upwind State primarily by (i) evaluating, with respect to
each upwind State, several air quality related factors, including
determining that all emissions from the State have a sufficiently great
impact downwind (in the context of the collective contribution nature
of the ozone problem); and (ii) determining the amount of that State's
emissions that can be eliminated through the application of cost-
effective controls. Before reaching a conclusion, EPA evaluated several
secondary, and more general, considerations. These include:
The consistency of the regional reductions with the
attainment needs of the downwind areas with nonattainment problems
The overall fairness of the control regimes required of
the downwind and upwind areas, including the extent of the controls
required or implemented by the downwind and upwind areas
General cost considerations, including the relative cost-
effectiveness of additional downwind controls compared to upwind
controls This section discusses these additional considerations.
1. Consistency of Regional Reductions With Attainment Needs of Downwind
Areas
a. General Discussion. Currently, air quality levels in the eastern
part of the United States are above the 1-hour NAAQS in various,
primarily urban, areas. Air quality levels are also above the 8-hour
NAAQS in those same areas, as well as many others.
The OTAG, and subsequently EPA, have conducted region-wide air
quality modeling, using the UAM-V model, which shows that in
approximately 20 primarily urban areas, the 1-hour nonattainment
problem will persist by the year 2007, even after all of the controls
specifically required under the CAA as well as Federal measures are
implemented.56 This nonattainment problem that remains after
implementation of those mandated controls may be termed ``residual
nonattainment.'' For the 8-hour NAAQS modeling shows that under the
same circumstances, at least one urban area that is linked to each
upwind State will continue to experience residual nonattainment, and
significantly more areas will be in nonattainment as well.
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\56\ As described elsewhere, the controls specifically required
under the CAA include the controls identified in the modeling
baseline, as well as certain Federal controls such as NLEV. These
controls do not include any additional reductions that may be
required in the local nonattainment areas as part of their
attainment demonstrations.
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Further, as discussed above, OTAG's subregional modeling as well as
EPA's CAMx modeling and State-by-State zero-out UAM-V modeling,
indicate that upwind States contribute significantly to those downwind
nonattainment problems under both standards. In general, under the 1-
hour standard, emissions from each upwind State affect at least
several, primarily urban, nonattainment areas downwind. For example,
each of the midwest/southern States of Ohio, Kentucky, Tennessee, West
Virginia, Virginia, and North Carolina affects between five and eight
downwind nonattainment areas. Under the 8-hour standard, emissions from
each upwind State affect nonattainment problems that comprise an even
larger geographic area. For example, Ohio, Kentucky, Tennessee, West
Virginia, Virginia, and North Carolina each affect between eight to
thirteen downwind States with nonattainment problems.
As described in section IV below, EPA has conducted additional
regionwide modeling which shows that upwind reductions comparable to
those required under today's rule have an appreciable impact on
downwind nonattainment problems under both NAAQS. The downwind impact
from each individual upwind State's reductions may be relatively small,
but the impact from all upwind reductions, collectively, is
appreciable. This regionwide modeling-- which employs the UAM-V model
relied upon by OTAG and also used by EPA for today's action--indicates
that even after implementation of the regional reductions, which help
downwind areas make progress toward attainment, certain downwind areas
under the 1-hour NAAQS, and numerous downwind areas under the 8-hour
NAAQS, will experience residual nonattainment. In addition, under the
8-hour NAAQS, many other areas with nonattainment problems are expected
to reach attainment based solely on the regional reductions.
Furthermore, as mentioned earlier, the above-described modeling
indicates no upwind States whose required regional reductions, in
combination with the other regional reductions and CAA required
controls, provide more ozone reduction than is necessary for every
downwind nonattainment problem affected by that upwind State to attain
under each NAAQS. That is, there is no instance of ``overkill,'' so
that none of the upwind reductions required under today's action is
more than necessary to ameliorate downwind nonattainment.
b. 8-Hour Nonattainment Problems. As indicated above, the upwind
reductions are useful in ameliorating downwind nonattainment under both
NAAQS, but they are particularly useful in areas with nonattainment
problems under the 8-hour NAAQS because more areas have such problems
under that standard. Emissions reductions from each upwind State affect
a broader swath of downwind 8-hour nonattainment problems, including
problems adjacent to, and further away from, the upwind State. For
example, emissions from Ohio affect nonattainment problems in each
State adjacent to Ohio, as well as numerous States further away. As
noted above, in some cases, the upwind reductions eliminate the
downwind nonattainment problem; in other cases, those reductions
ameliorate the downwind problem but residual nonattainment remains.
Moreover, under the 8-hour NAAQS, upwind contributions tend to be a
particularly large percentage of the downwind nonattainment problem.
For example, along the Northeast corridor, cumulatively upwind States
including adjacent States, contribute 83 percent of
[[Page 57404]]
Washington, DC's nonattainment problem; 68 percent of Maryland's
nonattainment problem; 65 percent of Pennsylvania's nonattainment
problem; and 85-88 percent of each of New Jersey's, New York's,
Connecticut's, and Massachusett's nonattainment problems. These high
levels of upwind contributions to widespread nonattainment problems--
both near to, and far from, the upwind State--indicate that the
regional reductions from the upwind areas may be expected to be useful
in ameliorating downwind nonattainment under the 8-hour NAAQS.
c. Commenters' Concerns. Commenters argued that in the NPR that EPA
failed to demonstrate that the proposed reductions in upwind emissions
were necessary for downwind areas to demonstrate attainment. Commenters
pointed out the lack of local attainment demonstrations under the 1-
hour NAAQS.57
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\57\ As noted in Section II.A., EPA proposed two analytical
approaches, the second of which is the same as EPA is today
promulgating. The commenters's criticisms seem to apply equally to
both approaches.
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The EPA does not believe a local attainment demonstration is
required before EPA can call on upwind States to reduce emissions
pursuant to section 110(a)(2)(D). The EPA believes that available
modeling analyses demonstrate that upwind reductions are necessary to
help downwind areas come into attainment. The OTAG and EPA subregional
modeling, UAM-V State-by-State zero-out modeling, and the CAMx
modeling, described above, link each upwind State's emissions and
downwind attainment needs, in a manner that is sufficient to support
today's action. To reiterate, under the 1-hour NAAQS, the emissions
reductions from each upwind State, combined with other emissions
reductions, are needed to reduce downwind nonattainment problems. That
need is underlined by the fact that the modeling relied on for today's
action indicates residual nonattainment after implementation of all
required controls and Federal measures. Even after implementation of
the regional reductions, there is residual nonattainment for at least
one downwind area linked to each upwind State. The same is true for the
8-hour NAAQS, as noted above.
The EPA recognizes that in the future, additional information may
become available that would shed further light on the amount of
emissions reductions needed for downwind areas to attain the NAAQS.
Local-scale modeling may indicate more precisely the ambient impact of
regional and local reductions on downwind nonattainment areas and the
amount of any residual nonattainment. Nevertheless, it should be
emphasized that the models relied on for today's action are state-of-
the-art, and that their various inputs--particularly the inventories--
have recently undergone close scrutiny and careful refinement through
public comment and expert analysis. Accordingly, EPA believes that the
overall model results indicating the general impact of upwind emissions
and reductions in emissions should be viewed as valid. Accordingly, EPA
believes that it has an adequate base of information to require the
regional reductions under the 1-hour and 8-hour NAAQS at this time.
2. Equity Considerations
The EPA believes further justification for today's action is
provided by overall considerations of fairness related to the control
regimes required of the downwind and upwind areas, including the extent
of the controls required or implemented by those areas.
The OTAG and EPA modeling analyses clearly indicate that upwind
emissions contribute more than trivial amounts to downwind
nonattainment problems. As a result, upwind emitters are exacerbating
the health and welfare risks faced by those who live and work in
downwind areas afflicted with unhealthful levels of ozone. The EPA
believes that the principle of simple fairness applies here: upwind
States should reduce their emissions that visit those health and
welfare problems upon their downwind neighbors. Otherwise, their
downwind neighbors would be obliged to pay additional costs to reduce
local emissions beyond what would otherwise be necessary to protect
their health from upwind emissions. In EPA's judgment, it is fair to
require the upwind sources to reduce at least the portion of their
emissions for which highly cost-effective controls are available.
Indeed, fairness considerations would point towards requiring upwind
reductions even if there were some degree of cost inefficiency.
Further, it should be recognized that the major urban nonattainment
areas have been required to incur control costs for ozone precursors
since shortly after the 1970 CAA Amendments. In general, over the past
quarter of a century, these areas have implemented SIP controls that,
in combination with Federal measures, place ozone-related controls on
virtually all portions of their inventory of ozone precursors,
including VOCs as well as NOx. The Air Quality Modeling TSD
includes descriptions of the control measures in place for several
major urban nonattainment areas. Although not every major urban
nonattainment area has complied with every CAA requirement for ozone
precursors, the major urban nonattainment areas have complied with
almost all of these requirements, and the CAA provides remedies to
assure complete implementation of the required provisions. These
measures have already lead to substantial reductions in ozone levels.
By comparison, upwind States have not implemented reductions intended
to reduce their impact on downwind nonattainment areas.
3. General Cost Considerations
The EPA also generally considered the cost-effectiveness of
additional local reductions in the 1-hour ozone nonattainment areas.
The EPA conducted this analysis as part of its Regulatory Impact
Analysis, completed under Executive Order 12866, for the rulemaking in
which EPA revised the ozone NAAQS, 62 FR 38866 (July 18, 1997). The EPA
surveyed the additional VOC and NOx controls available in
areas throughout the country that are expected to be nonattainment
under either NAAQS. The EPA ascertained that nationally, on average,
these additional measures would cost approximately $4,300 per ton
removed during the ozone season. See ``Control Measures Analysis of
Ozone and PM Alternatives: Methodology and Results,'' July 17, 1997,
table VII-2, p. 56. Although this figure is a national average, it
provides a basis to conclude that local reductions may be expected to
be more expensive than the approximately $1,500 in cost per ozone-
season ton removed for the regional NOx reductions required
in today's rulemaking.
Commenters criticized EPA's proposal to measure cost-effectiveness
in terms of cost per ton of emissions removed because it did not take
into account the ambient impact downwind of the emissions reductions.
Commenters cautioned that under certain circumstances, a high level of
emissions reductions upwind may result in high costs (even though cost-
effective on a per-ton basis), but relatively little ambient benefit
downwind. Commenters emphasized that emissions reductions tend to have
the greatest ambient benefit when they are within, or adjacent to, the
area with the nonattainment problem. Commenters also said that
emissions reductions further upwind have less ambient benefit.
Accordingly, commenters stated that EPA's cost-effectiveness
[[Page 57405]]
justification did not support its proposed reduction requirements.
The EPA acknowledges the concerns expressed by the commenters that
focusing solely on the cost effectiveness, defined in terms of cost per
ton removed, of the emissions reductions would exclude consideration of
the total costs incurred by the upwind sources, and would exclude
consideration of the downwind ambient benefits that those costs
achieve, compared to the costs of achieving the same ambient impact
through either local reductions or more extensive reductions in
adjacent upwind areas. The EPA further acknowledges air quality
modeling makes clear that reductions in emissions closer to the air
quality problem have a greater ambient impact.
However, EPA has not been presented with, nor been able to develop,
an accurate comparison of the downwind costs of emissions reductions
that would achieve the same ambient impact as the regional reductions
required by today's action. The EPA does not have comprehensive
information concerning available local measures or their costs or
ambient impacts.
However, as a qualitative matter, EPA believes that available
evidence indicates that the upwind costs are reasonable not only in
light of cost-effectiveness per ton removed, but also in light of the
downwind ambient impact of the emissions reductions. Under the 1-hour
NAAQS, emissions from each upwind State generally affect several
downwind nonattainment urban areas. Thus, matching the total ambient
impact of the emissions reductions from the upwind State would require
emissions reductions in several downwind areas.58
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\58\ Although the reductions required of any one individual
upwind State under today's rule may not, by themselves, result in
large ambient impacts downwind, those reductions, when combined with
reductions from other upwind States, do result in appreciable
reductions downwind.
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Although presently available information does not permit a useful
quantitative comparison of total upwind and downwind costs in terms of
their ambient impact, EPA believes that upwind reductions replace local
reductions that, on a cost-per-ton removed basis, may be expected to be
more expensive. Moreover, it should be recognized that for all of the
nonattainment areas under the 1-hour NAAQS, the residents have already
incurred substantial control costs to eliminate part of the local
contribution to the air quality problem. Under these circumstances, EPA
considers it equitable to require the upwind emitters to offset their
contribution to the problem through at least the reductions that are
the most highly cost-effective--in terms of cost-per-ton removed--
rather than require the residents of the downwind area to offset those
upwind contributions through even more local control measures.
Furthermore, under the 8-hour NAAQS, the available information--
again, on a qualitative basis--indicates that the upwind emissions
reductions replace a significantly greater set of local measures. As
indicated above, emissions from each upwind State affect a wide swath
of downwind areas with nonattainment problems. As a result, the
emissions reductions from the upwind State replace local reductions in
numerous downwind areas. Moreover, some of these downwind areas are
adjacent to the upwind State, while others are further away. Thus,
under the 8-hour NAAQS, EPA believes that the qualitative case is even
more vivid that the upwind emissions reductions replace substantial and
costly local measures.
Finally, with respect to the meteorological phenomenon that upwind
reductions have less ambient impact the further away they are from the
downwind nonattainment problem: EPA modeled the ambient impact of
regional variations in the levels of upwind emissions reductions. This
modeling, and its results, are discussed in the Air Quality TSD. In
brief, the modeling results indicate that it is neither more cost-
effective nor more beneficial to air quality to pursue subregional
variations in upwind emissions controls.
4. Conclusion
For the reasons discussed above, EPA believes that adequate
information is available to determine, on a qualitative basis, that the
upwind reductions required by today's action are reasonable in light of
the attainment needs downwind, and that the costs of those reductions
are reasonable in light of the costs the downwind areas would otherwise
face. For these and other reasons noted elsewhere, EPA believes that
requiring the regional reductions in today's notice is a reasonable
step to take at this time.
Of course, as more comprehensive information becomes available
(including additional modeling, additional information concerning local
control options and costs, as well as more refined regional air quality
information), EPA will continue to examine the issue of regional
transport. In addition, as described in Section III., EPA expects to
review the issue of regional transport by the year 2007 and may require
additional steps by either the upwind States or the downwind States, or
both, to address the issue further. Even so, as noted above, the
information that is available provides no evidence that the regional
reductions required today may prove not to be needed.
III. Determination of Budgets
The EPA used the highly cost-effective measures identified in
Section II.D. above to calculate the amounts of emissions in each
covered State that will contribute significantly to nonattainment or
interfere with maintenance in one or more downwind States (the
``significant amounts''). This Section further describes issues related
to cost-effective controls and the role of these controls in the
calculation of budgets.
First, as described earlier in this notice, EPA projected the total
amount of NOX emissions that sources in each covered State
would emit, in light of expected growth, in 2007 taking into account
measures required under the CAA (the ``2007 base year emissions
inventory''). The EPA then projected the total amount of NOX
emissions that each of those States would emit in 2007 if each such
State applied these highly cost-effective measures (2007 controlled
inventory). The difference between the 2007 base inventory and the 2007
controlled inventory for each covered State is the ``significant
amount'' that the State's SIP must prohibit to satisfy section
110(a)(2)(D)(i)(I). Each covered State's 2007 controlled inventory--
referred to in this Section as the State's ``emissions budget''--
expresses the total amount of NOX emissions remaining after
the State's SIP prohibits the ``significant amount'' of NOX
emissions in that State. Each covered State must demonstrate that its
SIP includes sufficient measures (of the State's choice) to eliminate
those emissions, and thereby meet its budget, in the time frames
discussed later in this notice.
A. General Comments on the Base Emission Inventory
Background: In the NPR, EPA solicited comment on technical
information used in revising the 1996 base year emissions inventories
and the growth and control assumptions used to develop the 2007
projection year base inventories. The EPA received over 200 comment
letters (from industry, associations, States, environmental
organizations, and U.S. Congressional representatives) on the condition
of 1996 base year and projected 2007 emission inventories. The EPA
accepted
[[Page 57406]]
proposed modifications to the extent EPA was able to validate them.
As discussed in the NPR (62 FR 60318), EPA established a 120-day
comment period (ending March 9, 1998) to address issues related to the
proposed rule. In order to develop revised inventories used to
recalculate the budgets for final rulemaking in a timely manner, EPA
felt that comments received after the March 9, 1998 deadline would be
addressed only if time and resources were available and after directing
attention to comments received prior to the end of the comment period.
The EPA is legally obligated under the Administrative Procedure Act to
respond only to comments timely submitted during the public comment
period. Response to comments timely submitted before the end of the
comment period fulfills EPA's obligation to 5 U.S.C. 553(c).
Although the Agency was not able to address all comments submitted
after March 9, 1998, as discussed in Section III.F.5. of this notice,
EPA is allowing commenters an additional opportunity to request
revisions to the source-specific data used to establish each State's
budget. During this time, EPA will be addressing those comments
submitted during the NPR and SNPR comment periods which were not
addressed for reasons indicated above, as well as evaluate comments
that are submitted per Section III.F.5. of the NFR.
1. Quality
Comment: Commenters suggested that the OTAG inventory may not be of
sufficient quality for use in the modeling and budget determinations
for the non-EGU point, area, nonroad mobile, and highway vehicle source
sectors. The commenters stated that OTAG originally intended the
inventories to be used in analyzing ozone transport mechanisms and the
effect of possible control measures, not for establishing emission
budgets as EPA has proposed. Additionally, as one commenter mentioned,
many States had prepared inventories only for their moderate and above
nonattainment areas, so that the remainder of the State's counties were
supplemented with USEPA data. In contrast to these criticisms, other
commenters supported the quality of the inventories and the procedures
used in their development.
Response: Under the initial OTAG inventory collection process, the
37 States in the domain provided emission estimates for each entire
State. The majority of the supplied data were 1990 State ozone SIP
emission inventories, but some States supplied data from later years
that reflected significant improvement over the 1990 data.
Additionally, OTAG collected point source data from the States to
update and revise existing emissions inventories used by OTAG. The
result of these efforts was an improved emissions inventory which OTAG
utilized for modeling as well as strategy analyses.
The EPA used the final OTAG version of the inventory for the
emission estimates in the NPR, and then improved the inventory with
data supplied by the States and industry through the public comment
period. As a result, the revised emissions inventory is the most
accurate available for modeling, strategy analyses, and budget
calculation purposes. The inventory has been through numerous versions,
each version reviewed and extensively commented on by States, industry,
and the public. These inventory data are more accurate than any other
data used in the past as the basis for the various State-specific SIP
revisions (such as rate-of progress SIP revisions or attainment
demonstrations). The EPA considers it sufficiently accurate for
purposes of determining the budgets.
The EPA recognizes that emission inventories change as more
accurate data or methods are developed for estimating emissions. For
inventory changes that may be necessary after final promulgation of the
budgets, EPA has a process for determining what changes need to be made
as well as how the changes would be made to the inventories. This is
discussed in further detail in Section III.F.5. of this notice.
Comment: Several commenters were concerned that the initial State
NOX emissions inventories submitted by the States were never
quality-assured or commented upon by the States, the regulated
community, or the public. Some commenters suggested the reevaluation of
emissions estimates with State, local, and industry support.
Response: Under the guidance of OTAG, the initial emission
inventories submitted by the States were quality-assured by technical
experts, including State and local emission inventory contacts,
industry, EPA staff and contractors, and the OTAG Emission Inventory
Technical Committee. As EPA amended and modified the inventory for use
in the modeling for the NPR, SNPR, and the budget analyses, additional
quality assurance was completed. The most accurate inventory
development tools available at the time were used to validate these
data and to quality assure emission calculations in these data bases.
Existing data sets, including the NET data, the OTC NOX
Baseline emission inventory, EPA'S AIRS/AFS major point source
reporting system, and EPA's Emission Tracking System (ETS), which
contains data submitted and certified as correct by the States, were
used for comparison purposes. Where discrepancies were found, either
before, during, or after the public comment period, States and industry
were contacted to clarify and support revised emission estimates.
2. Availability
Comment: Commenters asserted that the emissions inventory used for
the SIP modeling and budget calculations were not made available for
public review along with the proposed rule. One commenter stated that
the emissions inventory that forms the basis for the NPR (the SIP Call
inventory) did not become available until the first week in February
1998.
Response: On October 10, 1997, EPA posted emissions data on the TTN
for use and review during the public comment period (See NPR, 60318).
These data, in conjunction with the OTAG inventories, were the basis of
the initial proposed budgets and modeling analyses in the NPR. Thus,
these data were available to the public before the beginning of the
120-day comment period on the NPR, which allowed ample time to develop
budget, modeling, and cost analyses for submission during the comment
period. By notice dated January 28, 1998 (63 FR 4206), EPA issued a
caution that comments on the inventory must be submitted by the March
9, 1998 close-of-public-comment date, so that EPA could finalize the
inventories and use them for further analyses.
On February 3, 1998, in response to initial public comments and
internal review of the initially released data, draft amendments to the
emissions inventory were posted on the EPA's TTN site. These changes
included the addition of EGU sources less than or equal to 25 MWe which
were excluded from the initial budget calculation, correction of EGU
growth factors, and the reclassification to the non-EGU file of some
sources previously erroneously identified by OTAG as EGU sources.
Erroneously omitted non-EGU point source records were also added to the
emissions inventory. Area, highway, and nonroad mobile source
information was not modified in this iteration. By posting this data on
February 3, 1998, EPA allowed 5 more weeks for public comment on the
revised data, until the conclusion of the comment period for inventory
data on March 9, 1998. Because the revisions were fairly minor, EPA
believes this amount of time was adequate. The EPA did receive
[[Page 57407]]
comments by March 9, 1998 on the revised data it had posted on February
3, 1998.
B. Electricity Generating Units (EGUs)
Background: To determine the budget for each State's electricity
generating sector, EPA developed an inventory of baseline heat input
(mmBtu) and NOX emissions (tons/season) data for each unit.
In the NPR, EPA proposed to use the higher, by State, of 1995 or 1996
heat input data to calculate baseline heat input rates (62 FR 60352).
The EPA maintained this approach for the SNPR, but added 577 smaller
units to the State budget inventories, which had erroneously been
omitted for the NPR. These units included electricity generating
sources of 25 megawatts of electrical output (MWe) or smaller and
additional units not affected under the Acid Rain Program.
1. Base Inventory
Comment: Commenters suggested that using the higher of 1995 or 1996
utilization rates for setting the baseline for the EGU portion of the
budget may not be appropriate in all instances. In general, commenters
argued for various degrees of flexibility in choosing the baseline
year(s) to be used for calculation of budgets.
Response: As discussed below, EPA has made corrections to the
baseline heat input data for a small number of EGUs based on careful
review of the data supplied with source-specific comments. Using 1997
CEMS data is not a practical option because EPA has not had time to
extract from the Acid Rain Emissions Tracking System (ETS) the 5-month
ozone season heat input values, quality assure them, or publish them.
(Although EPA's Acid Rain Program intends to publish its 1997 Emissions
Scorecard later in 1998, this publication will contain only annual, not
ozone season, data.) Accordingly, EPA has finalized the EGU portion of
the budget for each State using the higher of the 1995 or 1996 ozone
season heat input values.
Comment: Commenters asserted revisions were needed to the published
heat input data for some EGUs and proposed related additional source-
specific changes. Commenters on this issue stated that inaccurate
calculations of heat input data resulted in significant errors in the
Statewide budgets. Several suggested the need for revision before
calculation of final budgets. Many of these commenters provided
specific data that they urged EPA to use in the final budget setting
process.
Response: The EPA has analyzed the data submitted by these
commenters and, where warranted, has made the requested adjustments.
Approximately 200 corrections were made to the baseline heat input data
for EGU sector inventories.
Comment: Commenters also noted the need to further correct, for
some States, the listing of units in the electricity generating sector
inventory. Commenters listed specific EGUs that EPA should either
include or remove from the inventory, or for which EPA should correct
applicable baseline data (e.g., capacity, operating parameters).
Several commenters argued that substantial revision of the inventory
was necessary before setting budgets under the final rulemaking.
Response: The EPA has analyzed the data submitted by these
commenters, including following up with commenters when needed to
assure proper interpretation of the data. Where warranted, EPA has
corrected the State inventories of units and applicable baseline data.
While the vast majority of corrections consisted of adding small
units (e.g., municipal generators and peaking diesel units), combustion
turbines, and independent power producers not affected under the Acid
Rain Program, some involved deleting units that are no longer
operational or have been misclassified and, in actuality, are
industrial non-electricity generating boilers. The net result is that
EPA has added approximately 800 units to the State EGU inventories. The
EPA believes that these inventories are sufficiently accurate to
develop a budget.
Comment: Commenters suggested types and sizes of sources to include
or exclude from the electricity generating sector inventory. As to the
sizes of sources to include in the inventory, commenters on the NPR
were roughly split on the inclusion of units less than or equal to 25
MWe. Several noted that emissions from sources below this level were
negligible and should not be included. One commenter noted, however,
that these sources should be included in the final budget because they
tend to operate on peak demand days which frequently correspond to high
ozone days. Several suggested that 15 MWe be the cutoff for the utility
component of the budget.
On a separate concern, a few commenters disagreed with the
inclusion of non-utility power generators in the utility list of
sources and proposed that they be included with industrial non-
electricity generating unit sources.
Response: Many of these comments appear to confuse discussions of
other related issues (e.g., core sources for NOX cap and
trade rule, appropriate sources for cost-effective control) with the
types and sizes of EGUs to be included in the baseline inventory for
setting the budget. All emissions should be included in the base
inventory and, thus, in the budget. As noted previously, using
information supplied by commenters, EPA has agreed to add many small
units to the base inventories of several States. Concurrently, EPA has
also decided not to classify EGUs less than or equal to 25MWe as core
sources for the trading program, as discussed in Section VII of this
notice, or to assume an emissions decrease for these small units
(``cutoff level'') as part of Statewide budgets for EGUs.
The EPA maintains its decision to include industrial units that
generate electricity in the definition of EGUs is entirely consistent
with the changing, more competitive, character of today's electric
power generation industry in the US. Also, these units are amenable to
the same NOX control technologies, at generally the same
cost-effectiveness, as utility units.
2. Growth
Background: In the NPR and SNPR, EPA used forecasts of future
electricity generation to apply State-specific growth factors in
calculating the emissions budgets for the electricity generating
sector. In the SNPR, EPA revised the growth factors (the ``corrected''
projections) to account for projected new combustion turbine and
combined cycle units inadvertently excluded in the analysis developed
in support of the NPR. The EPA also discussed in the SNPR that
``revised'' electricity generation projections could lead to lower
growth rates, and therefore lower budgets, and placed supporting
information in the docket. However, EPA proposed to use the
``corrected'' projections in calculating State budgets to provide
additional compliance flexibility to sources and States (63 FR 25905).
a. Growth Rates.
Comment: The EPA received approximately 36 comments in response to
the NPR and roughly 28 comments in response to the SNPR regarding the
estimated growth rates that were used to determine the NOX
budget for each State. These comments were submitted by State agencies,
associations, utilities, and a public interest group. Commenters
expressed concern regarding a number of specific issues, including the
following:
(i) the appropriateness of using growth factors to determine the
NOX budget,
[[Page 57408]]
(ii) use of the IPM model to establish the growth factors for each
State, and
(iii) the use of the ``corrected'' instead of the ``revised''
projections.
Some of these commenters opposed growth factors generally, but many
of them supported the concept of--but not the method proposed for--
applying a growth factor.
Response: The OTAG's technical analyses of NOX emissions
suggested that EPA needed to consider the electric power industry's
future growth in determining the amount of NOX reduction
that would be reasonable for the power industry to make in the future.
The OTAG factored the growth of the power industry's emissions from
1990 to 2007 into the air quality analysis that it performed. The
results of this analysis were the basis of its recommendations to EPA
to lower NOX emissions from the power industry in many
Eastern States. Because the Agency made its predictions about
attainment in 2007 based on projections of emissions considering
growth, rather than on historical emissions, the Agency also believes
that the State budgets to be used up to 2007 should account for growth
in electricity demand. Not accounting for growth in demand for
electricity would require States to reduce emissions below the level
that EPA predicted was necessary to reach attainment. By accounting for
growth through 2007 and applying that growth beginning in 2003, EPA
essentially allows sources to emit at a slightly higher level than 0.15
lb/mmBtu in the years 2003 through 2006.
In today's action, the Agency has determined to continue to
incorporate growth out to 2007 in developing State budgets for summer
NOX emissions. Not accounting for growth would mean that
additional control measures--to offset growth--would be required, and
EPA has not determined that those additional control measures would be
cost-effective. In considering growth, EPA has determined to continue
to use either 1995 or 1996 State-wide heat input data, for whichever
year was higher for units over 25 megawatts that burn fossil fuels for
baseline data. (More details on this approach can be found above in
Section III.B.1. Base Inventory).
To estimate growth, EPA considered several options. Ultimately, the
Agency has decided to use State-specific growth factors derived from
application of the Integrated Planning Model (IPM) using the 1998 Base
Case 59 (also referred to as the ``revised'' growth
factors). This is the same Base Case used for the Regulatory Analysis
in support of the SNPR. The reasons for using these data are discussed
below under ``Use of IPM.''
---------------------------------------------------------------------------
\59\ The Base Case is the condition of the industry in the
absence of the SIP call.
---------------------------------------------------------------------------
b. Use of IPM.
Comment: Many commenters questioned whether use of the IPM model
was appropriate to derive accurate State-specific growth factors.
Commenters expressed concern that there was too much variation between
each State's individual growth rate as determined by the IPM model, and
suggested that use of region-wide IPM growth factors may be more
appropriate. They also questioned the reliability and accuracy of the
IPM model, especially as applied on an individual State basis. A number
of commenters stated that EPA's growth projections were lower than
growth rates projected in the context of State utility planning
efforts. Several commenters suggested that EPA base its growth rates on
projections other than OTAG, or EPA's IPM forecasts; they especially
urged the Agency to consider individual State-prepared forecasts. This
was to avoid problems that commenters believe exist in EPA's use of the
IPM model for forecasting electricity generation in various areas of
the country. Specific concerns focused on:
(i) the effect of IPM projections and associated NOX
budgets on future growth within each State, and
(ii) how the IPM model accounts for:
--planned nuclear unit retirements,
--the impact of a deregulated utility marketplace, and
--improvements in energy efficiency and control technology.
Many commenters also generally expressed concern that there is
insufficient information or documentation on how EPA used the IPM model
to determine growth factors.
Many commenters asserted that EPA should not incorporate the growth
factors into the budget calculation process. These commenters argued
that adding growth to baseline activity and subsequently applying
controls reduces the stringency of the standards, and introduces an
unacceptable level of uncertainty. They suggested that the budgets
should be based on historic utilization rates, and that States could
then determine how to allocate their budgets to provide for growth.
These commenters recommended that, if a growth factor must be used,
then EPA should apply a uniform growth rate region-wide to determine
the NOX budget for each State.
Response: The EPA initially considered using the OTAG growth rates,
but found that they were largely based on past, State-specific
generation trends and did not factor in the more competitive electric
power market where electricity will be increasingly moving between
regions in response to the cost of producing electricity. The Agency
also found that there were several other major limitations that were
described in the NPR. (62 FR 60352-60353).
The Agency considered setting the State NOX budgets
based on past generation levels in States, but this approach also does
not consider how competition in the industry in the future will alter
electricity generation practices. It ignores growth and shifts in
production altogether. A variant of this approach, suggested by several
commenters, would be to use a uniform growth factor for all States
based on some projection of future growth through the 23 jurisdictions
covered by this rule. This approach appears even-handed, but EPA views
it as unfair and inaccurate with respect to States in which:
(i) utilities are particularly economical to operate, and
(ii) the generation of power by these firms is expected to grow at
a rate greater than average.
Another similar alternative suggested in the public comments was
that EPA use a uniform growth factor for all States in the same region,
e.g., the North American Electricity Reliability Council (NERC)
regions, or subregions. The problem with this approach is, again, that
certain States within the same region are expected to vary in their
rate of growth, given differences in their electric utilities. The fact
that some States are in several NERC regions also makes this approach
less practical.
The Agency looked at several well-recognized forecasts of regional
electricity generation growth, such as those provided by NERC, the
Annual Energy Outlook of the Energy Information Administration (EIA),
and Data Resources Incorporated's (DRI) World Energy Service U.S.
Outlook. None of these modeling systems provides results at the State
level. Therefore, the Agency would have to develop ways to apportion
these regional predictions to States. The EPA knows of no way to
apportion these regional values to States that would resolve the
concerns expressed by commenters. Furthermore, the Agency uses the
growth rates from IPM to calculate the cost-effectiveness of
NOX emission reductions, as well as to determine
NOX budgets for States. Therefore, using growth rates that
are not from IPM would lead the Agency to using one set of State-
specific
[[Page 57409]]
generation estimates to develop NOX budgets and a different
set of State-specific generation estimates for determining cost-
effectiveness. As a result, EPA's evaluations of future activities of
the power industry might not be considered consistent. Finally,
although each of these sources provides reasonable electricity
generation forecasts, each of the forecasts could be criticized for the
assumptions they make in a manner similar to the way commenters have
criticized growth factors from IPM.
Some commenters suggested that the Agency use individual State
forecasts instead of IPM forecasts, including projections used for
State utility planning efforts. The EPA rejected this type of approach
for two reasons. First, nothing in the comments suggested to EPA that
the State forecasts are more accurate or more reliable than the IPM
forecasts. Instead, the State forecasts varied State by State in the
way they predicted future electricity generation. Adoption of these
forecasts could result in inconsistencies in setting the State budgets.
Electricity generation forecasts require making many technical
assumptions which, admittedly, lead to some uncertainty in the results.
Accordingly, the Agency believes that the fairest way to determine
emissions budgets is to handle these assumptions in a consistent way
for all of the States, as long as a reasonable approach and reasonable
modeling assumptions are used.
Therefore, EPA has decided to use the IPM 1998 Base Case emissions
forecast for deciding State NOX budgets in today's action.
The Agency finds it to be the fairest and most reliable overall
approach to estimating growth factors. It deals consistently with the
technical assumptions that occur in energy forecasting and employs a
reasonable set of assumptions in the process of making a forecast. As
an added advantage, it has undergone considerable review by the
electric power industry over the last two years, and the industry was
aware that it might be applied as it is in today's rulemaking. Finally,
EPA's use of IPM for forecasting State growth rates provides for
overall consistency in forecasting future emissions and estimating the
cost-effectiveness of reductions in this rulemaking.
The EPA believes that IPM provides a reasonable forecast of State
growth rates because it carefully takes into account the most important
determinants of electricity generation growth that are facing the power
industry today. These major factors include: regional demands for
electricity, the impacts of wholesale competition that lead to changes
in market share for various utilities, changes in fossil fuel prices,
expected improvements in electricity generation technology, costs of
emission control technology, expected changes in generation unit
operations and regional dispatch practices to lower production costs,
nuclear unit retirements, alteration in planning reserve margins to
meet peak demand, and limitations in moving power between regions due
to transmission constraints.
An explanation of how EPA uses IPM to address these issues and
other important factors is included in EPA's Analyzing Electric Power
Generation under the CAAA, March 1998 (Docket no. V-C-3). Because EPA's
assumptions have been reviewed by the public over the last two years
and the Agency has worked with EIA and other groups to improve them in
response to comments and new information, the Agency believes that it
has made reasonable assumptions for a Base Case forecast of electric
power generation.
c. Use of ``Corrected'' Growth Rates.
Comment: Some comments on the SNPR expressed concern that the new
``corrected'' growth factors are artificially inflated and will
compromise efforts to improve air quality throughout the region. Some
of the commenters suggested that States should have the flexibility to
determine how to manage emissions from new sources in the context of
the original growth factors and NOX budgets proposed in the
NPR. Some of these commenters also stated that it was unclear why EPA
chose to use the ``revised'' projections in its cost analysis but
retained the ``corrected'' growth factors in its budget calculations.
Other commenters, however, were supportive of the new growth factors
and the use of the ``corrected'' projections. Finally, several
commenters requested that EPA further explain how the ``corrected''
growth factors were derived and subsequently used to generate the
NOX budgets.
Response: In the NPR, EPA proposed a set of growth factors based
upon the 1996 IPM Base Case forecast. In the SNPR, EPA corrected the
growth factors used in calculating State budgets to account for new
generation that had inadvertently been left out of the original
calculations (the ``corrected'' growth factors). On the basis of
comments that EPA has received on its assumptions for forecasting
electricity generation throughout the country during the last year, the
Agency revised a set of key assumptions at the beginning of 1998. These
assumptions lead to a better projection of electricity generation
nationally, by region, and by State. Therefore, the Agency has decided
to use the 1998 IPM Base Case forecast over the 1996 IPM Base Case
forecast as the basis for its ``revised'' State growth estimates.
The recent important changes that were incorporated into EPA's use
of IPM in 1998 include using the most recent NERC estimate of regional
electricity demand; the latest available EIA and NERC generation unit
data; updated fuel forecasts; updated assumptions on nuclear,
hydroelectric, and import assumptions (with special attention to
differences in summer use); and an increase in the level of detail in
the model to more accurately capture the transmission constraints that
exist for moving power between various regions of the country. The
Agency also updated its assumptions on the size and operation of all
electricity generation units of utilities and independent power
producers (with special attention to cogenerators) and updated its
assumptions on planning reserve margins and the costs of building new
generation capacity. For this, the Agency relied heavily on information
compiled from utilities by NERC and the EIA. Each of these agencies has
regular contact with the power industry and has its data reviewed by
the power industry. Again, details on these improvements in IPM can be
found in EPA's Analyzing Electric Power Generation under the CAAA,
March 1998 (Docket no. V-C-3).
In the SNPR, EPA used the ``revised'' growth factors in the IPM
model in its cost analysis but used the higher, ``corrected'' growth
factors to calculate State budgets. The EPA proposed the higher growth
factors because the Agency believed that this results in less cost and
more flexibility for sources to achieve their budget reductions
beginning in 2003. However, some commenters pointed out that EPA had
provided sufficient flexibility by accounting for growth to the year
2007 and applying that growth estimate beginning in 2003. These
commenters remarked that it was not necessary to add further
flexibility by using the higher, but less current and less accurate,
``corrected'' growth rates. They also stated that EPA should use the
most up-to-date information available. The EPA agrees and is using the
``revised'' growth rates based upon the 1998 IPM Base Case forecast to
calculate the State budgets used in today's final rule.
3. Budget Calculation
a. Input vs. Output.
Background: In the SNPR, the component of each State's budget
assigned to electricity generation was determined using the State's
total heat
[[Page 57410]]
input, applicable emission rate (0.15 lb/mmBtu), and projected growth
in total heat input to 2007. The Agency solicited comment on an
alternative approach to calculating the State's budget using each
State's share of the 23 jurisdiction electricity generation (electrical
output). The SNPR describes in detail the output-based approach, and
its possible benefits as advanced by its proponents (63 FR 25907). The
Agency asked for comments on the appropriateness, legality, rationale,
and methodology for incorporating the output-based approach when
calculating the electricity generation component of each State's
budget.
Comments: The Agency received comments both supporting and opposing
output-based State budgets. Supporters of output-based budgets
asserted:
An output-based budget would promote competition among
different types of electricity providers on an equal basis in a
deregulated electric utility industry.
An output-based budget would promote CO2,
mercury, SO2 and off-season NOX reductions beyond
what would occur under a system that assigns State budgets based upon
input.
An output-based budget may result in more cost-effective
NOX reductions.
Issuing output-based budgets is legally permissible.
The commenters opposed to output-based State budgets objected to
the allocation of allowances to non-NOX-emitting units, such
as nuclear, hydroelectric, solar, or geothermal power plants. They
claimed that this would make compliance more difficult and more costly
for fossil-fuel burning sources because fewer allowances would be
allocated to them.
Commenters opposed to output-based budgets also claimed that:
Output-based budgets would not necessarily improve energy
efficiency compared to existing incentives, such as fuel costs.
The output-based State budgets may not result in the same
geographic distribution of emissions as would occur under the original
budget allocation.
There could be significant administrative problems with
changing the basis of the State budgets.
In addition, some commenters, though in general supporting
allocations by output, specifically objected to allocating allowances
to nuclear-powered units because they believed that this method would
encourage nuclear-powered electrical generation, which, they further
believed, would have adverse ancillary impacts on the environment.
The Agency received additional comments on the method of allocating
State budgets to sources. Further discussion of these comments can be
found in Section VI.C.2 of this preamble.
Response: The EPA has an extensive history of promoting the
efficient use of natural resources, particularly energy, through both
voluntary and regulatory measures. Key emissions standards, such as the
standards for new vehicles and the recently promulgated new source
performance standards to new power plants, are written as output-based
fuel-neutral performance standards that promote the efficient use of
energy. The EPA has begun to work with States to find mechanisms to
more directly credit the use of energy efficiency measures in SIP. The
EPA also has a number of programs that encourage the use of energy
efficient technologies by providing energy users, particularly in the
residential, commercial and industrial sectors, with information on the
economic and environmental benefits of such technologies.
Although the Agency has concluded, for the reasons stated below,
that heat-input-based budgets to States are more appropriate at this
time, the EPA intends to work with stakeholders to overcome existing
obstacles and to design an output allocation system that could be used
by States as part of their trading program rules in their SIPs and by
EPA in future allocations to States.
The EPA considered how State NOX budgets would be
changed using the output approaches suggested by the commenters. The
EPA revised its State budget calculations using available electrical
generation data from the EIA for utility and non-utility generators for
the higher electrical generation output of either 1995 or 1996, by
State. In Table III-1 below, Column 2 presents the proposed budgets
based upon heat input. Column 3 presents the revised budgets based upon
heat input and the revised growth factors. Column 4 shows output-based
budgets, based upon all electrical generation. Some commenters
suggested including fossil-fuel and renewable energy source
generation--including hydroelectric, solar, wind, and geothermal
generation--but not nuclear generation. These are included in Column 5.
One commenter suggested using electrical generation from fossil-fuel
only, which is included in Column 6.
Table III-1.--State Budgets by Energy Source Basis
(Higher of 1995 or 1996 EIA data]
----------------------------------------------------------------------------------------------------------------
Column 1 Column 2 Column 3 Column 4 Column 5 Column 6
----------------------------------------------------------------------------------------------------------------
Proposed input- Revised input- Output-based
based budgets based budgets Output-based budgets--all Output-based
State fossil fuel- fossil fuel- budgets all generation budgets fossil
burning burning generation sources except fuel-burning
generators generators sources nuclear generators
----------------------------------------------------------------------------------------------------------------
Alabama......................... 30644 29026 34832 35068 32744
Connecticut..................... 5245 2583 7677 5156 4456
Delaware........................ 4994 3523 2392 3214 3417
District of Columbia............ 152 207 100 133 142
Georgia......................... 32433 30255 32223 31713 30819
Illinois........................ 36570 32045 44253 27888 29602
Indiana......................... 51818 49020 32212 43285 45831
Kentucky........................ 38775 34923 24847 33389 34166
Maryland........................ 12971 15033 13284 12969 13212
Massachusetts................... 14651 14780 11017 13248 13496
Michigan........................ 29458 28165 32275 32037 32457
Missouri........................ 26450 23923 19790 22700 23498
New Jersey...................... 8191 10863 12764 11227 11470
New York........................ 31222 30273 39503 39440 32114
[[Page 57411]]
North Carolina.................. 32691 31394 32006 30156 29866
Ohio............................ 51493 48468 39790 47143 50019
Pennsylvania.................... 45971 52006 53450 47014 48476
Rhode Island.................... 1609 1118 2242 3012 3202
South Carolina.................. 19842 16290 23252 14085 13831
Tennessee....................... 26225 25386 26410 26084 24770
Virginia........................ 20990 18258 19091 15700 15567
West Virginia................... 24045 26439 22853 30708 32527
Wisconsin....................... 17345 18029 15745 16637 16324
-------------------------------------------------------------------------------
Total....................... 563785 542007 542007 542007 542007
----------------------------------------------------------------------------------------------------------------
The Agency then calculated the effective NOX emission
rate for each State in terms of lb/mmBtu, assuming that the entire
electricity generation component of the budgets, as determined by the
input or output methods, were allocated to the electric generating
units (EGUs). The Agency wanted to evaluate whether the effective
NOX emission rate would be too low to prove feasible absent
participation by the State in an interstate NOX emission
trading program. The EPA found that under output-based State budgets
from all generation sources, three States would need to impose an
effective emission limitation of 0.10 lb/mmBtu or less on their fossil-
fuel burning electricity generators (see Column 3 in Table III-2
below). One State would need to impose an emission limitation of 0.07
lb/mmBtu. Such a low effective emission limitation may not be
technically achievable if a State chooses not to join an interstate
allowance trading program, unless the State requires some sources to
shutdown. In contrast, the Agency found that it was feasible and cost-
effective to make reductions even without an interstate NOX
trading program under an input-based State budget calculated using a
uniform NOX emission rate of 0.15 lb/mmBtu.
Table III-2.--Effective Emissions Rates for Each State by Output Basis
[Higher of 1995 or 1996 EIA data]
----------------------------------------------------------------------------------------------------------------
Column 1 Column 2 Column 3 Column 4 Column 5
----------------------------------------------------------------------------------------------------------------
Effective Effective
emission rate Effective emission rate Effective
under input- emission rate under output- emission rate
based budgets under output- based budgets under output-
State (Fossil fuel based budgets (all based budgets
burning (All generation (Fossil fuel-
generators) generation) except burning
(lb/mmBtu) nuclear) generators)
----------------------------------------------------------------------------------------------------------------
Alabama......................................... 0.15 0.18 0.18 0.17
Connecticut..................................... 0.15 0.45 0.30 0.26
Delaware........................................ 0.15 0.10 0.14 0.15
District of Columbia............................ 0.15 0.07 0.10 0.10
Georgia......................................... 0.15 0.16 0.16 0.15
Illinois........................................ 0.15 0.21 0.13 0.14
Indiana......................................... 0.15 0.10 0.13 0.14
Kentucky........................................ 0.15 0.11 0.14 0.15
Maryland........................................ 0.15 0.13 0.13 0.13
Massachusetts................................... 0.15 0.11 0.13 0.14
Michigan........................................ 0.15 0.17 0.17 0.17
Missouri........................................ 0.15 0.12 0.14 0.15
New Jersey...................................... 0.15 0.18 0.16 0.16
New York........................................ 0.15 0.20 0.20 0.16
North Carolina.................................. 0.15 0.15 0.14 0.14
Ohio............................................ 0.15 0.12 0.15 0.15
Pennsylvania.................................... 0.15 0.15 0.14 0.14
Rhode Island.................................... 0.15 0.30 0.40 0.43
South Carolina.................................. 0.15 0.21 0.13 0.13
Tennessee....................................... 0.15 0.16 0.15 0.15
Virginia........................................ 0.15 0.16 0.13 0.13
West Virginia................................... 0.15 0.13 0.17 0.18
Wisconsin....................................... 0.15 0.13 0.14 0.14
----------------------------------------------------------------------------------------------------------------
[[Page 57412]]
Advocates of an output-based approach contend that individual
sources would have the greatest incentive to improve their efficiency,
relative to all other sources in the program, if both State budgets and
individual source allocations were on an output basis and were updated
periodically. For example, if a company replaces a turbine with a more
efficient one, the unit supplying the turbine would reduce the amount
of fuel (heat input) the unit combusts and would reduce NOX
emissions proportionately, while the associated generator would produce
the same amount of electricity. Thus, the company would receive the
same allowances if an output-based allocation were updated after the
efficiency improvement. This same company would receive fewer
allowances under a system that reallocates based on heat input after
the efficiency improvement. The company would keep the same allowance
allocation if it had a permanent allocation, based upon either heat
input or output. With a permanent allocation, the company would have
more allowances available than before its efficiency improvements
because of its emission reductions, but fewer allowances than if it had
greater electrical output recognized through an updated allocation.
Thus, of the four approaches, an updated allocation based upon output
gives the greatest incentive for improving efficiency in electricity
generation.
To provide an incentive within the State budget determinations for
improving efficiency over time, EPA would need to issue the State
budgets based upon output and periodically update those State budgets.
However, many industry commenters wanted long-term or permanent
allowance allocations to allow for compliance planning. Updates to the
State budgets would require States to reallocate allowances to their
sources. In addition, States (both upwind and downwind) would find it
easier to manage their resources for improving air quality if they
receive a fixed budget for a period of years. With a fixed budget, a
State would have the choice of whether to periodically adjust
allocations rather than being required to periodically reallocate
allowances to its sources.
Finally, the Agency continues to have concerns about data available
to establish the baseline for an output-based State budget. The EIA
withholds some of the electricity generation information it collects
from non-utility generators in order to protect source confidentiality.
Therefore, part of the generation data required to establish State
budgets is not available to EPA. Thus, EPA would have difficulty in
computing and defending State budgets.
In addition, some units are cogenerators, which are electrical
generators that divert part of their heated steam to provide heat
(steam output), rather than to generate electricity. Information on
steam output from cogenerating units or from industrial boilers is not
currently available to EPA. A cogeneration unit that was included under
the State budget as an electricity generating unit based upon heat
input would only have its electrical output included in an output-based
State budget, ignoring the portion of heat input used to generate steam
output. Thus, output-based State budgets based on currently available
data could inadvertently underallocate budgets to States with many
cogenerators, which are some of the most efficient units. This could
actually discourage improvements in efficiency through cogeneration.
For the reasons stated above, the Agency concludes that it is not
appropriate to develop output-based State NOX emission
budgets at this time. However, the Agency does believe that output-
based allocations to sources could provide significant benefits. As
stated earlier in this Section, the EPA intends to work with
stakeholders to overcome existing obstacles and to design an output
allocation system based on electricity and steam generation that could
be used by States as part of their trading program rules in their SIPs.
In addition, EPA is proposing FIPs for States that do not submit
adequate SIPs by the deadline required by this final rulemaking. As
part of its proposal, the Agency is soliciting comment on source
allocations for each State based upon both input and output. While EPA
believes that the output data are not sufficiently complete or accurate
to use for final budgets or for final source allocations at this time,
the Agency is taking comment on the proposed allocations in order to
receive public comment and to develop more accurate and more complete
output data that could be used in the final FIP rulemaking.
The EPA does believe that, over the long-term, it should continue
to look at the issues that surround the use of output-based
allocations. In addition, as stated in Section III.B.5. of this
preamble, the Agency will review the progress of States in meeting
their budgets in 2007. In that review, the Agency will consider not
only whether the SIPs achieved the reductions that had been projected
to meet the budgets, but also issues such as future budget levels and
allocation mechanisms including shifting to an output-based allocation
method.
b. Alternative Emission Limits.
Comments: The EPA received numerous comments on the proposed
uniform control level of 0.15 lbs/mmBtu for the EGU sector assumptions
across the 23 jurisdictions. Many States supported this proposed
control assumption. The EPA also received a number of alternative
proposals. These contain emission-reduction assumptions ranging from
0.12 lb/mmBtu to be implemented on the schedule proposed in the NPR to
a phased approach that starts with 0.35 lb/mmBtu to be implemented by
sector and provides for further evaluation of the need for more
stringent levels. The latter commenters based their recommendations on
their views that emissions from upwind States do not have an ambient
impact that is as important as EPA believes, or that implementation of
the EGU control levels proposed by EPA would not be feasible by the
date EPA proposed. In addition, a number of utilities and other
commenters voiced concern that the proposed control assumption of 0.15
lb/mmBtu would be too stringent to provide sufficient surplus
allowances for trading.
Response: At the time of the proposal, EPA chose 0.15 lb/mmBtu as
the assumed uniform control level for EGUs because it provided the
greatest air quality improvements feasible and was cost-effective
because its cost ($1,700 per ton NOX removed in the 5-month
ozone season) was, on average, within the cost range of other controls
that had been recently promulgated or proposed. The EPA also
investigated the costs of several alternative uniform control options:
0.25, 0.20, and 0.12 (though 0.12 resulted in lower emission levels,
its average cost-effectiveness calculated at the time of the proposal
was $2,100/ton, exceeding EPA's target cost range of $1,000 to $2,000/
ton).
Subsequent to the NPR and SNPR, EPA updated its EGU costing model
(IPM) and revised stationary source emission inventories (based on
public comment). These revisions and corrections lowered the average
cost of compliance for all the control levels considered. Additionally,
EPA conducted extensive air quality modeling of a number of alternative
control levels. The results of the air quality analyses were examined
using a number of different metrics for both the one-hour and eight-
hour standards. These air quality analyses are discussed in more detail
in Section IV of this notice.
[[Page 57413]]
The revised air quality analyses show that there is no ``bright
line'' to illustrate at what control levels the air quality benefits
begin to diminish. The air quality metrics suggest there are
corresponding incremental air quality improvements at every incremental
control level. For example, tightening the control level improves ozone
levels in many non-attainment areas and leads to additional counties
achieving attainment under the one-and eight-hour standards. All
metrics analyzed show that as the control level moves from 0.25 to 0.20
to 0.15 to 0.12 lb/mmBtu, air quality benefits increase. The analyses
also show that none of the alternative control options results in
attainment of the ozone standard in all nonattainment areas.
The EPA did not select levels higher than 0.15 lb/mmBtu (such as
0.20 lb/mmBtu or higher) because the 0.15 lb/mmBtu level offers more
air quality benefits at a cost that is still highly cost-effective.
Moreover, EPA did not have information to indicate that these higher
levels could be implemented meaningfully sooner than controls at the
0.15 lbs/MmBtu level. The EPA acknowledges that the 0.12 lbs/MmBtu
emission level is also within the average cost-effectiveness range
based on the revised cost analysis. The incremental cost-effectiveness
of this option is $4,200 per ton, an incremental cost per ton which is
85 percent higher than that for the 0.15 lb/mmBtu level. However, for
reasons explained Section II.D., the EPA is not relying on this
emission level.
The revised IPM analyses project that under the 0.12 control
option, 54 percent of affected EGU capacity should install selective
catalytic reduction (SCR) and 41 percent should install selective non-
catalytic reduction (SNCR). The installation requirements for SNCR are
significantly less extensive than for SCR. The analysis of the 0.15 lb/
mmBtu control option projects 31 percent of affected EGU capacity
should install SCR and 54 percent should install SNCR. Further, the
technical record provides many examples in the United States and
internationally of the ability of coal-fired units to achieve emission
levels below 0.15 lb/mmBtu with the installation of SCR. The record
contains fewer international examples, and only one US example, of a
coal-fired unit's ability to achieve emission levels below 0.12 lb/
mmBtu.
In terms of the proposed level of control on which the trading
program budget is based, EPA believes that trading at 0.15 lb/mmBtu is
feasible because the proposed limit can readily be achieved by gas and
oil-fired boilers. In fact, more than 50 percent of gas and oil-fired
boilers already operate at NOX levels below 0.15 lb/mmBtu
and should readily be able to generate emission credits if affected
States join a trading program.
The EPA recognizes that for coal-fired boilers to operate at or
below a 0.15 lb/mmBtu emission limit, SCR would generally be necessary.
Under a trading scenario, however, if one coal-fired boiler is able to
emit below 0.15 lb/mmBtu by installing SCR, it can provide emission
credits to another coal-fired boiler and obviate the need for that
second boiler to install SCR.
A remaining issue is whether SCR can achieve NOX levels
below 0.15 lb/mmBtu. The EPA believes that SCR technology is capable
both of reducing NOX emissions by more than 90 percent and
reducing NOX rates below the proposed 0.15 lb/mmBtu limit,
provided the appropriate regulatory incentive (i.e., emission limit or
economic incentive) exists. As discussed in EPA's recent report,
``Performance of Selective Catalytic Reduction on Coal-Fired Steam
Generating Units,'' emission rates below 0.15 lb/mmBtu are currently
being achieved by a number of coal-fired boilers using SCRs. Examples
include: (1) Three Swedish boilers achieving rates between 0.04 and
0.10 lb/mmBtu; (2) six German boilers achieving rates between 0.08 and
0.14 lb/mmBtu; (3) two Austrian boilers achieving rates between 0.08
and 0.12 lb/mmBtu; and (4) four U.S. boilers achieving rates between
0.07 and 0.14 lb/mmBtu. The EPA also recognizes that these boilers,
with the exception of the Swedish boilers, have SCR systems designed to
achieve target emission limits. As a result, they fail to provide an
accurate picture of the emission levels which SCR is capable of
achieving below the target emission threshold. For this reason, EPA
cannot confidently conclude that enough units can feasibly achieve
levels at 0.12 lbs/MmBtu. In summary, EPA believes that an emission
rate of 0.15 lb/mmBtu reflects the greatest emissions reduction that
EPA can confidently conclude is feasible and that is highly cost-
effective, and provides ample allowances to sustain a market under the
NOX Budget Trading Program.
c. Consideration of the Climate Change Action Plan.
Background: The President's Climate Change Action Plan (CCAP) calls
for implementation of over 100 voluntary programs aimed at reducing
greenhouse gas emissions. A large number of them are aimed at reducing
future electricity demand throughout the country. Already, some of
these programs have shown striking results in accomplishing their
energy efficiency objectives.
Comment: Two commenters noted that it is inappropriate for EPA to
incorporate assumed reductions in energy use based on the voluntary
measures of the CCAP, which are not binding like a regulation.
Response: The EPA believes that it is appropriate to incorporate
the impact of the voluntary measures in the CCAP on future electricity
demand. The EPA has always believed that it is appropriate to
incorporate any reasonable assumptions that the Agency can support that
will affect future electricity demand, or electricity generation
practices, into its Base Case forecast. For example, improvements in
electricity generation technology, fuel prices changes, and other types
of assumptions that are important elements of EPA's forecast of
electricity generation and resulting air emissions are also not
mandated by regulation. The Agency has considered the impact of the
CCAP in using the IPM model for analysis since 1996, and documentation
of the assumptions that the Agency has been making have been available
for public review since April 1996. Until now, there have been no
challenges to this consideration in the numerous reviews that there
have been of EPA's documentation of how it uses the IPM model. Also, no
one has challenged EPA's specific approach to factoring the CCAP into
its electricity generation forecast. (This can be confirmed by
examination of the dockets for the Clean Air Power Initiative and the
Phase II Title IV NOX Rule, records of EPA's Science
Advisory Board, and the records of the Ozone Transport Assessment Group
meetings.)
The EPA updated its assumptions in IPM for the CCAP at the
beginning of 1998. The EPA updated its assumptions in the same manner
as it has done in the past--by lowering the most recent NERC demand
forecast by the amount of electricity demand between 2000 and 2010 that
the best available analysis suggests will occur due to the activities
in CCAP. The EPA used the in-depth evaluation of the future
implications of the CCAP for reducing electricity demand that was the
basis for the findings in the Administration's Climate Action Report,
July 1997. The amount of demand reduction that occurs appears in
Analyzing Electric Power Generation under the Clean Air Act, March
1998. The Climate Action Report analysis was reviewed extensively
within the Federal government by EPA, the Department of Energy and
other Federal agencies, and the report was reviewed publicly before its
publication. The EPA has not received criticism that it has overstated
[[Page 57414]]
the electricity demand reductions that are the basis for the carbon
reductions under the CCAP.
Notably, the electricity demand reductions were distributed evenly
throughout the United States, and therefore have no influence on the
share of the total amount of NOX emissions that each State
receives. Furthermore, the Agency examined the implications on its
cost-effectiveness determination of not including the CCAP reductions
in its electricity demand forecast. The EPA found that even if the
Agency did not assume the CCAP reductions, it was still highly cost-
effective to develop a regional level NOX budget for the
electric power industry, based on the level of control that EPA has
assumed. (These results appear in Chapter 6 of the Regulatory Impact
Analysis for the Regional NOX SIP Call, September 1998.)
C. Non-EGU Point Sources
Background: The EPA developed the NOX SIP call emissions
inventory for non-EGU point sources based on data sets originating with
the OTAG 1990 base year inventory. The OTAG prepared these base year
inventories with 1990 State ozone SIP emission inventories, and EPA
supplemented them with either State inventory data, if available, or
EPA's National Emission Trends (NET) data if State data were not
available.
For the SNPR, non-EGU point source inventory data for 1990 were
then grown to 1995 using Bureau of Economic Analysis (BEA) historical
growth estimates of industrial earnings at the State 2-digit Standard
Industrial Classification (SIC) level. These emissions were grown to
1995 for the purposes of modeling and to maintain a consistent base
year inventory with the EGU data. Because BEA data are historical
documentation of industry earnings, EPA considered these to be among
the best available indicators of growth between 1990 and 1995 (63 FR
25915). Once the common base year of 1995 was established for these
source categories, the BEA growth assumptions utilized by OTAG were
used to estimate the 2007 base case inventory.
1. Base Inventory
Comment: The majority of comments related to the non-EGU point
source inventory alleged that these inventories were incomplete or
inaccurate. The comments generally addressed missing sources, non-
existent or retired sources, incorrect source sizes, mis-classification
of processes, or emission allocation inconsistencies. Many of these
commenters provided specific adjustments to be made to the inventories,
including emissions modifications, activity factors, source sizes, and
facility name changes. A number of States supplied completely new
inventories to replace what was in the proposed data sets. Other
commenters made broad, general categorical comment on the quality of
the inventories with no supporting data.
Response: As was followed under the OTAG inventory update
procedures, all State supplied comments were generally incorporated
``as is'' with the understanding that each State quality-assured its
own data before submission. Industry-supplied comments were forwarded
to respective State agencies for review and where data were deemed
appropriate for inclusion, integrated into the inventories. In some
instances, States responded that the data provided by the State should
override that supplied by industry, or vice-versa. Comments were, in
some cases, not incorporated when necessary to prevent double counting
of emissions in point and area source inventories, where base year
emission modifications were calculated from permitted emission levels
and not actual operating activity, where additional supporting data
could not be provided by the commenter, or where comments were general
characterizations of inventories or inventory sectors. Note that even
after State review, if the EPA felt that the data, procedures,
methodologies, or documentation provided with the comment were not
sufficient, valid, or justifiable, comments, or portions thereof, were
excluded from the revision.
Both 1990 and 1995 base year emission and growth modifications were
submitted and where 1990 data were provided, the methods described
earlier in this Section were utilized to account for growth to 1995 and
2007 levels.
2. Growth
Comment: Several commenters suggest that the growth factors used to
determine 2007 non-EGU point source base year inventories are
inaccurate or inconsistent across regions and categories of the
inventory. They explained that if growth factors are to be used to
estimate future base year emissions, consistent national or region-wide
values should be utilized for all categories across all States within
the domain. This, they continue, would promote equitable potential
progress to all areas and not penalize those that have shown past poor
growth rates. Some commenters go on to state that growth rates based on
past growth automatically disadvantage States which have suffered from
unusually low growth rates. In addition to growth rates, some
commenters provided 2007 base year emission estimates either with or
without the growth and control information needed to validate their
calculation.
Response: As noted above, EPA relied on BEA State-specific
historical growth estimates of industrial earnings at the 2-digit SIC
level as among the best available indicators of growth for non-EGU
point sources. The BEA projection factors assume the continuance of
past economic relationships. These factors are published every five
years and adjusted to account for recent production and growth trends.
For this reason, BEA data provide a useful set of regional growth data
that EPA recommends for use in preparing emission inventory
projections. It is true that BEA projection factors differ among
different areas and different source categories because of historical
differences in industrial growth among those different areas and source
categories. However, in general, these projection factors offer the
most reliable indicators of future growth as are available.
In cases where commenters questioned the use of EPA's growth rates
but provided no alternative of their own, EPA had little choice but to
continue to use the BEA-derived growth rates. Some commenters provided
alternative or supporting information for modification of source
category or State growth estimates. In those cases where a State or
industry may have had more accurate information than the BEA forecast
(e.g., planned expansion or population rates), data were verified and
validated by the affected States and by EPA, and revisions were made to
the factors used for that category.
3. Budget Calculation
Background: In the NPR and SNPR, EPA proposed that EGUs with a
capacity less than or equal to 25 MWe or 250 mmBtu/hour would be
considered small sources (``cutoff level'') and, as such, EPA would not
assume an emissions decrease as part of the Statewide budget for this
group of sources. At the same time, EPA proposed 2 cutoff levels for
industrial (non-EGU) boilers and turbines: units with a capacity
greater than 250 mmBtu/hour were defined as large units subject to a 70
percent emission reduction assumption; units with a capacity less than
or equal to 250 mmBtu/hr but with emissions greater than 1 ton/day were
defined as medium units subject to reasonably available
[[Page 57415]]
control technology (RACT); and units with a capacity less than or equal
to 250 MmBtu/hr and with emissions less than or equal to 1 ton per day
were considered small sources for which no reduction would be assumed
in the budget. In the SNPR, EPA specifically invited comment on the
size cutoffs and on treating large industrial combustion sources
(greater than 250 mmBtu or approximately 1 ton per day) at control
levels equal to that for EGUs (63 FR 25909). As described below, this
approach has been modified somewhat in response to comments and further
analysis.
a. Proposed Control Assumptions.
Comments: Some comments supported EPA's proposed approach of
assuming 70 percent and RACT controls in its calculation of the
budgets. Numerous comments were received stating that the 70 percent
reduction is inappropriate, may not be cost-effective and may not be
achievable, especially for the following industries: cement plants;
municipal waste combustors; certain pulp and paper operations,
including lime kilns and recovery furnaces; glass manufacturing; steel
plants; and some industrial boilers. Some comments suggested a control
level of 60 percent rather than 70 percent. On the other hand, one
commenter stated that SCR and SNCR are applicable and have been
installed on hundreds of industrial sources.
Response: The EPA generally agrees that 70 percent emissions
reduction is not appropriate for all large sources or all large source
categories, even though SCR and SNCR are applicable and cost-effective
for many sources. Instead of applying a one-size-fits-all percentage
reduction to all large non-EGU sources, the specific emissions
decreases assigned to each of these source categories for purposes of
budget calculation in the final SIP Call rulemaking reflect the
specific controls available for each source category that achieve the
most emissions reductions at costs less than an average of $2,000 per
ton. As described elsewhere in this notice, EPA's analysis results in
calculating budget reductions ranging from 30 percent to 90 percent for
several source categories and no controls to several other source
categories.
b. Small Source Exemption.
Comments: In general, commenters were supportive of EPA including a
cutoff level as part of the budget calculation; however, there were
many suggestions on what the cutoff should be. The EPA received
numerous comments supporting the proposed cutoff level of 25 MWe for
EGUs, which is approximately equivalent to 250 mmBtu/hr or one ton per
day. In addition, EPA received a few comments supporting a 250 mmBtu/hr
cutoff for non-EGU point sources. Commenters indicated that the levels
were appropriate and that it was important to be consistent with cutoff
levels in the OTC's NOX trading program. The Ozone Transport
Commission (OTC) comprises the States of Maine, New Hampshire, Vermont,
Massachusetts, Connecticut, Rhode Island, New York, New Jersey,
Pennsylvania, Maryland, Delaware, the northern counties of Virginia,
and the District of Columbia. In September 1994, the OTC adopted a
memorandum of understanding (MOU) to achieve regional emission
reductions of NOX. These reductions are in addition to
previous OTC state efforts to control NOX emissions, which
included the installation of reasonably available control technology.
The OTC's NOX trading program requires utility and
nonutility boilers greater than 25 MWe or 250 mmBtu to reduce emissions
in order to meet a NOX budget and allows emissions trading
consistent with that budget. These NOX reductions will take
place in two phases, the first phase beginning on May 1, 1999 and the
second phase on May 1, 2003.
Some comments suggested assuming budget controls on units less than
or equal to 25 MWe at RACT levels without a cutoff level. Others
supported EPA's proposal of assuming no additional controls on these
sources. Some comments suggested exempting medium-sized non-EGU
sources.
Many commenters supported the general 1 ton per day exemption
contained in the NPR and SNPR. However, a few comments suggested a more
stringent cutoff level of 50-100 tons per year, similar to definitions
of ``major source'' in the CAA. One commenter recommended a less
stringent level of 5 tons per day cutoff level.
A few comments suggest using tons per day as the primary criterion
to define large- and medium-sized non-EGU sources, rather than boiler
capacity. This approach would exempt, for example, industrial boilers
that exceed the 250 mmBtu capacity, but which emit less than one ton
per day on average. The EPA's proposed approach considers a source
large if heat input capacity data are available and exceed the 250
mmBtu capacity criterion, regardless of its average daily emissions. In
support of this approach, commenters stated that industrial operations
do not usually operate at or near capacity, while EGUs often do.
A few commenters indicated that the OTAG recommendations for
turbines and internal combustion engines (in terms of horsepower cutoff
levels) be used. OTAG had recommended cutoff levels of 4,000 horsepower
for stationary internal combustion engines and 10,000 horsepower for
gas turbines.
Response: For reasons described below and in the NPR (62 FR 60354),
EPA believes that the cutoff levels of 250 mmBtu/hr and 1 ton per day
for large non-EGU point sources are appropriate. The EPA selected 250
mmBtu/hr and 1 ton per day primarily because this is approximately
equivalent to the 25 MWe cutoff used for the EGU sector. Emission
decreases from sources smaller than the heat input capacity cutoff
level, and that emit less than 1 ton of NOX per ozone season
day, are not assumed as part of the budget calculation; these sources
are included in the budget at baseline levels.
The EPA believes that the 1 ton per day exclusion contained in the
NPR and SNPR is appropriate and necessary. This level allows today's
rulemaking to focus, for the purpose of calculating the budget, on the
group of emission sources that contribute the vast majority of
emissions, while at the same time avoids assuming emissions reductions
from a very large number of smaller sources (as described in the
following paragraph). In taking today's first major step towards
reducing regional transport of NOX, EPA does not believe
that emission reductions from these small sources need to be assumed.
This approach provides more certainty and fewer administrative
obstacles while still achieving the desired environmental results.
Although other cutoff levels were suggested by commenters, EPA believes
that the cutoff levels described above strike the appropriate balance
so that reasonable controls may be applied by States to a sufficient
but manageable number of sources to efficiently achieve the needed
emission reductions.
Most small sources emit less than 100 tons of NOX per
year. Although their total emissions are low, small sources account for
about 90 percent of the total number of point sources. Thus, not
assuming controls on these sources at the present time would greatly
limit administrative complexity and reporting costs. This common-sense
approach results in reducing the non-EGU population potentially
affected by the ozone transport rule from more than 13,000 sources
estimated in the NPR and SNPR to under 1,200.
Although a few comments suggested using tons per day, not capacity
(MWe or mmBtu/hr), for setting cutoff levels, EPA chose primarily to
use capacity indicators. This approach is consistent
[[Page 57416]]
with the framework of the emissions trading program. In addition, EPA
is concerned that units could have low average emissions during the
ozone season but relatively high emissions on some high ozone days.
Accordingly, EPA is relying on a capacity approach first and a tons per
day approach second (where capacity data is not available or
appropriate) to define units for which reductions are assumed in EPA's
budget calculations.
As noted in the proposal notices, horsepower data was generally
absent from the available emissions inventory data. Thus, the OTAG
recommendation could not be used. Because quality assured data are
still lacking, EPA used alternative approaches to determine size
categories as described above. For the purposes of calculating the
State budgets, the following approach is used to determine whether
controls should be assumed on a particular source for the purposes of
calculating the budget:
1. Use heat input capacity data for each source if the data are
in the updated inventory.
2. If heat input capacity data are not available, use the
default identification of small and large sources developed by EPA/
Pechan for OTAG and also used to develop the NPR and SNPR budgets
for source categories with heat input capacity fields (``default
data'').
3. Emission reductions would be assumed if specific source heat
input capacity data or default data indicate that a source is
greater than 250 mmBtu/hr in the updated inventory.
4. If specific or default heat input capacity data are not
available in the updated inventory (or not appropriate for a
particular source category), emission reductions would be assumed if
the unit's average summer day emissions are greater than one ton per
day based on the updated inventory.
5. All others are ``small'' and no emission reductions are
assumed.
c. Exemptions for Other Non-EGU Point Sources.
Comments: Several comments described source categories that might
be excluded from being assigned assumed emissions decreases for
purposes of calculation of the NOX budgets. In the NPR, EPA
assumed a 70 percent reduction from large sources and RACT on medium-
sized sources. Some commented that it is not possible to control lime
kilns and recovery furnaces or that potential NOX emissions
reductions are very small. One comment noted that recovery units
typically emit at a rate of 0.15 lb/mmBtu or less and lime kilns at
0.20 lb/mmBtu or less and suggested establishing an emissions rate
floor so that sources emitting less than 0.15 lb/mmBtu (or some other
floor) would not need to further control. Other commenters suggested
exempting cyclone boilers less than 155 MWe and all aircraft engine
test facilities.
Response: The EPA agrees that for purposes of today's rulemaking
the State budgets should not reflect assumed reductions in emissions
from lime kilns, recovery units and aircraft engine test facilities.
The amount of emissions from these source categories is very small
relative to other point source categories considered in this
rulemaking. Further, there is no experience in applying NOX
control technologies full scale to aircraft engine test cells in the
U.S. (EPA-453/R-94-068, October 1994).
The EPA acknowledges that NOX controls may be available
at costs less than $2,000 per ton for lime kilns, recovery units and
aircraft engine test cells. However, these source categories include a
relatively small number of sources with a small amount of emissions.
The EPA is concerned that assuming controls on these sources for
purposes of State budgets would encourage States to attempt to regulate
these sources. The EPA believes State regulation could be inefficient
because of the relatively high administrative costs of developing
regulations for these few source categories (particularly for aircraft
engine test cells because no regulations have been developed for this
source category).
Similarly, EPA determined for each of the following non-EGU point
source categories that the amount of emissions are small relative to
the total non-EGU point source emissions and, thus, State regulation
could be inefficient because of the relatively high administrative
costs of developing regulations for these few source categories:
ammonia, ceramic clay, fiberglass, fluid catalytic cracking, iron &
steel, medical waste incinerators, nitric acid, plastics, sand/gravel,
secondary aluminum, space heaters, and miscellaneous fuel use
operations. Further, for many of these categories the number of sources
is small and/or control technology information is limited (e.g., where
an Alternative Control Techniques document does not exist for that
category). The EPA believes that it would be an inefficient approach to
suggest that States consider adopting emissions reduction regulations
for each of these categories. Therefore, EPA did not calculate
emissions reductions from these source categories for purposes of
calculating the budget.
At this stage in the process to reduce regional transport, EPA
considers it most efficient to focus State and administrative resources
on the source categories with greater amounts of emissions. While
States may choose to control any mix of sources in response to the SIP
call, EPA is not, in today's rulemaking, assuming reductions from these
source categories as part of the budget reduction calculation and does
not believe it is necessary for States to do so.
It should be noted that EPA is generally treating the non-EGU
boilers/turbines in the same manner as the EGUs to enable States that
opt into a trading program to develop a simple and effective trading
program. Thus, the size cutoffs discussed earlier in this section are
identical. Further, the regulatory definition of a unit has been
revised to make it clear that only fossil-fuel fired boilers and
turbines are affected; this is discussed in detail in the trading
program section later in today's notice. In addition, it should be
noted that EPA is not excluding reductions from cyclone boilers,
whether EGU or non-EGU, between 25-155 MWe from the calculation of the
State budgets in this rulemaking. Such sources can be large emitters of
NOX and EPA expects the control costs will be less than
$2000/ton on average through participation in the emissions trading
program.
d. Sources Without Adequate Control Information.
Comments: As described in the SNPR, there are many sources in the
emissions inventory which lack information EPA would need to determine
potentially applicable control techniques. The SNPR proposed to leave
these sources in the budget without assigning any emissions reductions.
The EPA received comments that generally supported the SNPR approach
not to assign emissions reductions to the diverse group of sources
where the Agency lacked sufficient information to identify potential
control techniques (63 FR 25909).
Response: This group of sources is diverse and does not fit within
the categories set out by EPA, but total emissions are low for this
group. The EPA believes that the effort needed to collect adequate
information concerning controls for those sources (about 6,000 small
and 260 medium or large) would be time consuming, the quality of the
information may be uncertain, and it would potentially affect only a
small amount of NOX emissions. Therefore, for purposes of
today's action, EPA continues not to assume decreases in emissions for
these sources for purposes of calculation of the State budgets, but to
keep them in the budgets at baseline levels. In the future, as more
information becomes available, and if additional NOX control
is needed to further reduce ozone transport, further
[[Page 57417]]
consideration of these sources may be necessary. Of course, States with
adequate information may choose to control these sources to meet their
budgets.
e. Case-By-Case Analysis of Control Measures.
Comments: Some commenters suggested that EPA simply assume
reasonably available control technology (RACT) for medium and, in some
comments, large sources in all upwind States on a case-by-case basis
and assure that marginally stringent source-specific reduction levels
are rejected. Many commenters stated that RACT default levels used by
EPA were not sufficiently accurate and that case-by-case analysis was
needed because every industrial source is different. Other comments
generally stated that control level decisions should only be made on a
case-by-case basis because each affected unit may have unique features
that alter its cost-effectiveness.
Response: In the final budget calculation procedure EPA does not
calculate RACT requirements for medium-sized sources. The assumption of
RACT or other controls on industrial boilers and turbines between 100-
250 mmBtu/hr would have been inconsistent with EPA's approach for
utility boilers and turbines, which exempts units less than or equal to
250 mmBtu/hr. To be consistent with the way EPA treats EGUs and because
data is often lacking for the smaller size sources, EPA redefined
``affected'' non-EGU units to primarily include those greater than 250
mmBtu. In cases where heat input data are not available, affected non-
EGU units are those greater than 1 ton per day; this level is also
consistent with the EGU cutoff because it is approximately equivalent
to the 250 mmBtu level. Consistency with the EGU approach is important
because it provides equity, especially among the smaller boilers and
turbines and simplifies the model trading program. Therefore, the final
rule does not calculate budget reductions for the medium size non-EGUs.
For the above reasons and as described below, EPA has examined the
non-EGU sources on a category-by-category basis and determined
appropriate control level assumptions for the large units. There are
several reasons why EPA did not choose to calculate the budget by
examining sources on a case-by-case basis. First, such an approach
would be inefficient since all large sources would need to be examined,
rather than some source categories being eliminated due to category
specific cost-effectiveness limitations or amount of emissions. Second,
it would be very difficult for the States to complete a case-by-case
analysis of their large sources, develop rules, and respond to the SIP
call within the 12 month time frame (or the statutory maximum 18
months). States needed much more time to respond to a similar
requirement, the 1990 CAA NOX RACT program. The CAA allowed
a 2-year period before the NOX RACT rules were due from the
States; however, few States met this time frame and several adopted
generic RACT rules which, in practice, resulted in much longer time
frames before the case-by-case RACT analyses were completed and State
rules adopted. Third, the option of participating in a trading program
should mitigate cost impacts on some sources that may have unique
configurations or other constraints. Fourth, EPA has often issued
standards on a category-wide basis (e.g., New Source Performance
Standards) which have proved workable even though some individual units
have higher costs than the average. Fifth, the results of such case-by-
case analyses may not be perceived to be as equitable as the
categorical approach because the control levels resulting from the
case-by-case approach are likely to vary from source-to-source and
State-to-State. Finally, the category-by-category approach selected by
EPA is preferred because it will achieve air quality benefits sooner
than the case-by-case approach.
f. Cost-Effectiveness.
Comments: The EPA received numerous comments on cost-effectiveness.
Those comments related to uniform control levels or cost per air
quality improvement are addressed elsewhere in this notice. Some
comments supported EPA's proposed $2,000 per ton approach. Some
commented that EPA should use incremental costs, which are the costs
and reductions associated with obtaining further control from a unit
that already has some level of controls installed. Several commenters
suggested using marginal costs, defined as the cost of the last ton of
NOX removed by a control strategy. Many stated that the
costs for non-EGUs should be no greater than for utilities on a $/ton
basis. One commenter noted that non-EGU costs will be considerably
lower than EPA estimates. One comment suggested that EPA assume no
further controls if the source has BACT, LAER, MACT or RACT already in
place. One comment supported a command-and-control approach instead of
the least cost for the non-EGUs, and asserted that controlling 13,000
sources through this rulemaking may not be feasible. Several commenters
suggested that CEMS costs for non-utilities should be included in the
cost-effectiveness determinations and that alternative monitoring
methodologies should be considered.
Response: The EPA believes that the approach of average cost-
effectiveness described in the proposal notices is appropriate for this
rulemaking. In establishing the upper limit of the cost-per-ton range
that EPA considers highly cost-effective for this rulemaking, EPA
relied on average cost-effectiveness values estimated for recently
proposed or promulgated rulemakings. The marginal cost-effectiveness
for the level of control decided upon in the other programs and
rulemakings was not always estimated or readily available. The EPA's
latest assessment of cost-effectiveness does account for the level of
existing or planned control in the baseline case. Therefore, when EPA
refers to average cost-effectiveness it is the average incremental cost
between the base and the more stringent level of control.
For the non-EGU point sources, in the NPR and SNPR EPA had
aggregated the non-EGUs as one group, which meant that a few source
categories with relatively low costs and high percentage emissions
decreases dominated overall average cost-effectiveness. For today's
final action, EPA revised its approach and analyzed individual source
categories to determine if control techniques are available at average
costs less than $2,000 per ton. Further, EPA included in this cost-
effectiveness approach the costs related to CEMS, because this is a new
and potentially high cost to some of the non-EGU source categories. As
described in the RIA that supports this final rulemaking, EPA's
analysis determined that the following non-EGU source category
groupings could achieve substantial emissions decreases at average
costs less than $2,000 per ton: industrial boilers and turbines,
stationary internal combustion engines, and cement manufacturing. As
further described in the RIA, controls for sources grouped in the
following categories exceed $2,000 per ton: glass manufacturing,
process heaters, and commercial and industrial incinerators.
The EPA believes that, over time, costs for non-EGU point sources
will be lower than current EPA estimates; however, the changes cannot
be quantified at this time. As discussed below, EPA agrees that one
source category that has a NOX standard set through the MACT
process should not be assumed to implement further controls.
g. Industrial Boiler Control Costs.
Comments: Several comments were submitted indicating that
industrial
[[Page 57418]]
boiler costs are generally higher than utility boiler costs. The
comments cited factors of load variability, smaller size/economies of
scale, firing of multiple fuels, and the ability to finance new
controls and pass on costs. Some comments stated that most industrial
boilers are one-seventh the size of utilities and, thus, EPA should
recognize that the costs of controls would generally be higher due to
economies of scale.
Response: The EPA agrees that industrial boiler sources are
generally smaller than utility boiler sources; however, some individual
industrial sources are larger than some utility sources. The EPA agrees
that costs, on average, to the industrial sector are expected to be
somewhat greater than that expected by the utilities due, in part, to
economies of scale and the need for CEMS (which are already in place at
utilities). Primarily due to the costs related to continuous emissions
monitoring systems, EPA's reanalysis of cost-effectiveness for
industrial boilers resulted in a control level of 60 percent, which is
less stringent on average than that for utilities.
h. Cement Manufacturing.
Comments: In the NPR, EPA proposed a 70 percent control assumption
on large sources and RACT on medium sources, including cement plants.
Some commenters suggested that cement manufacturing should be excluded
because in the SIP Call area, there are only a few cement plants and
they have low emissions. Several commenters noted that many cement
plants had already implemented NOX RACT controls. Some
comments disagreed with the costs and controls contained in EPA's
Alternative Control Techniques document (EPA-453/R-94-004, March 1994)
and added that EPA should not assume the same controls for different
types of cement plants. Several commenters stated that 70 percent
control is not feasible and SCR costs would be greater than $4,500 per
ton, but that 20-30 percent control is possible. One commenter stated
that the SIP call would provide a major competitive advantage to plants
outside the region, and that multi-plant companies may shut down
facilities inside the SIP call region and increase output at plants
outside.
Response: Over 50 cement manufacturing units together emit more
than twenty percent of emissions from large point sources not in the
trading program (about 40,000 tons per season). The EPA believes that
the emissions from this one industry are sufficiently high that it is
appropriate to examine the availability of cost-effective controls.
The cost and control estimates in the Alternative Control
Techniques (ACT) document were peer reviewed and, as such, are
considered by EPA as the best data available. Consistent with the ACT
document for this industry, EPA generally agrees with the commenters
that a 70 percent control level would exceed the $2,000 per ton level
used as EPA's cost-effectiveness framework. But, with the evidence
cited in the cement ACT document and in some comments, EPA believes
that a 30 percent reduction from uncontrolled levels would be within
the cost-effectiveness range for reducing emissions at all types of
cement manufacturing facilities. Therefore, the budget calculations
assume a 30 percent control level for this source category. The EPA
does not anticipate that, if States were to choose to apply a 30
percent control level to cement plants, this would be a major
competitive disadvantage for plants located in the SIP call area
because many cement plants in the region have already successfully
implemented such controls in State RACT programs.
i. Stationary Internal Combustion Engines.
Comments: One comment suggested EPA set RACT levels at 25 percent
for this category.
Response: As noted above, EPA is not using a RACT approach in the
final rulemaking, but has examined each non-EGU point source category
separately to determine the maximum available emissions reductions from
controls that would cost less than $2,000 per ton on average. As
described in the RIA, this process of looking at source categories
individually resulted in EPA changing the control level assumption for
this category from 70 percent in the NPR to 90 percent control in
today's final rule. As described elsewhere in this notice, EPA also
changed the control level assumptions for other source categories
through this more detailed approach.
For this source category, EPA determined based on the relevant ACT
document, that post-combustion controls are available that would
achieve a 90 percent reduction from uncontrolled levels at costs well
below $2,000 per ton. (EPA-453/R-93-032, 1993.) Therefore, the budget
calculations include a 90 percent decrease for this source category
from uncontrolled levels.
For spark ignited rich-burn engines, non-selective catalytic
reduction (NSCR) provides the greatest NOx reduction of all
technologies considered in the ACT document and is capable of providing
a 90 to 98 percent reduction in NOX emissions. The control
technique for spark ignited lean burn, diesel, and dual fuel engines is
selective catalytic reduction (SCR). The SCR provides the greatest
NOX reduction of all technologies considered in the ACT
document for these engines and is capable of providing a 90 percent
reduction in NOX emissions.
j. Industrial Boilers and Turbines.
Comments: Several commenters indicated that boilers using SNCR may
achieve 40-60 percent reduction, but not 70 percent. Other comments
supported the 70 percent control level proposed.
Response: The EPA examined the category of industrial boilers and
turbines to determine the largest emissions reductions that would
result from controls costing less than $2,000 per ton on average,
including costs related to CEM systems. As described in the RIA, for
this source category, EPA determined that controls, including SCR and
SNCR, are available that would achieve a 60 percent reduction from
uncontrolled levels at costs less than $2,000 per ton on average. For
those sources that participate in the trading program, EPA believes
that the costs would be further reduced. Therefore, the budget
calculations include a 60 percent reduction for this source category
from uncontrolled levels.
k. Municipal Waste Combustors (MWCs).
Comments: Several comments suggested that State budgets should not
reflect emissions decreases for MWCs beyond those already required by
the MACT rules.
Response: The NPR did not assume reductions for MWCs in the
calculation of the budgets. However, since MACT reductions are
required, and will be achieved well before 2007, those reductions
should be accounted for in the 2007 baseline emissions inventory. The
EPA agrees that additional emissions decreases beyond MACT levels are
not warranted for this source category at this time because they would
exceed the $2,000 per ton framework for highly cost-effective controls.
Therefore, EPA has incorporated the NOX emissions decreases
due to the MACT requirements into the 2007 baseline levels and not
assume any further reductions.
D. Highway Mobile Sources
Background: For the NPR and SNPR, highway vehicle emissions were
projected to 2007 from a base year of 1990. The NPR used the 1990 OTAG
inventory as its baseline. The 1990 OTAG inventory was based on actual
1990 vehicle-miles-traveled (VMT) levels for each State, based on State
[[Page 57419]]
submittals to OTAG where available, or on historical VMT data obtained
from the Highway Performance Monitoring System (HPMS) if State data
were not available. The EPA proposed to switch to historical 1995 VMT
levels from the HPMS; States were encouraged to submit their own 1995
VMT estimates where those estimates differed from HPMS.
In today's notice, EPA has implemented the changes it proposed in
the NPR in calculating baseline and projected future NOX
emissions from highway vehicles. A 1995 baseline is used for today's
notice in place of the 1990 baseline used in the NPR. The HPMS data
were used to estimate States' 1995 VMT by vehicle category, except in
those cases where EPA accepted revisions per the comments. These VMT
estimates reflect the growth in overall VMT from 1990 to 1995, as well
as the increase in light truck and sport-utility vehicle use relative
to light-duty vehicle use. The 1995 NOX emissions
inventories also reflect the type and extent of inspection and
maintenance programs in effect as of that year and the extent of the
Federal reformulated gasoline program. The EPA is continuing to use the
growth factors developed by OTAG for the purpose of projecting VMT
growth between 1995 and 2007. These growth factors were revised with
appropriately explained and documented growth estimates submitted
during the comment period for the NPR.
The 2007 highway vehicle budget components presented in today's
notice are based on EPA's MOBILE5a emission inventory model with
corrected default inputs, which represents the most current EPA
modeling guidance to States when developing their SIPs.60
---------------------------------------------------------------------------
\60\ Both MOBILE5a and MOBILE5b are official EPA models. States
can use either model in their SIPs, provided they use the corrected
default inputs with MOBILE5a. For the control programs evaluated in
today's action, MOBILE5a with corrected default inputs gives the
same emission estimates as MOBILE5b. Because both models are
considered valid by EPA and give the same emission estimates, the
EPA has determined that the choice of which model to use in
calculating highway vehicle emission budget components is a matter
of convenience. The EPA has chosen to retain the use of MOBILE5a for
today's action in order to maintain consistency with the OTAG
process, in which MOBILE5a with corrected default inputs was used to
construct its highway vehicle emission inventories and to calculate
the effectiveness of highway vehicle emission control options.
---------------------------------------------------------------------------
1. Base Inventory
Comment: The EPA received a number of comments on baseline highway
vehicle emission inventories. Most of these commenters proposed changes
to baseline VMT estimates or to control factors related to highway
vehicle emissions.
Response: In the NPR and SNPR, EPA asked commenters to provide
sufficiently detailed information to permit revision to county-level
emission inventories, in order to allow airshed modeling to be
performed using the revised inventories. A number of proposed VMT
revisions submitted by commenters were not sufficiently detailed to
permit county-level inventory revisions and therefore these revisions
were rejected. Other commenters provided sufficiently detailed data,
which were incorporated into the base year VMT inventory, with two
exceptions. Two States submitted 1995 VMT estimates that were
inconsistent with EPA and U.S. Department of Transportation information
on the relative contribution of light-duty trucks to total VMT. The EPA
chose to use the HPMS default data for these two States.
Comment: One commenter asked the EPA to use VMT from the 1996
Periodic Emissions Inventory (PEI) or 1996 National Emissions Trends
(NET), rather than 1995 Highway Performance Modeling System (HPMS) data
when calculating baseline inventories. Several other commenters
supported EPA's use of 1995 HPMS data to calculate baseline VMT
inventories.
Response: Guidance on how to construct the 1996 PEI was not
released until July 1998 and State PEI submittals are not expected
until 1999. The EPA has determined for this reason that the 1996 PEI is
not suitable for calculating the baseline VMT inventory. The EPA
considered using 1996 NET VMT data in its base inventories, but those
data were based on estimated 1995 HPMS inputs. The EPA has chosen to
use the actual 1995 HPMS data rather than estimates in order to reduce
the uncertainties associated with estimating baseline and 2007 emission
inventories.
Comment: One commenter suggested using a multi-year VMT activity
average to establish the highway emission baselines to smooth out
abnormal patterns, instead of relying solely on 1995 activity.
Response: The EPA proposed using 1995 VMT in order to shorten the
time period over which VMT growth would have to be projected. The EPA
is not aware of any evidence that suggests that 1995 was an abnormal
year in terms of VMT activity. Furthermore, States did not submit
multi-year VMT averages in response to the EPA's invitation to submit
their own VMT data. If the EPA were to construct multi-year averages,
it is not clear what time frame would be appropriate. The EPA believes
that the uncertainty related to having to project VMT growth estimates
over a longer time period is at least as great as the uncertainty
related to the representativeness of 1995 VMT. For these reasons, EPA
has chosen to use 1995 VMT for base year and projection year
inventories.
Comment: A number of commenters raised various issues about the use
of the MOBILE5 emission factor model for this analysis. Most of these
comments focused on specific assumptions or estimates incorporated in
MOBILE5 which may need to be modified or updated to account for new
information.
Response: The EPA is currently developing an updated emission
factor model called MOBILE6. When final, this model will supersede the
MOBILE5 model used by the EPA to develop baseline and 2007 emission
inventories and States' highway vehicle budget components. The concerns
raised by commenters are being evaluated as part of the MOBILE6
development process. At the present time, however, MOBILE5 remains
EPA's official emission factor model. The EPA currently is not able to
determine whether the highway vehicle emission modeling concerns raised
by commenters are valid or whether the changes they suggest would raise
or lower emission estimates; EPA is also not able to quantify the
effects of commenters' concerns using its current emission models. Some
of the changes EPA expects to make in its next official emission factor
model, such as the effects of aggressive driving and air conditioner
use, are likely to raise emission estimates; others, such as less-rapid
deterioration of emissions performance than previously forecast, are
likely to lower emission estimates. Because the overall effect of these
and other changes cannot yet be determined, the EPA has chosen to
continue using its current official emission model in today's action.
As discussed in Section III.F.5, the budgets presented in today's
action serve as a tool for projecting in advance whether States have
adopted measures that would produce the required amount of emissions
reductions, as indicated by the initial demonstration submitted in
September 1999. The budgets are also a means for determining from 2003
to 2007 whether States are fully implementing those measures. Thus, the
budgets are an accounting mechanism for ensuring that the upwind States
have adopted and implemented control measures that prohibit the
significant amounts of NOX emissions targeted by section
110(a)(2)(D)(i)(I). Although EPA's
[[Page 57420]]
projections of emissions from highway vehicles will change as the
Agency improves its emission models, these changes will not in and of
themselves require changes in the actions States undertake to reduce
ozone transport under today's action.
2. Growth
Comments: The EPA received numerous comments concerning its
projection of States' 2007 highway vehicle budget components. In
addition to the changes in baseline VMT discussed previously in Section
III.D.1 of this notice, the EPA received from a number of States
proposed revisions to VMT growth estimates and the effectiveness of
emission control programs.
Response: In today's action, EPA has implemented the following
changes it proposed in the NPR in calculating States' 2007 highway
vehicle budget components. The EPA has used State projections of VMT
growth from 1995 through 2007 for States that submitted appropriately
explained projections of VMT growth from 1995 to 2007. For other
States, EPA projected 2007 VMT levels from the 1995 baseline VMT levels
using the OTAG projected growth rates.
As proposed in the NPR, neither the highway vehicle budget
components nor the overall NOX budgets promulgated in
today's action alter the existing conformity process or existing SIPs'
motor vehicle emissions budgets under the conformity rule. The EPA has
determined that Federal agencies or Metropolitan Planning Organizations
(MPOs) operating in States subject to today's action do not have to
demonstrate conformity to the SIP Call budgets or the highway vehicle
budget component levels used to calculate the budgets. However, areas
will be required to conform to the motor vehicle emissions budgets
contained in the attainment SIPs for the new eight-hour standard. For
their attainment SIPs for transitional ozone nonattainment areas,
States might seek to rely on the modeling performed for the SIPs
submitted in response to today's action. To the extent that this
occurs, the VMT projections and motor vehicle emissions inventories
associated with today's action could have a role in the conformity
process, beginning when transitional areas are designated and
classified in 2000.
3. Budget Calculation
Background: The EPA proposed highway budget components based on
projected highway vehicle emissions in 2007 from a base year of 1990,
assuming implementation of CAA measures, such as inspection and
maintenance programs and reformulated fuels, measures already
implemented federally, and those additional measures expected to be
implemented federally by 2007. The additional Federal measures included
the National Low Emission Vehicle Standards and the 2004 Heavy-Duty
Engine Standards. The emission effects of revisions to the Federal
Emissions Test Procedure, which had also been promulgated in final
form, were not reflected in the projected 2007 emissions presented in
the proposal because neither the emissions that this measure is
designed to control nor the reductions in those emissions expected from
the test procedure revisions had been incorporated in the projected
2007 emission estimates or in peer- and stakeholder-reviewed EPA
emission models. The proposal also did not incorporate any benefits
from Tier 2 light-duty vehicle standards since the EPA had not yet
proposed or promulgated regulations concerning the level and
implementation schedule for Tier 2 standards. Seasonal emissions were
calculated by estimating emissions for a specific weekday, Saturday and
Sunday during the ozone season and multiplying by the number of days of
each type in the ozone season. These estimates were based on
temperatures and temperature ranges recorded for actual ozone episodes.
In the NPR, EPA proposed to change this approach to substitute monthly
average temperatures and temperature ranges for ozone episode-specific
temperatures when constructing the 2007 budgets. The highway vehicle
budget components presented in today's notice reflects this change.
Comment: A number of commenters suggested that the EPA change its
assumptions regarding emission control programs from those used in the
NPR. One commenter claimed that the NPR did not include a number of
cost-effective highway and nonroad mobile source NOX
reduction programs in its budget calculations. Other commenters
suggested that the EPA focus more on expanding the RFG and I/M
programs, adopting gasoline sulfur controls, implementing a
reformulated diesel fuel program, or implementing the Tier 2 program.
Contrary to these positions, a number of commenters agreed with the
EPA's decision not to assume any expansion of the RFG or I/M programs,
while still other commenters argued that the EPA should not include the
emission effects of gasoline sulfur controls or reformulated diesel
fuel in its calculation of State NOX budgets. One commenter
suggested that the EPA change its NLEV phase-in assumptions to match
the final NLEV agreement. One commenter asked EPA to include the effect
of the recent Revised Federal Test Procedure rule, which is aimed at
reducing excess emissions from aggressive driving or air-conditioner
use, in its budget calculation.
Response: Both the NPR and today's action include those mobile
source reductions which EPA has determined or proposed to determine are
technologically feasible, highly cost-effective, and appropriate to
implement on a national basis, and which have been promulgated in final
form or are expected to be promulgated in final form before States are
required to submit revised SIPs. The highway vehicle budget components
include the emission reductions resulting from implementation of the
NLEV program, including the phase-in schedule agreed to by the States,
automobile manufacturers, and EPA. The highway budget components do not
include the effect of Tier 2 light-duty vehicle and truck standards and
any associated fuel standards since these standards have not yet been
proposed.
The extent of the RFG and I/M programs was not assumed to change
beyond that assumed for the NPR, except for those States who were able
to demonstrate that the NPR's modeling assumptions did not conform to
the State's SIP and did not reflect CAA requirements. As discussed
elsewhere in today's notice and in the NPR, the NOX
reductions alone from these measures do not appear to be highly cost
effective in all of the areas that would be subject to reduced budgets.
Because these measures offer additional benefits beyond NOX
reductions, specific local areas may determine that these measures are
appropriate and cost effective given their full range of benefits.
The baseline and budget calculations include neither the increased
emissions from aggressive driving or air conditioner use, nor the
reductions in those emissions resulting from the Revised Federal Test
Procedure rule. These emission effects are not reflected in EPA's
MOBILE5a model; they are being evaluated for inclusion in MOBILE6.
While the EPA has developed a modified version of its MOBILE5 model to
estimate these effects for its Tier 2 study, this modified model has
not been used in any regulatory actions and is still subject to
revision as part of EPA's model development process. As discussed above
and in Section III.F.5. below, any
[[Page 57421]]
changes by EPA in its emission models will not in and of themselves
alter the emission reductions States must achieve to comply with the
requirements of today's action.
Comment: One commenter suggested that the EPA not split VMT using
weekend and weekday travel fractions when calculating monthly and
seasonal total VMT. Another State commenter proposed an alternative
method for calculating monthly and seasonal VMT from average daily VMT
which did not rely on the EPA weekend/weekday travel fractions, but
instead used monthly travel fractions specific to that State. Other
commenters supported the weekend/weekday inventory modeling approach
proposed by the EPA.
Response: The EPA and other organizations have amassed considerable
evidence that weekend and weekday travel patterns differ significantly.
The OTAG Final Report requested day-specific inventories for developing
day-of-the-week activity levels used in emission inventory development
and episode-specific modeling. Given this requirement, EPA has
determined that the approach outlined in the NPR is appropriate and
reasonable. The alternative method using State-specific monthly travel
fractions as proposed by one State is a reasonable alternative.
However, because EPA does not have the necessary information to apply
this method to all other States, EPA did not incorporate this method in
its analysis.
a. I/M Program Coverage.
Comment: One commenter urged the EPA to expand I/M programs to
cover all urbanized areas with populations above 500,000 as recommended
by OTAG. Other commenters also requested that EPA expand the I/M
program or require specific States to adopt specific types of I/M
programs. By contrast, other commenters supported the I/M approach
taken by the EPA in the NPR.
Response: The OTAG recommended that States consider expanding I/M
programs to cover all urbanized areas with populations above 500,000.
The EPA has considered this recommendation but does not believe it to
be appropriate to assume broader I/M implementation in calculating
State budgets for the reasons outlined in the NPR (62 FR 60355). The
State budgets promulgated in today's action reflect full implementation
of I/M as required by the CAA and State SIPs.
b. Emissions Cap.
Comment: One commenter suggested that the EPA consider capping
mobile source emissions, arguing that the proposed rule would place an
undue burden on stationary sources.
Response: The State NOX budgets promulgated in today's
action include the projected emission benefits of those NOX
controls that the EPA has determined are technologically feasible and
highly cost effective, as well as additional controls whose
implementation is not dependent on this rule. While the EPA's analysis
indicates that certain categories of stationary sources offer the
potential for large, highly cost-effective NOX emission
reductions, the State NOX budgets also reflect the emission
effects of a number of mobile source controls (See Table IV-2). The EPA
believes that it has applied its criteria for determining which
controls to assume in State NOX budgets equitably to both
mobile and stationary sources. In contrast to EGUs and large non-EGUs,
EPA has not concluded that a mass cap (which would effectively require
offsets for VMT growth) is highly cost effective. For these reasons,
EPA does not believe that today's action places an undue burden on any
emission sector and does not believe that a separate cap on mobile
source emissions is necessary.
c. Tier 2 Standards.
Comment: One commenter requested that EPA include the effects of
Tier 2 light-duty vehicle standards when calculating State budgets if
the NLEV program fails. Another commenter suggested that States not be
permitted to adjust their budgets in case the NLEV program fails.
Response: This issue is not yet ``ripe'' because NLEV is currently
being implemented and there are no signs that the program will fail.
The EPA will consider whether to adjust State budgets if automakers
representing a significant portion of new vehicle sales withdraw from
the NLEV program, as discussed in Section III.F.5.
d. Low Sulfur Fuel.
Comment: One commenter stated that the EPA disregarded OTAG's call
for reducing sulfur levels in fuel, which would have the effect of
reducing NOX emissions.
Response: The EPA's proposed rule and other actions match the OTAG
recommendations on fuels, contrary to the commenter's suggestion. The
OTAG gasoline recommendation stated, ``The USEPA should adopt and
implement by rule an appropriate sulfur standard to further reduce
emissions and assist the vehicle technology/fuel system [to] achieve
maximum long term performance.'' It did not request that EPA implement
a specific sulfur reduction proposal. The EPA is evaluating the costs
and benefits of reducing gasoline sulfur levels as part of its proposed
rulemaking to implement Tier 2 light-duty vehicle and truck standards.
The EPA is also evaluating the relationship between diesel fuel
standards and the emission standards as part of (i) its 1999 technology
review for its 2004 highway heavy-duty diesel engine standards and (ii)
its 2001 technology review for the Tier 3 and Tier 2 nonroad diesel
engine standards. Until these evaluations are complete, EPA believes it
is premature to assume any changes in fuel properties when calculating
States' highway vehicle budget components.
e. Conformity.
Comment: One commenter recommended that NOX
transportation conformity waivers should lapse in the wake of today's
action.
Response: Conformity waivers were granted on an area-by-area basis,
given the facts of the situation in each local area. Any withdrawal
should be based on similar local analysis, or upon submittal of a valid
attainment plan. Today's action is not based on this kind of local
analysis. Thus, there is no basis for any withdrawal of existing
NOX transportation conformity waivers. Furthermore, any such
withdrawal would not alter the Statewide NOX budgets set
forth in today's action. For these reasons, the EPA has concluded that
today's action does not alter existing conformity requirements,
including any NOX conformity waivers.
Comment: One commenter expressed concern that if current conformity
budgets do not incorporate the same control assumptions as the States'
budgets submitted in response to today's rulemaking, the growth in
areas currently subject to conformity budgets could threaten the
ability of States to meet the SIP call budgets. The commenter continued
that failure to tie conformity budgets to transport budgets would allow
these areas to grow to pre-SIP call control budget levels that could
cause an exceedance of the Statewide budget. The commenter also stated
that to address local ozone problems, transportation conformity plans
should reflect the mobile source controls assumed in the SIP call.
Response: Conformity budgets cannot be tied directly to the SIP
Call budgets because the latter are statewide and the former are
nonattainment-area-specific. The Statewide NOX budgets will
be enforced as described in today's action, regardless of the
conformity budgets in specific areas within the affected States. These
budgets should reflect the actual level of motor vehicle emissions
which States expect to occur.
[[Page 57422]]
As noted elsewhere in this section, conformity budgets will reflect
the mobile source controls assumed in the SIP Call budgets to the
extent that the attainment SIP ultimately relies upon those controls.
Today's action does not change the rules governing generation and use
of emission reduction credits to offset further growth in the
transportation sector as part of a local area's conformity
demonstration.
E. Stationary Area and Nonroad Mobile Sources
Background: The EPA developed the NOX SIP call emissions
inventory for area and nonroad mobile sources based on data sets
originating with the OTAG 1990 base year inventory. These base year
inventories were prepared with 1990 State ozone SIP emission
inventories supplemented with either State inventory data, if
available, or EPA's National Emission Trends (NET) data if State data
were not available. The OTAG 1990 nonroad emission inventories were
based primarily on estimates of actual 1990 nonroad activity levels
found in the October 1995 edition of EPA's annual report, ``National
Air Pollutant Emission Trends.'' In the NPR, EPA proposed switching to
EPA's 1997 ``Trends'' estimate of 1995 nonroad activity levels.
For the SNPR, area and nonroad mobile source inventory data for
1990 were then grown to 1995 using Bureau of Economic Analysis (BEA)
historical growth estimates of industrial earnings at the State 2-digit
Standard Industrial Classification (SIC) level. Because BEA data are
historical documentation of industry earnings, EPA considered these to
be among the best available indicators of growth between 1990 and 1995
(63 FR 25915). Once the common base year of 1995 was established for
these source categories, BEA growth assumptions utilized by OTAG were
used to estimate the 2007 base case inventory.
1. Base Inventory
Comment: The EPA received several comments on baseline area and
nonroad mobile source emission inventories. Several commenters
submitted estimates of their 1990 nonroad activity levels that differed
from NPR estimates. One commenter provided statewide 2007 base year
emissions estimates for numerous area source categories, while others
provided similar information for 1990 or 1995 emission estimates. Many
commenters expressed concern with existing area source inventory
estimates and provided revised county-level area source inventories.
One commenter suggested using a multi-year activity average to
establish the nonroad emission baseline, arguing that a multi-year
average would provide a more representative baseline than would a
single year's data alone.
Response: In the NPR and SNPR, EPA asked commenters to provide
sufficiently detailed information to permit revision to county-level
emission inventories, in order to allow airshed modeling to be
performed using the revised inventories. Some proposed area and nonroad
inventory revisions submitted by commenters were State-wide revisions
and did not contain sufficient detail to permit the EPA to revise
county-level nonroad emission inventories. Because the EPA could not
use these submittals to revise the county-level inventories used as
inputs to its air quality modeling analyses, these submittals were not
accepted. Other commenters did provide sufficiently detailed data, and
EPA revised the appropriate emission inventories to reflect the
commenters' estimates. These revised inventories were then grown to
1995 using BEA-derived growth factors, as described above.
Although EPA proposed in the NPR to switch to a 1995 inventory in
calculating baseline NOX emissions from nonroad mobile
sources, EPA has chosen not to do so in today's action. Using the 1995
inventory presented in the ``Trends'' report as the baseline for
today's action would have required the use of geographic allocation
methods that have not undergone peer review and have not been made
available for public comment by affected interests. The EPA has
concluded that the use of these unreviewed methods in today's action
would have deprived stakeholders of adequate opportunity to review,
understand, and comment on their baseline inventories and the methods
used to construct them. Hence, EPA has chosen to retain the 1990
baseline inventories for nonroad mobile sources presented in the NPR
for today's action, with the changes made in response to comments.
As discussed above, EPA has chosen to use 1990 nonroad activity
level estimates as the basis for its nonroad inventory projections. The
EPA is not aware of any evidence that suggests that 1990 was an
abnormal year in terms of nonroad activity. Furthermore, States did not
submit multi-year nonroad activity averages in response to EPA's
invitation to submit their own nonroad activity data. If EPA were to
construct multi-year averages, it is not clear what time frame would be
appropriate. To reduce the impact of unusual years, EPA would have to
take a long-term average. However, doing so would require EPA to use an
even earlier year as its base year for nonroad activity and inventory
projections. The EPA believes that the uncertainty related to having to
project nonroad activity growth estimates over a longer time period is
at least as great as the uncertainty related to the representativeness
of 1990 nonroad activity.
2. Growth
Comment: Several commenters suggest that the growth factors used to
determine 2007 stationary area and nonroad mobile source base year
inventories are inaccurate or inconsistent across regions and
categories of the inventory. They explained that if growth factors are
to be used to estimate future base year emissions, consistent national
or region-wide values should be utilized for all categories across all
States within the domain. This, they continue, would promote equitable
potential progress to all areas and not penalize those that have shown
past poor growth rates. Some commenters go on to state that growth
rates based on past growth automatically disadvantage States which have
suffered from unusually low growth rates. In addition to growth rates,
some commenters provided 2007 base year emission estimates either with
or without the growth and control information needed to validate their
calculation.
Response: As noted above, EPA relied on BEA State-specific
historical growth estimates of industrial earnings at the 2-digit SIC
level as among the best available indicators of growth for stationary
and nonroad area sources. BEA projection factors assume the continuance
of past economic relationships. These factors are published every five
years and adjusted to account for recent production and growth trends.
For this reason, BEA data provide a useful set of regional growth data
that EPA recommends for use in preparing emission inventory
projections. It is true that BEA projection factors differ among
different areas and different source categories because of historical
differences in industrial growth among those different areas and source
categories. However, in general, these projection factors offer the
most reliable indicators of future growth as are available.
In cases where commenters questioned the use of EPA's growth rates
but provided no alternative of their own, EPA had little choice but to
continue to use the BEA-derived growth rates. Some commenters provided
alternative or supporting information for modification of source
category or State
[[Page 57423]]
growth estimates. In those cases where a State or industry may have had
more accurate information than the BEA forecast (e.g., planned
expansion or population rates), data were verified and validated by the
affected States and by EPA, and revisions were made to the factors used
for that category.
3. Budget Calculation
Background: The EPA proposed nonroad mobile source budget
components based on projected nonroad mobile source emissions in 2007
from a base year of 1990. These projections were developed by
estimating the emissions expected in 2007 from all nonroad engines,
assuming implementation of those measures incorporated in existing
SIPs, measures already implemented federally, and those additional
measures expected to be implemented federally. The additional Federal
measures include: the Federal Small Engine Standards, Phase II; Federal
Marine Engine Standards (for diesel engines of greater than 50
horsepower); Federal Locomotive Standards; and the Nonroad Diesel
Engine Standards. In the NPR, EPA used the estimates developed by the
OTAG for nonroad mobile source baseline emissions and growth rates.
Comments: The EPA received comments to use a State-specific set of
growth rates for nonroad mobile source emissions.
Response: The EPA has used State estimates of 1990 nonroad activity
levels and growth rates for 1990 through 2007 received during the
comment period to revise its estimates of nonroad NOX
emissions in 2007, where those State estimates were appropriately
explained and documented. For other States, the EPA has retained the
baseline activity levels and growth rates used in the NPR, which in
turn were based on the growth rates developed for OTAG.
F. Other Budget Issues
1. Uniform vs. Regional Controls
Background: In the NPR, EPA bases the State budgets upon assumed
application of reasonable, highly cost-effective NOX control
measures. These measures were uniform across the 23 affected
jurisdictions. They consisted of 0.15 lbs/MmBtu for the EGU sector; and
70 percent control for large, and RACT for medium-sized, non-EGU point
sources.
Comments: A number of commenters opposed calculating budgets based
on uniform emissions reductions and cited the fact that OTAG
recommended a range of control levels. These commenters offered no
specific alternatives, such as varying the assumed control levels by
State or by groups of States, or alternative methods for determining
different control levels. Numerous comments were received supporting
the proposed uniform level of emissions reductions.
Response: The EPA has determined that each of the 23 jurisdictions
has sources that emit NOX in amounts that significantly
contribute to downwind nonattainment problems. Moreover, EPA has
determined that specified levels of control on certain sources in all
of the jurisdictions would be highly cost-effective. This analysis
applies with equal force to each of the 23 jurisdictions. It may be
that emissions from some States have greater ambient impact on downwind
nonattainment areas than emissions from more distant States. Even so,
each of the States' NOX emissions have a sufficient ambient
impact downwind to conclude that those amounts are significant
contributions and that NOX emissions from all the upwind
jurisdictions collectively contribute significantly to nonattainment
downwind. Differentiating the contributions of individual upwind States
on multiple downwind nonattainment areas is a highly complex task. The
contributions of individual States are likely to vary from downwind
area to downwind area, from episode to episode, and from NAAQS to
NAAQS. Accordingly, it would be extremely complex to develop a budget
for each State that would reflect the different impacts of its sources'
emissions on different downwind States.
Among many factors that EPA considered in weighing whether to
finalize a uniform control level or regional control levels in
calculating States' emission budgets was the concern that different
controls in one part of the SIP call area in combination with an
interstate emissions trading program may lead to increases in pollution
within areas having more restrictive controls. That is, if unrestricted
interstate emissions trading were allowed on an one-for-one basis,
emissions reductions might be expected to shift away from States
assigned more restrictive controls to States which received less
restrictive control requirements due to the lower control costs likely
to exist in States with less restrictive controls. This may result in
emissions above the budget level in areas with more restrictive
controls.
There are two alternatives for addressing the problem of shifting
emissions. The first is to allow trading only within uniform control
regions, but not between regions with NOX budgets reflecting
different levels of control. The advantage to this approach is that it
provides a straightforward way of preventing trades of excess emissions
into regions with more stringent standards. However, a trading program
that covers a smaller market area will provide less flexibility and
reduce the possible savings for the affected sources as compared with
larger trading programs. The second alternative is to establish a
trading ratio for trades between regions, to reflect the differential
impact of the emissions on nonattainment. The trading ratio should
reflect the relative contribution of emissions to downwind non-
attainment problems. The advantage to this approach is that it provides
the flexibility for trades between regions when the benefits of such
trades are large, while discouraging a shift of excess emissions into
regions with more stringent standards. However, none of the comments on
the proposal included a justification or description for trading
ratios, which would reflect the differential environmental implications
and discourage inappropriate shifting of excess emissions.
The ozone problem in the Eastern United States is the result of a
large number of different types of sources which affect widely
distributed nonattainment areas at different times under changing
weather patterns such that a broadly-established control program is
necessary. The EPA believes a reasonable strategy is to apply the most
cost-effective control strategies uniformly in contributing States in
order to eliminate the combined significant contribution from these
multiple sources in multiple States.
The EPA analyzed costs and air quality benefits for two regional
control level options that were based on a varying level of controls in
different parts of the 23 jurisdictions. The analysis did not show that
these two regional control alternatives would provide either a
significant improvement in air quality or a substantial reduction in
cost. An analysis of the costs and benefits of different control
options can be found in the docket. On the basis of the analysis, EPA
believes an alternative approach with differentiated NOX
budgets and regionally differentiated trading would not yield
significant additional air quality benefits or cost savings vis a vis a
regionwide trading program based on uniform NOX budgets.
2. Seasonal vs. Annual Controls
Comments: One commenter suggested that controls should be required
for the
[[Page 57424]]
entire year rather than just during the 5-month ozone season as
proposed.
Response: The EPA recognizes that control of nitrogen oxide
emissions would likely produce non-ozone benefits, as well as ozone
benefits. For example, NOX control would likely reduce
surface water acidification or eutrophication of surface waters. Annual
control of NOX may have a greater impact on winter and
spring NOX emissions, and therefore on acidification and
eutrophication, than ozone season (summer) NOX control to
the extent that acidification and eutrophication result from the
release of nitrogen compounds from snowpack during snowmelt and rain in
the spring. Control of NOX emissions also reduces fine
particulates and regional haze, so that annual control of
NOX emissions would result in greater non-ozone benefits.
However, the commenter's suggestion that EPA analyze the costs of, and
assume in calculating the budgets, annual NOX control to
address non-ozone problems is outside the scope of this rulemaking
proceeding. Here, EPA has proposed a NOX SIP call to address
the failure of certain SIPs to prohibit sources from emitting
NOX in amounts that contribute significantly to
nonattainment (or interfere with maintenance of attainment) of the
ozone NAAQS during the ozone season.
In analyzing the benefits of ozone season NOX control
under the proposed NOX SIP call for purposes of the RIA
(though not as a basis for the decisions in today's rule), EPA
considered both the ozone and non-ozone benefits. Non-ozone benefits
include the impact of ozone season NOX control on
acidification and eutrophication. In particular, emission modeling
performed by EPA indicates that the SIP Call would reduce wintertime
NOX emissions. This results in part because, once installed
to comply with the NOX SIP call, some NOX control
systems (e.g., low NOX burners which alter the combustion
process and cannot simply be turned off) would reduce emissions
throughout the year, even though the NOX limits would be
seasonal. Also see Section IX.
3. Full vs. Partial States
Background: In the NPR, the Agency indicated it was proposing to
include entire States rather than exempting portions of States in the
development of emissions budgets. The Agency's decision to include full
States was based upon three major points: (1) The division of
individual States by OTAG was based, in part, on computational
limitations in OTAG's modeling analyses; (2) the additional upwind
emissions from full, as opposed to partial, States would provide
additional benefit to downwind nonattainment areas; and, (3) Statewide
emissions budgets create fewer administrative difficulties than a
partial-State budget.
Comments: During the two comment periods, 43 comments were received
which specifically addressed some or all of the major points outlined
above. The underlying theme throughout the comments on this issue was
that the States and EPA had undertaken a comprehensive, scientifically
credible modeling/analysis study during the OTAG, and that the Agency
should follow OTAG's recommendations on this issue (i.e., allow for
partial-State emission budgets). Another common theme was that the
administrative difficulties outlined by the Agency in the NPR were
exaggerated, and that the affected States should be allowed to generate
partial-State, as opposed to statewide, emissions budgets, if their
State considered it feasible to do so. Comments were received that
portions of Alabama, Georgia, Michigan, Missouri, North Carolina, and
Wisconsin should be excluded from the SIP Call.
Response: The underlying concepts for responding to these comments
are (a) that the atmosphere is constantly in motion and has no
limitations at geo-political boundaries, and (b) that the larger the
geographic area that is controlled, the greater the downwind benefits.
For the States requesting partial-State emissions budgets, there are
NOX emissions throughout these entire States. The EPA did
State-specific modeling for each of the affected States, and these
additional modeling analyses support the concept of statewide emissions
budgets for each of the affected States. Furthermore, it is a
reasonable assumption, given the nature of ozone chemistry, that if
emissions from part of a State contribute significantly to downwind
nonattainment or maintenance problems, emissions from the entire State
contribute significantly to downwind nonattainment or maintenance
problems. In each of the affected States, there is no peculiar
meteorological phenomenon that would indicate that emissions from some
portion of that State would not impact downwind nonattainment or
maintenance problems. Thus, based on additional EPA modeling analyses
and their technical interpretation, EPA is not promulgating partial-
State emissions budgets. Since each State has the flexibility to
determine which sources to control in order to meet the budget, a State
can structure its control strategy to require fewer reductions in
certain portions of the State and greater controls in other areas, as
long as the significant amounts of emissions are eliminated.
4. NOX Waivers
Comments: The EPA received several comments supporting the approach
outlined in the NPR in which EPA would treat areas that had previously
received NOX waivers under section 182(f) of the CAA in the
same manner as other areas in the SIP call. The comments stated that
(1) special treatment (i.e., higher budget) for the waiver areas would
increase the burden on downwind States; (2) numerous modeling efforts,
including OTAG's, have shown that such disbenefits are generally minor
and occur on days with low ozone concentrations; (3) disbenefits are
small when upwind NOX reductions are modeled; (4)
disbenefits are better addressed at the local level; and (5) States
already have the flexibility to deal with NOX disbenefits,
if any, through the budget and trading by meeting the budget through
NOX emission decreases in other areas of the State or
acquiring allowances through trading. In addition, some commenters
requested EPA to revoke waivers previously granted. Commenters also
noted that the localized disbenefits are no less of a problem in the
Northeast than in the Midwest.
Numerous comments were also submitted which oppose the approach
outlined in the NPR. The comments generally stated that in States with
NOX waiver areas, the NOX budget should be
increased where NOX decreases lead to ozone increases;
otherwise States might seek reductions disproportionately outside the
sensitive areas, resulting in cost-effectiveness levels greater than
the $2000 per ton framework described in the SIP call proposals.
Comments referred to disbenefits in Cincinnati, Louisville and the
Chicago/Gary areas. Many commenters suggested that EPA wait for further
modeling analyses to be completed and that the zero-out runs are
inappropriate for evaluating the NOX disbenefit issue. Some
stated that the NOX budget might interfere with local
attainment and harm local public health. Other comments recommended
that EPA consider the impact of additional VOC costs that might be
needed to offset local ozone increases.
Response: In today's final rulemaking, EPA is setting
NOX emissions budgets for each of the jurisdictions affected
by this action. These budgets are set in the same manner for areas
without NOX waivers as areas with NOX waivers,
except in the case of NOX waivers granted for I/M programs.
Although
[[Page 57425]]
adverse comments were submitted, none of them provided any modeling
analysis or support documentation showing how a State or States with
NOX waiver areas should be assigned a larger budget or
proposing a specific alternative approach for assigning those budgets.
In contrast, modeling described by EPA in the NPR and SNPR as well as
additional modeling conducted by the Agency and some commenters
continues to show that the benefits of NOX emissions
decreases greatly outweigh any disbenefits. These findings are
discussed in Section IV, and summarized below.
The EPA considered the strengths and limitations in the commenters'
modeling analyses in evaluating whether the technical evidence
presented in the comments supports the arguments made by the
commenters. The EPA's review of the commenters' modeling indicates that
in general (a) downwind ozone benefits increase as greater
NOX controls are applied to sources in upwind States, (b)
the net benefits of NOX control at the level of the SIP Call
outweigh any local disbenefits, and (c) upwind NOX
reductions tend to mitigate local disbenefits in downwind areas.
One commenter, the Lake Michigan Air Director's Consortium (LADCO),
submitted air quality modeling directed toward investigating the
disbenefits in nonattainment areas around Lake Michigan due to the
NOX controls in the SIP Call proposal. The commenter's
general finding was that the greatest ozone decreases with these
NOX controls occur on high ozone days, while the greatest
disbenefits occur on low ozone days. The EPA concurs with this finding,
based on a review of the technical information provided by the
commenter. Specifically, there were no predicted increases in ozone
(i.e., disbenefits) in peak 1-hour ozone on any of the 4 days modeled
by LADCO that had daily maximum 1-hour concentrations >=125 ppb in the
Base Case. Also, on the 3 low ozone days which had predicted
disbenefits, the increases were not large enough to result in a peak
value >=125 ppb. Concerning 8-hour concentrations, only 1 of the 9 days
with a predicted 8-hour daily maximum concentration >=85 ppb had an
increase in peak ozone due to the SIP Call NOX controls.
Also, there was a small disbenefit on the one day modeled which had an
8-hour daily maximum concentration <85 ppb,="" but="" the="" magnitude="" of="" the="" disbenefit="" on="" this="" day="" was="" relatively="" small="" and="" did="" not="" cause="" the="" 8-="" hour="" peak="" value="" to="" exceed="" 85="" ppb.="" thus,="" based="" on="" this="" evaluation,="" epa="" generally="" found="" that="" the="" submitted="" modeling="" did="" not="" refute="" the="" overall="" conclusions="" epa="" has="" drawn="" concerning="" the="" impacts="" of="">X
emissions in the relevant geographic areas.
As described in the NPR, the OTAG process included lengthy
discussions on the potential increase in local ozone concentrations in
some urban areas that might be associated with a decrease in local
NOX emissions. The OTAG modeling results indicate that urban
NOX emissions decreases produce increases in ozone
concentrations locally, but the magnitude, time, and location of these
increases generally do not cause or contribute to high ozone
concentrations. That is, NOX reductions can produce
localized, transient increases in ozone (mostly due to low-level, urban
NOX reductions) in some areas on some days, but most
increases occur on days and in areas where ozone is low. In the SNPR,
EPA documented the estimated ozone benefits of the proposed Statewide
NOX budgets based on an air quality modeling analysis. The
major findings of that analysis include: Any disbenefits due to the
NOX reductions associated with the budgets are expected to
be very limited compared to the extent of the air quality benefits
expected from these budgets.
The results of EPA's assessment of the comments and available
modeling corroborate and extend the findings presented in the SNPR.
Thus, with respect to regional ozone transport and today's final
action, EPA believes it is not appropriate to give special treatment to
areas with NOX waivers.
Several nonattainment areas in the 23 jurisdictions were granted
waivers from certain NOX requirements in past rulemaking
actions. In the Federal Register notices granting the waivers, EPA
stated that the continued approval of these waivers is contingent on
the results of the final ozone attainment demonstrations and plans (See
61 FR 2428 January 26, 1996, LADCO). The attainment plans will
supersede the initial modeling information which was the basis for
waivers EPA granted (e.g., the LADCO waiver). The attainment plans were
due in April 1998 and were to incorporate the results of the OTAG
process. The EPA's rulemaking action to reconsider the initial
NOX waiver may occur simultaneously with rulemaking action
on the attainment plans. Therefore, as these new modeling analyses are
submitted to EPA, they will be reviewed to determine if the
NOX waiver should be continued, altered, or removed.
As discussed above, EPA has accounted for the continued presence of
NOX waivers for I/M programs in modeling States'
NOX budgets. Historically, EPA gives States considerable
latitude in designing their I/M programs. This latitude is granted in
recognition of the unique economic and air quality circumstances faced
by each State. States have used this latitude to develop a range of I/M
program designs. Some States have adopted EPA-recommended enhanced I/M
programs; other States have adopted different I/M program designs.
The EPA acknowledges that some of the States granted NOX
waivers may be able to modify their programs to obtain NOX
reductions at minimal cost. However, some of the States which have been
granted an I/M NOX waiver have developed unique I/M program
designs in terms of the model years covered, the emission testing
equipment used, and possibly the number, location, and design of the
testing and repair stations. The cost for these States to modify their
I/M programs to obtain NOX reductions are likely to exceed
the level that EPA has determined to be highly cost-effective for the
purpose of reducing ozone transport. As a result, the EPA has chosen to
not include additional emissions reductions due to I/M NOX
programs when calculating NOX budgets.
5. Recalculation of Budgets
In the NPR, the EPA made proposals concerning what would happen if
additional information becomes available after EPA's final rulemaking
action. Examples of such information might include: (a) Source-specific
information useful in determining RACT, (b) revised growth or other
assumptions, (c) revised models and inventory estimates, (d)
unexpectedly low implementation rates for NLEV, and (e) other new
federal measures, i.e. Tier 2 controls. In the Recalculation of Budgets
Section of the NPR, EPA proposed that if additional data become
available after EPA's final rulemaking action, such data could be
considered prior to State submittal of revised SIPs. The EPA asked for
comments on this approach.
Most of the comments received were in favor of allowing States to
adjust their emission budgets based on the most recent available data
on emissions and RACT levels. There were several comments that any new
calculation methodologies should be applied across all States and be
approved at EPA Headquarters, and that all States should use the same
methodology.
A few commenters did not agree, however. One said that EPA should
not recalculate the budgets upward. Another said there should be no
downward ratcheting of budgets. One
[[Page 57426]]
commenter said that it would be premature to assume that as new
information becomes available the budget should be adjusted to reflect
this. According to this commenter, it would be more appropriate to
perform a complete air quality modeling analysis to determine if an
adjustment in States' NOX budgets is in order.
The divergent views reflected in these comments has convinced EPA
that it should clarify the role of the budgets in this rule. In light
of that role, as explained below, EPA has decided to allow only a
limited opportunity to revise the budgets in the very near term.
However, under the approach the Agency is following, the rule would not
penalize States for not ultimately achieving the budgets, if the State
initially projected compliance using the data set forth in this rule,
and the State has fully implemented all of the measures reflected in
those initial projections, and the measures are as effective in
reducing NOX emissions as they were projected to be in the
State plan.
As explained in the NPR, SNPR, and above, EPA based the budgets on
its choice of measures that are highly cost-effective and therefore are
the easiest for upwind States to implement to reduce transport.
However, EPA sought to structure the rule to give the upwind States a
choice of which mix of measures to adopt to achieve the aggregate
amount of required NOX emissions reduction.
To offer the States this choice, EPA employed a multi-step approach
leading to a numerical budget for each State. In the first step, EPA
projected the mass emissions for EGUs and industrial boilers out to
2007, taking into account measures required under the CAA and projected
growth. The result was a base case 2007 subinventory for each of those
two categories. Next, EPA projected the 2007 mass emissions for other
sectors of the emission inventory (e.g., mobile sources), again taking
into account projected growth and measures required under the CAA and
existing SIPs, thereby creating a base case 2007 subinventory for each
of them as well. The aggregation of all of the base case 2007
subinventories is the complete base case 2007 inventory. The EPA then
applied cost-effective control measures to the EGU, industrial boiler
and other non-EGU source categories as explained in section III., to
determine the amount of the reductions from these categories. The EPA
applied control measures to the base case inventory to develop the
final budget. Thus, the final budget is the sum of (1) the emissions
remaining after application of the cost-effective control measures to
the subinventories for the categories for which controls are assumed
for purposes of budget calculation and (2) the emissions in the base
case 2007 subinventories for the categories for which EPA assumed no
controls.
The rule then requires each upwind State to use the same base case
2007 inventory in its 1999 SIP submittal as EPA used in developing the
State's budget. In that SIP submittal, the State must show that the
measures it has adopted will achieve the same aggregate emissions
reductions as the control strategies assumed by EPA in developing the
State's budget. More specifically, to demonstrate compliance with the
SIP call, a State must adopt and implement control measures that are
projected to achieve the aggregate emissions reductions determined by
EPA based on the application of highly cost-effective controls to EGUs,
industrial boilers and other affected non-EGUs. While a State may
choose to achieve those reductions through application of measures
other than those used by EPA in calculating required reductions, any
measures it adopts must achieve the reductions assumed by EPA in the
development of its budgets.
The control measures that the State chooses to require will become
the enforceable mechanism under the NOX SIP call. If a State
elects to regulate boilers, turbines or combined cycle units that are
greater than 250 mmBtu/hr-- regardless of whether they are connected to
an electrical generator of any size--or to regulate boilers, turbines
and combined cycle units that serve electrical generators greater than
25 Mwe, regardless of the heat input capacity of the unit, the State
must provide mass emissions limits or their equivalent (see section
VI.A.2) for these sources or source categories. The mass emissions
limits may be set on a source-by-source basis or may be set for an
entire group of sources allowing trading between the sources. These
mass emission limits must assume growth no greater than EPA's
calculations. Any growth that occurs in that category would have to be
accommodated within the mass emission allocations provided by the State
for that category, even if the growth in that category should prove to
exceed EPA's projections. This is appropriate because as discussed in
the SNPR and Section VI.A.2. of today's preamble, EPA believes that the
control approaches, growth assumptions, and monitoring for this group
of sources have advanced to the point that complying with, tracking,
and enforcing a maximum mass emissions limit is reasonable.
Furthermore, based on the analyses in the RIA, EPA believes that mass
emission limits remain highly cost-effective for these categories when
growth is accommodated within the limits. The EPA modeled the expected
growth in capacity and capacity utilization of the source categories
listed above based on growth assumptions in the IPM that have been
subject to extensive public comment and refinement over a several-year
period. On the basis of their growth, assumptions and assumed emissions
rates, EPA determined that mass emission limits would remain highly
cost-effective when new sources are covered within the limits. EPA
projects that even if actual growth for this group of sources exceeds
the projected growth by over one-third, mass emission limits would
remain highly cost-effective according to the criteria used for this
rule.
For other categories, EPA will not require a State to remain within
a mass emission allocation. Today's rule does require a State to use
the base case 2007 inventory in its budget demonstration. However, the
rule does not require States to obtain additional reductions in cases
where a State's 2007 emissions exceeds its budget due to higher than
expected emissions from source categories other than the categories
listed above (certain boilers, turbines, and combined cycle units).
These exceedances may be the result of growth that exceeds projections
for those source categories. However, if a State elects to control
these other source categories to achieve the required reductions in
whole or part, the adopted measures must be as effective in reducing
NOX emissions as they were projected to be in the State
plan. Any failure by a State to adopt measures adequate to achieve
reductions equal to the required amount would be treated as
noncompliance with this rule. Any failure by the State to implement
these measures by the appropriate date would be considered a failure to
implement those measures.
In contrast, the overall budget number itself is not enforceable
against the State. The budget serves as a tool for projecting in
advance whether a State has adopted measures that would produce the
required amount of emissions reductions, as indicated by the initial
demonstration submitted in September 1999. The budgets are also a means
for determining from 2003 to 2007 whether States are fully implementing
those measures. Thus, the budgets are an accounting mechanism for
ensuring that the upwind States have adopted and implemented control
measures that prohibit the significant
[[Page 57427]]
amounts of NOX emissions targeted by section
110(a)(2)(D)(i)(I).
Given that States will not be subject to enforcement actions if
emissions in 2007 from uncontrolled sectors exceed the base case 2007
inventory projections, EPA does not intend to revise those projections
merely because such new information becomes available over time.
Rather, EPA intends to allow commenters an additional opportunity to
request revisions to the source-specific data used to establish each
State's budget in this SIP call. This opportunity will be made
available during the first sixty days of the 12-month period between
signature of today's rule and the deadline for submission of the
required SIP revisions (i.e., November 23, 1998). Commenters would need
to submit any proposed changes in their inventories to the EPA Air and
Radiation docket (A-96-56) within that sixty day period. Individuals
interested in modifications requested by commenters may review the
materials as they are submitted and available in the docket. At the end
of this period, EPA will, within sixty days, evaluate the data
submitted by commenters and, if it is determined to be technically
justified, revise this rule to incorporate it into the State budget
determinations. For a comment to be considered, the request for
modification must be submitted in electronic format containing, at a
minimum, the data elements listed below for each source category.
Additionally, no comment will be considered unless information is
provided to corroborate and justify the need for the requested
modification. For example, corroborating information in the case of the
EGUs can be the inclusion of copies of each source's official same year
EIA 860 or 861 form submissions that support the requested change. For
non-EGUs, corroborating information can include 1995 operational and
emissions information officially submitted (during that time period) by
the source to a federal, State, or local government regulating entity.
Each request for modification of data for EGU sources must include
the following information:
Federal Information Placement System State Code.
Federal Information Placement System (FIPS) County Code.
Plant name.
Plant ID numbers (ORIS code preferred, State agency
tracking number also or otherwise).
Unit ID numbers (a unit is a boiler or other combustion
device).
Unit type (also known as prime mover; e.g., wall-fired
boiler, stoker boiler, combined cycle, combustion turbine, etc.).
Primary fuel on a heat input basis.
Maximum rated heat input capacity of unit.
For electrical generating units, nameplate capacity of the
largest generator the unit serves.
For 1995 and 1996 ozone season heat inputs.
1996 (or most recent) average NOX rate for the
ozone season.
Latitude and longitude coordinates.
Stack parameter information (height, diameter, flow,
etc.).
Operating parameters (hours per day, seasonal throughput,
etc.).
Identification of specific change to the inventory, and
The reason for the change.
Each request for modification of data for non-EGU point sources
must include the following information:
Federal Information Placement System State Code.
Federal Information Placement System (FIPS) County Code.
Plant name.
Facility primary standard industrial classification code
(SIC).
Plant ID numbers (NEDS, AIRS/AFS, and State agency
tracking number also or otherwise).
Unit ID numbers (a unit is a boiler or other combustion
device).
Primary source classification code (SCC).
Maximum rated heat input capacity of unit.
1995 ozone season or typical ozone season daily
NOX emissions.
1995 existing NOX control efficiency.
Latitude and longitude coordinates.
Stack parameter information (height, diameter, flow,
etc.).
Operating parameters (hours per day, seasonal throughput,
etc.).
Identification of specific change to the inventory, and
The reason for the change.
Each request for modification of data for stationary area and
nonroad mobile sources must include the following information:
Federal Information Placement System State Code.
Federal Information Placement System (FIPS) County Code.
Primary source classification code (SCC).
1995 ozone season or typical ozone season daily
NOX emissions.
1995 existing NOX control efficiency.
Identification of specific change to the inventory, and
The reason for the change.
Each request for modification of data for highway mobile sources
must include the following information:
Federal Information Placement System State Code.
Federal Information Placement System (FIPS) County Code.
Primary source classification code (SCC) or vehicle type.
1995 ozone season or typical ozone season daily vehicle
miles traveled (VMT).
1995 existing NOX control programs.
Identification of specific change to the inventory, and
The reason for the change.
After this initial ``shake out'' period before submission of the
SIP revisions, EPA will not adjust inventories or the resulting State
budgets merely because some new information on a segment of EPA's
projections comes to its attention. However, when EPA reviews each
State's reports, it will pay special attention to the causes for any
exceedance of the portions of the inventory that the State is
controlling as a means to meet today's rule. If a State exceeds its
budget because of greater-than-expected growth in areas not having
additional controls, EPA would not penalize the State by requiring the
State to offset those increased emissions. Rather, EPA would use the
base case projections for all sectors (as revised after the initial
period described above) and focus on whether the State had implemented
the measures that its 1999 demonstration had shown would, based on
those base case inventories, achieve the budget levels. Similarly, the
rule would not penalize the State if components in the budget prove
inaccurate because of changes in models (e.g., the release of an
updated MOBILE model) or because of technical errors (e.g., the size of
a unit was incorrectly identified in the inventory, a unit was double-
counted, or the RACT level assumed in the base is different from what
the State ultimately selected as RACT with EPA approval).
In the NPR, EPA also raised the question of what would happen if
EPA adopts national measures beyond what EPA already assumed in the
base case 2007 inventory. The EPA indicated that it could use either of
two approaches in response: (1) States could receive credits for the
real emission reductions that result from the new Federal measures and,
therefore, implement a smaller portion of its planned emission
reductions, or (2) States would be required to continue to implement
the measures in their revised SIPs because affected States are required
to continue to achieve emissions reductions equivalent to those which
can be achieved through application of highly cost-effective control
measures.
[[Page 57428]]
One commenter supported the emission reduction credit for State
SIPs resulting from new Federal national measures adopted after the
State emission budgets are defined but before 2007. According to this
commenter, in such a case the State could implement a smaller portion
of its planned emission reductions because of the reduction brought
about by the Federal national rule. Another commenter said the EPA
should allow full credit for all Federal measures and encouraged the
EPA to timely implement and adopt all Federal measures. A State said
States should be allowed to take full SIP credit for Federal measures
which are implemented in these States. According to one commenter, not
allowing States to take credit for new Federal measures would have the
effect of downward ratcheting of NOX budgets. Other States
said new Federal measures not accounted for in the SIP call should not
be used to offset State measures required to achieve the mandated
NOX emissions reductions.
The EPA has decided to adopt the second approach described above.
Thus, EPA's adoption of a national measure not reflected in the base
case 2007 inventory would not allow the State to avoid a measure that
would otherwise be needed to demonstrate that the State will achieve
the required reductions. As stated above, the SIP must prohibit all
emissions that contribute significantly to downwind nonattainment and
maintenance problems. The State therefore is required to eliminate an
amount of emissions corresponding to what is achievable with the highly
cost-effective measures identified in this notice. The comments
received have not provided an adequate basis for concluding that EPA's
adoption of an additional national measure justifies scaling back on
that requirement. For that reason, EPA will not allow States to adjust
the base case 2007 inventory inventories to reflect any such additional
national measures. Rather, for these reports the States should continue
to use the base case 2007 inventory set forth in this rule.
In the SNPR, EPA also discussed establishing a process for
reassessing the State budgets for the post-2007 timeframe. Today's
final rule is based on analyses using the most complete,
scientifically-credible tools and data available for the assessment of
transport. The EPA expects that there will be a number of updates and
refinements in air quality methodologies and emissions estimation
techniques over the next 10 years. Therefore, EPA intends to reassess
ozone transport using the latest emissions and air quality monitoring
data and the next generation of air quality modeling tools. The
reassessment will include an evaluation of the effectiveness of the
regional NOX measures States have implemented in response to
today's final rule. Modeling analyses will be used to evaluate whether
additional local or regional controls are needed to address residual
nonattainment in the post-2007 timeframe. The assessment will also
examine differences in actual growth versus projected growth in the
years up to 2007 as well as expected future growth throughout the
entire OTAG region. The reassessment will also review advances in
control technologies to determine what reasonable and cost-effective
measures are available for purposes of controlling local and regional
ozone problems. In addition, EPA will continue to look at the issues
that surround the use of output-based State budget allocations. Based
on this reassessment, EPA may establish new budget levels and
allocation mechanisms for the post-2007 timeframe. The current budget
levels and the measures used to comply with today's final rule will
remain in effect until EPA takes action on establishing new State
budgets.
6. Compliance Supplement Pool
The EPA has received comments expressing concern that some sources
may encounter unexpected problems installing controls by the compliance
deadline that, in turn, could cause unacceptable risks for a source and
its associated industry. More specifically, commenters have expressed
concerns related to the electricity industry. If unexpected problems
arise for specific sources that are used to generate electricity, some
commenters believe that compliance with the May 1, 2003 deadline could
adversely impact the reliability of the electricity supply. Commenters
that raised concerns regarding the compliance deadline generally
supported additional compliance flexibility for the SIP call.
In both the NPR and SNPR, EPA solicited comment on a number of
provisions that would provide additional flexibility to both States and
sources for the requirements of the NOX SIP call. In the
NPR, EPA proposed that the NOX SIP call would require full
implementation of controls by no later than September 2002, but
solicited comment on the range of implementation dates from between
September 2002 and September 2004. In addition to the compliance
deadline, EPA also solicited comment on the role of banking as a
separate compliance flexibility for the NOX SIP call.
Banking may generally be defined as allowing sources that make
emissions reductions beyond current requirements to save and use these
excess reductions to exceed requirements in a later time period.
Depending upon the design of a trading program, banking provisions can
provide companies greater latitude for when controls are installed at
particular sources. In the SNPR, EPA presented a range of options for
incorporating banking in the NOX Budget Trading Program
including early reduction provisions and phasing in controls. The EPA
received many comments supporting banking in the NOX Budget
Trading Program and also as a general flexibility mechanism that should
be permissible for any State program used to comply with the
NOX SIP call.
In response to comments supporting an extended compliance deadline,
EPA has moved the deadline from the proposed date of September 2002 in
the NPR to May 1, 2003. As discussed further in Section V, this change
provides sources 7-8 additional months for implementing control
requirements while ensuring that controls are fully implemented by the
2003 ozone season. The EPA believes that the compliance date of May 1,
2003 for NOX controls to be installed to comply with the
NOX SIP call is a feasible and reasonable deadline. See
Section V.A.1. and the technical support document ``Feasibility of
Installing NOX Control Technologies By May 2003'' for
further discussion.
To provide additional flexibility to States and sources for
complying with the NOX SIP call beyond the extension of the
compliance deadline, EPA is establishing banking provisions and a
compliance supplement pool in today's final rule. The banking
provisions are outlined in Section III.F.7. The compliance supplement
pool is a voluntary provision that provides flexibility to States in
addressing concerns associated with full compliance by May 1, 2003.
Each State will be able to use the pool to cover excess emissions of
sources that are unable to meet the compliance deadline during the 2003
and 2004 ozone seasons. The pool may be used to credit sources that
make early reductions and to directly delay the compliance deadline for
specific sources. Credits issued from the compliance supplement pool
will not be valid for compliance past the 2004 ozone season. The EPA
established the compliance supplement pool by calculating one pool for
the entire NOX SIP call region. The pool was then allocated
to the States in proportion to the size of the emissions reduction they
are required to achieve under the NOX SIP call so that each
[[Page 57429]]
State has its own compliance supplement pool. The size of each State's
compliance supplement pool and the procedures that will apply to the
use of the pool are described below.
a. Size of the Compliance Supplement Pool. The EPA believes it is
important for the size of the pool to be capped. Capping the pool makes
it possible to estimate the potential impact that the compliance
supplement pool may have on NOX emissions during the 2003
and 2004 ozone seasons. Furthermore, EPA does not anticipate problems
for sources in meeting the May 1, 2003 deadline. If there are such
cases, they should be relatively few in number. Therefore, the size of
the pool only needs to be large enough to cover the limited potential
for unexpected compliance delays.
Today's final rule sets the size of the regional compliance
supplement pool at 200,000 tons. The EPA believes this is a reasonable
size for the pool given the analyses that were used in establishing the
State NOX budgets for today's final rule. As discussed in
Section V.A.1., EPA believes the most cost-effective control strategies
available to comply with the proposed budgets include post-combustion
controls (Selective Catalytic Reduction [SCR] and Selective Non-
catalytic Reduction [SNCR]) and combustion controls (e.g., low
NOX burners, overfire air, etc.) on large electric
generating units and large non-electric generating units. For the
reasons cited in Section V.A.1., EPA estimates that the implementation
of SCR controls is potentially more complicated and requires more time
than SNCR or combustion controls and, therefore, would determine what
the longest schedule would be for full implementation of the assumed
NOX controls. Since EPA estimates that a single SCR
installation will take about 23 months, EPA expects the first SCR
installations to be completed in 2001. Since compliance is required by
2003, one can assume 33 percent of SCR capacity will be installed each
year from 2001 to 2003. The 200,000 ton number is sufficient to cover
the excess emissions that must be offset if one year's worth of SCR
installations were delayed by a year. Table III-3 shows each State's
compliance supplement pool. The 200,000 tons were allocated to States
in proportion to the size of the emissions reduction they are required
to achieve under the NOX SIP call. The EPA used this
allocation methodology based on the assumption that the need for the
pool would be directly related to the magnitude of the emissions
reductions required in each State to comply with the NOX SIP
call.
Table III-3.--State Compliance Supplement Pools
[Tons]
----------------------------------------------------------------------------------------------------------------
Compliance
State Base Budget Tonnage supplement
reduction pool
----------------------------------------------------------------------------------------------------------------
Alabama......................................... 218,610 158,677 59,933 10,361
Connecticut..................................... 43,807 40,573 3,234 559
Delaware........................................ 20,936 18,523 2,413 417
District of Columbia............................ 6,603 6,792 (189) 0
Georgia......................................... 240,540 177,381 63,159 10,919
Illinois........................................ 311,174 210,210 100,964 17,455
Indiana......................................... 316,753 202,584 114,169 19,738
Kentucky........................................ 230,997 155,698 75,298 13,018
Maryland........................................ 92,570 71,388 21,182 3,662
Massachusetts................................... 79,815 78,168 1,648 285
Michigan........................................ 301,042 212,199 88,842 15,359
Missouri........................................ 175,089 114,532 60,557 10,469
New Jersey...................................... 106,995 97,034 9,960 1,722
New York........................................ 190,358 179,769 10,590 1,831
North Carolina.................................. 213,296 151,847 61,450 10,624
Ohio............................................ 372,626 239,898 132,728 22,947
Pennsylvania.................................... 331,785 252,447 79,338 13,716
Rhode Island.................................... 8,295 8,313 (18) 0
South Carolina.................................. 138,706 109,425 29,281 5,062
Tennessee....................................... 252,426 182,476 69,950 12,093
Virginia........................................ 191,050 155,718 35,332 6,108
West Virginia................................... 190,887 92,920 97,967 16,937
Wisconsin....................................... 145,391 106,540 38,851 6,717
---------------------------------------------------------------
Total....................................... 4,179,751 3,023,113 .............. 200,000
----------------------------------------------------------------------------------------------------------------
b. State Distribution of the Compliance Supplement Pool. States
have two options for making the pool available to sources. One option
is to distribute some or all of the pool to sources that generate early
reductions during ozone seasons prior to May 1, 2003. The second option
is to run a public process to provide tons to sources that demonstrate
a need for a compliance extension. A State wishing to use the
compliance supplement pool may divide the State pool and make some of
it available to sources through both options, or may use only one of
the options for distributing the pool to sources prior to May 1, 2003
according to the procedures discussed below. Tons that are not
distributed by a State prior to May 1, 2003 will be retired by EPA.
(1) Early Reduction Credits. The EPA encourages States to consider
making the compliance supplement pool available to sources through an
early reduction credit program. States may use early reduction credits
as an incentive for sources to make NOX emissions reductions
prior to the 2003 ozone season that would otherwise not occur. By
generating early credits or acquiring them from other sources,
companies will be able to use the early reduction credits to extend the
timeframe for achieving actual emissions reductions at specific sources
that may require additional time. To establish an early credit program,
States that participate in the NOX Budget Trading Program
may use the provisions
[[Page 57430]]
set forth in that trading program (See Section VII.F). States not
participating in the NOX Budget Trading Program are also
free to develop their own rules for granting early reduction credits
and recognizing the credits for compliance during the 2003 and 2004
ozone seasons. The procedures for establishing an early credit program
are presented below in Section III.F.7.c.
(2) Direct Distribution to Sources. States may also distribute the
compliance supplement pool directly to sources that demonstrate a need
for the compliance supplement. Under this approach, sources would be
responsible for demonstrating to the State and public that achieving
compliance by May 1, 2003 would create undue risk either to its own
operation or its associated industry. Before granting a direct
distribution to a source, the State must provide the public an
opportunity to comment on the validity of the need for direct
distribution of the compliance supplement. The direct distribution
process must be initiated and completed between September 30, 2002 and
May 1, 2003. States which choose to grant early reduction credits
cannot conduct the direct distribution until all early reduction
credits have been issued by the State. By postponing the direct
distribution until after September 2002, sources will have the maximum
opportunity to achieve compliance, either through installation of
controls or with early reduction credits, before using this option.
States and the public will also be better positioned to determine
legitimate requests after September 2002.
To ensure that direct distribution of the compliance supplement is
only provided to sources that truly need a compliance extension, States
are only permitted to give credits to an owner or operator of a source
that demonstrates the following:
The process of achieving compliance by May 1, 2003 would
create undue risk for the source or its associated industry. For
electric generating units, the demonstration should show that
installing controls would create unacceptable risks for the reliability
of the electricity supply during the time of installation. This
demonstration would include a showing that it was not feasible to
import electricity from other systems during the time of installation.
Non-electric generating sources may also be eligible for the compliance
supplement based on a demonstration of risk comparable to that
described for the electricity industry.
For a source subject to an early reduction credit program,
it was not possible to compensate for delayed compliance by generating
early reduction credits at the source or by acquiring credits generated
by other sources.
For a source subject to an emissions trading program, it
was not possible to acquire allowances or credits for the 2003 ozone
season from sources that will make reductions beyond required levels
during the 2003 ozone season.
7. Banking
As noted in the NPR and SNPR, States have the flexibility to choose
their own set of control measures to meet their Statewide
NOX budget established under the NOX SIP call.
States and sources have supported the use of emissions trading programs
as a control measure for complying with the NOX SIP call
requirements. EPA has provided a model cap-and-trade program
(NOX Budget Trading Program) for large stationary sources
that States can adopt as one option for establishing an emissions
trading program. A number of commenters (both States and sources) have
also expressed interest in pursuing alternative trading programs in
addition to or as a substitute for the NOX Budget Trading
Program. One possible flexibility mechanism available to sources
subject to an emissions trading program is the ability to bank
emissions reductions. Banking may generally be defined as allowing
sources that make emissions reductions beyond required levels to save
and use these excess reductions to compensate for emitting emissions
above required levels in a later time period. In the SNPR, EPA
requested comment on whether and how banking should be incorporated
into the design of the NOX Budget Trading Program. In the
proposal, four banking options were presented: (1) Banking would not be
a feature; (2) banking would begin when the trading program begins (May
2003); (3) sources would be allowed to generate early reductions
credits for use after the start of the program and banking would
continue after the program begins; (4) banking would begin with the
first phase of a two-phase trading program and continue thereafter
(i.e., phased-in control requirements). The EPA also requested comment
on options for managing the use of banked allowances in order to limit
the potential for emissions to be significantly higher than budgeted
levels because of banking. The EPA specifically proposed using a ``flow
control'' mechanism in the latter two banking options where the
potential exists for a large amount of banked allowances to be
available for use at the start of the program.
a. Banking Starting in 2003. Comments for the NOX Budget
Trading Program were generally supportive of including banking in the
trading program. Commenters noted that allowing sources to make excess
reductions in one year and use these reductions to emit above required
levels in a later year encourages early and cost-saving emission
reductions, helps avoid end-of-season emissions spikes (because unused
allowances retain their value for compliance in future years), and
encourages more expedient development and implementation of
NOX control technology. Commenters pointed out that banking
also provides sources flexibility in achieving emission reduction
goals, allowing them to save allowances in years when the cost of
achieving a given emission level is relatively low for use in years
when the cost is relatively higher (for example, a year characterized
by low availability of nuclear and hydro generation capacity would be a
higher cost year). Thus, banking was seen by many commenters as a
critical tool for sources to respond to uncertainty. Some commenters,
however, expressed caveats along with their support for banking. They
cited the need for some form of bank management to ensure that the use
of banked allowances does not detract from the environmental goal of
the NOX SIP call. At least one commenter recommended that
EPA identify banking as an area to be reviewed for problems during
audits of the program to ensure it did not have a detrimental impact.
The EPA also received comments supporting banking that were not
specific to the NOX Budget Trading Program. Many commenters
addressed the concept of banking when proposing alternative strategies
for establishing and implementing the State budgets that were proposed
in the NOX SIP call. These comments regarded banking as a
fundamental factor in establishing the timing and control level for the
State budgets. With all other factors being equal, a NOX SIP
call that allows banking provides additional flexibility and cost
savings to affected sources than a NOX SIP call without
banking. For this reason, many commenters included banking in their
alternative proposals.
In order to provide additional flexibility to States and sources
under the NOX SIP call as discussed in section III.F.6., and
recognizing that States may pursue alternative trading programs other
than the NOX Budget Trading Program, the Agency believes it
is important to establish criteria for banking that would apply to all
programs that States may use to comply with requirements of the
NOX SIP call.
[[Page 57431]]
Therefore, EPA is setting forth provisions in today's final rule that
will allow banking in the NOX Budget Trading Program and
other State trading programs. Trading programs used to comply with the
NOX SIP call may allow banking to start in the first control
period of the program, May 1 through September 30, 2003. Beginning in
that control period, States may allow sources included in these
programs to bank NOX emissions reductions not otherwise
required by the State's SIP, for compliance in future control periods.
As outlined below, the banking provisions also require the use of a
flow control mechanism beginning in 2004 and allow States to credit
early reductions generated by sources prior to 2003 that may be used
for compliance only in the 2003 and 2004 ozone seasons. The final rule
for the NOX Budget Trading Program conforms with these
banking provisions. Additionally, alternative emissions trading
programs used to comply with the SIP call will be subject to these
banking criteria as well other applicable criteria in Sec. 51.121 and
any other applicable EPA guidance such as the Economic Incentive
Program rules and guidance.
b. Management of Banked Allowances. Many utility and industry
commenters generally opposed the use of discounts or constraints on
banked allowances, arguing that such measures would reduce the
incentives to control emissions beyond required levels. In addition,
commenters felt the measures were overly complex and restrictive, as
well as unnecessary, since the stringent control level proposed would
serve as a barrier to overcontrol, precluding the establishment of a
sizeable bank. Several commenters remarked that any decision regarding
whether and to what extent a trading program should impose restrictions
on the use of banked allowances should proceed from an analysis of the
air quality effects of that use; in the absence of such an analysis,
there would be little basis for imposing restrictions or for deciding
what restrictions would properly address air quality effects. However,
these commenters did not provide analyses demonstrating that the use of
banked allowances in any given season would not be a problem in the
context of the NOX SIP call. One commenter pointed out
specifically that the sheer magnitude of the SIP call region should
preclude EPA from implementing a flow control management scheme similar
to that used under the Ozone Transport Commission's (OTC) trading
program, since protection of problem areas would not be feasible on
such a large scale.
Several commenters who were opposed to the management of banked
allowances, however, stated that if restrictions were to be imposed,
they would favor flow control as the most cost-effective, least rigid
means of management. A few commenters added that, if implemented, flow
control should be applied on a source-by-source basis so as to avoid
penalizing all of the participants in the trading program for the
excess banking of individual participants. One commenter stated that if
EPA concludes that there is an adequate basis for imposing some type of
restriction, it should avoid placing any absolute limit on the amount
of banked allowances that can be used in a given season. Another
commenter suggested that if EPA chooses to propose managed banking, it
should consider establishing an initial period without managed banking
upon which a managed banking program can later be based if it turns out
that ``trading contributes to nonattainment.'' Several additional
commenters, most notably northeastern States and a few environmental
groups, supported the use of a flow control management system to
discourage excess use of banked allowances in any one ozone season. One
such commenter suggested that EPA conduct an analysis similar to that
used by the OTC in determining the appropriate level of flow control
for the SIP call region.
Based on the stated goal of the NOX SIP call, to achieve
specified limits on NOX emissions for the purpose of
reducing NOX and ozone transport across State boundaries in
the eastern half of the United States, EPA believes it is appropriate
to place some limitation on the amount of emissions variability that
may occur with banking, and therefore, occur with the transport of
NOX. At the same time, any limitations on banking should
still fit within the market-based structure of trading programs, rather
than imposing overly stringent limits that would potentially eliminate
the advantages of having banking in the first place. For these reasons,
EPA is including a provision in today's final rule requiring any State
program used to comply with the requirements of the NOX SIP
call that allows banking to limit the potential effects of banking
through a flow control mechanism as described below. The flow control
mechanism will be applicable starting in the 2004 ozone season. In this
year, unused credits from the compliance supplement pool as well as
unused credits or allowances from the 2003 ozone season would be
considered banked.
The EPA believes that the flow control mechanism serves as an
important insurance policy against emissions variability in emissions
trading programs used to comply with the NOX SIP call. The
mechanism as described below would only restrict the use of banked
allowances or credits when a significant amount are used for compliance
in a specific ozone season. Based on the analyses in the RIA, EPA
believes that the flow control mechanism is set at a level that will
allow sources to use banking without restriction. However, the flow
control mechanism provides the extra security to downwind areas that
banking will not result in significant increases of emissions above
budgeted levels. The EPA also recognizes that a wide variety of
emissions trading programs may be used by States. Therefore, the
requirements for the flow control mechanism described below are
intended to be general, thus allowing States the flexibility to adjust
the flow control mechanism to fit the specific needs of each program.
Section VII.F. also provides further discussion of the flow control
mechanism and describes how it is incorporated into the NOX
Budget Trading Program.
The flow control mechanism allows the unlimited banking of
emissions reductions by sources during and after 2003, but discourages
the ``excessive use'' of banked allowances or credits by establishing
either an absolute limit on the number of banked allowances or credits
that can be used each season or a rate discounting the use of banked
allowances or credits over a given level. The key issue with flow
control is to establish the level at which flow control is triggered.
In the SNPR, EPA solicited comment on establishing the level at 10
percent of the ozone season budget for the sources included in the
trading program. This level was proposed because 10 percent seems to be
a reasonable number that would allow a significant amount of banked
allowances or credits to be used, but not so many as to jeopardize the
intended effects of the NOX SIP call in a given season. The
EPA also proposed the 10 percent number because it is the level used
for flow control in the OTC's trading program. Although some commenters
questioned whether this number is appropriate for the NOX
SIP call region, commenters did not provide explicit analyses or
recommendations for a different number. Thus, EPA continues to believe
that 10 percent is a reasonable number and is including this in today's
final rule. Based on the analyses in the RIA, EPA does not
[[Page 57432]]
anticipate sources to bank above the 10 percent level. Therefore, this
level should prevent significant emissions increases resulting from
banking without restricting sources normal operations. The effect of
flow control set at 10 percent of the trading program budget is that
for a given season, sources may use banked allowances or credits for
compliance without restrictions in an amount up to 10 percent of the
NOX budget for those sources in the trading program. Banked
allowances or credits that are used in an amount greater than 10
percent of the NOX budget for those sources will have
restrictions that are described below.
The EPA believes it is necessary to provide flexibility to States
for determining how to apply the 10 percent flow control in individual
trading programs and for determining the appropriate restrictions for
banked allowances or credits that are used in an amount greater than
the 10 percent number. States have the flexibility to apply the flow
control mechanism to specifically control the use of banked allowances
or credits at each source or to apply the mechanism more broadly across
the entire trading program. For example, by applying flow control at
the source level, a State would allow each source participating in the
trading program to use banked allowances without restrictions in an
amount not greater than 10 percent of its allowable NOX
emissions for the ozone season. Conversely, flow control could be
applied so that individual sources may use banked allowances or credits
in an amount more than 10 percent without restrictions, but the total
number used throughout the entire trading program (i.e., total number
of banked credits or allowances used for compliance throughout all
States participating in the trading program) could not exceed 10
percent of the allowable NOX emissions for all sources in
the trading program without restrictions. The net effect is the same
under either approach--banked allowances or credits may be used each
year without restrictions in an amount that does not exceed 10 percent
of the allowable NOX emissions for all sources covered by
the trading program. The NOX Budget Trading Program uses the
latter approach. See Section VII.F. for more details.
The second issue for the flow control mechanism is to determine
what restrictions should be placed on banked allowances or credits that
are used in an amount greater than 10 percent of the allowable
NOX emissions for all sources covered by the trading
program. Again, EPA is providing flexibility for the restrictions that
States may use. States may use a discount that is no less than two-for-
one, requiring sources to retire one additional banked allowance or
credit for each banked allowance or credit used for compliance in an
amount greater than the 10 percent level. Or States may set the 10
percent level as a hard cap and not allow any banked allowances or
credits to be used in an amount greater than the 10 percent level.
Although the discount option provides more flexibility to sources and
more uncertainty regarding NOX emissions in a given year,
EPA believes both options serve as an acceptable restriction for
limiting the variability of emissions associated with banking. As
described in Section VII.F, the NOX Budget Trading Program
uses the 2-for-1 discount as the applicable restriction.
c. Early Reduction Credits. The majority of commenters for the
NOX Budget Trading Program generally supported the option of
awarding early reduction credits. Commenters noted that the issuance of
credits will provide cost savings and environmental benefits by
encouraging early reductions, facilitate compliance with the budget by
allowing sources to earn allowances that may be used to delay more
stringent emission reductions, and stimulate the market by ensuring
allowances are available for trading at the program start. Several
commenters advocated making early reduction credits available for any
reductions that exceed baseline controls, whereas other commenters
supported early reduction credits only if they exceed the controls
required under the SIP call, as was proposed by EPA. A few other
commenters suggested levels between these two options. A few OTC States
suggested that OTC allowances banked in Phase II (between 1999-2003 for
reductions beyond an approximate 0.20 lb/mmBtu rate) could be used as
early reduction credits in the NOX Budget Trading Program,
either one-for-one or at a discount ratio, depending on the level
beyond which credits were awarded in the latter program. A few
remaining commenters, concerned about the potential for creating or
exacerbating ozone violations, supported early reduction credits and
banking only if coupled with flow control.
Regarding the appropriate length of the period in which early
reductions could be earned, some commenters supported EPA's proposed
option in the SNPR of a two-year early reduction period, while others
favored a three or four-year period. At least one commenter
specifically recommended that the early reduction period start in
January 1995, while another suggested September 1998. Several
commenters rejected EPA's suggestion that early reduction credits be
calculated as a set-aside from the first five years of allowances,
arguing that treating the credits as set-asides would be inconsistent
with the nature of early reduction credits. Conversely, a few other
commenters felt the credits should be awarded from within State budgets
to avoid budget inflation. Additional commenters criticized EPA's
suggestion that if early reduction credits were awarded, they be
awarded at the company level, arguing instead for individual source
awards. One commenter stated that awards on a company basis would not
address the load shifting concerns EPA cited, while another thought EPA
could address the load shifting concern by basing credits on activity
levels in a historic period rather than by shifting to a company-level
award. Finally, at least one commenter felt that States should be able
to independently establish parameters for awarding voluntary early
reductions.
For the reasons set forth in Section III.F.7, Compliance Supplement
Pool, EPA is allowing, but not requiring, States to grant early
reduction credit to sources that reduce their ozone season
NOX emissions below levels specified by the State prior to
the 2003 control period. The early reduction credits may be used by
sources for compliance during the 2003 and 2004 ozone seasons. EPA
believes that an early credit program can be helpful to encourage
emissions reductions prior to the 2003 ozone season that would not be
made without an economic incentive for the sources to act. Furthermore,
the early credit program will provide additional allowances or credits
for use during the 2003 and 2004 ozone seasons. By generating early
credits or acquiring early credits from other sources that generated
credits, companies would have greater latitude in determining when
actual emissions reductions are achieved at specific sources. As
discussed in Section III.F.7, this may be beneficial to some companies
that are concerned about the time and effort required to install all
necessary emissions controls prior to May 2003. States will be limited
in the amount of early reduction credits that they may grant by the
amounts set forth in Section III.F.7 Compliance Supplement Pool. The
potential pool of credits that is available to each State is intended
to be large enough to provide a real incentive for early reductions and
enough flexibility to allow the installation of some control equipment,
if necessary, past May 2003.
[[Page 57433]]
Section VII.F. of today's preamble outlines how the early credit
program is being incorporated into the NOX Budget Trading
Program and how banked allowances from the OTC program may be
integrated with this provision. States that develop alternative trading
programs may craft their early reduction program to meet the needs of
their specific trading program. The following outlines the general
requirements that any early reduction program used to comply with the
NOX SIP call should meet. For an emission reduction to be
eligible as an early reduction credit, it must meet the following
criteria:
Surplus--The reduction is not contained in the State's SIP
or otherwise required by the CAA.
Verifiable--The reduction can be verified as actually
having occured.
Quantifiable--The reduction is quantified according to
procedures set forth by the State and approved by EPA. Early reduction
credits generated by sources serving electric generators with a
nameplate capacity greater than 25 MWe or greater or boilers,
combustion turbines and combined cycle units with a maximum design heat
input greater than 250 mmBtu/hr, should be quantified according to the
monitoring provisions of part 75, subpart H as required in
Sec. 51.121(h)(1)(iv).
Beyond the above requirements, States are free to develop an early
credit program that meets the needs of their specific trading program
provided the State does not issue credits in an amount greater the size
of the credit pool presented in Section III.F.7. A State's early credit
program may be established for any ozone season occurring after a
State's early credit rule is approved by EPA into the State's SIP
revision and before May 1, 2003.
To ensure that a State does not issue an amount of early credits
beyond the amount specified in each State's compliance supplement pool,
EPA recommends that a State develop procedures to be used in case there
is an over-subscription of the early credit pool. Possible options
include granting early credits on a first-come, first-served basis or
waiting until all applications are submitted and then discounting the
early credits on a pro-rata basis so that the amount of early credits
issued equals the size of the State's pool. States may also influence
the amount of early credits that sources generate by considering what
level of emissions reductions the State will recognize as early
reductions. For example, a State may choose to issue early reduction
credits for any reductions below applicable requirements. However, the
State may choose to make the demonstration more stringent by requiring
early reduction credits to be generated by reductions that are below a
limit that is tighter than applicable requirements (e.g., grant early
reductions that are 30 percent below applicable requirements or below a
fixed level such as 0.20 lb/mmBtu).
In the SNPR, EPA also solicited comment on a phased-in
NOX Budget Trading Program that would begin in 2001, two
years prior to the compliance date for the NOX SIP call. In
response to the proposal, most commenters that discussed the phase-in
program option were generally opposed to it. Their primary argument was
that such a program would effectively accelerate the compliance date
for NOX controls under the SIP call. A few commenters,
however, still supported the phase-in approach as a means of mitigating
the uncertainties inherent in the allowance market that would develop
for the 2003 control period, allowing sources to gain experience prior
to 2003. Some commenters specifically favored a phase-in approach only
if it does not interfere with the 2003 ozone season compliance
schedule, whereas others supported a phase-in approach as a means of
reducing the burdens of the 2003 ozone season compliance schedule.
Today's final rule requires States to achieve the necessary
emissions reductions by May 2003 and does not require States to phase-
in controls prior to 2003. States that wish to phase-in controls prior
to 2003 as a part of a State trading program may do this, but they are
not required to do so to comply with the NOX SIP call.
States that establish a phased-in trading program in order to allow
sources to generate early reduction credits will be subject to the
requirements for early reductions as described above, including the
requirement that a State may not grant an amount of early reductions in
excess of the State's compliance supplement pool. For a discussion of
how the Ozone Transport Commission's trading program may be integrated
with the compliance supplement pool and the early reduction provisions,
see Section VII.F, which describes the banking provisions of the
NOX Budget Trading Program.
G. Final Statewide Budgets
1. EGU
a. Description of Selected Approach. As described in Section
III.B.3. of this notice, the EGU budget component is calculated based
on applying a 0.15 lb/mmBtu emission limit to sources greater than 25
MWe. This limit is applied uniformly across all States that are covered
by this SIP call. The higher of 1995 or 1996 heat input, grown to 2007
is used to calculate the budget component.
b. Summary of Budget Component. Both the 2007 electricity
generating Base Case and the electricity generating Budget component
were revised from the levels in the SNPR based on the changes described
in Section III.B.3. of this notice. These revisions are shown in Tables
III-4 and III-5. The difference between the revised 2007 Base Case and
Budget emissions from the SNPR and the final Base Case and Budget
emissions is shown in Table III-4. Negative changes indicate decreases.
The final percent reduction from the 2007 Base Case to the Budget is
shown in Table III-5.
Table III-4.--Changes to Revised SNPR Base Case and Budget Components for Electricity Generating Units
[Tons NOX/season]
----------------------------------------------------------------------------------------------------------------
Percent Revised Final Percent
State Revised base Final base change budget budget change
----------------------------------------------------------------------------------------------------------------
Alabama..................... 85,201 76,900 -10 30,644 29,051 -5
Connecticut................. 7,048 5,600 -21 5,245 2,583 -51
Delaware.................... 10,727 5,800 -46 4,994 3,523 -29
District of Columbia........ 236 *0 -100 152 207 36
Georgia..................... 84,890 86,500 2 32,433 30,255 -7
Illinois.................... 119,756 119,300 0 36,570 32,045 -12
Indiana..................... 159,917 136,800 -14 51,818 49,020 -5
Kentucky.................... 130,919 107,800 -18 38,775 36,753 -5
[[Page 57434]]
Maryland.................... 37,575 32,600 -13 12,971 14,807 14
Massachusetts............... 24,998 16,500 -34 14,651 15,033 3
Michigan.................... 73,585 86,600 18 29,458 28,165 -4
Missouri.................... 81,799 82,100 0 26,450 23,923 -10
New Jersey.................. 17,484 18,400 5 8,191 10,863 33
New York.................... 43,705 39,200 -10 31,222 30,273 -3
North Carolina.............. 86,872 84,800 -2 32,691 31,394 -4
Ohio........................ 167,601 163,100 -3 51,493 48,468 -6
Pennsylvania................ 120,979 123,100 2 45,971 52,000 13
Rhode Island................ 1,351 1,100 -19 1,609 1,118 -31
South Carolina.............. 57,146 36,300 -36 19,842 16,290 -18
Tennessee................... 83,844 70,900 -15 26,225 25,386 -3
Virginia.................... 51,113 40,900 -20 20,990 18,258 -13
West Virginia............... 76,374 115,500 51 24,045 26,439 10
Wisconsin................... 45,538 52,000 14 17,345 17,972 4
-----------------------------------------------------------------------------------
Total................... 1,568,655 1,501,800 -4 563,784 543,825 -4
----------------------------------------------------------------------------------------------------------------
*The base case for DC is actually projected to be 3 tons per season. The base case values in this table are
rounded to the nearest 100 tons.
Table III-5.--Final NOX Budget Components and Percent Reduction for Electricity Generating Units
[tons/season]
----------------------------------------------------------------------------------------------------------------
Percent
State Final base Final budget reduction
----------------------------------------------------------------------------------------------------------------
Alabama......................................................... 76,900 29,051 62
Connecticut..................................................... 5,600 2,583 54
Delaware........................................................ 5,800 3,523 39
District of Columbia............................................ *0 207 NA
Georgia......................................................... 86,500 30,255 65
Illinois........................................................ 119,300 32,045 73
Indiana......................................................... 136,800 49,020 64
Kentucky........................................................ 107,800 36,753 66
Maryland........................................................ 32,600 14,807 55
Massachusetts................................................... 16,500 15,033 9
Michigan........................................................ 86,600 28,165 67
Missouri........................................................ 82,100 23,923 71
New Jersey...................................................... 18,400 10,863 41
New York........................................................ 39,200 30,273 23
North Carolina.................................................. 84,800 31,394 63
Ohio............................................................ 163,100 48,468 70
Pennsylvania.................................................... 123,100 52,000 58
Rhode Island.................................................... 1,100 1,118 -2
South Carolina.................................................. 36,300 16,290 55
Tennessee....................................................... 70,900 25,386 64
Virginia........................................................ 40,900 18,258 55
West Virginia................................................... 115,500 26,439 77
Wisconsin....................................................... 52,000 17,972 65
-----------------------------------------------
Total....................................................... 1,501,800 543,825 64
----------------------------------------------------------------------------------------------------------------
*The base case for DC is actually projected to be 3 tons per season. The base case values in this table are
rounded to the nearest 100 tons.
2. Non-EGU Point Sources
As indicated in the proposal and discussed earlier in this notice,
EPA continues to believe that technically feasible control measures
costing between an average of $1,000 to $2,000 per ozone season ton
(1990 dollars) are highly cost-effective and therefore should be the
basis for determining the significant amounts that must be eliminated
by each covered jurisdiction. In the SNPR, EPA committed to examining
alternatives that would limit the number of affected non-EGU sources
for the purpose of establishing emissions budgets, yet still achieve
the environmental objective of mitigating broad-scale ozone transport.
The EPA examined alternatives that target reductions from the largest
non-EGU source category groupings, and within each of the largest
groupings applied the cost-effectiveness criteria. The resulting
emissions budget covers the majority of emissions from large non-
utility sources, and does not include reductions from small sources and
sources that, as a group, are not efficient to control, or are already
covered by other Federal measures (e.g., CAA Sec. 112 MACT). The
description below summarizes the budget approach for non-EGU point
sources.
a. Description of Selected Approach.
(1) NOX Budget Sources. The following approach is used
to determine if a unit's emissions would be decreased as part of the
budget calculation.
[[Page 57435]]
Industrial boilers, turbines, stationary internal combustion engines
and cement manufacturing are the only non-EGU sources for which
reductions are assumed in the budget calculation.
1. Use heat input capacity data for each source if the data are in
the updated inventory.
2. If heat input capacity data are not available, use the default
identification of small and large sources developed by EPA/Pechan for
OTAG and also used to develop the NPR and SNPR budgets for source
categories with heat input capacity fields (``default data'').
3. Emission reductions would be assumed if specific source heat
input capacity data or default data indicate that a source is greater
than 250 mmBtu/hr in the updated inventory.
4. If specific or default heat input capacity data are not
available in the updated inventory (or not appropriate for a particular
source category), emission reductions would be assumed if the unit's
average summer day emissions are greater than one ton per day based on
the updated inventory.
5. All others are ``small'' and no emission reductions are assumed.
It should be noted (as described earlier in this section) that no
emissions reductions are assumed for point sources with capacities less
than or equal to 250 mmBtu/hr but with emissions greater than 1 ton/day
for purposes of calculating the budget. This is a change from the NPR
which assumed RACT controls on units with capacities less than or equal
to 250 mmBtu/hr and emissions greater than 1 ton/day.
(2) Control Levels. For purposes of calculating the State
NOX budgets for the relevant sources (described above), the
following emissions decreases from uncontrolled levels were assumed:
1. Non-EGU boilers and turbines--60% decrease.
2. Stationary internal combustion engines--90% decrease.
3. Cement manufacturing plants--30% decrease.
These controls result in an overall reduction in emissions from all
affected large non-EGU point sources of almost 40 percent (187,800 tons
per season decrease).
Each State's budget is based on application of these controls
beginning on May 1, 2003. The EPA recognizes that if States include
these source categories in a regionwide trading program, as EPA
encourages States to do, each State will comply with its budget through
compliance of its sources with the requirements of the regionwide
trading program. Of course, under the trading program, sources in a
State may acquire or sell allowances that will, in turn, allow for
higher or lower emissions levels for that State than assumed in this
action. Because EPA has determined that the ambient effect of such a
trading program across the region is consistent with the basis for
including States in the SIP call (see discussion below at Section IV),
EPA has structured its rule to allow a State to meet its budget by
including the amount of emissions for which sources in the State hold
allowances from out-of-State sources. Overall, total NOX
emissions in the region will be within the budget.
b. Summary of Budget Component. Both the 2007 Base Case and Budget
component for non-electricity generating point sources were revised
based on the changes described above. Changes to the 2007 base reflect
changes in the base year (1995) emissions and changes in growth
factors. Changes to the budget components reflect these changes as well
as the change in level of control. These resulting budget components
are shown in Tables III-5 and III-6. The difference between the 2007
Base Case and Budget emissions as revised in the SNPR and the final
Base Case and Budget emissions for non-electricity generating point
sources is shown in Table III-6. Negative changes indicate decreases.
The final percent reduction from the 2007 Base Case to the Budget is
shown in Table III-7.
Table III-6.--Changes to Revised Base Case and Budget Components for Non-Electricity Generating Point Sources
[Tons NOX/season]
--------------------------------------------------------------------------------------------------------------------------------------------------------
Revised base Final base Percent change Revised budget Final budget Percent change
--------------------------------------------------------------------------------------------------------------------------------------------------------
Alabama................................................. 48,187 49,781 3 24,416 37,696 54
Connecticut............................................. 5,254 5,273 0 3,103 5,056 3
Delaware................................................ 5,276 1,781 -66 2,271 1,645 -28
District of Columbia.................................... 311 310 0 259 292 13
Georgia................................................. 33,939 33,939 0 14,305 27,026 89
Illinois................................................ 65,351 55,721 -15 40,719 42,011 3
Indiana................................................. 51,839 71,270 37 29,187 44,881 54
Kentucky................................................ 19,019 18,956 0 11,996 14,705 23
Maryland................................................ 10,710 10,982 3 5,852 7,593 30
Massachusetts........................................... 9,978 9,943 0 6,207 9,763 57
Michigan................................................ 61,656 79,034 28 35,957 48,627 35
Missouri................................................ 12,320 13,433 9 9,012 11,054 23
New Jersey.............................................. 22,228 22,228 0 12,786 19,804 55
New York................................................ 20,853 25,791 24 14,644 24,128 65
North Carolina.......................................... 34,412 34,027 -1 19,267 25,984 35
Ohio.................................................... 53,329 53,241 0 30,923 35,145 14
Pennsylvania............................................ 74,839 73,748 -1 41,824 65,510 57
Rhode Island............................................ 327 327 0 327 327 0
South Carolina.......................................... 34,994 34,740 -1 18,671 25,469 36
Tennessee............................................... 67,774 60,004 -11 34,308 35,568 4
Virginia................................................ 25,509 39,765 56 10,919 27,076 148
West Virginia........................................... 42,733 40,192 -6 21,066 31,286 49
Wisconsin............................................... 21,263 22,796 7 11,401 17,973 58
-----------------------------------------------------------------------------------------------
Total............................................... 722,101 757,281 5 399,416 558,618 40
--------------------------------------------------------------------------------------------------------------------------------------------------------
[[Page 57436]]
Table III-7.--Final NOX Budget Components and Percent Reduction for Non-Electricity Generating Point Sources
[Tons/season]
----------------------------------------------------------------------------------------------------------------
Percent
Final base Final budget reduction
----------------------------------------------------------------------------------------------------------------
Alabama......................................................... 49,781 37,696 24
Connecticut..................................................... 5,273 5,056 4
Delaware........................................................ 1,781 1,645 8
District of Columbia............................................ 310 292 6
Georgia......................................................... 33,939 27,026 20
Illinois........................................................ 55,721 42,011 25
Indiana......................................................... 71,270 44,881 37
Kentucky........................................................ 18,956 14,705 22
Maryland........................................................ 10,982 7,593 31
Massachusetts................................................... 9,943 9,763 2
Michigan........................................................ 79,034 48,627 38
Missouri........................................................ 13,433 11,054 18
New Jersey...................................................... 22,228 19,804 11
New York........................................................ 25,791 24,128 6
North Carolina.................................................. 34,027 25,984 24
Ohio............................................................ 53,241 35,145 34
Pennsylvania.................................................... 73,748 65,510 11
Rhode Island.................................................... 327 327 0
South Carolina.................................................. 34,740 25,469 27
Tennessee....................................................... 60,004 35,568 41
Virginia........................................................ 39,765 27,076 32
West Virginia................................................... 40,192 31,286 22
Wisconsin....................................................... 22,796 17,973 21
-----------------------------------------------
Total....................................................... 757,281 558,618 26
----------------------------------------------------------------------------------------------------------------
3. Mobile and Area Sources
a. Description of Selected Budget Approach. As discussed in Section
III.D.3 of the notice, EPA proposed highway budget components based on
projected highway vehicle emissions in 2007 from a base year of 1990,
assuming implementation of those measures incorporated in existing
SIPs, such as inspection and maintenance programs and reformulated
fuels, measures already implemented federally, and those additional
measures expected to be implemented federally by 2007. As discussed in
Section III.E of this notice, EPA proposed nonroad mobile source budget
components based on projected nonroad mobile source emissions in 2007
from a base year of 1990. These projections were developed by
estimating the emissions expected in 2007 from all nonroad engines,
assuming implementation of those measures incorporated in existing
SIPs, measures already implemented federally, and those additional
measures expected to be implemented federally. For area sources, no
cost-effective control measures were identified in the NPR. Because no
comments were received that demonstrate that additional controls for
highway, nonroad, or area sources are both feasible and highly cost-
effective, the final budgets are based on the same levels of controls
that were proposed.
b. Summary of Budget Component. Changes were made to the baseline
stationary area, nonroad and highway mobile source budget data as
discussed in Sections III.D. and III.E. of this notice. Budget
components were calculated using the updated baseline and the controls
discussed above. The resulting final budget components for these
sectors are contained in Tables III-7, III-8, and III-9 below, along
with the difference between the proposed Budget emissions and the final
Budget emissions. The budget components are not compared to the 2007
base because no reductions were calculated beyond the base case. In the
NPR and SNPR, EPA used a 2007 CAA baseline for these source sectors.
Because the measures that are assumed in the budgets for these sectors
are measures that would occur in the absence of the SIP call, EPA
believes that it is more appropriate to use the budget level for these
source sectors as the baseline and compare the total budgets to this
revised baseline.
Table III-8.--Final NOX Budget Components for Stationary Area Sources
[Tons/season]
----------------------------------------------------------------------------------------------------------------
Proposed
budget Final budget Percent change
----------------------------------------------------------------------------------------------------------------
Alabama......................................................... 25,229 25,225 0
Connecticut..................................................... 4,587 4,588 0
Delaware........................................................ 1,035 963 -7
District of Columbia............................................ 741 741 0
Georgia......................................................... 11,901 11,902 0
Illinois........................................................ 7,270 7,822 8
Indiana......................................................... 25,545 25,544 0
Kentucky........................................................ 38,801 38,773 0
Maryland........................................................ 8,123 4,105 -49
Massachusetts................................................... 10,297 10,090 -2
[[Page 57437]]
Michigan........................................................ 28,126 28,128 0
Missouri........................................................ 6,626 6,603 0
New Jersey...................................................... 11,388 11,098 -3
New York........................................................ 15,585 15,587 0
North Carolina.................................................. 9,193 10,651 16
Ohio............................................................ 19,446 19,425 0
Pennsylvania.................................................... 17,103 17,103 0
Rhode Island.................................................... 420 420 0
South Carolina.................................................. 8,420 8,359 -1
Tennessee....................................................... 11,991 11,990 0
Virginia........................................................ 25,261 18,622 -26
West Virginia................................................... 4,901 4,790 -2
Wisconsin....................................................... 10,361 8,160 -21
-----------------------------------------------
Total....................................................... 302,350 290,689 -4
----------------------------------------------------------------------------------------------------------------
Table III-9.--Final NOX Budget Components and Percent Reduction for Nonroad Sources
[Tons/season]
----------------------------------------------------------------------------------------------------------------
Proposed
budget Final budget Percent change
----------------------------------------------------------------------------------------------------------------
Alabama......................................................... 18,727 16,594 -11
Connecticut..................................................... 9,581 9,584 0
Delaware........................................................ 4,262 4,261 0
District of Columbia............................................ 3,582 3,470 -3
Georgia......................................................... 22,714 21,588 -5
Illinois........................................................ 56,429 47,035 -17
Indiana......................................................... 27,112 22,445 -17
Kentucky........................................................ 22,530 19,627 -13
Maryland........................................................ 18,062 17,249 -4
Massachusetts................................................... 19,305 18,911 -2
Michigan........................................................ 24,245 23,495 -3
Missouri........................................................ 19,102 17,723 -7
New Jersey...................................................... 21,723 21,163 -3
New York........................................................ 30,018 29,260 -3
North Carolina.................................................. 18,898 17,799 -6
Ohio............................................................ 42,032 37,781 -10
Pennsylvania.................................................... 29,176 25,554 -12
Rhode Island.................................................... 2,074 2,073 0
South Carolina.................................................. 12,831 11,903 -7
Tennessee....................................................... 47,065 44,567 -5
Virginia........................................................ 25,357 21,551 -15
West Virginia................................................... 10,048 10,220 2
Wisconsin....................................................... 15,145 12,965 -14
-----------------------------------------------
Total....................................................... 500,018 456,818 -9
----------------------------------------------------------------------------------------------------------------
Table III-10. Final NOX Budget Components and Percent Reduction for Highway Vehicles
[Tons/season]
----------------------------------------------------------------------------------------------------------------
Proposed
budget Final budget Percent change
----------------------------------------------------------------------------------------------------------------
Alabama......................................................... 56,601 50,111 -11
Connecticut..................................................... 17,392 18,762 8
Delaware........................................................ 8,449 8,131 -4
District of Columbia............................................ 2,267 2,082 -8
Georgia......................................................... 77,660 86,611 12
Illinois........................................................ 77,690 81,297 5
Indiana......................................................... 66,684 60,694 -9
Kentucky........................................................ 46,258 45,841 -1
Maryland........................................................ 28,620 27,634 -3
Massachusetts................................................... 23,116 24,371 5
Michigan........................................................ 81,453 83,784 3
Missouri........................................................ 55,056 55,230 0
New Jersey...................................................... 39,376 34,106 -13
New York........................................................ 94,068 80,521 -14
[[Page 57438]]
North Carolina.................................................. 73,056 66,019 -10
Ohio............................................................ 92,549 99,079 7
Pennsylvania.................................................... 73,176 92,280 26
Rhode Island.................................................... 5,701 4,375 -23
South Carolina.................................................. 49,503 47,404 -4
Tennessee....................................................... 67,662 64,965 -4
Virginia........................................................ 79,848 70,212 -12
West Virginia................................................... 21,641 20,185 -7
Wisconsin....................................................... 41,651 49,470 19
-----------------------------------------------
Total....................................................... 1,179,477 1,173,163 -1
----------------------------------------------------------------------------------------------------------------
4. Potential Alternatives to Meeting the Budget
The EPA believes that there are additional control measures and
alternative mixes of controls that a State could choose to implement by
May 1, 2003. Examples of such measures are described below and
illustrate that options are potentially available in several source
categories.
The EPA believes that, with respect to EGUs, there is a large
potential for energy efficiency and renewables in the NOX
SIP call region that reduce demand and provide for more
environmentally-friendly energy resources. For example, if a company
replaces a turbine with a more efficient one, the unit supplying the
turbine would reduce the amount of fuel (heat input) the unit combusts
and would reduce NOX emissions proportionately, while the
associated generator would produce the same amount of electricity.
Renewable energy source generation includes hydroelectric, solar, wind,
and geothermal generation. EPA recognizes that promotion of energy
efficiency and renewables can contribute to a cost-effective
NOX reduction strategy. As such, EPA encourages States in
the NOX SIP call region to consider including energy
efficiency and renewables as a strategy in meeting their NOX
budgets. One way to achieve this goal is by including a provision
within a State's NOX Budget Trading Rule that allocates a
portion of a State's trading program budget to implementers of energy
efficiency and renewables projects that reduce energy-related
NOX emissions during the ozone season. Another is to include
energy efficiency and renewables projects as part of a State's
implementation plan.
The EPA is working to develop guidance on how States can integrate
energy efficiency into their SIPs by both of these mechanisms. The
guidance will present EPA's current thinking on the important elements
to include in a functional system that allocates a portion of a State's
trading program budget to implementers of energy efficiency and
renewables projects within the context of the NOX Budget
Trading Program. In addition, EPA will issue guidance outlining
procedures for including energy efficiency and renewables projects in a
State's SIP as control strategies for achieving the State's
NOX budget, separate from the NOX Budget Trading
Program. EPA plans to issue these guidance documents in the Fall of
1998 so that they will be available to States early in their SIP
planning process.
With respect to non-EGUs, individual States could choose to require
emissions decreases from sources or source categories that EPA exempted
from the budget calculations. For example, there are many large sources
for which EPA lacked enough information to determine potential controls
and emissions reductions; States may have access to such information
and could choose to apply cost-effective controls. In addition, States
could choose to regulate one or more of the non-EGU stationary sources
or source categories which EPA had exempted because emissions were
relatively low considering other source categories in the 23
jurisdictions. In individual States, emissions from such sources could
be a high percentage of uncontrolled emissions and, thus, be subject to
efficient, cost-effective control for that particular State. Further,
States may take other approaches to developing their budgets, such as
cutoffs based on horsepower rather than tons per day, since they might
have access to data that EPA did not have for all 23 jurisdictions.
With respect to mobile sources, States could implement other
NOX control measures in lieu of the controls described
earlier in this section. For example, vehicle inspection and
maintenance programs can provide significant NOX reductions
from highway vehicles. Additional NOX reductions can be
obtained by opting into the reformulated gasoline program, by
implementing measures to reduce the growth in VMT, and by implementing
programs to accelerate retirement of older, higher-emitting highway
vehicles and nonroad equipment.
5. Statewide Budgets
The revised Statewide budgets that reflect the changes to the base
year inventory and growth factors for all sectors and the revised
control levels for the non-EGU point source sector described above are
shown in Table III-11. For the 23 jurisdictions combined, the budgets
result in a 28 percent reduction from the base case. In the NPR and
SNPR the percent reduction was 35 percent. The difference in the
percent reduction is due to several factors. First, in the NPR and SNPR
reductions from certain highway and nonroad controls were assumed to
occur as a result of measures implemented between promulgation of this
rule and 2007. These measures include National Low Emission Vehicle
Standards, the 2004 Heavy-Duty Engine Standards, the Federal Small
Engine Standards, Phase II, Federal Marine Engine Standards (for diesel
engines of greater than 50 horsepower), Federal Locomotive Standards,
and the Nonroad Diesel Engine Standards. These controls were reflected
in the budget but were not included in the base case. For the final
rule, EPA determined that these measures should be included in the base
case, rather than the budgets, because the measures would be
implemented even in the absence of this rulemaking. Based on the
emission levels that were used in the SNPR, the effect of using this
approach to setting the base case is to decrease the percent reduction
from 35 percent to approximately 31 percent.
[[Page 57439]]
The additional change in the percent reduction (from 31 percent to 28
percent) is primarily due to EPA's decision not to assume controls for
several non-EGU source categories and to change the level of control
for those non-EGU categories for which controls are assumed. Although
the overall percent reduction went from 35 percent to 28 percent, the
difference between the budget proposed in the SNPR and the final
budgets in today's notice is less than 3 percent.
Table III-11.--Revised Statewide NOX Budgets
[Tons/season]
----------------------------------------------------------------------------------------------------------------
Percent
State Base Budget reduction
----------------------------------------------------------------------------------------------------------------
Alabama......................................................... 218,610 158,677 27
Connecticut..................................................... 43,807 40,57 37
Delaware........................................................ 20,936 18,523 12
District of Columbia............................................ 6,603 6,792 -3
Georgia......................................................... 240,540 177,381 26
Illinois........................................................ 311,174 210,210 32
Indiana......................................................... 316,753 202,584 36
Kentucky........................................................ 230,997 155,698 33
Maryland........................................................ 92,570 71,388 23
Massachusetts................................................... 79,815 78,168 2
Michigan........................................................ 301,042 212,199 30
Missouri........................................................ 75,089 114,532 35
New Jersey...................................................... 106,995 97,034 9
New York........................................................ 190,358 179,769 6
North Carolina.................................................. 213,296 151,847 29
Ohio............................................................ 372,626 239,898 36
Pennsylvania.................................................... 331,785 252,447 24
Rhode Island.................................................... 8,295 8,31 30
South Carolina.................................................. 138,706 109,425 21
Tennessee....................................................... 252,426 182,476 28
Virginia........................................................ 191,050 155,718 18
West Virginia................................................... 190,887 92,920 51
Wisconsin....................................................... 145,391 106,540 27
-----------------------------------------------
Total........................................................... 4,179,751 3,023,113 28
----------------------------------------------------------------------------------------------------------------
IV. Air Quality Assessment
A. Assessment of Proposed Statewide Budgets
In the SNPR, EPA documented the estimated ozone benefits of the
proposed Statewide NOX budgets based on an air quality
modeling analysis. The major findings of that analysis are as follows:
(1) The emissions reductions associated with the proposed Statewide
budgets are predicted to produce large reductions in both 1-hour and 8-
hour concentrations in areas which currently violate the NAAQS and
which would likely continue to have violations in the future without
the SIP call budget reductions.
(2) Looking at individual ozone ``problem areas'' considered by
OTAG shows similar results, based on the available metrics.
(3) Any ``disbenefits'' due to the NOX reductions
associated with the budgets are expected to be very limited compared to
the extent of the benefits expected from these budgets.
(4) Even though the budgets are expected to reduce 1-hour and 8-
hour ozone concentrations across all 23 jurisdictions, nonattainment
problems requiring additional local control measures will likely
continue in some areas currently violating the NAAQS.
(63 FR 25903)
B. Comments and Responses
The EPA received numerous comments on the air quality modeling of
the proposed NOX budgets. The following is a summary of the
main comments and EPA's responses.
Comment: Commenters stated that the emissions inventories used for
modeling were flawed because EPA's projection of the base year
emissions to 2007 improperly treated growth for certain electric
generation units by growing these units beyond their design capacity.
Response: The EPA agrees with this comment and has revised the 2007
emissions projections for modeling to take this factor into account.
For the modeling described in the SNPR, EPA applied State-level growth
factors uniformly to existing sources in each State. This did not
account for maximum capacity and could have resulted in sources being
modeled with emissions that were higher than their actual capacity
would allow. For the modeling described in this notice, EPA has revised
the projection procedures to use IPM to allocate growth to existing
units considering their design capacity. As described below, EPA has
remodeled the 2007 Base Case and the Statewide budgets using this
revised inventory and found that the conclusions from the revised runs
do not differ from those based on the SNPR model runs of these budgets.
Comment: Commenters stated that EPA's modeling in the SNPR examined
the impacts of the budgets applied regionwide (i.e., for each State for
which a budget is required), rather than the impacts on downwind
nonattainment of the budgets applied only in upwind States. Therefore,
according to the commenters, this modeling is not useful for indicating
the impact of the State budgets on downwind nonattainment or
maintenance problems.
Response: The EPA is well aware that many States in the SIP Call
region are both upwind and downwind States, that is, they are upwind of
certain nonattainment areas and downwind from other States. For
example, Pennsylvania is upwind of New York City, and emissions from
Pennsylvania sources significantly contribute to this nonattainment
problem; and
[[Page 57440]]
Pennsylvania is downwind of several States, emissions from which
significantly contribute to Philadelphia's nonattainment problem.
The EPA is further aware that modeling analyses that evaluate
emissions reductions in each State affected by today's rulemaking do
not isolate the precise impact of emissions reductions from each upwind
State on nonattainment in a State that is itself both an upwind and
downwind State. That is, the emissions reductions in that upwind/
downwind area impact its own nonattainment problems. To return to the
example noted above, because emissions reductions in Pennsylvania
affect Philadelphia's air quality, modeling Pennsylvania's emissions
reductions along with emissions reductions in all other affected States
does not isolate the impact of emissions reductions from States upwind
of Pennsylvania on Philadelphia's air quality. As a result, EPA is
aware that the regionwide modeling of different budget levels does not
indicate the differential impact on downwind areas of higher budget
levels as compared to lower budget levels in upwind areas.
Nevertheless, EPA believes that regionwide modeling of the State
budgets is a useful indication of the overall impacts of various budget
levels. Today's rulemaking requires regionwide emissions reductions,
which will carry certain costs and will have certain impacts viewed on
a State-by-State basis and on a regionwide basis. The multi-State
budgets promulgated today mean that in a State that is both upwind and
downwind of other States, such as Pennsylvania, the air quality will,
in fact, be improved by the emissions reductions in upwind States and
by the reductions within the States that are required to improve air
quality further downwind. Thus, it is necessary to consider the upwind
emissions reductions together with the downwind emissions reductions in
order to fully evaluate the air quality impacts of the Statewide
budgets. Regionwide modeling is the only available approach to indicate
these ``real world'' impacts in individual States, as well as allow an
assessment of those impacts in light of their costs. Accordingly, this
modeling is useful in evaluating the overall impacts of the alternative
budget levels considered in the course of the rulemaking. The EPA
believes that a comparison of the overall impacts of alternative budget
levels, in turn, serves as a means to confirm whether the budget levels
promulgated in today's rulemaking yield meaningful air quality
benefits. Moreover, EPA has conducted other modeling which indicates
the impact of budget-level emissions on air quality downwind, as
discussed below.
Comment: Commenters stated that EPA should have modeled the
proposed budgets on a State-by-State basis in order to assess the
downwind benefits of applying the budgets in each State.
Response: The EPA performed a multi-factor analysis to determine
the amount of a State's emissions that significantly contribute to
downwind nonattainment and what the resulting State budget should be.
This is discussed in detail in Section II.C., Weight of Evidence
Determination of Covered States. Specifically, EPA determined that
emissions from all sources in certain States contribute to downwind
problems, but that only a portion of those emissions--in some cases, a
relatively small portion--may be reduced through highly cost-effective
controls. The EPA established a budget for each State based on the
elimination of these emissions. After EPA established the budgets, EPA
performed air quality modeling to quantify the overall ozone benefits
of the budgets applied in all upwind States on selected downwind areas.
This modeling is described below. The EPA considered the results of
this modeling as an additional piece of evidence in the analysis to
confirm that the amount of emissions reductions from upwind States
collectively provide meaningful reductions in nonattainment downwind.
For the purposes of this modeling it is sufficient to model the
budgets collectively, and not State-by-State, to demonstrate that the
intended benefits of the budgets are achieved. Commenters who
recommended State-by-State modeling generally argued that it would
indicate that the reductions from a particular State would have a
relatively small impact downwind, particularly compared to the impact
of local reductions or reductions from other upwind States. In general,
such a modeling result could stem from the relatively small amount of
emissions reductions required of a particular upwind State under the
SIP Call, due to EPA's decision to base the budgets on cost-effective
controls rather than, more expensive controls. However, EPA's air
quality modeling of the ambient impact of the required budgets in the
upwind States on downwind nonattainment (discussed below) shows that
even if the downwind ambient impact of the required reductions from a
particular upwind State were small, that impact, when combined with the
impact from the reductions required from other upwind States, provides
meaningful downwind benefits. Ozone air quality problems are caused by
the collective contribution from numerous sources over a large
geographic area, so that it is appropriate to assess the impact of
reductions from a particular upwind State in combination with
reductions from other upwind States. The downwind air quality benefits
from these upwind reductions confirm the appropriateness of the
promulgated budgets.
Comment: Commenters stated that EPA should have modeled alternative
control options to determine if less stringent controls, either applied
uniformly or on a subregional basis (i.e., multi-State subregional
variations in control levels), would provide air quality benefits
essentially equivalent to EPA's proposal. In addition, commenters
submitted a considerable number of new modeling analyses intended to
show that (a) sufficient downwind ozone benefits can be achieved with
control levels less stringent than those associated with EPA's
proposal; (b) controls applied in certain upwind States, when examined
on a State-by-State basis, do not provide ``significant'' benefits in
any downwind nonattainment area; and/or (c) NOX controls
increase ozone locally in some areas and these increases are greater
than the predicted decreases. In addition to new control strategy
modeling, commenters submitted modeling that pertains to the finding of
significant contribution. The EPA's responses to this modeling are
discussed in Section II.C., Weight of Evidence Determination of Covered
States and in the Response to Comment document.
Response: In response to the comments on the need to model
alternative controls, EPA has modeled alternative budgets based on
several EGU and non-EGU control options. For the most part, these
alternative budgets were modeled regionwide in order to assess, as
discussed above, the benefits considering both downwind and upwind
emissions reductions, collectively. Further, as discussed below, EPA
modeled several other types of scenarios including runs to assess the
impacts of the proposal applied in upwind States on several downwind
areas. The EPA's modeling analyses are summarized below and described
in detail in the Air Quality Modeling TSD.
Regarding the new control strategy modeling submitted by
commenters, EPA has reviewed this information in the same way it
reviewed the new modeling on ``significant contribution'', as described
in Section II.C., Weight of Evidence Determination of Covered States.
Specifically, EPA reviewed the commenters' modeling to determine and
[[Page 57441]]
assess (a) the technical aspects of the models that were applied; (b)
the treatment of emissions inventories; (c) the types of episodes
modeled; (d) the methods for aggregating, analyzing, and presenting the
results; (e) the completeness and applicability of the information
provided; and (f) whether the technical evidence supports the arguments
made by the commenters. A summary of this review is discussed next. For
the most part, the commenters used either the UAM-V model and/or the
CAMX model to assess the relative impacts of various
NOX control strategies. As discussed in Section II.C. Weight
of Evidence Determination of Covered States, modeling results from both
models are viewed by EPA as technically acceptable. Concerning the
emissions used for modeling, most commenters stated that they used the
EPA SNPR or IPM-derived 2007 Base Case emissions as a starting point
for developing emissions for the control scenarios. However, the
commenters did not provide emissions data summaries in order for EPA to
confirm which inventories were used in the modeling. Also, the
commenters did not document in detail how they applied the controls to
the emissions inventory.
Most of the control strategy modeling submitted by commenters was
performed for the July 1995 episode although a few commenters performed
modeling for all four OTAG episodes and one commenter provided modeling
for a non-OTAG episode in June of 1991. As discussed in Section II.C.,
and in the Response to Comment document, EPA's ability to fully
evaluate and utilize the modeling submitted by commenters was hampered
in some cases because only limited information on the results was
provided.
The EPA considered the strengths and limitations in the commenters'
modeling analyses in evaluating whether the technical evidence
presented in the comments supports the arguments made by the
commenters. A detailed review of the commenters' modeling is contained
in the Response to Comment document. In general, this review indicates
that (a) downwind ozone benefits increase as greater NOX
controls are applied to sources in upwind States, (b) emissions
reductions at the level of the SIP Call, even when evaluated on an
individual State-by-State basis, reduce ozone in downwind nonattainment
areas, (c) the net benefits of NOX control at the level of
the SIP Call outweigh any local disbenefits, and (d) upwind
NOX reductions tend to mitigate local disbenefits in
downwind areas. Thus, based on this evaluation, EPA generally found
that the submitted modeling did not refute the overall conclusions EPA
has drawn concerning the impacts of NOX emissions in the
relevant geographic areas. However, because the extent and level of
detail in the information presented by the commenters was, in many
cases, limited and/or qualitative, the EPA decided to model a number of
alternative control scenarios for all four OTAG episodes. The results
of EPA's modeling of the impacts of alternative NOX controls
are described next.
C. Assessment of Alternative Control Levels
As indicated above, EPA has remodeled the Base Case and Statewide
budgets using updated EGU emissions which do not exceed the capacity of
individual units. In addition, EPA has performed modeling of various
alternative EGU and non-EGU control options. Further, EPA has modeled
the benefits in selected downwind areas of the budgets applied in
upwind States. The results of EPA's modeling analyses are summarized
below and described in more detail in the Air Quality Modeling TSD.
1. Scenarios Modeled
As part of EPA's assessment, a 2007 SIP Call Base Case (hereafter
referred to as the ``Base Case'') and eight emissions scenarios were
modeled, as listed in Table IV-1. The first four scenarios (i.e.
``0.25'', ``0.20'', ``0.15t'', and ``0.12'') were designed to evaluate
alternative EGU and non-EGU controls applied uniformly in all 23
jurisdictions. For each of these four scenarios, EGU emissions were
determined assuming a cap-and-trade program across all 23
jurisdictions. The 0.15t scenario reflects the SIP Call proposal for
both non-EGU and EGU sources. Note that non-EGU controls were modeled
at the level of the proposal for all scenarios except for the 0.25
scenario for which less stringent controls were assumed.
Table IV-1.--Emissions Scenarios Modeled
Base Case:
2007 SIP Call Base Case \1\
Point Sources: CAA Controls.
Area Sources: OTAG ``Level 1'' Controls.
Highway Vehicles: OTAG ``Level 0'' Controls.
0.25......................................... 0.25 lb/mmBtu, interstate 60% reduction for large
trading. sources.
0.20......................................... 0.20 lb/mmBtu, interstate 70% reduction for large
trading. sources, RACT for medium
sources\2\.
0.15t........................................ 0.15 lb/mmBtu, interstate 70% reduction for large
trading. sources, RACT for medium
sources.
0.12......................................... 0.12 lb/mmBtu, interstate 70% reduction for large
trading. sources, RACT for medium
sources.
0.15nt....................................... 0.15 lb/mmBtu, intrastate 70% reduction for large
trading. sources, RACT for medium
sources.
Downwind Scenarios for Analysis of ``Transport'':
(1) 0.15nt EGU and non-EGU controls in the Northeast \3\; 2007 Base
Case emissions elsewhere.
(2) 0.15nt EGU and non-EGU controls in Georgia; 2007 Base Case
emissions elsewhere.
(3) 0.15nt EGU and non-EGU controls in Illinois, Indiana, and
Wisconsin; 2007 Base Case emissions elsewhere.
\1\ See Table IV-2 for a listing of Base Case control measures.
\2\ Reductions are from 2007 ``uncontrolled'' emissions. Non-EGU sources
>250mmBtu/hr are considered as ``large''; sources <250mmbtu r,="" but="">1tpd are considered as ``medium''. The non-EGU point source controls
assumed for purposes of this modeling do not match the levels assumed
for the purpose of calculating the final budgets.
\3\ Northeast includes Connecticut, Delaware, District of Columbia,
Maryland, Massachusetts, New Jersey, New York, Pennsylvania, and Rhode
Island.
[[Page 57442]]
The EPA also modeled a 0.15 intrastate trading scenario,
``0.15nt'', which was constructed with EGU emissions that meet each
State's budget without interstate trading. In developing the EGU
emissions for this scenario, intrastate trading among sources in a
State was allowed to occur. The benefits of the 0.15nt scenario
compared to those from the 0.15t scenario were examined to determine
whether an interstate trading program would affect the overall benefits
of the proposal.
The last three scenarios in Table IV-1 were designed to evaluate
the downwind benefits resulting from reductions in transport due to the
budgets in upwind States. Each of these scenarios constitutes a
separate modeling run that applies the 0.15nt scenario in a different
downwind area. For example, in the ``nt15NE'' scenario, the 0.15nt
emissions budgets were applied only in those Northeast States subject
to the SIP Call. The predictions from each of these three modeling runs
for specific downwind areas were compared to the Base Case to estimate
the impacts of the budgets applied only within the downwind area. The
predictions from these three runs were then compared to the 0.15nt
scenario across all 23 jurisdictions to estimate the additional
benefits in each downwind area due to reductions in transport resulting
from the budgets applied in both upwind and downwind States.
2. Emissions for Model Runs
As indicated in Table IV-1, Base Case emissions for area sources
(including nonroad), highway vehicles, and non-EGU sources represent a
combination of OTAG emissions data for various control levels. This
includes CAA controls on non-EGU point sources, OTAG ``level 1''
controls on area sources, and ``level 0'' controls on highway vehicles.
The control measures included in the Base Case for each source category
are listed in Table IV-2. These modeling runs were performed before
changes were made to the inventory in response to comments. For the 23
jurisdictions as a whole, the Base Case NOX emissions that
were modeled are 2 percent higher than the final Base Case emissions
that reflect changes made in response to comments.
Table IV-2.--2007 SIP Call Base Case Controls
------------------------------------------------------------------------
EGUs:
Title IV Controls [ phase 1 and 2 ].
--250 Ton PSD and NSPS.
--RACT & NSR in non-waived NAAs.
Non-EGU Point:
--NOX RACT on major sources in non-waived NAAs.
--250 Ton PSD and NSPS.
--NSR in non-waived NAAs.
--CTG and Non-CTG VOC RACT at major sources in NAAs and OTR.
--New Source LAER.
Stationary Area:
--Two Phases of VOC Consumer and Commercial Products and One Phase
of Architectural Coatings controls.
--VOC Stage 1 and 2 Petroleum Distribution Controls in NAAs.
--VOC Autobody, Degreasing and Dry Cleaning controls in NAAs.
Nonroad Mobile:
Fed Phase II Small Eng. Stds.
--Fed Marine Eng. Stds.
--Fed Nonroad Heavy-Duty (=50 hp) Engine Stds--Phase 1.
--Fed RFG II (statutory and opt-in areas).
--9.0 RVP maximum elsewhere in OTAG domain.
--Fed Locomotive Stds (not including rebuilds).
--Fed Nonroad Diesel Engine Stds--Phases 2 and 3.
Highway Vehicles:
--National LEV.
--Fed RFG II (statutory and opt-in areas).
--9.0 RVP maximum elsewhere in OTAG domain.
--High Enhanced I/M (serious and above NAAs).
--Low Enhanced I/M for rest of OTR.
--Basic I/M (mandated NAAs).
--Clean Fuel Fleets (mandated NAAs).
--On-board vapor recovery.
--HDV 2 gm std.
Rate of Progress Requirements:
--Effectively, ROP through 1999.
------------------------------------------------------------------------
Note that area and mobile source emissions were held constant at
Base Case levels in all scenarios. The Base Case emissions for EGUs
were obtained from simulations of IPM which projected 1996 electric
generation to 2007 based on economic assumptions, unit specific
capacity, and the requirements in Title I and Title IV of the CAA. The
Base Case emissions that were modeled for the EGU sector are 4 percent
higher than the final Base Case emissions for this sector. The EGU
emissions estimates for each of the control scenarios in Table IV-1
were also derived using the IPM. Table IV-3 summarizes the emissions
reductions provided by the control scenarios compared to the Base Case.
The development of emissions data for air quality modeling is further
described in the Air Quality Modeling TSD.
[[Page 57443]]
Table IV-3.--Summary of NOX Emissions Reductions
----------------------------------------------------------------------------------------------------------------
Region \1\ 0.25 0.20 0.15t 0.12 0.15nt
----------------------------------------------------------------------------------------------------------------
Percent Reduction in Point Source NOX Emissions From 2007 SIP Call Base Case
----------------------------------------------------------------------------------------------------------------
Northeast....................... 29 39 49 52 46
Midwest......................... 40 51 59 65 58
Southeast....................... 35 49 54 61 56
SIP Call \2\.................... 37 48 57 62 57
----------------------------------------------------------------------------------------------------------------
Percent Reduction in Total NOX Emissions From 2007 SIP Call Base Case
----------------------------------------------------------------------------------------------------------------
Northeast....................... 13 18 22 24 21
Midwest......................... 22 28 33 36 32
Southeast....................... 19 26 29 32 30
SIP Call \2\.................... 20 26 30 33 30
----------------------------------------------------------------------------------------------------------------
\1\ The Northeast includes Connecticut, Delaware, District of Columbia, Maryland, Massachusetts, New Jersey, New
York, Pennsylvania, and Rhode Island; the Midwest includes Illinois, Indiana, Kentucky, Michigan, Missouri
Ohio, West Virginia, and Wisconsin; the Southeast includes Alabama, Georgia, North Carolina South Carolina,
Tennessee and Virginia.
\2\ ``SIP Call'' includes the total percent reduction over all 23 jurisdictions subject to budgets as part of
this notice.
3. Modeling Results
The EPA applied UAM-V for each of the four OTAG episodes to
simulate ozone concentrations for the Base Case and each scenario. The
results for the uniform regionwide scenarios are presented first. This
is followed by the results comparing interstate and intrastate trading.
The results for the assessment of overall downwind benefits of the
budgets applied in upwind States is presented last.
The analysis of model predictions focused 1-hour daily maximum
values and 8-hour daily maximum values predicted for all 4 episodes.
The rationale for analyzing the model predictions in this way is
discussed in Section II.C. Each of the control scenarios was evaluated
using the four ``metrics'' listed in Table IV-4. Note that the model
predictions used in calculating the metrics were restricted to those 1-
hour values >=125 ppb and 8-hour values >=85. Model predictions less
than these concentrations were not included in the analysis.
Table IV-4.--Air Quality Metrics
------------------------------------------------------------------------
Metric 1: Exceedances........ The number of values above the
concentration level of NAAQS.\1\
Metric 2: Ozone Reduced-ppb.. The magnitude and frequency of the
``ppb'' reductions in ozone.
Metric 3: Total ppb Reduced.. The total ``ppb'' reduced by a given
scenario, not including that portion of
the reduction that occurs below the
level of the NAAQS.
Metric 4: Population-Weighted The same as Metric 3, except that the
Total ppb Reduced. ozone reductions are weighted by the
population in the grid cell in which the
reductions occur.
------------------------------------------------------------------------
\1\ 1-hour values >=125 ppb; 8-hour values >=85 ppb.
A full description of these metrics and the procedures for
selecting ``nonattainment'' receptors for calculating the metrics can
be found in the Air Quality Modeling TSD. In brief, ``nonattainment''
receptors for the 1-hour analysis include those grid cells that (a) are
associated with counties designated as nonattainment for the 1-hour
NAAQS and (b) have 1-hour Base Case model predictions >=125 ppb. These
grid cells are referred to as ``designated plus modeled'' nonattainment
receptors. Using these receptors, the metrics were calculated for each
1-hour nonattainment area as well as for each State. To calculate the
metrics by State, the ``nonattainment'' receptors in that State were
pooled together.
For the 8-hour analysis, ``nonattainment'' receptors include those
grid cells that (a) are associated with counties currently violating
the 8-hour NAAQS and (b) have 8-hour Base Case model predictions >=85
ppb. These grid cells are referred to as ``violating plus modeled''
nonattainment receptors. The metrics were calculated on a State-by-
State basis for the 8-hour analyses.
In general, the four metrics lead to similar overall conclusions.
The results for the full set of receptor areas (i.e., ``designated plus
modeled'' for the 1-hour NAAQS and ``violating plus modeled'' for the
8-hour NAAQS) are provided in the Air Quality Modeling TSD for all four
metrics. In this preamble, Metrics 1 and 3 are presented to illustrate
the results.
a. Impacts of Alternative Controls. The impacts on ozone
concentrations of the 0.15t scenario and each of the alternative
scenarios are provided by region (i.e., Midwest, Southeast, and
Northeast) in Tables IV-5 and IV-6 for Metrics 1 and 3, respectively.
The complete set of data for individual States and 1-hour nonattainment
areas is provided in the Air Quality Modeling TSD. Table IV-5 shows the
percent reduction in the number of exceedances across all four episodes
between each control scenario and the Base Case. Table IV-6 shows the
percent reduction in total ozone above the NAAQS provided by each
scenario, compared to the total ozone above the NAAQS in the Base Case.
[[Page 57444]]
Table IV-5.--Results for Metric 1: Number of Exceedances
----------------------------------------------------------------------------------------------------------------
0.25 0.20 0.15t 0.12 0.15nt
----------------------------------------------------------------------------------------------------------------
Percent Reduction in the Number of Exceedances 1-Hour Daily Maximum >=125 ppb
----------------------------------------------------------------------------------------------------------------
Midwest......................... 25 32 38 43 38
Southeast....................... 23 33 34 40 36
Northeast....................... 24 31 36 39 36
SIP Call Total.................. 24 31 36 40 37
----------------------------------------------------------------------------------------------------------------
Percent Reduction in the Number of Exceedances 8-Hour Daily Maximum >=85 ppb
----------------------------------------------------------------------------------------------------------------
Midwest......................... 35 44 50 54 49
Southeast....................... 30 40 46 51 48
Northeast....................... 26 34 41 44 41
SIP Call Total.................. 30 39 45 49 45
----------------------------------------------------------------------------------------------------------------
Table IV-6.--Results for Metric 3: Total ``ppb'' Reduced
----------------------------------------------------------------------------------------------------------------
0.25 0.20 0.15t 0.12 0.15nt
----------------------------------------------------------------------------------------------------------------
Total ``ppb'' Reduced Compared to the Total ``ppb'' Above NAAQS in Base Case \1\ 1-Hour Daily Maximum >=125 ppb
----------------------------------------------------------------------------------------------------------------
Midwest......................... 31 39 45 49 44
Southeast....................... 27 37 39 44 41
Northeast....................... 25 32 37 40 37
SIP Call Total.................. 27 35 40 43 40
----------------------------------------------------------------------------------------------------------------
Total ``ppb'' Reduced Compared to the Total ``ppb'' Above NAAQS in Base Case 8-Hour Daily Maximum >=85 ppb
----------------------------------------------------------------------------------------------------------------
Midwest......................... 35 42 48 52 47
Southeast....................... 33 44 49 53 50
Northeast....................... 28 37 43 46 43
SIP Call Total.................. 31 40 46 50 46
----------------------------------------------------------------------------------------------------------------
\1\ The values in this table were calculated by dividing the Total ``ppb'' Reduced in the control scenario by
the Total ``ppb'' above the NAAQS in the Base Case. These values represent the percent of total ozone above
the NAAQS in te Case that is reduced by the control scenario.
The results indicate that the 0.15t scenario provides substantial
reductions in both 1-hour and 8-hour ozone concentrations in all three
regions.
In the Midwest the 0.15t scenario provides a 38 percent reduction
in 1-hour exceedances and a 45 percent reduction in ``total ozone''
>=125 ppb. The regionwide Midwest reductions in 8-hour exceedances and
``total ozone'' >=85 ppb are 45 percent and 50 percent, respectively.
Considering individual 1-hour nonattainment areas in this region, the
reduction in exceedances due to the 0.15t controls are 36 percent over
Lake Michigan,61 73 percent in Southwest Michigan, and 54
percent in Louisville. The corresponding reductions in ``total ozone''
>=125 ppb are 44 percent over Lake Michigan, 81 percent in southwest
Michigan, and 64 percent in Louisville. The results for other areas are
contained in the Air Quality Modeling TSD.
---------------------------------------------------------------------------
\61\ The rationale for analyzing the impacts over Lake Michigan
is discussed in Section II.C, Weight of Evidence Determination of
Covered States.
---------------------------------------------------------------------------
In the Southeast, 1-hour exceedances are reduced by 39 percent and
the ``total ozone'' >=125 ppb by 34 percent. Considering individual
nonattainment areas in the Southeast, the 0.15t scenario provides a 36
percent reduction in 1-hour exceedances in Atlanta and a 39 percent
reduction in exceedances in Birmingham. The reduction in ``total
ozone'' >=125 ppb is 41 percent in Atlanta and 54 percent in
Birmingham. The overall regionwide ozone benefits across the Southeast
are also large for the 8-hour NAAQS. For example, the number of 8-hour
exceedances in this region is reduced by 46 percent with the 0.15t
scenario.
In the Northeast, 0.15t provides a 37 percent reduction in 1-hour
exceedances and a 34 percent reduction in ``total ozone'' >=125 pp. For
individual nonattainment areas in the Northeast, the reductions in both
Metrics 1 and 3 range from approximately 25 percent in Washington, DC
up to 100 percent in Pittsburgh. For the serious and severe 1-hour
nonattainment areas along the Northeast Corridor from Washington, DC to
Boston, the 1-hour reductions vary from city to city, but are generally
in the range of 25 percent to 55 percent. The regionwide reductions in
8-hour exceedances and ``total ozone'' >=85 ppb in the Northeast are
above 40 percent.
In general, results from the scenarios evaluated demonstrate that
the larger the reduction in NOX emissions, the greater the
overall ozone benefit. As indicated in Table IV-5 and IV-6, the 0.25
and 0.20 scenarios generally do not provide the same level of reduction
as the 0.15t scenario in any of the three regions, whereas the 0.12
scenario provides additional ozone benefits beyond 0.15t in all three
regions. Also, the results indicate that even with the most stringent
control option considered, nonattainment problems requiring additional
local controls may continue in some areas currently violating the
NAAQS.
The impact on ozone reductions of a trading program versus meeting
the budgets in each State can be seen by comparing the results for the
0.15t and 0.15nt scenarios. The data in Tables IV-5 and IV-6 indicate
that there is no overall loss of ozone benefits for either 1-hour or 8-
hour concentrations across the 23 jurisdictions due to trading. On a
regional basis, the benefits of interstate and intrastate trading at
the 0.15 control level are essentially the same in the Northeast and
Midwest and slightly less with interstate trading in the Southeast.
[[Page 57445]]
As indicated in the summary of comments, several commenters stated
that there would be local disbenefits due to the EPA proposal that
would outweigh any benefits. The modeling runs discussed here shed
light on the issue. Of the four metrics examined by EPA, Metrics 3 and
4 (i.e., ``Total ppb Reduced'' and ``Population-Weighted Total ppb
Reduced'') are most appropriate for identifying any net disbenefits
because the ozone decreases and any increases (disbenefits) are
considered in calculating each of these metrics. The metrics will have
negative values for situations in which the total disbenefits are
greater than the total benefits. The EPA examined the 1-hour estimates
for these metrics for each 1-hour nonattainment area and the 8-hour
estimates by State to identify any areas in which the modeling
indicated a net disbenefit. The results indicate that the only net
disbenefit predicted in any of the scenarios was in Cincinnati for the
1-hour NAAQS. However, these disbenefits occurred only in the 0.25 and
0.20 scenarios. In the 0.15t scenario, there is a net 32 percent
benefit in Cincinnati with Metric 3 and a net benefit of 23 percent
with Metric 4. There were no net Statewide 8-hour disbenefits in any of
the scenarios examined by EPA.
b. Impacts of Upwind Controls on Downwind Nonattainment. The
impacts of the budgets applied in upwind States on downwind ozone in
the (a) the Northeast, (b) Georgia, and (c) Illinois-Indiana-Wisconsin,
were evaluated by comparing the 0.15nt scenario to the three downwind
transport assessment scenarios listed in Table IV-1. In each of these
three scenarios, EPA modeled the 0.15nt option in one of the downwind
areas with the Base Case emissions applied in the rest of the OTAG
region.62 The results of each downwind control run were
compared to the Base Case in order to assess the benefits of the
controls applied within those areas (i.e., the downwind areas).
Similarly, the predictions for the 0.15nt regionwide scenario were
compared to the Base Case to estimate the benefits in each area of the
downwind plus upwind controls. The benefits of the upwind controls were
determined by calculating the difference between the benefits of the
downwind controls compared to the benefits of the downwind plus upwind
controls. The results are provided in Table IV-7. The following is an
example of how the benefits of upwind controls were calculated for
Metric 1 (i.e., number of exceedances). In the Northeast, there were
1052 grid-day exceedances of the 1-hour NAAQS predicted in the Base
Case scenario. In the downwind control scenario (i.e., 0.15nt applied
in the Northeast only), the number of exceedances declined to 827 grid-
days which represents a 21 percent reduction in exceedances from the
Base Case due to controls in the Northeast. In the downwind plus upwind
scenario, the number of 1-hour exceedances declined even further to 670
grid-days which is a 36 percent reduction from the Base Case.
Therefore, the upwind controls provide a 15 percent reduction in 1-hour
exceedances in the Northeast (i.e., 36 percent versus 21 percent).
---------------------------------------------------------------------------
\62\ As described in the Air Quality Modeling TSD, emissions
from the intrastate trading scenario rather than the interstate
trading scenario were used for the analysis of upwind controls in
order to avoid any potentially confounding effects of small changes
in the downwind emissions between the downwind control scenario and
the downwind plus upwind control scenario due to interstate trading.
---------------------------------------------------------------------------
For Metric 3 (i.e., Total ``ppb'' Reduced), the impact of upwind
controls on downwind ozone was determined using two approaches. The
first approach is similar to the procedures followed described above
for exceedances. For example, in the Northeast the total ppb >=125 ppb
(across all grids and days) in the Base Case was 14,724 ppb. In the
downwind control scenario the total ppb reduced by these controls was
3289 ppb which represents a 22 percent reduction (i.e., 3289 ppb
divided by 14,724 ppb) in total ppb >=125 ppb. In the downwind plus
upwind control scenario, the total ppb reduced was 5500 ppb which
represents a 37 percent reduction in total ppb >=125 ppb in the Base
Case. Therefore, the upwind controls provide a 15 percent reduction in
total ppb >=125 ppb (i.e., 37 percent versus 22 percent). The results
for Metric 3 calculated using this first approach are presented in
Table IV-7.
A second approach to analyze the benefits of upwind controls using
Metric 3 is to determine the fraction or percentage of the total
reduction from downwind plus upwind controls that comes from just the
upwind controls. This is determined by first subtracting the ppb
reduced by downwind controls from the ppb reduced by downwind plus
upwind controls. This difference provides an estimate of the portion of
the reduction due to upwind controls. Then, the portion of the
reduction due to upwind controls is divided by the reduction from
downwind plus upwind controls to estimate the percent of reduction due
to the upwind controls only. For example, in the Northeast the 1-hour
total ppb reduced by the downwind plus upwind controls is 5500 ppb and
the total ppb reduced by the downwind controls is 3289 ppb. The
difference (2211 ppb) is the estimated amount of reduction due to
upwind controls. Thus, in this example, the upwind controls provide 40
percent (i.e., 2211 ppb divided by 5500 ppb) of the total ppb reduction
in the downwind plus upwind regionwide scenario. The results for Metric
3 using this second approach for estimating the impacts of upwind
controls are provided in Table IV-8.
--------------------------------------------------------------------------------------------------------------------------------------------------------
1-hour daily max 8-hour daily max
-----------------------------------------------------------------------------------------------
DW \1\ DW + UW \1\ UW \1\ DW DW + UW UW
--------------------------------------------------------------------------------------------------------------------------------------------------------
Percent Reduction in Exceedances
--------------------------------------------------------------------------------------------------------------------------------------------------------
Northeast............................................... 21 36 15 18 40 22
Lake MI................................................. 29 36 7 11 17 6
IL/IN/WI................................................ 35 50 15 27 57 30
Atlanta................................................. 30 39 9 \2\ NA NA NA
Georgia \3\............................................. 30 39 9 15 27 12
--------------------------------------------------------------------------------------------------------------------------------------------------------
Percent Reduction in Total ``ppb'' Above the NAAQS
--------------------------------------------------------------------------------------------------------------------------------------------------------
Northeast............................................... 22 37 15 23 43 20
Lake MI................................................. 39 44 5 20 28 8
IL/IN/WI................................................ 17 33 16 32 62 30
Atlanta................................................. 37 43 6 NA NA NA
[[Page 57446]]
Georgia................................................. 37 43 6 25 35 10
--------------------------------------------------------------------------------------------------------------------------------------------------------
\1\ ``DW'' denotes the reductions due to the downwind controls; ``DW + UW'' denotes the reductions due to controls applied regionwide in upwind plus
downwind areas; and ``UW'' denotes the incremental additional reduction in exceedances.
\2\ NA: The metrics for the 8-hour NAAQS were not calculated for individual 1-hour nonattainment areas.
\3\ The 1-hour results for Georgia are the same as for Atlanta because Atlanta is the only 1-hour nonattainment area in that State.
Table IV-8.--Percent of the Total ppb Above the NAAQS That Is Reduced
Due to Upwind Controls
------------------------------------------------------------------------
1-hour daily 8-hour daily
max (percent) max (percent)
------------------------------------------------------------------------
Northeast............................... 40 48
Lake MI................................. 12 27
IL/IN/WI................................ 49 48
Atlanta................................. 14 NA
Georgia................................. 14 28
------------------------------------------------------------------------
In the following discussion of the impacts of upwind controls on
ozone in the three downwind areas, the results for Metric 3 focus on
the second approach for calculating upwind impacts using this metric
since the results based on the first approach are similar to those for
Metric 1, as indicated in Table IV-7.
In the Northeast, the upwind controls provide a 15 percent
reduction in 1-hour exceedances and a 22 percent reduction in 8-hour
exceedances. The results in Table IV-8 indicate that upwind controls
provide 40 percent or more of the total ppb reduction from the downwind
plus upwind control scenario for both the 1-hour and 8-hour NAAQS.
Considering the results for several 1-hour nonattainment areas in the
Northeast, the upwind controls reduce the number of 1-hour exceedances
by 21 percent in Baltimore, 12 percent in Philadelphia, 12 percent in
New York City, 19 percent in Greater Connecticut, and 3 percent in
Boston. The percent of the total ppb reduction from the downwind plus
upwind controls that is due to the upwind controls alone is 48 percent
in Baltimore, 29 percent in Philadelphia, 38 percent in New York City,
47 percent in Connecticut, and 25 percent in Boston. The results for
all of the Northeast 1-hour nonattainment areas are provided in the Air
Quality Modeling TSD.
The impacts of upwind controls on nonattainment in Georgia were
examined using the 0.15nt scenario in Georgia versus the Base Case
scenario and the scenario with 0.15nt applied regionwide. The results,
as shown in Table IV-7, indicate that the upwind controls are predicted
to reduce the number of 1-hour exceedances in Atlanta by 9 percent.
Also, in Atlanta, 14 percent of the 1-hour total ppb above the NAAQS
reduced by the downwind plus upwind regionwide scenario is due to the
controls applied in upwind States. For the 8-hour NAAQS, the upwind
controls provide a 12 percent reduction in 8-hour exceedances within
the State of Georgia. The upwind controls provide 28 percent of the
total ppb reduction in the downwind plus upwind regionwide control
scenario.
To assess the benefits in Illinois-Indiana-Wisconsin due to upwind
controls, EPA examined the data for the Lake Michigan receptor area and
for the three States, combined. The discussion of results focuses on
the Lake Michigan receptor area. The data for this area and the three
States are provided in Table IV-7. For the Lake Michigan receptor area,
there is a 7 percent reduction in 1-hour exceedances and a 6 percent
reduction in 8-hour exceedances due to upwind controls. The upwind
controls provide 12 percent of the total 1-hour reduction and 27
percent of the total 8-hour reduction that results from the downwind
plus upwind regionwide controls. In Illinois, Indiana, and Wisconsin,
the reduction in 1-hour and 8-hour exceedances due to upwind controls
are larger than over Lake Michigan (i.e., 15 percent and 30 percent for
1-hour and 8-hour exceedances, respectively). The upwind controls
provide nearly 50 percent of the total ppb reductions associated with
the downwind plus upwind regionwide control scenario for both the 1-
hour and 8-hour NAAQS.
Based on the results discussed above, EPA believes that the
controls in today's rulemaking applied in upwind areas will reduce the
number of 1-hour and 8-hour exceedances in downwind nonattainment
areas. The analysis indicates that in downwind areas, a substantial
portion of the 1-hour and 8-hour ozone reductions provided by the
regionwide application of these controls are due to those controls in
upwind areas.
c. Summary of Findings. The EPA has performed an air quality
assessment to estimate the ozone benefits of the proposal and several
alternative uniform regionwide control levels. In addition, EPA
examined the overall benefits in several major downwind nonattainment
areas of the application of the proposal in upwind States. The results
of EPA's assessment corroborate and extend the findings presented in
the SNPR. The major findings are as follows: (1) The NOX
emissions reductions associated with the proposed Statewide budgets are
predicted to produce large reductions in (a) 1-hour concentrations
>=125 ppb in areas which are currently nonattainment for the 1-hour
NAAQS and which would likely continue to have a 1-hour nonattainment
problem in the future without the SIP call budget reductions, and (b)
8-hour concentrations >=85 ppb in areas which currently violate the 8-
hour NAAQS and which would likely continue to have an 8-hour ozone
problem in the future without the SIP call budget reductions.
(2) The more NOX emissions are reduced, the greater the
benefits in reducing ozone concentrations. There does not appear to be
any ``leveling off'' of benefits within the range of NOX
reductions associated with EPA's proposal. That is, NOX
reductions at control levels less than EPA's proposal provide fewer air
quality benefits than the proposal and NOX reduction greater
than the proposal provide more air quality benefits.
[[Page 57447]]
(3) Any disbenefits due to the NOX reductions associated
with the budgets are expected to be very limited compared to the extent
of the benefits expected from these budgets.
(4) There are likely to be benefits in major nonattainment areas
due to the downwind application of controls in the proposed budgets.
Reductions in ozone transport associated with the collective
application of the budgets in upwind States are expected to provide
substantial ozone benefits in downwind areas, beyond what is provided
by the budgets applied in the downwind areas alone. Together, the
downwind reductions and transport reductions from upwind controls will
provide significant progress toward attainment in major nonattainment
areas within the OTAG region. However, even with the most stringent
control option considered, nonattainment problems requiring additional
local control measures may continue in some areas currently violating
the NAAQS.
V. NOX Control Implementation and Budget Achievement
Dates
A. NOX Control Implementation Date
In the NPR, the EPA proposed to mandate NOX emissions
decreases in each affected State leading to a budget based on
reductions to be achieved from both Federal and State measures. The EPA
further proposed that the required SIP revisions for achieving the
portion of the NOX reduction from State measures be
implemented by no later than September 2002. The EPA also requested
comment on a range of compliance dates between September 2002 and
September 2004.
The EPA stated that this range of compliance dates is consistent
with the requirement for severe 1-hour nonattainment areas to attain
the standard no later than 2005 (for severe-15 areas) or 2007 (for
severe-17 areas). With respect to the 8-hour ozone standard, EPA stated
that the CAA provides for attainment within 5 years of designation as
nonattainment, which must occur no later than July 2000, with a
possible extension of up to 10 years following designation as
nonattainment. The EPA stated that the range of implementation dates--
from September 2002 to September 2004--is consistent with the
attainment time frames for the 8-hour standard (62 FR 60328-29). For
the reasons described in Section III, below, the applicable attainment
date for all affected downwind areas is ``as expeditiously as
practicable,'' but no later than certain prescribed dates. In many
cases, the date for achieving the upwind reductions will make the
difference as to when downwind States will attain. Thus, it is
appropriate for EPA to require the upwind reductions to be achieved as
expeditiously as practicable. Subsection 1., below, analyzes the
earliest date feasible for achieving the upwind reductions.
1. Practicability
After reviewing the comments and analyzing the feasibility of
implementing the NOX controls assumed for purposes of
developing the State emissions budgets, as well as other measures which
States may choose to rely on to meet the rule, the EPA is today
determining that the required implementation date must be by no later
than May 1, 2003. The Agency received many comments on the feasibility
of installing appropriate control technology by 2003, and the
succeeding paragraphs address many of the significant comments
submitted on this topic.
Some commenters asserted that a compliance deadline of September
2002 is infeasible for completing the installation of the assumed
NOX controls. Some of these commenters argued that there are
not enough trained workers, engineering services or materials and
equipment to install NOX controls by the September 2002
deadline. Other commenters expressed concern that utilities will not
have sufficient time to install NOX controls without causing
electrical power outages; these commenters stated that such power
outages would have adverse impacts on the reliability of the
electricity supply. Commenters also expressed concern that retrofitting
NOX controls would require increasing the operation of less
efficient units, which would increase compliance costs.
In response to these comments, the Agency has conducted a detailed
examination of the feasibility of installing the NOX
controls that EPA assumed in constructing the emissions budgets for the
affected States (hereinafter, the ``assumed control strategy''). See
the technical support document ``Feasibility of Installing
NOX Control Technologies By May 2003,'' EPA, Office of
Atmospheric Programs, September 1998. The Agency's findings are
summarized below. Based on these findings, the EPA believes that the
compliance date of May 1, 2003 for NOX controls to be
installed to comply with the NOX SIP call is a feasible and
reasonable deadline. The Agency is also providing some compliance
flexibility to States for the 2003 and 2004 ozone seasons by
establishing State compliance supplement pools as described above in
Section III.F.6.
The EPA's projections for the assumed control strategy include
post-combustion controls (Selective Catalytic Reduction [SCR] and
Selective Noncatalytic Reduction [SNCR]) and combustion controls (e.g.,
low NOX burners, overfire air, etc.)
a. Combustion Controls. In general, the implementation of
combustion controls should be readily accomplished by May 1, 2003 for
the following reasons. First, there is considerable experience with
implementing combustion controls. Combustion control retrofits on over
230 utility boilers, accounting for over 75 GWe of capacity under the
title IV NOX program, took place within 4 years (i.e., from
1992 through 1995). Moreover, the combustion retrofits under Phase I of
the Ozone Transport Commission's Memorandum of Understanding were
completed in the same time frame. As a result of this experience, the
sources and permitting agencies are familiar with the installation of
combustion controls. This familiarity should result in relatively short
time frames for completing technology installations and obtaining
relevant permits.
Second, combustion controls are constructed of commonly available
materials such as steel, piping, etc., and do not require reagent
during operation. Therefore, the EPA does not expect delays due to
material shortages to occur at sites implementing these controls.
Third, there are many vendors of combustion control technology.
These vendors should have ample capacity to meet the NOX SIP
call needs because they were able to satisfy significant installation
needs during the period 1992 through 1995, as mentioned above. Since
then these vendors have had relatively few installation needs to fill.
Therefore, it is reasonable to expect that implementation of post-
combustion controls, not combustion controls, would determine the
schedule for implementing all of the projected NOX controls.
b. Post-Combustion Controls. Tables V-1 and V-2 present the Agency
projections of how many electricity generating units and industrial
sources, respectively, would need to be retrofitted with post-
combustion NOX controls under the assumed control strategy.
[[Page 57448]]
Table. V-1.--Electricity Generating Units
------------------------------------------------------------------------
Projected No.
NOX Control of
installations
------------------------------------------------------------------------
Coal SCR................................................. 142
Coal SNCR................................................ 482
Oil/gas SNCR............................................. 15
--------------
Total................................................ 639
------------------------------------------------------------------------
Table. V-2.--Non-Electricity Generating Units
------------------------------------------------------------------------
Projected No.
NOX Control of
installations
------------------------------------------------------------------------
SCR on coal-fired sources................................ 55
SCR on oil/gas-fired sources............................. 225
SCR on other sources..................................... 1
--------------
Total................................................ 281
==============
SNCR on coal-fired sources............................... 195
SNCR on oil/gas-fired sources............................ 0
SNCR on other sources.................................... 40
--------------
Total................................................ 235
------------------------------------------------------------------------
There are three basic considerations related to implementation of
post-combustion controls (SCR and SNCR) by the compliance date: (1)
Availability of materials and labor, (2) the time needed to implement
controls at plants with single or multiple retrofit requirements, and
(3) the potential for interruptions in power supply resulting from
outages needed to complete installations.
The EPA examined each of these considerations. An adequate supply
of off-the-shelf hardware (such as steel, piping, nozzles, pumps, soot
blowers, fans, and related equipment), reagent (ammonia and urea), and
labor would be available to complete implementation of post-combustion
controls projected under the assumed control strategy.
However, the catalyst used in the SCR process is not an off-the-
shelf item and, therefore, requires additional consideration. Based on
the projections shown in the tables above, the EPA estimates that about
54,000 to 90,000 m\3\ of catalyst may be needed in SCR installations.
The EPA has found that currently the catalyst suppliers can supply
about 43,000 to 67,000 m\3\ of catalyst per year. However, of this
supply about 5,000 to 8,000 m\3\ of catalyst per year is needed to meet
the requirements of the existing worldwide SCR installations. Based on
these estimates, the EPA conservatively concludes that adequate
catalyst supply should be available if SCR installations were to occur
over a period of two years or more.
In addition, in comments to EPA's proposed NOX reduction
program, the Institute of Clean Air Companies (ICAC) stated that more
than sufficient vendor capacity existed to supply retrofit SCR catalyst
to the sources that would be controlled by SCR under the assumed
control strategy.
Implementation of a NOX control technology on a
combustion unit involves conducting facility engineering review,
developing control technology specifications, awarding a procurement
contract, obtaining a construction permit, completing control
technology design, installation, testing, and obtaining an operating
permit. The EPA evaluated the amount of time potentially needed to
complete these activities for a single unit retrofit and found that
about 21 months would be needed to implement SCR while about 19 months
would be needed to implement SNCR.
The EPA examined several particularly complicated implementation
efforts to assure an accurate and realistic estimate of the time needed
to install SCR and SNCR. The EPA examined the data and determined that
the assumed control strategy might lead one plant to choose to install
a maximum of 6 SCRs. In another instance, a different plant might
choose to install a maximum of 10 SNCRs under the assumed control
strategy. The estimated total time needed to complete these
installations is 34 months for 6 SCR systems and 24 months for 10 SNCR
systems.
Finally, the EPA examined the impact(s) that outages required for
connecting NOX post-combustion controls to EGUs could
potentially have on the supply of electricity and on the cost of this
rule. The EPA has found that, generally, connections between a
NOX control system and a boiler can be completed in 5 weeks
or less. This connection period has been accounted for in both the
single and multi-unit implementation times presented in the previous
paragraph. On an EGU, the connection would have to be completed during
an outage period in which the unit is not operational. The EPA's
research reveals that currently, on average, about 5 weeks of planned
outage hours are taken every year at an electricity generating unit.
Therefore, the EPA expects that connection between a NOX
control system and such a unit would be completed during one of these
planned outages.
Results of EPA's analyses reflect that, even if all of the post-
combustion controls projected in Table V-1 for the EGUs were to be
connected to these units in one single year, no disruption in the
supply of electricity would occur. If each of these plants takes the
five week outage in a single block of time, no cost increase is
expected to occur. However, if a plant divides the five week outage
into two or more periods, a cost increase of less than one-half of one
percent may be expected. See the technical support document
``Feasibility of Installing NOX Control technologies By May
2003,'' EPA, Office of Atmospheric Programs, September 1998.
Based on the estimated timelines for implementing NOX
controls at a plant and availability of materials and labor, the EPA
estimates that the NOX controls in the assumed control
strategy (which is one available method for achieving the required
NOX reductions in each covered State) could be readily
implemented by September 2002, without causing an adverse impact on the
electricity supply or on the cost of compliance. The EPA bases this
conclusion on its analysis that the most complex and time-consuming
implementation effort--one involving 6 SCR systems--would take 34
months, and that all of the controls could be installed within this
period without causing any disruptions in the supply of electricity.
Further, the EPA notes that the September 27, 1994 OTC
NOX Memorandum of Understanding (MOU) provides that large
utility and nonutility NOX sources should comply with the
Phase III controls by the year 2003. The levels of control in the MOU
are 75 percent or 0.15 lb/106 btu in the inner and outer
zones of the Northeast OTR, levels comparable to the controls assumed
in setting the budget for today's rulemaking. Moreover, several States
in the Northeast OTR have submitted SIP revisions implementing this
level of emissions reductions from NOX sources in those
States by May 1, 2003. This further supports the feasibility of the May
1, 2003 implementation date for these controls.
The EPA has determined that States would have sufficient time to
implement other NOX control measures in lieu of the boiler
controls described above. For example, vehicle I/M programs have
historically required no more than two years to implement, including
the time needed to pass enabling State legislation and to construct the
necessary emission testing facilities. The time required to implement
measures to reduce VMT depends on the nature of the measure, but many
VMT reduction measures require no more than one or two years to
implement. State opt-ins to the RFG program have generally required
less
[[Page 57449]]
than one year to implement. Even if the EPA were to determine that
supply considerations warranted a delay in implementing the opt-in
request, the delay cannot exceed two years.
States can also take advantage of the NOX-reducing
benefits that energy efficiency and renewables projects provide, many
of which could be developed in less than three years and incorporated
into a SIP. Examples of efficiency/renewables projects that have been
accomplished within a 3-year time frame and have resulted in
significant NOX reductions include reducing boiler fuel use
by utilizing waste heat, implementing short-term steam trap maintenance
and inspection programs, and undertaking building upgrades using EPA's
Energy Star Buildings approach.
2. Relationship to SIP Submittal Date
Under this rule, as explained in Section B. below, States are
required to submit revised SIPs by September 30, 1999. Commenters have
suggested that based on the requirements of this rulemaking, sources in
these States would need to begin early planning of compliance
strategies before the September 30, 1999 date. The EPA disagrees. The
EPA's technical analysis described above indicates that if these
sources begin planning and specification of controls by even as late as
April 2000, then they would be able to complete control technology
implementation by May 1, 2003.
3. Rationale
To assure adequate lead-time for implementation of controls, the
EPA has moved the compliance deadline from the proposed date of
September 2002 in the NPR to May 1, 2003. Since the ozone seasons in
areas in the eastern U.S. end in the fall and begin in the spring,
setting the implementation date for May 1, 2003 will provide sources 7-
8 additional months for implementing control requirements while not
undermining the ability of areas to attain. The additional
implementation time will occur during the cooler months of the year, a
time when ozone exceedances generally do not occur. Thus, with either
the September 2002 implementation date or the May 1, 2003
implementation date, the 2003 ozone season would be the first to
benefit from full implementation of the SIP call reductions.
Several commenters contend that EPA does not have the authority to
establish the compliance date. Since section 110(a)(2)(D)(i) is silent
as to the implementation schedule for measures to prevent significant
contribution, the EPA disagrees that the statute prohibits the EPA from
establishing an implementation date for control measures that will
achieve the reductions established by the SIP call. Thus, the EPA must
look to the other provisions in the CAA, the legislative history, and
the specific facts of today's rule to determine whether it is
reasonable for the Agency to set the implementation date for the
control measures. Furthermore, for the reasons provided in this
Section, the EPA believes it is necessary to use its general rulemaking
authority under section 301(a) to establish the latest date for
implementation through a rule in order to ensure that downwind areas
attain the standard as expeditiously as practicable and that areas
continue to make progress toward attaining the NAAQS. See NRDC v. EPA,
22 F.3d 1125, 1146-48 (D.C. Cir. 1994).
With respect to the facts of this particular situation, this SIP
call entails a complex analysis of the interstate transport of
NOx and ozone and involves 23 jurisdictions. Although the
States made significant progress through the OTAG process, they were
unable to reach a final resolution on the emission reductions necessary
or the schedule to achieve reductions to address upwind emissions.
Thus, it would not be reasonable for EPA to leave open the issue of
implementation in light of the need for downwind areas to rely on these
reductions in order to demonstrate attainment by their attainment
dates. See also the discussion in Section II.A.
Furthermore, EPA believes that requiring implementation of the SIP-
required upwind controls, and thereby mandating those upwind
reductions, by no later than May 1, 2003, is consistent with the
purpose and structure of title I of the CAA. Under both section
172(a)(2), which establishes attainment dates for areas designated
nonattainment for the 8-hour standard, and section 181(a), which
establishes attainment dates for nonattainment areas for the 1-hour
standard, areas are required to attain ``as expeditiously as
practicable'' but no later than the statutorily-prescribed (for section
181(a)) or EPA-prescribed (for section 172(a)(2)) attainment dates. The
implementation date of May 1, 2003 fits with both the more general
requirement for areas to attain ``as expeditiously as practicable'' and
the latest attainment dates that apply for purposes of the 1-hour
standard and that EPA will establish for the 8-hour standard.
The overarching requirement for attainment is that areas attain
``as expeditiously as practicable.'' This requirement was established
in the CAA in the 1970 Amendments and has been carried through in both
the 1977 and 1990 Amendments. Thus, although Congress has provided
outside attainment dates under the 1970, 1977, and 1990 Amendments,
States have always been required to attain as expeditiously as
practicable. Congress has furthered this concept of ensuring that
emission reductions are achieved on an expeditious, yet practicable,
schedule through its inclusion of other provisions in the CAA that rely
on similar concepts. Most notably, under both subpart 1 and subpart 2
of part D of title I of the CAA, areas are required to make reasonable
further progress toward attainment and thus are not allowed to delay
implementation of all measures until the attainment year.\63\ While the
ROP requirements directly apply only to emission reductions that
designated nonattainment areas need to achieve to address local
violations of the standard, these provisions highlight congressional
intent that--at a minimum--reasonably available or practicable measures
should not be delayed if such measures are needed to attain the
standard by the applicable attainment date. Thus, it is consistent for
EPA to require upwind areas to adopt practicable control measures on a
schedule that will help to ensure timely attainment of the standard in
downwind areas.
---------------------------------------------------------------------------
\63\ CAA sections 171(1) and 172(c)(2) (requiring that
nonattainment area SIPs provide for reductions in emissions that may
reasonably be required by the Administrator for the purpose of
ensuring attainment of the applicable national ambient air quality
standard by the applicable date; 182(b)(1) and (c)(2)(B) (requiring,
respectively, 15 percent reductions between 1990 and 1996 and
additional 3 percent average reductions per year until the
attainment date, unless, among other things, the plan includes ``all
measures that can be feasibly implemented in the area, in light of
technological achievability'').
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In addition, the May 1, 2003 implementation date is consistent with
the statutorily-prescribed ``outside'' 1-hour attainment dates for many
of the areas that will benefit from the SIP call reductions.
Currently, areas designated nonattainment for the 1-hour standard
have attainment dates ranging from 1996 to 2010. For those with
attainment dates in the years 1996-1999, EPA is analyzing whether such
areas should receive an attainment date extension due to transported
emissions or whether such areas should be reclassified, or ``bumped
up,'' under section 181(b)(2), to the next higher classification and
therefore be subject to additional control requirements and a later
attainment
[[Page 57450]]
date.\64\ To the extent that an attainment date extension is
appropriate, consistent with the general requirement of the CAA, it
should be no later than the date by which the necessary reductions can
practicably be achieved. Thus, it is appropriate for EPA to require
upwind reductions by May 1, 2003--a date that EPA has determined can be
practicably achieved--in order to allow these areas to attain as
expeditiously as practicable. Additionally, there are areas with
attainment dates of 2005 \65\ and 2007 \66\ that will benefit from the
reductions upwind States will require in response to the SIP call. The
May 1, 2003 compliance date is sensible in light of the requirement for
these areas to make reasonable further progress toward attainment under
section 182(c)(2)(B) and to attain as expeditiously as practicable but
no later than 2005 or 2007.
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\64\ See Guidance on Extension of Attainment Dates for Downwind
Transport Areas, Memorandum from Richard Wilson, dated July 17,
1998.
\65\ Severe-15 areas, such as Baltimore and Philadelphia, as
well as any Serious areas that do not receive an attainment date
extension and are bumped up due to a failure to attain, will need to
attain no later than 2005.
\66\ Severe-17 areas, such as New York City, Philadelphia,
Chicago and Milwaukee, need to attain the standard no later than
2007.
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The implementation date of May 1, 2003 is also consistent with the
attainment date scheme for the 8-hour ozone NAAQS. The EPA is required
to promulgate designations for areas under the 8-hour ozone NAAQS by
July 2000. Pub. L. No. 105-178 section 6103 and CAA section 107(d)(1).
In draft guidance EPA made available for comment in August 1998, the
EPA indicated that most new areas that violate the 8-hour ozone NAAQS
(but not the 1-hour ozone NAAQS) can achieve sufficient emissions
reductions to produce one ozone season's clean air quality by the end
of 2003 if EPA establishes May 1, 2003 as the compliance date for this
rule.\67\ The EPA suggested that these areas would also be eligible for
an ozone transitional classification, provided they submit a SIP by
2000 (see the August 1998 proposed guidance). Therefore, in the
proposed guidance, EPA has indicated that when the Agency reviews and
approves ozone transitional area SIPs, the Agency anticipates
establishing December 31, 2003 as the attainment date, for planning
purposes, for almost all of the transitional areas. The EPA believes
that establishing December 31, 2003 as the attainment date for these
areas is consistent with the requirement of CAA section 172(a)(2)(A)
that ``the attainment date for an area designated nonattainment with
respect to a [NAAQS] shall be the date by which attainment can be
achieved as expeditiously as practicable, but no later than 5 years
from the date of designation.'' The EPA interprets this requirement to
mandate that controls, either in the downwind nonattainment area or in
upwind areas, should be implemented as expeditiously as practicable,
when doing so would accelerate the date of attainment. For the reasons
described elsewhere, the EPA believes it is practicable for States to
implement the controls mandated under today's rulemaking by May 1,
2003, and that doing so would ensure that areas subject to the 8-hour
NAAQS will attain the standard as expeditiously as practicable. Doing
so will be consistent with the requirement that downwind nonattainment
areas make reasonable further progress toward attainment.
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\67\ ``Proposed Implementation Guidance for the Revised Ozone
and Particulate Matter (PM) National Ambient Air Quality Standards
(NAAQS) and the Regional Haze Program,'' John S. Seitz, Director,
Office of Air Quality Planning and Standards, to Regional Office Air
Division Directors, August 18, 1998. The guidance has been made
available for 30-days public comment through a Federal Register
Notice of Availability (63 FR 45060, August 24, 1998). The date of
the notice is the official start date for the comment period.
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B. Budget Achievement Date
In the NPR, the EPA stated that although it would mandate the full
implementation of the required SIP controls by an earlier date, it
would require the affected States to demonstrate that they will achieve
their NOX budgets as of the year 2007. The NPR explained
that the 2007 date would allow EPA to make use of the substantial
technical information collected by OTAG. The OTAG had selected the year
2007, had collected inventory data geared towards this date, and had
generated air quality modeling information geared towards this date.
The NPR further stated that the EPA had doubts that there would be
significant differences in amounts of emissions and impact on ambient
air quality between an earlier date and 2007, in light of the fact that
during this period, emissions would generally increase somewhat as a
result of growth in activities that generate emissions, but would also
decrease due to continued application of federally mandated controls.
The EPA continues to believe that 2007 is an appropriate target
date for the affected States to use in demonstrating whether their SIP
will achieve the required emissions reductions, generally for the same
reasons as expressed in the NPR. Based on the 2007 projections, States
are expected to achieve their statewide emissions budgets (based on the
required emissions reductions achieved by May 1, 2003) by September 30,
2007 which is the end of the ozone season.
Throughout this rulemaking process, the EPA has relied on technical
data generated by OTAG geared towards the 2007 date, and it would be an
ill-advised use of resources if EPA did not incorporate the emissions
inventories and modeling results generated by the multi-stakeholder
OTAG process, and instead developed comparable information for an
earlier date. Such an effort would be time consuming and resource
intensive. Furthermore, no State is disadvantaged by the requirement to
demonstrate compliance with the budget later than the requirement to
implement SIP controls because States may count both the growth in
emissions and the reductions in emissions from Federal measures that
would occur in the interim. Finally, the year 2007 is the latest
attainment date under the 1-hour NAAQS for areas in States affected by
today's rulemaking, i.e., the severe-17 areas of including Chicago,
Milwaukee, and New York, so that this date is a sensible target date
for affected States to use in projecting whether they will achieve the
required emissions reductions.
VI. SIP Criteria and Emissions Reporting Requirements
A. SIP Criteria
The NPR and SNPR discussed SIP revision approval criteria and the
schedule for States' submission plans for meeting statewide emission
budgets in response to this SIP call under section 110(a)(2)(D). The
EPA received a number of comments related to the proposed SIP approval
criteria. This section summarizes these comments on key issues and
presents EPA responses.
1. Schedule for SIP Revision
In the NPR, EPA proposed that each State must submit a
demonstration that it will meet its assigned Statewide emission budget
(including adopted rules needed to meet the emission budget) by
September 30, 1999.68 The EPA received numerous comments
concerning this proposed timeframe.
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\68\ In the NPR, EPA proposed the SIP submittal date to be
within 12 months of the date of final promulgation of this
rulemaking. Promulgation means signature so long as the rulemaking
is made available to the public on the same day.
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Comments: The EPA received many comments on the practicality of
allowing States 12 months to submit SIPs in response to this
rulemaking. Some commenters articulated that some States anticipate
administrative obstacles that could create problems in
[[Page 57451]]
submitting their SIP revisions by 1999. On the other hand, many
commenters expressed concern about extending the SIP submittal deadline
to 18 months based on the additional adverse impact that NOX
emissions from upwind areas would have on downwind air quality if the
schedule for reductions were extended. Arguing that the States would
have ample time to formulate an approvable SIP, these commenters
supported a 12-month SIP submission date.
Response: After considering these comments, EPA is requiring that
SIP revisions be submitted within 12 months after the date of signature
of this final rule. This date is appropriate in light of the fact that
States which are subject to today's rulemaking will need to achieve
reductions in NOX emissions by May 1, 2003. Requiring States
to submit SIP revisions within the 12-month timeframe will ensure that
controls necessary to reduce these emissions will be in place on time.
The Agency believes the health risks associated with ozone
pollution require the NOX SIP call to proceed expeditiously.
Delaying the SIP submission date by an additional 6 months would hinder
downwind areas' efforts to improve air quality in a timely manner.
Twelve months is adequate time to submit a NOX reduction
SIP. States were involved in the OTAG for 2 years and, during that
time, developed lists of feasible NOX control strategies and
compiled information about control strategy costs. This groundwork will
assist States in making decisions about their NOX reduction
strategies and should expedite the SIP submittal process. Further,
States developed NOX emission inventories for modeling
purposes during the OTAG process. The States, therefore, have the
information for the source categories on which to focus. As a result,
many elements needed for putting together a NOX reduction
strategy have already moved forward.
Since OTAG concluded in June 1997, the States have had time for
internal review of data, and refinement of their emission inventories.
This SIP call rulemaking provides EPA's view of a reasonable cost-
effective strategy to reduce NOX in the 23 jurisdictions.
The EPA's action provides a good starting point for State
NOX reduction strategies; States can embrace the Agency's
approach or use it as a basis for tailoring their own programs. If
States elect to participate in EPA's model trading rule, the SIP
process will be further simplified because States can adopt the entire
package of recommended strategies.
Therefore, under section 110(k)(5) for the 1-hour NAAQS and section
110(a)(1) for the 8-hour NAAQS, a demonstration that each State will
meet the assigned Statewide emission budget (including adopted rules
needed to meet the emission budget) must be submitted to EPA in its SIP
revision.
2. Approvability Criteria
In the NPR, EPA described the elements listed below that States
must include in their ozone transport SIP revisions (62 FR 60365).
The EPA proposed that the approvability criteria for transport SIP
submissions appear in 40 CFR 51.121. Most of the criteria are
substantially identical to those that already apply to attainment SIPs,
for example, a description of control measures that the State intends
to use.
The SNPR proposed additional SIP approvability criteria for control
strategies that will help States meet their NOX budgets (63
FR 25912-25914). The legal authority for these additional approvability
criteria was articulated in the SNPR (63 FR 25913, footnote 5). The EPA
received numerous comments related to these additional criteria.
a. Source Categories Subject to Additional Approvability Criteria.
In the SNPR, EPA proposed that, if a State should choose to meet this
SIP call by regulating NOX sources (boilers, turbines and
combined cycle units) serving electric generators with a nameplate
capacity greater than 25 MWe and boilers with a maximum design heat
input greater than 250 mmBtu/hr, the State would need to frame these
control measures and monitoring requirements as either: (1) Mass
emissions limits, (2) emissions rates assuming maximum utilization, or
(3) an alternative approach, as described more fully in the next
subsection. The EPA solicited comment on the reasonableness of
extending these approvability criteria to additional NOX
sources. The EPA explained that the ability to comply with a mass
emissions limit using reasonably available technology and to accurately
and consistently monitor mass emissions were key factors for coverage
by the additional approval criteria.
In the SNPR (63 FR 25923), EPA also outlined criteria for sources
to participate in the NOX Budget Trading Program. The EPA
explained that the ability to accurately and consistently monitor
NOX mass emissions was a key factor for participation in the
trading program. The EPA proposed that the trading program include the
same sources listed above as well as other large steam-producing units
(units above 250 mmBtu/hr) which would include combustion turbines or
combined cycle systems, as well as boilers that do not serve electrical
generators.
The EPA now believes that the SIP approvability criteria should
cover all NOX sources serving electric generators with a
nameplate capacity greater than 25 Mwe and all boilers, combustion
turbines and combined cycle units with a maximum design heat input
greater than 250 mmBtu/hr. The Agency believes this group is
appropriate because of the considerations set forth in the SNPR. For
example, all of these sources can comply with a mass emissions limit
using reasonably available technology and can accurately and
consistently monitor mass emissions. In addition, EPA believes that
mass emissions limits remain highly cost-effective for these sources,
even when future growth is accommodated within the limits. Based on the
analyses in the RIA, EPA projects that even if actual growth for this
group of sources exceeds EPA's projected growth by over one-third, mass
emission limits would remain highly cost-effective according to the
criteria used for this rule. Therefore, in this final rule, EPA is
requiring that the additional SIP approvability criteria outlined below
apply to States that select regulatory requirements covering boilers,
turbines and combined cycle units that are greater than 250 mmBtu/hr--
regardless of whether they are connected to an electrical generator of
any size--or to boilers, turbines and combined cycle units that serve
electrical generators greater than 25 Mwe, regardless of the heat input
capacity of the unit.
b. Pollution Abatement Requirements. The EPA proposed requiring
States that choose to meet their budget through control requirements
for such large NOX sources to express the requirements 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 source's 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 assurance equivalent
to or greater than option (1) or (2) that seasonal emissions budgets
will be attained and maintained.
Comments: Seven commenters generally support the approach of
[[Page 57452]]
expressing regulatory requirements as mass emissions limitations. One
of these commenters does not object to a mass limit provided that the
limit covers a time period no shorter than the ozone season, and that
sources should be allowed to maintain flexibility within the ozone
season. Several commenters generally support a rate-based limit, one of
which noted that EPA's own rule-effectiveness studies show that rate-
based limits can be very effective. Another commenter opposes the use
of mass emission limits and urges EPA not to require monitoring
procedures and data generation that are inconsistent with current
requirements under the Acid Rain Program (namely the use of an
emissions rate limit). Other commenters believe that States, not EPA,
should decide the form of the limit. Finally, one commenter recommends
both a cap on mass emissions and an emissions rate limitation.
Response: As explained in the SNPR (63 FR 25912), EPA believes that
regulatory requirements in the form of a maximum level of mass
emissions for a source or group of sources have the greatest likelihood
of achieving and maintaining the Statewide NOX emissions
budget. As with the entire SIP call, the new approvability criteria are
designed to apply to total emissions throughout the ozone season and
are not intended to apply to shorter time periods within the ozone
season. This, however, does not limit a State's ability to require
emissions limitations for a shorter time period if deemed necessary in
a specific ozone attainment plan.
Although several commenters supported using rate-based limits, they
did not provide evidence to refute EPA's belief that the proposed
criteria would provide superior environmental results over rate-based
limits alone. The EPA maintains that the proposed criteria provide the
greatest assurance to downwind States that the air emissions from
upwind States will be effectively managed over time. Regarding EPA's
rule effectiveness studies, they do confirm that rate-based limits can
be effective in achieving a specific emissions rate. However, the
studies do not address the emissions variations that may take place at
the regulated sources due to changes in utilization under rate-based
limits, including the potential for significant increases, particularly
in light of utility restructuring. Under the proposed criteria, mass
emissions from the regulated sources would stay within a fixed tonnage
amount despite shifts in utilization of the sources. Finally, EPA does
not believe that the rate-based NOX emissions limits
prescribed under title IV of the CAA are relevant to this rulemaking.
Since the time of the 1990 CAA amendments, EPA, States, local
governments, and the regulated community have all gained considerable
experience with regulatory requirements expressed in terms of mass
emissions limitations which demonstrates their feasibility and high
degree of effectiveness. For these reasons and the reasons described in
the SNPR, EPA is including these additional SIP approvability criteria
in today's action.
c. Monitoring Requirements. The Agency proposed requiring these
large combustion NOX sources to use continuous emissions
monitoring systems (CEMS), and requested comment on requiring the use
of the NOX mass monitoring provisions in 40 CFR part 75 to
demonstrate compliance with applicable emissions control requirements.
Comments: Some commenters generally support the use of CEMS for
large combustion sources. One commenter noted that while the preamble
and the proposed revisions to part 51 would require CEMS on all
sources, the requirements set forth in subpart H of part 75 allow for
non-CEMS monitoring options for units that are infrequently operated or
that have low mass emissions of NOX.
Response: The EPA believes that programs like the Acid Rain Program
and RECLAIM have shown that CEMS can be effectively used on boilers,
turbines and combined cycle units to demonstrate compliance with a mass
emissions limitation. The Agency also believes that, while CEMS provide
more consistent and accurate data, allowing non-CEMS monitoring options
for low-emitting or infrequently operated units greatly increases the
cost effectiveness of these requirements without significantly
jeopardizing the quality of the data used to ensure compliance with the
requirements of the SIP call. Therefore, EPA agrees with the commenter
that the part 75 provisions allowing non-CEMS monitoring options for
low-emitting or infrequently operated units are reasonable. The EPA is
requiring the use of the NOX mass monitoring provisions in
40 CFR part 75 in the final SIP approval criteria.
d. Approvability of Trading Program. In the SNPR, EPA expressed its
intent to approve the portion of any State's SIP submission that adopts
the model rule, provided: (1) The State has the legal authority to
adopt the model rule and implement its responsibilities under the model
rule, and (2) the SIP submission accurately reflects the NOX
emissions reductions to be expected from the State's adoption of the
model rule (63 FR 25913). The EPA also stated that a State could
develop State regulations in accordance with the model rule. In Section
VII.C.3 of this preamble, the Agency clarifies the extent to which a
State's regulations may deviate from the model rule and still receive
streamlined approval. Regulations providing for streamlined approval
appear in paragraph (p) of 40 CFR 51.121.
3. Sanctions
In the preamble to the proposed rule, EPA explained the mandatory
sanctions process that is established in section 179(a) and (b) of the
CAA (62 FR 60368). This process is triggered upon a finding by EPA that
a State failed to submit a SIP in response to a SIP call. One
sanction--either increased offsets for new or modified major stationary
sources or restrictions on highway funding--is imposed 18 months after
the finding is made and the second sanction 6 months later. The EPA
requested comment on the order in which these two sanctions should be
imposed in response to the SIP call. The EPA further requested comment
on whether EPA should use its discretion under section 110(m) to expand
the geographic scope of the highway funding sanction.
Comment: One commenter specifically commented on the order in which
the two sanctions should be imposed. The commenter recommended that the
offset sanctions apply first--18 months after the finding--and the
restrictions on highway funding apply second--6 months after the offset
sanction.
Response: This is the approach that EPA took in its final rule
addressing the sequence of mandatory sanctions for State failures to
respond to submittals required under part D of title I of the CAA. For
the reasons stated in the preamble to that final rule (59 FR 39832),
EPA is providing in the final SIP call rule that the offset sanction
will apply 18 months after EPA makes a finding and the restrictions on
highway funding will apply 6 months after the offset sanction applies.
Comments: Several commenters generally commented that EPA should be
fair and equitable in making findings and imposing sanctions. Other
commenters suggested that to be fair and equitable--and because the
sanctions are an important backstop to ensuring emission reduction are
achieved--EPA should apply the same or similar sanctions to upwind
attainment areas as to nonattainment areas that do not comply with the
SIP call. Recognizing that the highway
[[Page 57453]]
sanction can apply to attainment areas only under section 110(m), one
commenter encouraged EPA to develop a mandatory clock for the
imposition of discretionary sanctions. Finally, one commenter stated
that the nature and timing of sanctions should reflect a State's
particular circumstances; however, this commenter also emphasized the
need for parties to know the impact of sanctions ahead of time so that
they can effectively react.
Response: The EPA agrees that sanctions are an important backstop
and plans to make timely findings where States fail to submit or submit
an incomplete or disapprovable SIP in response to the SIP call. The EPA
agrees that areas should be treated fairly and plans to ensure that
areas with similar circumstances are not treated differently in making
findings of failure to submit and incompleteness. However, at this
time, EPA is not prepared to determine whether and when it is
appropriate to use the discretion provided under section 110(m) in
imposing sanctions. The EPA believes it is not appropriate to make a
general determination regarding the application of sanctions under
section 110(m); rather if circumstances warrant the use of sanctions
under section 110(m), EPA may take future rulemaking action to use that
authority. Before EPA uses the section 110(m) authority, EPA must go
through notice-and-comment rulemaking, which should provide States
adequate certainty about EPA's intentions on the use of discretionary
sanctions and time to respond to any action that EPA may take.
Comment: One commenter suggested that the timeframes for the
imposition of sanctions are too short and will undermine States'
efforts to comply with the SIP call. In addition, the commenter states
that the imposition of sanctions serves no useful purpose in light of
EPA's intent to promulgate a FIP.
Response: The EPA did not propose imposing sanctions more
expeditiously than the timeframes mandated by the CAA. If EPA makes a
finding of failure to submit or incompleteness shortly after the SIP is
due, the State will have 18 months in which to make a submission that
EPA determines is complete before the first sanction would be imposed.
Thus, the statute provides sufficient additional time for the State to
correct the problem before any sanction would apply. Under the statute,
sanctions apply independently of EPA's obligation to promulgate a FIP.
Congress recognized that the most efficient and effective programs are
those operated by the State; thus, the CAA provides for the continued
imposition of sanctions as a means to encourage States to adopt a
program to replace the FIP.
Comment: One commenter opposes restrictions on highway funding
imposed by any highway sanction in nonattainment areas and especially
Statewide.
Response: Under section 179(a) and (b), the highway funding
sanction is one of two sanctions that must be imposed due to a
continuing failure of a State to adopt a SIP program, including a SIP
in response to a SIP call. Under section 179(b), the highway funding
sanction can only apply in a nonattainment area. However, under the
discretionary sanctions provision in section 110(m), EPA may impose the
highway funding Statewide. (See 59 FR 1476, 1479-80 for a more detailed
discussion.) The EPA would undertake notice-and-comment rulemaking
before imposing sanctions beyond the nonattainment area pursuant to
section 110(m).
Comments: Finally, several commenters recommended that EPA not
sanction serious areas for failing to demonstrate attainment by 1999
where those areas are affected by transported emissions that will not
be controlled until after the 1999 attainment date.
Response: The EPA is not addressing in this rulemaking the process
for imposing sanctions for areas that fail to submit or submit
incomplete or unapprovable attainment demonstrations. The EPA recently
issued a policy memorandum explaining how it anticipates addressing
transport for serious areas through rulemaking actions on submitted
attainment demonstrations. See memorandum from Richard D. Wilson, EPA
Acting Assistant Administrator, to EPA Regional Administrators, dated
July 16, 1998, ``Extension of Attainment Dates for Downwind Transport
Areas.''
In the preamble to the proposed rule, EPA indicated that if an area
fails to implement an approved SIP, the Agency can make a finding that
triggers the sanctions clock but does not trigger an obligation to
promulgate a FIP. Compare sections 179(a)(1) and 110(c)(1). One
commenter noted that EPA should take a forceful role in assuring
implementation. Implementation of control measures to achieve the
reductions required under the NOX SIP call is crucial in
moving all areas to attainment of the ozone standards. The EPA intends
to make findings of failure to implement where the circumstances
warrant such a finding.
4. FIPs
Comment: The EPA received several comments supporting the approach
outlined in the NPR in which EPA would propose a FIP at the same time
as taking final action on the SIP call. The comments noted that the
FIPs may be necessary to enforce the SIP call budgets and to assure
fair treatment of complying States and industry as compared to States
that are not responsive to the SIP call. In addition, many comments
were submitted urging EPA to delay proposal of FIPs until (1) after the
States have had time to respond to the SIP call, (2) the need for the
FIP is established, or (3) up to 2 years after the final SIP call.
Response: Also signed today is a separate notice titled ``Federal
Implementation Plans to Reduce the Regional Transport of Ozone,'' EPA
is proposing FIPs for each of the jurisdictions affected by the final
SIP call rulemaking. While EPA will have a non-discretionary duty to
promulgate a FIP within 2 years of a finding that a State has failed to
submit a complete SIP, EPA agrees with certain commenters that the
timing of the FIP proposal should allow for promulgation in time to
require NOX emissions reductions by sources at about the
same time in States that comply with the SIP call and States that do
not. Under a delayed FIP proposal approach, sources in the non-
complying States might experience an unfair competitive advantage over
sources in States which elected to reduce their NOX
emissions and reduce interstate transport of ozone and ozone precursors
in an earlier timeframe, consistent with the SIP call rulemaking. More
importantly, delaying the FIP proposal would potentially delay
reductions of ozone pollution and NOX emissions in any non-
complying State which would unnecessarily jeopardize attainment and
public health and welfare. Therefore, proposing a FIP today will ensure
that EPA can promulgate a FIP very shortly after the time the SIPs are
due, in the event of any State's failure to comply with today's final
rule.
B. Emissions Reporting Requirements for States
As stated in the November 7, 1997 NPR and the May 11, 1998 SNPR,
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 SIP call and to assure the
downwind affected States
[[Page 57454]]
and EPA that the ozone transport problem is being
mitigated.69
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\69\ Legal authority for the reporting requirements was
articulated in the supplemental notice of proposed rulemaking (63 FR
25915-6).
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1. Use of Inventory Data
If tracking and periodic reports indicate that a State is not
implementing all of its NOX control measures beginning on
May 1, 2003 or is off track to meet its required reductions by
September 30, 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. Noncompliance with the
NOX transport SIP call 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.
The EPA will use 2007 data to assess how each State's SIP actually
performed in meeting the statewide NOX emissions budget.
2. Response to Comments
The EPA proposed reporting requirements in the May 11, 1998 SNPR.
That proposal elicited several comments during the public comment
period. Some of these comments resulted in changes to the final
reporting requirements.
Comment: One commenter asked that the EPA review the need for
triennial collection of annual (i.e for the full year) emissions data
for uncontrolled sources, as compared to collection of only ozone
season data for uncontrolled sources.
Response: The EPA has reviewed the need for reporting of full year
emissions (as opposed to only ozone season emissions), and has revised
the final rule to remove a requirement that full year emissions be
reported. In the final rule, only ozone season emissions must be
reported in the annual, triennial and 2007 reports. This NOX
SIP call is aimed at controlling transport of emissions during the
ozone season and reporting of full year emission for the purposes of
this SIP call is not necessary.
Comment: One commenter said that EPA should evaluate the reporting
burden to entities other than the 22 States and the District of
Columbia. These entities are likely to include owners/operators of
facilities that will be required to report emissions data to States as
part of this information collection. Another commenter said EPA should
address the additional resource burden on States and facilities
required to report.
Response: Since the emissions reporting rule does not place
requirements directly on any sources but only on the 23 jurisdictions
which receive the SIP call, the EPA is under no legal obligation to
evaluate the indirect burdens on sources that may result from the
promulgation of this rule. However, based on EPA's assumed control
strategy, EPA has performed an analysis of costs which could be
incurred by facilities if States require facilities analyzed in EPA's
assumed control strategy to report information to aid States in
complying with the rule. This cost information includes both capital
costs for monitoring equipment, such as continuous emission monitors,
and labor costs for testing. These costs are included in the RIA for
this rule which is located in the docket for the rulemaking (docket no.
A-96-56).
Comment: One commenter is concerned that the definition of point
and area sources does not coincide with the definition of smaller point
sources included in the inventory, nor with the definition of major
sources in ozone nonattainment areas where the threshold is either 25
or 50 tons per year. Another commenter stated that the definition of
``point source'' should reach at least down to the 50 ton per year
level, if not lower. This commenter also said that, for consistency,
EPA should have a single definition of ``point source'' for the purpose
of this rule.
Response: All sources with NOX emissions equal to or
greater than 100 tons per year will remain point sources. However, the
EPA has revised its definition of point source for this final rule's
reporting requirements to allow States the option of specifying a
smaller threshold than 100 tons/year of NOX for defining
point source. When a State chooses this option, non-mobile sources
smaller than the State-defined threshold would be area sources in that
State. This allows States to tailor their definition of point source to
maintain consistency with their own current requirements.
In the proposal, the EPA specifically solicited comments on whether
the State reporting time for 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. This would allow corrective actions, if needed,
to be taken prior to the next ozone season. The EPA also solicited
comments on whether different reporting schedules should be established
for the different source categories, so that the data which can be
obtained more readily would be submitted sooner. The EPA has received
several comments on these topics, suggesting a variety of reporting
times.
Comment: A State recommended that since the performance of electric
generating facilities is known promptly, EPA should shorten the
reporting time to no later than 4 to 6 months after the end of the
ozone season for which the data are collected. The comment did not
specify whether this reporting period , which is shorter than the
proposed 12 months, would apply only to electric generating facilities
or should apply to all NOX emitting sources. Another State
said the point source emissions reporting period can be shortened to 9
months. Other commenters favored a 12 month or more reporting period.
Several commenters did not believe that 12 months after the end of the
calendar year is a reasonable time to submit reports and suggested
periods ranging from 18 to 24 months. Some commenters thought the
reporting time for area and mobile sources must be longer than for
point sources; one commenter thought the reporting time for all source
types should be uniform.
Response: Many of the emissions from large electric generating
facilities would be reported directly to EPA more rapidly than 12
months, if States elect to adopt the model trading program; however,
the EPA continues to believe that 12 months from the end of the
calendar year for which the data is collected is a reasonable time to
require a State to report all emissions from all types of sources. This
12 month period is supported by the comments which say that 12 months,
or even less in some situations, is a sufficient reporting time. The
EPA believes that States can report emissions from area and mobile
sources, as well as stationary sources, within the 12 month period. The
uniform 12 month reporting period for all source types was chosen to
simplify reporting requirements. However, a State has the option of
collecting emissions from particular sectors more rapidly if it wishes.
Therefore in the final rule, the EPA is requiring that States submit
the required annual and triennial emissions inventory reports no later
than 12 months after the end of the calendar year for which the data
are collected. Because downwind nonattainment areas will be relying on
the upwind NOX reductions to assist them in reaching
attainment by the required dates, EPA believes it is important that
data be submitted as soon as practicable to verify that the necessary
emissions reductions are being achieved. Early reports will allow
States to more quickly respond to implementation problems detected by
the reports. States should formally notify the appropriate EPA
[[Page 57455]]
Regional Office when making the submittals.
3. Final Rule
After taking into account the comments submitted in response to the
May 11, 1998 proposal, EPA today is promulgating emission inventory
reporting requirements for States subject to the NOX SIP
call. The regulatory text appears in 40 CFR 51.122, and the main
emission reporting requirements are summarized in Table VI-1 below.
Table VI-1.--Summary of NOX Reporting Requirements
------------------------------------------------------------------------
then, your State
If you own or operate and must report to EPA
the source's
------------------------------------------------------------------------
A point source.............. You are not subject Ozone season2
to regulations emissions.
relied on to
achieve the NOX
reductions required
in this SIP call 1.
1. triennially 3,5.
2. for 20075.
A point source.............. You are subject to Ozone season
regulations relied emissions.
on to achieve the
NOX reductions
required in this
SIP call 1.
1. annually 4.
2. triennially 5.
3. for 2007 5.
An area source.............. You are not subject Ozone season
to regulations emissions.
relied on to
achieve the NOX
reductions required
in this SIP call 1.
1. triennially.
2. for 2007.
An area source.............. You are subject to Ozone season
regulations relied emissions.
on to achieve the
NOX reductions
required in this
SIP call 1.
1. annually 6.
2. triennially.
3. for 2007.
A mobile source............. You are not subject Ozone season
to regulations emissions.
relied on to
achieve the NOX
reductions required
in this SIP call 1.
1. triennially.
2. for 2007.
A mobile source............. You are subject to Ozone season
regulations relied emissions.
on to achieve the
NOX reductions
required in this
SIP call 1.
1. annually 6.
2. triennially.
3. for 2007.
------------------------------------------------------------------------
1The EPA considers the State to rely on regulations to achieve the NOX
reductions required if those regulations require reductions beyond
those reflected in the base case 2007 inventory.
2 Ozone season is May 1 through September 30.
3 Triennial reporting (which is every 3 years) starts with emissions
occurring in 2002.
4 Annual reporting starts with emissions occurring in 2003.
5 Triennial and 2007 reports for point sources contain additional data
elements not required in the annual reports.
6 The data elements in the annual report for area and mobile sources
satisfy the reporting requirements for these source categories for the
triennial and 2007 reports. However, the triennial reports start with
emissions occurring in the year 2002 and the annual reports start with
emissions occurring in the year 2003.
4. Data Elements to be Reported
In addition to reporting the NOX emissions values shown
in Table VI-1, the State must report other critical data necessary to
generate and validate these values. This includes data used to identify
source categories such as site name, location and (source
classification code) SCC codes. It also includes data used to generate
the NOX emissions values such as fuel heat content and
activity level. The specific data elements required for each source
category are further defined in 40 CFR 51.122.
5. 2007 Report
The EPA is requiring that States submit to EPA for the year 2007 a
special onetime statewide NOX emissions inventory from all
NOX sources (point, area, and mobile) within the State. The
data reporting requirements are identical to the reporting requirements
for the triennial inventories, and this reporting requirement is being
imposed to allow evaluation of whether the budget is met in 2007. This
one-time special inventory is necessary because the ordinary 3-year
reporting cycle does not fall in the year 2007.
States which must submit the 2007 inventory may project incremental
changes in emissions from 2007 to 2008 to allow the 2008 inventory
requirement to be more easily met and to reduce the burden on States
which must submit full NOX inventories for consecutive
years, i.e., 2007 and 2008.
The EPA received comments saying that EPA should not require the
special report in 2007 due to increased resources required but rather
should adjust the schedule of the triennial reports so that a triennial
report year will fall on 2007. Alternatively, the EPA could eliminate
the 2008 triennial report. The EPA has considered these alternatives,
but believes that the schedule which was proposed is necessary to
maintain consistency with
[[Page 57456]]
other EPA reporting requirements and is not unnecessarily burdensome.
6. Ozone Season Reporting
The EPA is requiring that the States provide ozone-season (i.e.,
May 1 through September 30) 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 the triennial and 2007
reports, ozone season emissions from all NOX source
categories within the State, controlled or uncontrolled, must be
reported. The EPA is requiring that each State provide its ozone season
calculation method to EPA for approval.
7. Data Reporting Procedures
When submitting a formal NOX budget emissions report and
associated data, the State should formally notify the appropriate EPA
Regional Office of its activities. States are required to report
emissions data in an electronic format to one of the locations 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 an approved trading program 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.
For the latest information on data reporting procedures, call the
EPA Info Chief help desk at (919) 541-5285 or e-mail to
info.chief@epamail.epa.gov.
8. Confidential Data
Emissions data being requested in today's action are not 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.
C. Timeline
The reporting requirements fit into the general time line
summarized below:
September 30, 1999--Deadline for SIP submissions in response to
this SIP call.
2002--The first triennial emissions inventory report must be submitted
for ozone season emissions for this year. States must collect emissions
inventory information for all NOX sources in the State. This
report must be submitted by December 31, 2003 (i.e., 12 months after
the end of the calendar year for which the data are collected.)
May 1, 2003--The SIP measures required to achieve the NOX
reductions must be implemented by this date.
2003--The first annual emissions inventory report must be submitted for
certain ozone season NOX emissions for this year.
Specifically, States must collect emissions information regarding all
sources for which the State is relying on measures to meet its
NOX budget (``SIP call sources''). This report is due
December 31, 2004.
2004--The second annual emissions inventory report must be submitted
for ozone season emissions from SIP call sources for this year. This
report is due December 31, 2005.
2005--The second triennial report must be submitted for ozone season
emissions from all NOX sources for this year. The report is
due December 31, 2006.
2006--The third annual report must be submitted for ozone season
emissions from SIP call sources in the State for this year. This report
is due December 31, 2007.
2007--The special year 2007 emission inventory report for ozone season
emissions from all NOX sources in the State must be
submitted for this year. This report is due December 31, 2008. The EPA
will assess whether States have met their budgets in the year 2007.
2008--The third triennial emissions inventory report must be submitted
for ozone season emissions for this year. This report is due December
31, 2009.
Annual and triennial reports must continue to be submitted in
future years beyond 2008 in order for the EPA to track compliance with
the budget or any revisions to the budget that may occur after 2007.
VII. NOX Budget Trading Program
A. General Background
In the November 7, 1997 proposed rulemaking, EPA offered to develop
and administer a multi-state NOX trading program to assist
States in the achievement of their budgets. Today's notice sets forth a
model program on which States may choose to base their SIP submittal.
The trading program employs a cap on total emissions in order to ensure
that emissions reductions under the transport rulemaking are achieved
and maintained, while providing the cost effectiveness of a market-
based system. States can voluntarily choose to participate in the
NOX Budget Trading Program by adopting the final model rule,
which is a fully approvable control strategy for achieving over 90
percent of the emissions reductions required under the transport
rulemaking.
B. NOX Budget Trading Program Rulemaking Overview
Prior to publication of the proposed NOX Budget Trading
Program, EPA held two public workshops to solicit comments and
suggestions from States and other stakeholders on a NOX cap-
and-trade program. Over 150 people participated in each of the
workshops. To facilitate meaningful comments from these participants,
EPA developed papers on critical issues that were made available for
review prior to each workshop. These papers discussed major issues
relevant to developing a NOX Budget Trading Rule, delineated
options and, in some cases, offered recommendations. The issues
associated with each working paper were presented at the workshops,
followed by open discussion periods allowing workshop participants to
comment and discuss each issue. Input from workshop participants was
extremely helpful in drafting the proposed NOX Budget
Trading Program. In addition to
[[Page 57457]]
input gained from the workshop process, the NOX Budget
Trading Program builds directly upon the Ozone Transport Commission's
NOX Budget Program and recommendations from the OTAG's
Trading and Incentives Workgroup. On May 11, 1998, EPA published the
proposed NOX Budget Trading Program as a part of the
supplemental notice for the proposed ozone transport rulemaking. The
final NOX Budget Trading Rule published in today's notice
reflects changes that have been made in response to comments received
on the May 11, 1998 proposal.
C. General Design of NOX Budget Trading Program
1. Appropriateness of Trading Program
The EPA proposed that a voluntary market-based program be
established as one possible means for a State to meet its
NOX emissions reduction obligations under the NOX
SIP call. The vast majority of commenters, including States, industry,
and environmental groups, supported a market approach over traditional
``command and control'' mechanisms to fulfill reduction requirements.
However, many commenters argued that the proposed State budgets, based
on the cost-effectiveness of an emission limit of 0.15 lb/mmBtu for
large combustion sources, are too stringent to provide sufficient
surplus allowances to support a market. These commenters argued that
cost and technological constraints would prevent regulated sources from
over-controlling, thus reducing the pool of allowances and the cost
savings EPA predicts would accompany trading. However, several other
commenters stated that the trading program was the most cost-effective
means to reduce emissions and would in fact generate sufficient
allowances for trading. These commenters noted that all but the highest
emitting coal-fired units can achieve this rate, and that many sources
are able to achieve emission limits significantly below 0.15 lb/mmBtu.
They also argued that, at least in the early years of the trading
program, the growth factors used to determine the budgets will lead to
a less stringent emission reduction requirement than 0.15 lb/mmBtu.
The EPA notes that nothing requires a State to impose a 0.15 lb/
mmBtu limit on its large combustion sources. The States will select in
their SIPs which sources to regulate and the type of regulation to
impose in order to achieve their NOX budgets. The EPA
believes that trading for large combustion sources under a budget based
on 0.15 lb/mmBtu is a feasible, highly cost-effective means of meeting
a State's budget. The Agency believes that 0.15 lb/mmBtu can easily be
achieved by gas and oil-fired boilers. In fact, more than 50 percent of
gas and oil-fired boilers already operate at NOX levels
below 0.15 lb/mmBtu and should therefore easily be able to generate
excess allowances if trading is allowed. The EPA recognizes that for
coal-fired boilers to operate at or below a 0.15 lb/mmBtu emission
limit, selective catalytic reduction (SCR) will generally be necessary.
Under a trading scenario, however, if one coal-fired boiler is able to
emit below 0.15 lb/mmBtu by installing SCR, it can provide excess
allowance to another coal-fired boiler and obviate the need for that
boiler to install SCR. (For further technical justification for the
feasibility of 0.15 lb/mmBtu, see Section III.B.2 of this preamble.) In
summary, EPA concludes that, should a State elect to control large
combustion sources with a budget based on an emission rate of 0.15 lb/
mmBtu, ample allowances would exist to sustain a market under the
NOX Budget Trading Program.
Several of the commenters who did not support the trading program
proposed by EPA were generally wary of the use of market approaches for
environmental regulation, especially in the context of ozone attainment
strategies, citing concerns that emissions in existing nonattainment
areas may increase under such a program. The EPA, however, believes
that a trading program is an appropriate mechanism to achieve the
NOX reductions required under the SIP call. The EPA proposed
the trading program in the SNPR based on recommendations from OTAG,
experience from the Ozone Transport Commission, and EPA's public
workshops held in November and December 1997. This trading program was
designed to mitigate transport of ozone and its precursors to
facilitate attainment and maintenance of the ozone NAAQS. Analyses in
conjunction with the SIP call show that implementation of a trading
program with a uniform control level results in no significant changes
in the location of emissions reductions than would result from a non-
trading scenario (``Supplemental Ozone Transport Rulemaking Regulatory
Analysis'', April 1998, page 2-19). The NOX reductions
required by the SIP call will significantly lower background levels of
ozone and can be coupled with local measures to achieve further
NOX reductions, as well as VOC reductions, where necessary
to reach attainment. States concerned with contribution by local
sources in the trading program are free to limit emissions from
particular sources by imposing source-specific emission limits where
deemed necessary.
2. Alternative Market Mechanisms
The SNPR proposed to establish a model cap-and-trade program for
certain large combustion sources. This proposed program employs a cap
on total emissions to ensure achievement and maintenance of the
emissions reductions required under the NOX SIP call while
providing the flexibility and cost effectiveness of a market-based
system. Several commenters supported EPA's recommendation for a cap-
and-trade program. Several others complained that EPA's focus on a
capped trading program was inappropriate, citing OTAG's recognition
that NOX market systems could also be implemented without an
emissions cap. As a result, these commenters felt that EPA could not
make a cap a prerequisite to approval of a State trading program. They
suggested that EPA recognize that a rate-based program can be part of a
viable SIP, perhaps by outlining parameters of an acceptable
alternative program or working with OTAG States to develop a rate-based
program that would better accommodate future growth. Another issue
raised by a few commenters was that the trading program would either
conflict with or would ignore existing local or State-based trading
programs.
The EPA first reiterates that the model program is voluntary (63 FR
25918). In providing a cap-and-trade program as a streamlined means by
which to comply with the NOX SIP call, EPA does not preclude
implementation of other solutions. The purpose of the trading program
is to provide a compliance mechanism that capitalizes on a proven means
of cost effectively meeting a specific emissions budget that the Agency
will assist States in administering.
As OTAG concluded, the procedures for a cap-and-trade program have
already been developed and used successfully, whereas procedures for
other types of multi-state trading programs have not been developed and
implemented to the same degree. Therefore, EPA does not have the same
level of experience or established protocols to follow in the design
and administration of other types of trading programs. The OTAG did
encourage development of provisions to implement other types of trading
programs, and EPA recognizes that these alternative trading programs
may be appropriate in some circumstances.
[[Page 57458]]
However, EPA recommends a cap-and-trade program for purposes of the
NOX SIP call because, by limiting total NOX
emissions to the level determined to address the interstate transport
problem, a cap better ensures achievement and maintenance of the
environmental goal articulated in the NOX SIP call. In
contrast, under a non-cap trading program, the addition of new sources
to the regulated sector or increased utilization of existing sources
could increase total emissions above the level determined to address
transport, even though a NOX rate limit is met.
States, however, have the flexibility to respond as they see fit to
meet their emissions budgets established under the NOX SIP
call. States are free to pursue other regulatory mechanisms or include
other types of trading programs in their SIPs, whether newly created or
already existing, on the condition that they meet EPA's SIP approval
criteria as delineated for the NOX SIP call. These criteria
mandate that regulatory requirements for boilers, turbines and combined
cycle units that are greater than 250 mmBtu or that serve electrical
generators that are greater than 25 MWe be expressed in one of three
ways: (1) In terms of mass emissions; (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
these sources; or (3) an alternative approach for expressing regulatory
requirements, provided the State demonstrates, to EPA's satisfaction,
that its alternative provides equivalent or greater assurance than
options (1) or (2) that seasonal emissions budgets will be attained and
maintained. For further information regarding SIP approvability
criteria, see Section VI.A.2.b of this preamble.
3. State Adoption of Model Rule
In the SNPR, EPA proposed that States electing to participate in
the NOX Budget Trading Program could either adopt the model
rule by reference or develop State regulations in accordance with the
model rule. The few commenters on this issue were primarily concerned
about lack of guidance by EPA in this area for State adoption of the
model rule and the potential for deviation from the model rule in the
State-adopted rules. This section clarifies EPA's intent in issuing a
model rule and distinguishes between sections of the model rule that
State rules must mirror, and those that States may choose to alter or
eliminate while maintaining a SIP that is approvable for purposes of
joining the NOX Budget Trading Program.
a. Process for Adoption. One commenter suggested that rather than
adopting the NOX Budget Trading Program, it should be
sufficient for each State to include a statement in its SIP declaring
that the State will participate in the Federal program, along with a
demonstration of the authority for the State to do so. This would leave
the details in the Federal rule and avoid differences that could arise
through each State adopting its own rule. However, EPA does not have
the statutory authority under title I to promulgate a Federal cap-and-
trade program to achieve a State's SIP call budget unless the State
fails to respond adequately to the SIP call. The EPA understands the
commenter's concern regarding differences among State rules to
implement the NOX Budget Trading Program, and intends to
ensure consistency as explained in the following Section.
The EPA's intent in issuing a model rule for the NOX
Budget Trading Program is to provide States with a model program that
serves as an approvable strategy for achieving more than 90 percent of
the required reductions under the NOX SIP call. States
choosing to participate in the program will be responsible for adopting
State regulations to support the NOX Budget Trading Program,
and submitting those rules as part of the SIP. As articulated in the
proposed rulemaking (63 FR 25920), there are two legal alternatives for
a State to use in joining the NOX Budget Trading Program:
incorporate 40 CFR part 96 by reference into the State's regulations,
or adopt State regulations that mirror 40 CFR part 96 but for the
variations and omissions described below.
b. Model Rule Variations. The EPA would like to clarify the
variations and omissions from the model rule that are acceptable in a
State rule, to provide States flexibility while still ensuring the
environmental results and administrative feasibility of the program.
More specifically, EPA will clarify those variations that maintain a
State's eligibility for the streamlined SIP approval associated with
adoption of the model rule, those changes that will require more
extensive review by EPA prior to approval, and those changes that are
not acceptable for incorporation into the NOX Budget Trading
Program.
In order for a SIP revision to be approved for State participation
in the NOX Budget Trading Program, on a streamlined basis or
otherwise, the State rule should not deviate from the model rule except
in the areas of applicability, NOX allowance allocation
methodology, and early reduction credit methodology (all of which are
described briefly in the following paragraphs and in more detail in
subsequent Sections of today's notice). Deviations from the model rule
regarding allocation methodologies and early reduction credit
methodologies as defined in this Section do not impact a State's
eligibility for streamlined approval of its SIP with respect to the
NOX Budget Trading Program. However, some deviations
regarding applicability will require more extensive EPA review, as
explained below. Changes to program applicability may render a State's
rule ineligible for streamlined approval, though the rule would still
be eligible for approval after a more thorough EPA review.
State rules that deviate beyond the applicability, allocation, and
early reduction credit flexibility provided in the model rule would not
be approvable for inclusion in the NOX Budget Trading
Program. SIPs incorporating a trading program that is not approved for
inclusion in the broader NOX Budget Trading Program may
still be acceptable for purposes of achieving some or all of a State's
obligations under the NOX SIP call, provided the SIP
criteria outlined in Section VI.A.2.b are met. However, only States
participating in the NOX Budget Trading Program would be
included in EPA's tracking systems for NOX emissions and
allowances used to administer the multi-state trading program.
For States participating in the NOX Budget Trading
Program, applicability is one of the three main areas in which the
State may deviate from the model rule. State rules need to include an
applicability section that at least covers the core sources defined in
the model rule, but States may allow additional stationary sources to
participate in the trading program. These sources must be able to
monitor and report emissions in accordance with the model rule, and
identify an individual responsible for fulfilling program requirements
to be eligible for inclusion. States have three options to expand
applicability and one to limit it, as explained in the following
paragraphs.
States may choose to expand applicability either by: (1) Including
smaller sources in the core source categories, (2) including additional
source categories, or (3) providing individual sources the ability to
opt in. Expansion of applicability to smaller core sources will
maintain the State's eligibility for streamlined SIP approval with
regard to the NOX Budget Trading Program. Including
additional source categories beyond the core sources (e.g., municipal
waste combustors), however, will require more careful review by EPA
[[Page 57459]]
in some cases to ensure that the trading program requirements can be
met, and therefore preclude streamlined SIP approval otherwise
associated with adoption of the model rule. Regarding individual source
opt-ins, States have the discretion to determine whether or not to
include this provision in their State rule. The opt-in provision is not
a prerequisite to approval of a SIP incorporating the NOX
Budget Trading Program. However, if a State does choose to include
provisions for opt-in sources, these provisions must mirror those in
the model rule. Providing the provisions do so, the SIP remains
eligible for streamlined EPA approval.
States may also choose to limit applicability of the trading
program by allowing units with a low federally enforceable
NOX emission limit (e.g. 25 tons per control period) to be
exempt from trading program requirements. A State may include this
exemption provision as it appears in the model rule to allow these
sources not to participate in the trading program, or a State may omit
the provision. Neither of these actions will interfere with streamlined
SIP approval by EPA, provided the exemption provisions mirror the model
rule if included in the State rule.
In terms of allocations, States must include an allocation section
in their rule, conform to the timing requirements for submission of
allocations to EPA that are described in this preamble, and allocate an
amount of allowances that does not exceed their State trading program
budget. However, States may allocate NOX allowances to
NOX budget sources according to whatever methodology they
choose. The EPA has included an optional allocation methodology in 40
CFR part 96, but States are free to allocate as they see fit within the
bounds specified above, and still receive streamlined SIP approval for
purposes of the NOX Budget Trading Program.
Today's final rule also includes an optional methodology in
Sec. 96.55(c) that States may use for issuing early reduction credits
from the State compliance supplement pools. However, States may
distribute the State compliance supplement pool to sources as they wish
in accordance with the requirements set forth in 40 CFR 51.121(e)(3)
and still receive streamlined SIP approval for purposes of the
NOX Budget Trading Program.
In summary, a State is eligible for streamlined approval of the
portion of their SIP incorporating the NOX Budget Trading
Program if the State adopts all the provisions of the model rule (e.g.,
banking and monitoring provisions) with variations incorporated only in
the manner explained in this Section. Streamlined approval requires
that applicability extends only to the core sources, or to core sources
and smaller sources within the core source categories and that the opt-
in provision and the exemption option for sources with a low federally
permitted emission limit, if included, mirror those in the model rule.
Regarding allocations, eligibility for streamlined approval extends to
those State rules whose allocations do not exceed the State trading
program budget and are determined in accordance with the timing
requirements delineated in the model rule. A State rule is still
eligible for approval, but not streamlined approval, if the
applicability determination for the NOX Budget Trading
Program extends beyond the core sources to additional source
categories, to allow for the additional review necessary to ensure such
an extension of applicability is administratively feasible and
environmentally sound. A State rule is also eligible for streamlined
approval if it includes methodologies for issuing credit from the State
compliance supplement pool in accordance with the provisions in 40 CFR
51.121(e)(3). Differences among States in these areas will provide
flexibility while not detracting from the operation or implementation
of the multi-state trading program. Therefore, variations as explained
in this section are acceptable to EPA with assurance that State rules
will be sufficiently consistent. In addition, joint implementation of
the program with EPA will ensure that once these consistent rules are
established, they will be implemented consistently as well.
Several commenters expressed concern that the lack of prohibitions
on State-imposed trading restrictions in conjunction with the model
rule would lead to variation between States and cripple the trading
program. The EPA agrees with commenters that additional restrictions
imposed on the trading program by individual States could increase
economic costs without providing significant environmental benefit.
Therefore, EPA does not believe that any restrictions on trading are
necessary, and does not foresee approving State rules that include
trading restrictions in SIPs incorporating the NOX Budget
Trading Program. However, to address local air quality problems, a
State participating in the NOX Budget Trading Program may
establish permit limitations for specific sources participating in the
trading program. The EPA considers such a limitation appropriate given
local air quality concerns and does not consider it a trading
restriction, and therefore the incorporation of such limitations will
not preclude streamlined SIP approval. These sources would still
participate in the NOX Budget Trading Program and the
unconstrained market operating in the program, but could not use
allowances to exceed their permit limitation; the source would be held
to the permitted limit, regardless of how many allowances it holds for
the purposes of the trading program. This topic is discussed in more
detail in the next Section.
4. Unrestricted Trading Market
a. Geographic Issues. For the NOX SIP call, EPA is
basing the State budgets on the uniform application of reasonable,
cost-effective NOX control measures for each State
determined to contribute significantly to nonattainment in a downwind
State. The EPA's analyses show that the collective reductions across
the region will produce significant air quality benefits across the
region. The development of and justification for the State budgets
under the NOX SIP call is described in Section III,
Determination of Budgets. Although the analyses in today's final action
demonstrate that the collective emissions for the NOX SIP
call region significantly contribute to nonattainment, the location of
particular emissions does impact the effects that the emissions have on
other areas within the region. Emissions in some locations may cause
greater overall effects than emissions from other locations.
In the SNPR, EPA proposed a single trading program allowing all
emissions to be traded on a one-for-one basis without restrictions on
trading allowances within the SIP call region. The EPA also solicited
comment on whether the trading program should attempt to factor in
differential effects of NOX emissions based on the location
of the emissions. Possible options for factoring in the differential
effects include defining exchange ratios for trades between areas based
on the differential effects of emissions between areas, establishing
subregions for trading, and/or prohibiting certain trades (63 FR 25902
at 25919).
The Agency received more than fifty comments on this issue from the
regulated community, States, and environmental organizations. A number
of commenters did support limiting trading by establishing smaller
subregions within the SIP call region or
[[Page 57460]]
establishing trading ratios based on the idea that there are
differential effects of NOX emissions based on the location
of the emissions. However, none of these commenters included a complete
proposal with a justification or description for the appropriate
subregional boundaries or trading ratios. The majority of commenters on
this subject favored unrestricted trading within areas having a uniform
level of control. Most commenters supporting unrestricted trading
stated that restrictions would result in fewer cost-savings without
achieving any additional environmental benefit and would increase the
administrative burden of implementing the program. They expressed
concern that discounts or other adjustments or restrictions would
unnecessarily complicate the trading program, and therefore reduce its
effectiveness.
Consistent with the proposal, the final model rule is designed to
be a single jurisdiction trading program allowing all emissions to be
traded on a one-for-one basis, without restrictions or limitations on
trading allowances within the trading area. EPA has used the IPM to
evaluate the emissions and cost impacts of alternative regulatory
options under the SIP call for the electric power sector. These
analyses can be found in the RIA. The model has been used to show the
level and location of emissions if the SIP call were implemented under
a number of different alternatives including unrestricted trading and
command-and-control approaches. The results indicate that significant
shifts in the location of emissions reductions would not occur with
unrestricted trading compared to where the reductions would occur under
command-and-control and intrastate only trading scenarios. Based upon
the IPM results and EPA's air quality modeling, EPA has chosen a
region-wide trading program allowing all emissions to be traded on a
one-for-one basis without trading restrictions. EPA's analyses suggest
that the net effect of all the trades is that the net emissions will
not significantly shift within the region compared to a command-and-
control scenario. For this reason, EPA believes that the need for
trading subregions or trading ratios that differ from one-for-one are
unsubstantiated for the purposes of this SIP call and the
NOX Budget Trading Program.
Although the location of net emissions is not expected to
significantly shift as a result of trading, it is possible that a State
may identify a specific location (e.g., major NOX source
adjacent to or within an urban center) where NOX reductions
would be particularly beneficial for ozone mitigation. For these
situations, a State may establish a specific permit limitation
restricting the amount of NOX that may be emitted from the
source. The source would still be included in the trading program but
it would not be allowed to emit above the amount specified in the
permit limitation regardless of the number of NOX allowances
it may hold. The source would be allowed to trade the allowances it is
unable to use. In this way, States will be able to tailor specific
attainment strategies within the framework of the NOX Budget
Trading Program without restricting the trading options for most
sources included in the program.
b. Episodic Issues. The EPA also received several comments
addressing the episodic nature of ozone formation and whether this
should be factored into the design of the trading program. Commenters
noted that under the NOX SIP call, which is designed to
reduce total NOX emissions from May through September of
each year, it is still possible that NOX emissions may be
relatively higher during ozone episodes compared with NOX
emissions on other days between May and September. In addition, the
effect of a unit of emissions may be higher during ozone episodes. To
address this concern, the commenters stated that the trading program
should provide incentives or safeguards to ensure that NOX
emissions reductions are achieved specifically during ozone episodes.
One commenter asserted that emissions could either be capped during
ozone episodes or that the trading program could place a premium on the
use of NOX allowances during ozone episodes. The commenter
recommended the latter option. The premium would require that sources
surrender NOX allowances at rates greater than 1-to-1 for
each ton of NOX emitted during the ozone episodes.
Consistent with the NOX SIP call, the NOX
Budget Trading Program focuses on reducing total NOX
emissions from May to September for the jurisdictions that are
identified in the NOX SIP call and that choose to
participate in the trading program. Proposals to address NOX
emissions during specific episodes and in specific nonattainment areas
are more closely tied to issues affecting individual attainment plans
rather than the goal of the NOX SIP call which is to reduce
transport. It would be very difficult to apply the appropriate premium
to the individual sources that contribute NOX emissions
affecting specific ozone episodes. The meteorology and source
contribution for each ozone episode is different. And in some cases,
NOX emissions and the resulting ozone may be transported for
several days before contributing to an ozone violation.
Provisions designed to ensure that NOX emissions
reductions are achieved specifically during ozone episodes are more
likely to be effective in controlling NOX emissions that are
released adjacent to or within locations frequently affected with
elevated ozone levels. Where a State identifies such a source, EPA
believes specific permit limitations are an appropriate and effective
method for controlling the source's emissions. As stated in the
previous section, EPA believes that States may use permit limitations
to tailor specific attainment strategies within the framework of the
NOX Budget Trading Program without restricting the trading
options for most sources included in the program. Furthermore, this
provides each State more flexibility in establishing its attainment
plan rather than applying one approach to address the episodic nature
of ozone throughout the SIP call region. Therefore, EPA has not
included additional trading restrictions to address ozone episodes in
the design of the final NOX Budget Trading Program.
D. Applicability
1. Core Sources
In the SNPR, EPA proposed that compliance with the emission
limitation requirements of the NOX Budget Trading Rule,
i.e., the requirement to hold sufficient NOX allowances to
cover emissions, apply to a core group of large stationary 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 was considered fossil fuel-fired if fossil fuels
accounted for more than 50 percent of the unit's heat input on an
annual basis. The EPA solicited comment on the appropriateness of the
categories included in the core group, whether the size cut-offs should
be higher or lower for the source categories, and the appropriateness
of including other source categories in the core group. Comments on the
concept of a core group fell into three broad categories:
Those who agreed with the core group concept and who
generally agreed
[[Page 57461]]
with EPA's proposed core group definition;
Those who felt that the core group definition was too
limiting; and
Those who felt that the core group definition was too
inclusive.
a. Commenters Who Felt the Core Group Should Not Be Changed.
Commenters who supported the concept of a core group generally and the
cut-offs proposed by EPA specifically explained that the cut-offs are
consistent with the Acid Rain Program and that the use of a core group
will minimize inconsistencies that could impede establishment of
interstate trading. Commenters also added that the program should
provide the flexibility to allow additional sources to opt-in on an
individual basis or for States to bring in additional sources on a
categorical basis. Some of these commenters added that the timing for
bringing in these sources or source categories should be dependent upon
the ability of the source or source category to accurately monitor
emissions. For some source categories it might be appropriate to bring
them in at the start of the program; for others, it might be necessary
to wait until their ability to quantify emissions has improved.
Commenters who generally supported the concept of a core group of
sources as it was defined in the SNPR did have several specific
concerns. One commenter noted that while the SNPR preamble clearly
explained that the rule only included fossil-fuel-fired units, the rule
itself was not clear on this issue. Another commenter suggested that
because the proposed definition differentiated between electrical
generating units and non-electrical generating units it excluded
sources that should be in the trading program such as cogeneration
facilities that consisted of boilers greater than 250 mmBtu/hr that
served electric generating units with a rating of less than 25 MWe.
The EPA agrees that the establishment of a core group will help
facilitate interstate trading as well as compliance with the emissions
budget. If there is not some minimum group of trading participants,
sources that are in the program will have less of an opportunity to
trade allowances and realize the economic benefits of trading. In
addition, by ensuring that most of the emissions from industries
covered by the trading program are included in a capped system, the
trading program can be simplified because concerns about load shifting
to uncapped sources is minimized. The EPA also agrees that making the
cut-offs consistent with existing regulatory programs helps to minimize
conflicts with existing regulatory programs. The EPA also agrees with
both of the concerns raised by the commenters. Therefore the regulatory
definition of unit has been clarified to make it clear that a unit must
be fossil-fuel fired. The EPA has also added a clarification to the
definition of fossil-fuel fired. This clarification is intended to
define a baseline period for determining if a unit is fossil-fuel
fired. The revised definition states that 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. An existing unit is considered fossil-fuel fired
if it meets this criterion for any year since 1990 (or if not operating
since 1990 during the last year of operation). A new unit is considered
fossil-fuel fired if it is projected to meet this criterion or, if
after operation begins, it does meet this criterion.
In addition, to address the concern about excluding cogeneration
facilities that are greater than 250 mmBtu/hr that serve electric
generating units with a rating of less than 25 MWe, the applicability
has been changed to include all units greater than 250 mmBtu/hr,
regardless of how much electricity they generate.
b. Commenters Who Felt the Core Group Should Be Expanded.
Commenters who felt the trading program should be expanded focused on a
number of areas. Several commenters argued generally that the program
should allow any source to participate if the source can document that
emissions reductions have been achieved. A number of commenters
mentioned as examples the inclusion of medium-sized and smaller
stationary sources in the RECLAIM program. A few commenters argued that
the addition of certain sources is needed for consistency with the OTC
NOX Budget Rule. Other commenters opposed the core group
concept because they believe that regulation of low-level and local
sources in the Northeast is an essential step in solving the ozone
problem. Others argued that excluding non-utility sources from the
trading program unfairly excludes these sources from least-cost
compliance options. Some commenters suggested specific categories of
units that should be allowed to, but not required to, participate in
the trading program. These included:
(1) Municipal waste combustors;
(2) Internal combustion engines;
(3) Process units;
(4) Units for which the output product is not comparable to other
units on which the allocations are based, such as process heaters,
hazardous waste incinerators, process vents and nitric acid plants.
The EPA believes that many of the concerns about the core source
definition stem from a misunderstanding of its purpose. The core
sources definition was intended to indicate the minimum applicability
requirements that a State rule would have to include to participate in
a larger multi-state program that EPA would help to administer. It was
not intended to limit individual States from including more sources (as
long as the sources meet certain criteria further explained below) in
the larger multi-state program (63 FR 25924). Nor was it intended to
prohibit a State (or group of States) from developing its own trading
program with a more limited applicability.
If, however, a State or group of States developed a trading program
that did not meet the minimum requirements set forth in the model
NOX Budget Trading Program, such as minimum core source
applicability, EPA would not participate in the administration of such
a trading program. This is because it would not be administratively
cost-efficient for EPA to manage multiple trading programs with a
variety of applicability and other requirements designed to address the
same issue.
The EPA is not expanding the core source group to include any
additional sources because EPA believes that this decision is better
left to the states. Therefore the model rule will allow a State to
expand the applicability of the trading program to include additional
stationary sources if the sources meet certain criteria. These criteria
include the ability to accurately and consistently monitor and report
emissions and the ability to identify a party responsible for ensuring
that monitoring and reporting requirements are met, for authorizing
allowance transfers and for ensuring compliance. The EPA's rationale
for setting these minimum criteria are set forth in the preamble to the
SNPR (63 FR 25923). Also, EPA addresses issues specifically related to
the monitoring requirements for these sources in Section D.3 of today's
preamble.
There are two mechanisms that can be used to include more sources
in the program. One is for a State to expand the applicability criteria
to include other source categories; the other is to give individual
sources the ability to opt-in.
States that choose to expand the applicability criteria can do so
(1) by lowering the applicability threshold for source categories that
are already part of
[[Page 57462]]
the core group in order to include smaller sources or (2) by including
additional source categories that are not included in the core group.
For instance a State in the OTC might choose to lower the applicability
cut-off for electrical generating units to 15 MWe to make the program
more consistent with the existing OTC NOX Budget Program. If
a State chose to expand the applicability criteria for source
categories already included in the core group this would not affect
EPA's streamlined approval of the NOX Budget Trading program
component of the State's SIP.
A State might choose to lower the applicability cut-off for sources
in the core group to create different applicability cut-offs for new
and existing units. This could help to better facilitate integration
with a State's new source review program. The EPA took comment on this
concept in the SNPR and received comments both for and against this
proposal. Commenters who opposed it suggested that it would be a
disincentive to replace old units with new cleaner units. Some of these
commenters also noted that expanding the applicability cut-off for all
units would provide an incentive to replace these older units.
Commenters who favored it suggested that it would be an incentive to
make new units as clean as possible. The EPA believes that it is
appropriate for States to determine how best to handle the issue of
small new units.
Another reason to allow smaller sources to opt-in is to simplify
monitoring for situations in which a common stack is shared by a number
of units, some of which are affected and some which are not. In this
situation the owner or operator would have to either install monitors
at each of the affected units, or install monitors at the common stack
and at all of the non-affected units, so that the emissions from these
units could be deducted from the emissions from the affected units. If
the owner or operator is allowed to opt-in the nonaffected unit, they
will be able to install one set of monitors at the common stack
accounting for the emissions from all of the units.
If a State chose to include additional source categories, EPA would
have to review the SIP submittal to ensure that those additional source
categories met the minimum criteria for monitoring and reporting
emissions and for having a responsible official. As further explained
in the SNPR (63 FR 25924), EPA would also have to determine if it could
successfully administer a regional trading program with the inclusion
of these additional source categories.
In the SNPR, EPA proposed developing a list of specific additional
source categories beyond the core group which a State could bring into
the trading program without affecting EPA's streamlined approval of the
trading component of the SIP. While this concept received general
support, none of the commenters provided enough specific support to
demonstrate that all of the sources in a given source category could
meet the criteria to accurately and consistently monitor emissions.
These comments are discussed in Section D.3.
The EPA believes that the opportunity for States to expand the
applicability to include additional sources addresses concerns about
incompatibility with the applicability requirements of existing
programs, such as the OTC Trading Program, as well as concerns that an
individual State might want to expand the program to address local
ozone problems.
The other mechanism that can be used to broaden the applicability
of the program is the individual opt-in procedures in subpart I of part
96. These provisions allow a source to opt-in, if it can meet the
monitoring and reporting requirements of part 75. The EPA received a
number of comments about the monitoring requirements of part 75 as they
related to opt-ins. These comments are addressed in Section D.3 of
today's preamble.
In the SNPR (62 FR 25940-25942 and 62 FR 25991-25994), EPA proposed
that the individual opt-in provisions would only be applicable to
fossil-fuel-fired, stationary boilers, combustion turbines, and
combined cycle systems smaller than the applicability cut-offs of 25
MWe or 250 mmBtu/hr. The EPA agrees that the RECLAIM program has
demonstrated that many combustion sources that are not included in the
core applicability criteria can accurately and consistently monitor
NOX mass emissions using CEM (or other alternative protocols
for units with low mass emissions) that are very similar to the
provisions in subpart H of part 75. Therefore, in today's action EPA is
allowing States to expand the opt-in provisions to include any
stationary combustion source that emits to a stack and can meet the
monitoring and reporting requirements of subpart H of part 75.
States that choose to add other combustion sources that are not
part of the core group would also have to address issues related to
allocating allowances for those types of sources. Allocation
methodologies that may be appropriate for source categories covered in
the core group may not be as applicable for other source categories.
For instance, as one commenter noted, an output based allocation
methodology might not make as much sense for a municipal waste
combustor, since the primary purpose of a municipal waste combustor is
to combust waste, not to generate usable output.
c. Commenters Who Felt the Core Group Is Overly Inclusive. A number
of commenters argued that the burdens associated with including certain
source categories would outweigh the benefits and that particular types
of sources should therefore be excluded from the core group. Many of
these commenters stated that individual sources in these groups should
be allowed to opt in where there is a net economic benefit to them to
participate rather than mandating inclusion of the source category.
Specific categories include: non-utility boilers generally; generators
of power for on-site use; combustion turbines exempt from Title IV;
small cyclone boilers; combustion turbines below 100 MWe; small,
particularly municipal, electric generating units (e.g., those under 25
MWe); and units with low potential to emit as defined by enforceable
limits (e.g., peaking units with potential to emit less than 100 tons
per year).
The EPA does not believe there is a great distinction between
similarly sized utility and non-utility boilers. Both categories of
boilers are similar in design, have similar control options and have
similar control costs. Therefore, EPA is not excluding large non-
utility boilers from the trading program. The EPA believes the same
arguments that apply to utility and non-utility boilers also apply to
generators of power for on-site use and generators of power for resale.
In light of the fact that utility restructuring will provide more
opportunities for generators of power for on-site use to resell the
power they produce in the future, EPA believes that this distinction is
even harder to make. Therefore, EPA is not excluding large generators
of power for on-site use from the trading program.
In accordance with title IV of the CAA, the Acid Rain Program
exempts simple combustion turbines that commenced commercial operation
before November 15, 1990. These units were exempted from the Acid Rain
Program because the SO2 emissions from these units were
extremely low. The NOX emissions from these units are
potentially higher; therefore, EPA is not adding a specific exemption
for these types of units. However, many of these units are small and/or
infrequently operated, so their actual NOX emissions may be
quite low; therefore, some of these units may qualify for the
[[Page 57463]]
alternative compliance options for units with low NOX mass
emissions, explained below. Combustion turbines smaller than 100 MWe
are also likely candidates to qualify for the alternative compliance
option explained below.
The Acid Rain Program exempts cyclone boilers with a maximum
continuous steam flow at 100 percent load of greater than 1060 thousand
lb/hr from NOX control requirements under part 76. These
units were exempted because one of the primary criteria in title IV of
the CAA for setting emissions limitations under part 76 was
comparability of cost with low NOX emission controls on
boilers categorized as group 1 boilers under Title IV (large
tangentially fired and dry bottom, wall fired). There is no such
criterion in the CAA applicable to this rulemaking. Also, since the
emission reductions required by this rulemaking are more substantial
than the emission reductions required under part 76 70, the
cost per ton of reducing NOX emission reductions is
correspondingly higher. Therefore, applicability cutoffs that were
relevant in the part 76 rulemaking are not relevant in this rulemaking.
---------------------------------------------------------------------------
\70\ The lowest emission rate required under part 76 is 0.40
lbs/mmBtu.
---------------------------------------------------------------------------
In response to the comment that small electrical generators less
than 25 MWe should be exempt from the NOX Budget Trading
Program, they were proposed to be exempt and will be exempt under the
final model rule. They do still have the option of opting into the
program if they choose to do so.
In the SNPR (63 FR 25926), EPA took comment on allowing units with
a low federally enforceable NOX emission limit (e.g. 25 tons
per ozone season), that because of their size would be included in the
trading program, to be exempt from the requirements of the trading
program. In general commenters supported this concept. One commenter
who supported the concept also added that it would be important to
ensure that there were adequate requirements to assure that the
individual sources who took advantage of this option demonstrated
compliance with their unit-specific caps. The commenters who disagreed
with this option expressed concern that a State's budget could be
exceeded if emissions from these units were not accounted for.
Based on the comments received EPA continues to believe that it is
appropriate to offer States the option of providing units that are
above the applicability threshold but that have a very low potential to
emit an alternative compliance option. This option would allow units
that meet the requirements described below to be exempt from the
requirements to hold allowances, and to comply with quarterly reporting
requirements. In order to address the concern that sources must
demonstrate compliance with their individual cap, EPA has added
specific requirements that sources must meet in order to use this
alternative compliance option.
Units that use this option would be required to:
(1) have a federally enforceable permit restricting ozone season
emissions to less than 25 tons;
(2) keep on site records demonstrating that the conditions of the
permit were met, including restrictions on operating time;
(3) report hours of operation during the ozone season to the
permitting authority on an annual basis.
A unit choosing to use this compliance option would be required to
determine the appropriate restrictions on its operating time by
dividing 25 tons by the unit's maximum potential hourly NOX
mass emissions. The unit's maximum potential hourly NOX mass
emissions would be determined by multiplying the highest default
emission rate for any fuel that the unit burned (using the default
emission rates, in part 75.19 of this chapter) by the maximum rated
hourly heat input of the unit (as defined in part 72 of this chapter).
States would be allowed, but not required, to incorporate this
alternative compliance option into their SIPs. The EPA does agree that
if a State does incorporate this option into the SIP, it would have to
account for the emissions under its budget. Thus a State that chose to
use this option would have to either:
(1) Subtract the total amount of potential emissions permitted to
be emitted using this approach from the trading portion of the budget
before the remaining portion of the trading budget is allocated to the
trading participants; or (2) Offset the difference between total amount
of potential emissions permitted to be emitted using this approach and
the 2007 base year inventory emissions for these same sources with
additional reductions outside of the trading portion of the budget.
If States choose not to incorporate this alternative compliance
option into their SIPs, or if they choose to incorporate it exactly as
it is set forth in the model rule, it will not affect the streamlined
approval of the trading rule portion of the SIP. A State may choose to
require an alternative means of ensuring that the potential to emit for
units utilizing the alternative means of compliance is limited to less
than 25 tons, however if a State deviates from the model rule in this
way, the SIP will no longer receive streamlined approval.
2. Mobile/Area Sources
The proposed rule did not include mobile or area sources in the
trading program, but solicited comment on expanding applicability to
include these sources, or to include credits generated by these
sources, in the trading program. Mobile and area sources were not
included in the proposed trading rule due to EPA's concerns related to
ensuring that reductions were real, developing and implementing
procedures for monitoring emissions, and identifying responsible
parties for the implementation of the program and associated emissions
reductions.
The EPA received comment from State and local government, industry
and coalitions of industry, and environmental groups regarding the
inclusion of mobile and area sources in the program. Comments focused
on the following main areas: inclusion or exclusion of mobile and area
sources, subcategories of mobile sources for inclusion, and the use of
pilot programs to foster innovation.
Some commenters urged EPA to include mobile and area sources with
as few restrictions as possible in the trading program, primarily on an
opt-in or voluntary basis. These commenters argued that excluding
mobile sources would reduce the potential scope and benefits of the
trading by placing a large portion of States' NOX inventory
outside the scope of the trading program. They noted that the existence
of RECLAIM protocols for mobile and area source credit generation
demonstrated that EPA's quantification, verification, and
administration concerns were misplaced.
The majority of commenters, however, indicated that mobile sources
should not be included at this time and that the model rule should not
be delayed to address concerns related to inclusion of these sources.
Some commenters argued against ever including mobile and area sources
in the program. One State argued that inclusion of mobile and area
sources would destroy the integrity of the program since mobile and
area source reductions are not necessarily real, verifiable and
quantifiable, failing to display a level of certainty comparable to
those sources included in the trading program. A few commenters
indicated that mobile sources were inherently unsuited to a capped
system, since the difficulties of measuring emissions from these
sources precludes their inclusion in a budget.
[[Page 57464]]
Several commenters suggested that some categories of mobile sources
should be included while other categories should not. Commenters
indicated, for example, that it is not feasible to have individual
motorists participate in the cap-and-trade program due to the burdens
and administrative complexity associated with such a vast number of
sources and responsible parties in a trading system. Alternatively,
commenters argued that manufacturers, fuel distributors, and fleet
owners could be included if they were able to generate surplus emission
reductions by going beyond the requirements established by some Federal
measures. These commenters specifically cited the low-RVP regulations,
the vehicle scrappage guidance, and the locomotive regulations as
examples of such Federal measures.
Several commenters who recommended that mobile sources not be
included in the program at this time also recommended that EPA sponsor
pilot programs in States to study the feasibility of inter-sector
trading and to develop mechanisms to address the specific concerns
mentioned regarding the inclusion of mobile and area sources. Along
similar lines, one industry commenter stated that mobile sources may be
appropriate candidates for participation in the trading program only if
adequate emission reduction measurement protocols can be developed.
Foreseeing this occurrence, some commenters felt that EPA should leave
a placeholder in the rule or add a provision that would include mobile
and area sources once the mechanisms to address the specific concerns
of EPA and others have been developed.
The model trading program that EPA is finalizing today will not
include mobile and area sources for the reasons outlined in the SNPR.
The EPA concurs with the concerns raised by commenters against the
inclusion of mobile and area sources, regarding program integrity,
emissions monitoring, and accountability. Most of the proponents of
including mobile or area sources listed general reasons for including
them such as increasing market efficiency, lowering costs, or simply
the existence of RECLAIM protocols to do so. However, these commenters
did not provide sufficient information or documentation to support the
validity of these assertions, and several acknowledged that the
potential for improvement in market efficiency or lower compliance
costs was difficult to ascertain. Further, one proponent acknowledged
that the RECLAIM protocols are new and not yet extensively utilized.
In fact, a recent audit of the RECLAIM program indicates that the
volume of mobile source credits used under the program is very small
(only 99 NOX tons have been converted from mobile source
reductions in the last five years). Only 5 requests for conversion of
mobile source emission reduction credits to RECLAIM trading credits
were approved in 1994, and no further requests had been received as of
May 1998. The small amount of credits relative to the significant
resource expenditure for the conversion of mobile source credits under
the RECLAIM program (i.e., the need for case-by-case review given the
variability and complexity of the petitions) suggests that the RECLAIM
mobile source protocols and strategy are not yet a cost-effective
option for the trading program.
The EPA remains willing to consider adding mobile or area sources
to the trading program in the future. Most commenters recommended that
the program be opened to mobile or area sources once adequate
mechanisms are developed for addressing related concerns. In response
to these comments, and those recommending that EPA support pilot
programs in States in order to facilitate resolution of the areas of
concern for mobile and area sources, EPA will investigate how grant
funding may be used for such pilots. Additionally, EPA is pursuing
possible ways to incorporate mobile and area source strategies into
other trading and incentive programs. Through these efforts, EPA will
work with States in finding solutions to adequately address concerns
such as emissions variability, difficulty in controlling emissions
growth, difficulty in monitoring emissions levels, and difficulty in
establishing emissions baselines. Through this process, EPA and States
will explore and develop the necessary protocols that could eventually
allow the inclusion of mobile and area sources in some capacity in the
NOX Budget Trading Program. Anticipating that the
quantification, verification, and administration concerns regarding
expansion of the trading program to include mobile and area sources may
be sufficiently resolved in the future, EPA is reserving in this
rulemaking a section in part 96 for future inclusion of mobile or area
sources in the NOX Budget Trading Program.
The EPA is aware of other concerns on which the Agency did not
receive comment, including the adequacy of some of the existing mobile
source protocols and the enforcement of mobile source credit generation
strategies. These emerging issues, coupled with past experience, and
the issues raised by commenters lead EPA to conclude that it is not
appropriate to include mobile and area sources in the NOX
Budget Trading Program at this time.
3. Monitoring
For the reasons set forth in the SNPR (63 FR 25938-40), EPA
proposed that sources in the NOX Budget Trading Program use
the monitoring methodologies in proposed subpart H of part 75 to
quantify their NOX mass emissions (63 FR 28032). The
comments that EPA has received can be classified into three main
categories:
Support for requiring the use of part 75 to demonstrate
compliance with the trading program,
Support for using CEMS on large units, but concerns about
using part 75 as the monitoring protocol, and
Concerns about requiring CEMS.
Some of the commenters concerned about requiring CEMS focused on
units of any size that are not subject to the provisions of the Acid
Rain Program. Others focused on smaller units.
The EPA proposed revisions to part 75 (63 FR 28032) for a number of
reasons, one of which was to add procedures for monitoring
NOX mass emissions (subpart H). These procedures could be
used by sources to comply with any State or Federal program requiring
measurement and reporting of NOX mass emissions. In
particular, subpart H would be used by sources to meet the monitoring
and reporting requirements of the NOX Budget Trading Rule
(part 96) and the monitoring and reporting requirements of the SIP call
for (1) combustion units (boilers, turbines and combined cycle units)
which serve electric generators greater than 25 MWe and (2) combustion
units greater than 250 mmBtu/hr, regardless of whether they serve a
generator.
The part 75 revisions also proposed to make a number of other
changes that would affect units using part 75 to comply either with the
requirements of title IV or the requirements of a NOX mass
emissions program that incorporated or adopted the requirements of part
75. These included a number of minor changes to simplify and streamline
the rule to make it more efficient for both affected facilities and
EPA, a new excepted monitoring methodology that would reduce monitoring
burdens for affected facility units with low mass emissions, new
quality assurance requirements based on gaps identified by EPA during
evaluation of the initial implementation of part 75, and several minor
technical
[[Page 57465]]
changes to maintain uniformity within part 75 and to clarify various
provisions.
The following discussion addresses comments received in the SNPR
docket (A-96-56) that are related to the general requirement to monitor
emissions, the requirement to monitor emissions using CEMS, and the
requirement to monitor using part 75. Although EPA had requested that
all comments related to the use of part 75 for monitoring
NOX mass be submitted to the part 75 docket (A-97-35), some
comments also dealt with the specific requirements set forth in part
75.
In today's rulemaking, EPA is finalizing sections of part 75
related to monitoring NOX mass emissions as well as those
which address the excepted monitoring methodology for units with low
mass emissions of NOX and SO2 that combust oil or
natural gas. Units using this methodology to comply with the
requirements of part 96 would be subject only to the NOX
mass emission requirements and not to the SO2 mass emission
requirements. For a more complete discussion of the NOX mass
monitoring and reporting provisions in part 75, see the Amendments to
Part 75 Section below and Appendix A of this preamble. These Sections
discuss both the comments received in the part 75 docket as well as the
comments received in the SNPR docket that address the specific
requirements of part 75.
a. Use of Part 75 to Ensure Compliance with the NOX
Budget Trading Program. Several commenters supported the idea of
requiring all sources in the trading program to meet the monitoring
provisions of part 75. Some of these commenters noted that part 75
provides the consistent and accurate monitoring requirements necessary
to ensure the integrity of a cap and trade program. They also noted
that the proposed revisions offered the flexibility needed for sources
to be able to reasonably comply.
Several commenters supported the concept of trying to consolidate
the monitoring and reporting requirements for units in the
NOX Budget Trading Program already subject to part 75 under
the Acid Rain Program.
Response: The EPA agrees that accurate and consistent data are
important to ensure the integrity of a trading program and that the
protocols in part 75 provide for such accurate and consistent data from
stationary combustion sources. Today's final model rule would require
all sources in the trading program (including sources currently subject
to part 75) to use the monitoring and reporting procedures set forth in
subpart H of part 75.
b. Use of CEMS on Large Units. A number of commenters expressed
support for the requirement that large units should use CEMS to
quantify NOX mass emissions. Many of these commenters did,
however, have concerns about using part 75 as the basis for this
monitoring. Some of these commenters elaborated that part 75 was
specifically developed for utility units and that it might not be
applicable to other types of units. Commenters also expressed concerns
about costs associated with upgrading existing CEM systems to meet the
part 75 requirements. The main alternatives they suggested were either
using existing State monitoring and reporting requirements or allowing
States the discretion to create or approve new monitoring and reporting
requirements.
Response: For reasons set forth in the preamble to the SNPR, EPA
believes that the use of CEMS, in general, and the protocols in part
75, more specifically, are the most effective way to ensure that
NOX mass emissions from large combustion sources are
quantified in an accurate and consistent manner from source to source
and are reported in a consistent and cost-efficient way. This is
important to maintain the integrity and efficiency of the trading
system.
The EPA believes that the protocols in part 75 can appropriately be
applied to all of the core sources (fossil fuel-fired electric
generating units and industrial boilers). The issues associated with
monitoring NOX mass emissions from a stack attached to a
boiler, turbine, or combined cycle unit are the same regardless of
whether that boiler, turbine, or combined cycle unit is owned or
operated by a utility, by an independent power producer, or by a
manufacturer. The EPA does acknowledge that there may be additional
issues associated with monitoring NOX mass from units such
as process heaters or cement kilns.
The RECLAIM program uses very similar protocols to the ones in part
75 to quantify NOX mass emissions. Both RECLAIM and part 75
require the use of NOX CEMS and flow CEMS to quantify
NOX mass emissions from large sources combusting solid fuel.
Both RECLAIM and part 75 also offer large oil and gas units an
additional option for monitoring. This option involves the use of a
fuel flowmeter and fuel sampling and analysis. The RECLAIM program
requires monitoring of source categories that are in the NOX
Budget Trading Program core group, such as boilers and turbines, but
also requires monitoring of source categories that are not in the core
group, such as process heaters and cement kilns.
RECLAIM needed to establish a standing working group to resolve
issues related to monitoring NOX mass from such a wide range
of source categories (See South Coast Air Quality Management District,
RECLAIM Program Three Year Audit and Progress Report, May 8, 1998). EPA
does not believe that the problems that RECLAIM has had with monitoring
are related to the protocols that program uses. Rather, EPA believes
these problems are due to the limited experience that both States and
sources have with monitoring such a wide range of source categories.
The EPA believes that regardless of what protocols are used, if
States opt to bring additional source categories into the trading
program, issues related to monitoring at specific source categories
will arise. These issues will need to be resolved, thus improving State
and EPA experience with those source categories. If a State wants to
include additional sources beyond those included in the core group,
then EPA would resolve issues through the initial certification process
for opt-in units. The EPA will also provide additional guidance on
specific source categories, sharing the experiences gained with
individual opt-in units.
Using one basic set of protocols will make it easier for states,
sources and EPA to work together while gaining more experience with
these sources and resolving the issues in a cooperative and consistent
manner.
The EPA believes that the most significant costs associated with
upgrading from an existing NOX emission rate monitoring
system to a part 75 NOX mass monitoring system are
associated with the need to monitor NOX mass and would be
incurred regardless of the specific monitoring protocol that was
required. Many existing CEM rules other than part 75 require sources to
monitor NOX emission rate (in lbs/mmBtu) or NOX
concentration corrected for oxygen (in ppm)(e.g. monitoring
requirements under Subpart D, Da, Db of part 60). In order to meet
these requirements, a NOX monitoring system must consist of
a NOX concentration CEM, a diluent CEM and a data
acquisition and handling system (DAHS). The DAHS is the part of the
system that collects raw monitor data, performs calculations, and
generates reports.
In order to upgrade an existing system so that it can monitor
NOX mass, a source must install a flow CEMS, if it burns
solid fuels, or must install either a flow CEMS or a fuel flow meter if
it burns a homogeneous oil or gas. In addition, the source would have
to
[[Page 57466]]
upgrade its DAHS to reflect the reporting of NOX mass rather
than NOX emission rate or NOX concentration.
These costs must be incurred, regardless of the protocol that a source
used to monitor NOX mass.
The EPA believes that a single monitoring and reporting protocol
for the NOX Budget Trading Program will keep the costs of
upgrading systems to a minimum. This is because equipment vendors will
be able to create standardized systems that will be applicable to all
sources in the program, rather than having to create many different
State- and source-specific systems. A single monitoring and reporting
protocol will also help ensure a level playing field for all affected
sources.
For these reasons, part 96 requires all large units to monitor
NOX mass emissions using CEMS in accordance with part 75.
However, as explained below, part 75 does offer various monitoring
options for low-emitting or infrequently operated oil- and gas-fired
units, in addition to CEMS.
c. Commenters Who Do Not Believe That CEMS Are Necessary. Some
commenters expressed concerns about requiring CEMS on any unit that
does not currently have a CEMS monitoring requirement. Suggested
alternatives included the use of stack test data and emission factors.
Some commenters also suggested the testing and monitoring provisions of
a source's title V permit.
Response: For large sources, EPA does not believe that stack test
data and emission factors provide the consistent and accurate data
needed to facilitate a trading program. Stack test data provide a one-
time assessment of a source's emission rate. Emission factors at best
are based on a series of stack tests at similar units. A unit's actual
emission rate may fluctuate greatly over time due to factors such as
the way the unit and/or its associated control equipment is operated
and maintained and the quality of fuel that the unit burns. An emission
factor or stack test will often not be representative of that unit's
actual normal emissions. Continuous monitoring of actual emissions will
ensure that fluctuations in emission rates are accounted for. Because
CEMS provide continuous monitoring, they can also indicate when
emission control equipment is malfunctioning, thus, helping to ensure
that the owners of units continue to properly operate and maintain any
installed emission control equipment.
Title V permits incorporate all of the monitoring requirements to
which a source is subject in order to demonstrate compliance with its
current regulatory requirements. In addition, where a source is not
subject to any other monitoring requirements, it sets forth minimum
monitoring requirements. In many cases the current regulatory
requirements do not require compliance with a mass emissions
limitation. Therefore, the monitoring requirements are not designed to
demonstrate compliance with a mass emission limitation.
Even when a source may have monitoring requirements designed to
demonstrate compliance with a mass emissions limitation, the stringency
of these requirements often varies from source to source and from State
to State. These variations in turn lead to inconsistencies in sources'
accounting of mass emissions. This both creates an uneven playing field
for sources and undermines the integrity of the trading program.
The EPA believes that it is necessary for all sources in the
trading program to be subject to accurate and consistent monitoring
requirements designed to demonstrate compliance with a mass emission
limitation. This will ensure compliance with the requirements of the
SIP Call and will ensure the integrity of the trading program.
The EPA does believe that it is appropriate to provide lower cost
monitoring options for units with low NOX mass emissions.
Part 75 allows non-CEMS alternatives to quantify NOX mass
emissions for gas and oil fired units that have low NOX mass
emissions and/or that operate infrequently.
In contrast, EPA does not believe that the types of protocols set
forth in the Compliance Assurance Monitoring (CAM) rule, part 64, are
appropriate for a trading program because they were not designed to
quantify mass emissions. The preamble to the CAM rule further
elaborates why these protocols are not appropriate for a trading
program (62 FR 54915, 54916, 54922).
The EPA believes that the types of protocols in RECLAIM and the
Ozone Transport Commission's NOX Budget Trading Program
(``OTC Program'') are more appropriate for a trading program because
they were specifically designed to quantify NOX mass
emissions. The EPA also believes that the flexible monitoring options
offered by part 75 are consistent with the type of flexibilities
offered in RECLAIM and the OTC Program. RECLAIM requires CEMS on all
units that burn solid fuels and all units that emit more than 10 tons
per year, regardless of the type of fuel they burn.. The OTC Program
requires CEMS on all units that burn solid fuels and all units that do
not qualify as peaking units, that are larger than 250 mmBtu/hr or that
serve generators greater than 25 MW. Like RECLAIM and the OTC Program,
part 75 requires CEMS on all units that burn solid fuel. Part 75 also
requires the use of CEMS on oil and gas fired units that emit more than
50 tons of NOX annually (or for units that only report
during the ozone season, 25 tons of NOX during the ozone
season), or that don't qualify as peaking units. In both the OTC
Program and part 75, a peaking unit is defined as a unit that has a
capacity factor of no more than 10 percent per year averaged over a
three year period and no more than 20 percent in any one year.
The EPA believes that these exceptions in part 75 provide cost-
effective monitoring alternatives to CEMs for small, low mass emitting,
or infrequently used units, and therefore, it is appropriate that part
96 require all units to use part 75.
d. Issues Related to Monitoring and Reporting Needed to Support a
Heat Input Allocation Methodology. For monitoring and reporting
NOX mass emissions, subpart H of part 75 requires the use a
NOX concentration CEM and a flow CEM. Since the methodology
does not require the use of heat input, EPA would not require sources
to monitor or report heat input or NOX emission rate for a
NOX mass emission reduction program. If a State elects to
use a periodically updating allocation methodology that utilizes heat
input, it may need to require sources using this methodology to monitor
and report heat input also.
e. Amendments to Part 75 (1) Summary of Part 75 Rulemaking. Title IV of
the CAA requires the EPA to promulgate regulations for continuous
emissions monitoring (CEM). On January 11, 1993, final rules (40 CFR
part 75) were published (58 FR 3590). Technical corrections were
published on June 23, 1993 (58 FR 34126) and July 30, 1993 (58 FR
40746). A notice of direct final rulemaking and a notice of interim
final rulemaking making further changes to the regulations were
published on May 17, 1995 (60 FR 26510 and 60 FR 26560, respectively).
Subsequently, on November 20, 1996, a final rule was published in
response to public comments received on the direct final and interim
rules (61 FR 59142).
The EPA proposed further revisions to part 75 on May 21, 1998 (63
FR 28032). These revisions included a new subpart H which sets forth
procedures for monitoring NOX mass emissions, which could be
used by sources to comply with any State or Federal program requiring
measurement of NOX mass emissions, including the
requirements
[[Page 57467]]
of the NOX Budget Trading Rule (part 96). The May 21, 1998
proposed revisions also proposed to make a number of other changes that
would affect units that were using part 75 to comply either with the
requirements of title IV or the requirements of a NOX mass
trading program under title I that incorporated or adopted the
requirements of part 75. These included a number of minor changes to
simplify and streamline the rule to make it more efficient for both
affected facilities and EPA; a new excepted monitoring methodology that
would reduce monitoring burdens for affected facility units with low
mass emissions; and new quality assurance requirements to fill in gaps
identified by EPA during evaluation of the initial implementation of
Part 75.
(2) Schedule For Part 75 Final Rulemaking. The comment period for
the proposed revisions to part 75 ended on July 20, 1998. EPA
anticipates completing rulemaking on all of proposed revisions to part
75 by the end of the year. However, because the revisions to subpart H
of part 75 relating to the monitoring and reporting of NOX
mass emissions are integral requirements of the SIP Call, EPA is
finalizing most of the requirements of subpart H of part 75 with
today's action.
The EPA is also finalizing a new excepted monitoring methodology
for units that combust natural gas and or fuel oil with low mass
emissions of NOX and SO2. These provisions are
being finalized because they are one of the methodologies that certain
gas and oil units can use to quantify NOX mass under the new
subpart H of part 75.
The EPA is not finalizing the rest of the proposed revisions to
Part 75 at this time because EPA is still evaluating the comments
received on the proposed rulemaking. Many of these remaining provisions
will be applicable to any unit that must use the requirements of part
75 in order to meet the requirements of title IV or to meet the
requirements of a State or Federal NOX reduction program
that adopts the part 75 requirements. For example, the proposed
revisions would allow a unit with CEMS to be exempt from the
requirement to perform a linearity test in any quarter that the
combustion unit for which the CEMs is installed operates for less than
168 hours. If EPA ultimately finalizes this proposed flexibility, it
will become available both to units using part 75 to comply with title
IV and to units using it to comply with the part 96 model trading rule.
As another example, EPA proposed quality assurance requirements for
moisture monitors that would be needed if pollutant concentration
(NOX, SO2 or CO2) were measured on a
dry basis and needed to be converted to a wet basis so that mass
emissions could be determined using a stack flow meter. If EPA
ultimately finalizes this proposed requirement it will affect both
units using part 75 to comply with title IV and units using it to
comply with part 96 (or a State or Federal NOX mass
reduction program that adopts part 75).
The EPA is also not yet finalizing the recordkeeping and reporting
requirements associated with either the NOX mass monitoring
provisions in subpart H or the low mass emitter monitoring methodology
because EPA believes that these reporting requirements should be
coordinated with any changes in the reporting requirements that result
from the finalization of the rest of proposed revisions to part 75.
Therefore, EPA has closed the part 75 docket (A-97-35, with respect
to the provisions that are being finalized in today's rulemaking:
section 75.19, a new excepted methodology for estimating emissions for
units with low mass emissions; and subpart H, a new subpart setting
forth provisions for monitoring, recording and reporting NOX
mass emissions, except where EPA has reserved final action on related
aspects of these provisions. EPA has not closed the docket with respect
to the other provisions that were the subject of EPA's, May 21, 1998
proposal (63 FR 28032).
(3) Summary of Major Differences Between Proposed and Final
Revisions to Part 75. The final rule contains two main differences to
the NOX mass monitoring and reporting provisions from what
was proposed. The first is that a new methodology for calculating
NOX mass emissions is included. This methodology utilizes a
NOX concentration CEM and a flow CEM to calculate
NOX mass emissions. The second is that sources that are not
subject to title IV are not required to monitor and report data outside
of the ozone season unless otherwise required to do so by the
Administrator or the permitting authority administering the
NOX mass trading program.
The final rule also contains two main differences from the proposal
with regard to the new excepted monitoring methodology for low mass
emitters. The first is that the methodology is applicable to units with
calculated NOX mass emissions of up to 50 tons, rather than
25 tons as proposed. The second is that in lieu of using default rates
for NOX set forth in the rule, the owner or operator of a
unit using this methodology may instead elect to determine a unit
specific rate by conducting stack testing. All of these changes are
discussed in greater detail in Appendix A of this notice. At this time
EPA is only addressing the comments dealing with the two main issues
for which EPA is finalizing revisions to part 75, the reporting of
NOX Mass (subpart H) and a new excepted monitoring
methodology for low emitters (Sec. 75.19). The EPA intends to address
the rest of the comments on the part 75 rulemaking in a separate,
future rulemaking. The discussions in Appendix A also address comments
received in the SNPR docket (A-96-56) that related specifically to the
monitoring requirements set forth in part 75.
E. Emission Limitations/Allowance Allocations
Each State has the ultimate responsibility for determining the size
of its trading program budget and its individual source allocations as
long as the trading budget plus emissions from all other sources do not
exceed the State's SIP Call budget. The proposed rule published on May
11, 1998 set timing requirements identifying when the allocations
should be completed by each State and submitted to EPA for inclusion in
the NOX Allowance Tracking System (NATS) and provided an
option specifying how a State might allocate NOX allowances
to the NOX budget units. Today's final model rule clarifies
the timing requirements for submission of allowance allocations to EPA
and provides an optional allocation approach. Each State remains free
to adopt the Model Rule's allocation approach or adopt an allocation
scheme of its own provided it meets the specified timing requirements,
requires new sources to hold allowances, and does not allocate more
allowances than are available in the State trading budget.
1. Timing Requirements
In the SNPR, EPA set timing requirements identifying when a State
would finalize NOX allowance allocations for each control
period in the NOX Budget Trading Program and submit them to
EPA for inclusion into the NATS. In developing the proposal, the Agency
reasoned that uniform timing requirements would be important to ensure
that all NOX budget units in the trading program would have
sufficient time and the same amount of time to plan for compliance for
each control period, and sufficient time and the same amount of time to
trade NOX allowances. After considering a range of timing
requirements, EPA proposed options that allocated NOX
allowances 5
[[Page 57468]]
to 10 years in advance of the applicable control period. The proposal
attempted to strike a balance between systems that change the
allocations on an annual basis and systems that establish a single,
permanent allocation.
The proposed rule included the following timing requirements for
the allocation of NOX allowances: by September 30, 1999,
each participating State would submit NOX allowance
allocations to EPA for the control periods in the years 2003, 2004,
2005, 2006, and 2007. After the initial allocation, two timing
requirements were proposed for allocations following the year 2007. The
option set forth in the proposed Model Rule would require a State to
submit allocations to EPA for the control period in the year that is 5
years after the applicable submission deadline. For example, by January
1, 2003 each State participating in the trading program would issue its
allocations for the control period in 2008. The State would issue
allocations for the 2009 summer season by January 1, 2004. The second
option, discussed in the preamble of the supplemental notice, would
require the State to submit five years' worth of allowance allocations
at a time, every five years, starting in 2003. For example, by January
1 , 2003, each State participating in the trading program would issue
allocations for the control periods in the years 2008 through 2012. The
supplemental notice solicited comment on these timing options as well
as the full range of possible timing requirements (including a single,
permanent allocation system and an annually changing allocation
system). The supplemental notice also solicited comment on a provision
requiring EPA to allocate NOX allowances to NOX
budget units if a State were to fail to meet the timing requirements.
Comments: Although comments covered the entire range of possible
timing requirements, commenters generally supported striving for
administrative simplicity and ensuring sufficient planning horizons for
affected sources, while still addressing the needs of a changing
marketplace. Most comments fell into one of five categories.
First, a few commenters favored the option set forth in the
proposed Model Rule that would update the allocations each year, five
years in advance of the applicable control period. However, most of
these commenters also supported a system which would update the
allocations less than five years prior to the applicable control period
as that would allow more recent data to be used in the allocations. One
commenter advocated allocating for the previous season based on current
year data (i.e., allocations would be issued at the end of the season
for the preceding control period).
Approximately ten commenters favored the approach which would issue
allowances five to ten years in advance. This group found that five to
ten years of allocations satisfies the desire to have a sufficient
planning horizon while still ensuring responsiveness to changing market
conditions. Utilities generally opposed allocating single year
allowances as it might be disruptive to utility planning.
The third category of commenters advocated longer term or permanent
allocations. Most utility and business commenters favored allocations
that were issued in ten year blocks at a minimum to provide sufficient
time to plan future activities and amortize investments. A report
submitted by a State proposed that allocations extend over the capital
life of equipment, which was at least ten years.
A fourth set of commenters, which included three States, favored
shorter term allocations. These States commented that they may want to
base their allocations on more recent data than that proposed by the
Model Rule and suggested that three years would provide sufficient
planning time for sources. One State suggested tying allocations to the
submission of triennial inventories.
A final group of commenters suggested that no timing requirement
was necessary. They suggested that just as sources may participate in
an interstate trading program with allocations based upon different
methodologies, those same sources may participate in such a program
even if they receive their allowances at different times or for
different periods.
Several State commenters asserted that September 1999 was too early
to have allocations set. These States suggested that the allocation
process is difficult and takes longer than one year. One State
suggested that the early allocation deadline would effectively prevent
States from issuing allowances based upon output for the first period
because an output approach could not be developed in time.
Response: Most commenters supported issuing allowances at least a
couple of years prior to the season in which they would be used. The
commenters generally cited the goal of balancing changing market
conditions with providing sufficient planning horizons, as had the
Agency in the proposal. The EPA agrees that the certainty in having
allowances at least a couple of years into the future would provide
some predictability for sources in their control planning and build
confidence in the market. Most of the State commenters suggested three
years prior to the control season as an adequate length of time for
sources to know their allocations. The Agency agrees that a trading
system could work with sources knowing their allocations three years
prior to the control season. Therefore, EPA has modified its original
proposal to ensure that sources would always have allowances at least
three years in advance of the use date.
In addition to addressing how many years in advance the allocations
are determined, the Agency has also considered whether allocations
should be issued one control period at a time or for multiple control
periods at a time (e.g., five to ten control periods). In response to
the comments received, the Agency has determined that it would be
appropriate to set minimum timing requirements rather than prescribing
a set length of time for all States. Therefore, the Agency is now
requiring States choosing to participate in the NOX Budget
Trading Program to allocate a minimum of one summer season of
allowances at a time (at least three years in advance of the applicable
control period).
Moving from requiring five summer seasons of allocations (three
years in advance of the first season) to one summer season of
allocations (three years in advance) has the advantage of allowing the
allocation system to be updated sooner with more recent data. This
would provide those States that want to use updating systems to more
fully avail themselves of an updating system. The system could also
incorporate new sources more quickly, thus reducing the need for larger
new source set-asides.
However, the Agency has determined that a State may decide to issue
allowances further into the future than the one-season minimum period
required by this final rule and still receive streamlined EPA review of
its trading program. The NOX Allowance Tracking System will
be able to handle allocations for longer periods. Therefore, this Final
Rule sets out minimum timing requirements of one season (three years in
advance), but States may issue allocations in larger blocks for as many
as 30 seasons into the future and still receive streamlined EPA review.
However, in determining the length of time for which a State issues
allocations, a State should consider any potential adjustments that may
occur to its future State budgets. For example, as stated in Section
III.B.5.
[[Page 57469]]
of this preamble, the Agency may establish new budget levels for the
post-2007 timeframe. States issuing long-term allocations should
address how the allocations would be adjusted if new budget levels are
established in the future. The Agency does believe that having
allocations three years prior to the relevant control period would be
the minimum needed to support an active multi-state trading market
intended to reduce compliance costs for all States involved.
The three-year minimum timing requirement also is compatible with
beginning the program in 2003, with at least the first year's
allocations submitted to EPA by September 30, 1999. Sources will know
their first year's allocations three years prior to the start of the
program, and by April 1, 2003, all sources will have allocations for at
least four seasons--2003, 2004, 2005 and 2006. The Agency maintains
that the first year's allowances should be issued by September 30, 1999
to provide some predictability for sources in their control planning
and build confidence in the market. It also ties in with the State's
SIP submittal deadlines. For States participating in the trading
program, the allowances are an integral part of the State's plan to
satisfy the requirements of this SIP call. For sources in the Trading
Program, the allowances are the mechanism by which State budget
requirements are translated into source-specific limitations, and
therefore the allocations should be submitted with the SIP submittals.
In response to States who are worried about completing allocations in
this time frame, EPA notes that one State in the OTC resolved its
allocations in six weeks, demonstrating that it is possible to
establish allocations in less than one year.
Requiring only one year's worth of allowances at a time has the
added benefit of being able to more quickly accommodate States that
want to switch allocation methodologies after the start of the program.
For example, a State may decide to issue its initial allocations based
on heat input data because it has not yet finalized an approach to
issuing output-based allocations. The State could take a few additional
years to refine the alternative approach to issuing allowances. When
the State is ready to adopt the output approach, the State would be
able to start using the new approach much sooner than it would be able
to under a system that issued allocations in larger blocks.
Therefore, this preamble sets the following timing requirements for
the allocation of NOX allowances which will be able to
accommodate States that want to issue allocations one year at a time as
well as States that would like to issue allocations in larger blocks:
by September 30, 1999, the State would submit NOX allowance
allocations to EPA for at least the control period of 2003. After this
initial allocation, by April 1 of every year starting in 2001, the
State must, at a minimum, submit allowance allocations to EPA for the
control period in the year that is three years after the applicable
submission deadline. For example, by April 1, 2001, a State would
submit allocations for the control period in 2004. By April 1, 2002, a
State would submit allocations for the control period in 2005. This
minimum requirement would allow a State to submit blocks of allowances
that represent any number of years should the State prefer to do so.
For example, by the September 30, 1999 deadline, a State could submit
allocations for only the 2003 control period or for multiple control
periods (e.g., the five control periods of 2003-2007). The SIP would
provide that if the State fails to submit allocations by the required
date, EPA would allocate allowances based on the previous year's
allocation within 60 days of the applicable deadline. This approach
would ensure that starting in 2003, all sources would always have at
least three years of allowances in their accounts.
Today's Model Rule presents an allocation approach that satisfies
the minimum timing requirements. However, the initial allocation is for
three control periods (2003-2005) because this would avoid updating
allocations on an input basis. Any variation on the following approach
would be acceptable providing it satisfies the minimum requirements
specified in the previous paragraph. After this initial allocation, the
model rule would have the State submit allowance allocations to EPA for
the control period in the year that is three years after the applicable
submission deadline. By April 1, 2003, a State would submit allocations
for the control period in 2006. By April 1, 2004, a State would submit
allocations for the control period in 2007, and so forth.
2. Options for NOX Allowance Allocation Methodology
The Agency proposed that the NOX Budget Trading Rule
include a recommended NOX allowance allocation methodology.
The proposed Model Rule laid out an example of an allocation
methodology using heat input data for source allocations. The preamble
to the proposed Model Rule solicited comment on this methodology as
well as two additional options using either input or output data for
determining allocations. The first alternative to using heat input
would base the allocation recommendation on heat input data for the
first five control periods of the trading program and then convert the
allocations to an output basis for the control periods after 2007. The
final option would base the allocation recommendation on output data
for all NOX Budget units from the start of the trading
program. The Agency also solicited comment on a suggested schedule for
establishing a method for output-based allocations, and on any
technical or data issues relevant to output-based allocations, as well
as on the use of a fuel-neutral or output-neutral calculation to
determine allocations for NOX Budget units.
Comments: The Agency received numerous comments on the issue of
whether to suggest an allocation recommendation to States.
Approximately 25 commenters suggested that no recommendation is
necessary. Many of these commenters emphasized that EPA had no
authority to prescribe an allowance allocation methodology and a
recommendation could be misinterpreted as a requirement for SIP
approval. Several commenters requested that EPA clarify that the SIP
approval process will be consistently applied to all States regardless
of the allocation method chosen by a State, as long as the total
allocation does not exceed a State's trading budget. Approximately half
of the commenters who stated that no recommendation was necessary
suggested that if EPA were going to make a recommendation, the
recommendation should be a heat input approach.
Close to fifty commenters suggested that an Agency recommendation
was a good idea, but they were divided on the appropriate methodology.
This group included all the State commenters who suggested that a
recommended approach was appropriate for use as a default allocation
mechanism by States that did not determine their own allocations.
Many commenters supported the heat input approach used in the
example in the supplemental notice. Two State commenters said that the
proposed example approach was a useful default for States that did not
come up with their own allocations. Other commenters suggested that
heat input is an easily understood metric for all sources and the data
is readily available.
However, many suggested that EPA should recommend an output method
because they believe output-based allocations tend to reward more
efficient
[[Page 57470]]
fuels over fuels that require a higher heat input to generate the same
amount of electricity. Other reasons cited for output-based allocations
include the incentive that updating output allocations provides for
reducing emissions of pollutants such as CO2 and mercury.
Several commenters suggested that output-based allocations would allow
the environmental goals of the program to be achieved more cost-
effectively; their arguments rested upon assertions that issuing
allowances to non-NOX emitting units in an output-based
system would reduce the need for NOX controls over time. One
State commenter said that an output approach was the consensus of
participants at EPA Workshops held prior to drafting of the
Supplemental Notice and therefore should be the recommended approach
suggested by EPA.
One commenter had a specific recommendation for an updating output-
based allocation system which would issue allowances each year for the
current control period. Administrative simplicity, economic efficiency,
incentives for innovation, and lower consumer impact were cited as
reasons supporting that position.
Additional commenters favored the output-based approach but only
for fossil-fuel fired sources and renewables. Several commenters
submitted letters opposing a ``fuel-neutral'' policy and objected to
including nuclear sources in an output allocation to sources. They
stated that a fuel neutral policy would provide incentives for nuclear
generation which has the potential to release small amounts of
radiation to the environment as well as the potential for generation of
high-and low-level radioactive waste.
Response: As was stated in the SNPR, EPA believes that it is
important for as many States as possible to participate in the
NOX Budget Trading Program. The Agency recognizes that
States have unanimously favored flexibility in developing their own
allocation methodologies. Further, the comments that EPA received in
response to the SNPR (as well as in response to the workshops held
prior to publication of the SNPR) provided no clear consensus for one
methodology over another.
However, the Agency believes it is important to provide a model
allocation methodology that States may choose to use as a guide for
their own allocation process. Several States have commented that
including an example method in the Model Rule would be useful as a
backup for States who do not come up with an alternative method of
allocation. An outlined approach in the Model Rule may also facilitate
the regulatory process within a State that wants to quickly adopt the
Model Rule.
Therefore, today's Model Rule includes an optional allocation
methodology. The Agency has carefully considered arguments for
alternative allocation methods. The EPA would support a decision by a
State to use either heat input or output data as a basis for source
allocations or for the State to auction some or all of its allocation.
In determining the basis for the methodology presented in today's Model
Rule, EPA has decided to use the heat input approach because it is
concerned that an output-based approach has not been fully developed or
made available for public comment. Further, before issuing a model
output-based allocation approach, the Agency would need to make several
revisions to current reporting and monitoring provisions. EPA would
have to revise part 75 to monitor and report temperature, pressure, and
steam heat output (mmBtu) for units with some or all of their output as
heated steam. EPA would also need to put in place procedures which take
advantage of the most accurate data possible. For example, the Energy
Information Administration (EIA) solicited comment in a July 17, 1998
Federal Register Notice on a proposal to make electricity generating
data non-confidential and publicly available from non-utility
electricity generators (63 FR 38620). EPA will not know if this
information is available to the Agency or to States through EIA for
some time. If EIA were to decide that this information should remain
confidential in the future, then EPA and States would need to collect
their own data from sources. Additionally, the Agency is currently
unaware of any public databases of output information besides those for
electrical generation output for certain electrical generating units.
Output information would only become available if sources report it
directly to the Agency or to States.
While today's final Model Rule includes a heat input approach, the
Agency is continuing to work on developing an updating output approach
to source allocations. For States that wish to use output in developing
their source allocations and are willing to wait for EPA to finalize
such an approach, EPA plans to issue a proposed system for output-based
allocations in 1999 and finalize an output-based option in 2000.
However, the Agency's ability to issue an output-based approach on this
schedule is contingent upon resolving the issues and promulgating the
necessary rule changes mentioned in the previous paragraph.
Assuming EPA finalizes an output-based option in early 2000, States
wishing to use this output-based system could adopt the necessary
rules, and output data could be measured and collected at
NOX budget units during the control periods in the years
2001 and 2002. Output data could then be available for States to
calculate allocations for the control periods starting in 2006. Heat-
input-based allocations could be used for the 2003 through 2005 control
seasons.
However, this does not prohibit a State from developing its own
output-based system on a faster timeline. For example, if a State has
developed an output-based approach for use in its initial allocations,
it may use that approach. Or, the State may issue its initial
allocation for 2003 using heat input data and then by April 1, 2001
issue output allocations for the control periods starting in 2004.
The Agency recognizes that a State's choice of when and for what
blocks of time it issues allocations is intertwined with the choice of
allocation methodology. Several commenters suggested that more
incentives for generation efficiency and therefore ancillary
environmental benefits (CO2 and mercury reductions) are
provided in an output system with periodic updates, and those
incentives are lost in an heat input system that is periodically
updated. These commenters suggested that with a heat-input-based
system, States should issue permanent allocations rather than updating
the allocations. An allocation system that issues permanent streams of
allowances (using either a heat input or an output methodology) would
still provide an incentive for generation efficiency although perhaps
not to the extent that an updating output system might. However, if a
State issues a permanent stream of allowances to existing sources, that
State would have to decide how to address new sources (options include
establishing an allocation set aside or an auction, or requiring new
sources to obtain allowances from existing sources).
3. New Source Set-Aside
The Agency proposed an allocation set-aside account equaling 2
percent of the State trading program budget for each control period for
new NOx Budget units as part of its recommended allocation
approach. The concept and size of the set-aside is included only as an
optional feature of the Model Rule; however, the Model Rule requires
new sources to hold allowances to cover
[[Page 57471]]
their emissions. The supplemental notice proposed that allowances from
the set-aside be given out on a first-come, first-served basis at an
emission rate of 0.15 lb/mmBtu multiplied by a budget unit's maximum
design heat input. The source would then be subject to a reduced
utilization calculation so that a reduction in the emission rate below
0.15 lb/mmBtu would be rewarded, but a reduction in utilization would
not. In other words, EPA would deduct NOx allowances
following each control period based on the unit's actual utilization
for the control period. After the deduction, the allocation that had
been granted to the new unit from the set-aside would equal the product
of 0.15 lb/mmBtu and the budget unit's actual heat input for the
season. EPA solicited comments on the use of a set-aside as part of the
recommended allocation methodology as well as the proposed size and
operation of the set-aside.
Comments: The Agency received many comments regarding the proposal
for a new source set-aside. While several commenters were opposed to a
new source set-aside because it might bias control decisions in favor
of adding new sources relative to controlling existing sources,
numerous other commenters expressed general support for accommodating
new sources with allowances.
Several of these commenters offered suggestions for how the set-
aside should be designed. A few commenters stated that the size of the
set-aside should be related to the timing requirements and noted that
shorter timing requirements make it easier to accommodate new growth.
One commenter who advocated annually updating the allocation system
noted that its proposal would eliminate the need for a new source set-
aside. Some commenters supported the set-aside concept but asserted
that States should be able to decide the correct size. Other commenters
agreed with the set-aside concept in theory but did not think the
allowances should come from existing sources.
Additional commenters had specific proposals for the size of the
set-aside. One commenter suggested that the size of the set-aside
should reflect the actual growth projected in budget calculations and
that the unused portion of the set-aside should be retired. A few
commenters agreed with the proposed 2 percent size.
Several commenters offered suggestions on how to issue the set-
aside allowances to new sources. One commenter suggested that the
allowances should be given to new sources at the actual emission rate
if it was below the proposed 0.15 lb/mmBtu level.
Finally, several commenters suggested that the concept of a set-
aside was an issue that should be left completely up to the States.
Response: The Agency believes that a new source set-aside should be
large enough to provide all new units entering the trading program with
allocations. The Agency maintains that as much as possible within the
context of the overall trading budget, allocations should be provided
to new sources on the same basis as that used for existing units until
the time when the new sources receive an allocation as part of an
updating allocation system. Therefore, the Agency continues to include
a new source set-aside as part of its optional allocation methodology
described in the Model Rule. The EPA proposed the 2 percent set-aside
in the SNPR after looking at the amount of growth from new sources
projected by the Integrated Planning Model (and used in the budget
determinations) and estimating how much growth could be expected over
the five year period that new sources might have to wait before
receiving an allocation. In light of the allocation methodology and
timing specified in today's Model Rule as well as revisions made to the
growth factors used in State budget determinations since the SNPR, the
Agency has re-evaluated the size of the new source set-aside proposal.
The revised Integrated Planning Model projects approximately \1/2\
percent annual growth in capacity utilization for new sources. Given
the timing and optional allocation methodology specified in today's
Model Rule, the 2003, 2004, and 2005 set-aside would need to
accommodate any source that started operating after May 1, 1995.
Assuming the \1/2\ percent growth rate projected by IPM, the Agency
finds that a 5 percent set-aside should be large enough to accommodate
all new sources for the 2003, 2004, and 2005 control seasons.
After 2005, the new source set-aside would need to accommodate any
source that commenced operation after May 1 of the control period three
years prior to the control period in which the set-aside would be
available. For example, in 2006, the set-aside should be large enough
to accommodate any source that commenced operation after May 1, 2003.
Assuming the growth rates predicted by the IPM, the Agency finds that a
2 percent set-aside should be large enough to accommodate new source
growth after May 1, 2003.
A 5 percent set-aside provision for the first three control seasons
and 2 percent for the control periods starting in 2006 is incorporated
into today's Model Rule as an option States may adopt. However, States
may choose to handle new sources in any way as long as the emissions
from new sources are subject to the overall State budget. For example,
some States may choose to issue allowances for longer periods of time
than that outlined as the minimum requirement in today's Model Rule.
These States may find that a 5 percent set-aside is not sufficient to
accommodate all their new source growth, and may want to consider a
larger set-aside or alternative means to accommodate new sources. Or,
States may decide to allocate allowances based on a new source's
permitted or actual emissions, which may be lower than 0.15 lb/mmBtu.
This would require a smaller set-aside.
In the model rule set-aside provision, allowances will be issued to
new sources on a first-come, first-served basis. Allowances that are
not issued to new sources in the applicable control period will be
returned to the existing sources in the State on a pro-rata basis to
guard against the possibility of a disproportionately large set-aside.
The EPA maintains its position that new sources should receive
allowances at the same rate as that applied to existing sources (i.e.,
large electric generating units would receive allowances at a 0.15 lb/
mmBtu rate, large non-electric generating units would receive
allowances at the average emission rate for existing large non-electric
generating units after controls are in place, as explained in section 4
below). However, to reinforce the flexibility available on these
issues, as long as a State requires new sources to hold allowances, the
Agency reiterates that States may have any size set-aside (including
zero), may allocate the set-aside in whatever manner they choose, and
may carry over from one year to the next any amount of allowances
(subject to the banking provisions on this SIP call). If a State
decides to return unused allowances from a new source set-aside to
existing sources, the State would indicate to EPA (as the administrator
of the allowance tracking system) what number of allowances should be
returned to which existing units.
4. Optional NOX Allocation Methodology in Model Rule
While specific source allocations are required for States
participating in the NOX Budget Trading Program, the
allocation methodology presented here is an optional approach that may
be adopted by States. As long as a State (1) does not allocate more
allowances than are available in the State NOX trading
[[Page 57472]]
budget, (2) requires new sources to hold allowances, and (3) issues
allocations on a schedule that meets the minimum timing requirements,
the State may adopt whatever methodology it finds the most appropriate
and still qualify for inclusion in the NOX Budget Trading
Program.
The Model Rule contains the following optional allocation
methodology. It differs from the approach presented in the proposed
rule on the timing provisions, the allocation methodology for non-
electric generating units, and the size of the optional new source set-
aside. As proposed in the SNPR, initial unadjusted allocations to
existing NOX Budget units serving electric generators 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 2003,
2004, and 2005, the heat input used in the allocation calculation for
large electric generating units equals the average of the heat input
for the two highest control periods for the years 1995, 1996, and 1997.
Once the State completes the initial allocation calculation for all the
existing NOX budget units serving electric generators for
2003, 2004, and 2005, the State would adjust the allocation for each
unit upward or downward so that the total allocations match the
aggregate emission levels apportioned by an approved SIP to the State's
NOX Budget units serving electric generators. Then, the
State would adjust the allocation for each unit proportionately so that
the total allocation equals 95 percent of the aggregate emission levels
apportioned to the State's NOX Budget units serving electric
generators (to provide for the 5 percent new source set-aside). A State
would submit the 2003, 2004, and 2005 allocations to EPA by September
30, 1999.
For the control periods starting in 2006, the heat input used in
the allocation calculation for large electric generating units equals
the heat input measured during the control period of the year that is
four years before the year for which the allocations are being
calculated. Once the State completes the initial allocation calculation
for all existing budget units, and the State adjusts the allocations to
match the aggregate emission levels apportioned to NOX
Budget units serving electric generators, the State would adjust the
allocation for each unit proportionately so that the total allocation
equals 98 percent of the aggregate emission levels apportioned to
NOX Budget units serving electric generators (to provide for
the 2 percent new source set-aside).
For reasons explained elsewhere in today's rulemaking, EPA
determined the aggregate emission levels for large non-electric
generating units in each State budget based upon a 60 percent reduction
rather than the 70 percent proposed in the SNPR. The 60 percent
reduction results in an average emission rate across the region of 0.17
lbs/mmBtu for large non-electric generating units. Therefore, initial
unadjusted allocations to existing large non-electric generating units
would be based on actual heat input data (in mmBtu) for the units
multiplied by an emission rate of 0.17 lb/mmBtu. For non-electric
generating units subject to the trading program, 1995 heat input data
is used in the allocation calculation for the control periods 2003,
2004, and 2005 (1995 is the most recent data the Agency knows is
currently available for non-electric generating units). Once the State
completes the initial allocation calculation for all the existing large
non-electric generating units for 2003, 2004, and 2005, the State would
adjust the allocation for each unit upward or downward so that the
total allocations match the aggregate emission levels apportioned by an
approved SIP to the State's large non-electric generating units. Then,
the State would adjust the allocation for each unit proportionately so
that the total allocation equals 95 percent of the aggregate emission
levels apportioned to the State's large non-electric generating units
(to provide for the 5% new source set-aside). A State would submit the
2003, 2004, and 2005 allocations to EPA by September 30, 1999.
For the control periods starting in 2006, the heat input used in
the allocation calculation equals the heat input measured during the
control period of the year that is four years before the year for which
the allocations are being calculated. Once the State completes the
initial allocation calculation for all existing budget units, and the
State adjusts the allocations to match the aggregate emission levels
apportioned to large non-electric generating units, the State would
adjust the allocation for each unit proportionately so that the total
allocation equals 98 percent of the aggregate emission levels
apportioned to large non-electric generating units (to provide for the
2% new source set-aside).
A State would establish a separate allocation set-aside for new
units each control period. Five percent of the seasonal trading budget
will be held in a set-aside account for the control periods in 2003,
2004, and 2005. At the end of the relevant control period, the State
would submit a NOX allowance transfer request to EPA to
return any allowances remaining in the account to the existing sources
in the State on a pro-rata basis.
The allowances would be issued to new sources on a first-come
first-served basis at a rate of 0.15 lb/mmBtu for NOX Budget
units serving electric generators and 0.17 lb/mmBtu for large non-
electric generating units multiplied by the budget unit's maximum
design heat input. Following each control period, the source would be
subject to a reduced utilization calculation, in which EPA would deduct
NOX allowances based on the unit's actual utilization.
Because the allocation for a new unit from the set-aside is based on
maximum design heat input, this procedure adjusts the allocation by
actual heat input for the control period of the allocation. This
adjustment is a surrogate for the use of actual utilization in a prior
baseline period which is the approach used for allocating
NOX allowances to existing units.
F. Banking Provisions
As explained in Section III.F.7., EPA requested comment in the SNPR
on whether and how banking should be incorporated into the design of
the NOX Budget Trading Program. Banking may generally be
defined as allowing sources that make emissions reductions beyond
current requirements to save and use these excess reductions to exceed
requirements in a later time period. Options ranged from a program
without banking to several variations of a program with banking, prior
to and/or following the start of the program. The EPA also requested
comment on options for managing the use of banked allowances in order
to limit the emissions variability associated with banking. The EPA
specifically proposed using a ``flow control'' mechanism in cases where
the potential exists for a large amount of banked allowances to be
available.
This section addresses how banking has been incorporated into the
NOX Budget Trading Program based on the criteria set forth
in the NOX SIP call.
1. Banking Starting in 2003
In accordance with the provisions discussed in III.F.7.a., trading
programs used to comply with the NOX SIP call may allow
banking to start in the first control period of the program, the 2003
ozone season. The majority of commenters supported banking in the
context of the NOX Budget Trading Program. Based on the
advantages that banking can provide, as discussed in the SNPR and the
comments, the NOX
[[Page 57473]]
Budget Trading Program has been designed to allow banking starting in
the first control period of the trading program. NOX Budget
units that hold additional NOX allowances beyond what is
required to demonstrate compliance for a given control period may
carry-over those allowances to the next control period. These banked
allowances may be used or sold for compliance in future control
periods.
2. Management of Banked Allowances
The NOX SIP call establishes that a flow control
mechanism be paired with any banking provisions to limit the potential
for emissions to be significantly higher than budgeted levels because
of banking. This mechanism allows unlimited banking of allowances saved
through emissions reductions by sources, but discourages the
``excessive use'' of banked allowances by establishing either an
absolute limit on the number of banked allowances that can be used each
season or a rate discounting the use of banked allowances over a given
level. In the SNPR, EPA solicited comment on the application of flow
control in the NOX Budget Trading Program. Although many
commenters were opposed to any restrictions on the use of banked
allowances, several commenters stated that if restrictions were to be
imposed, they would favor flow control as the most cost-effective,
least rigid means of management. A few commenters added that, if
implemented, flow control should be applied on a source-by-source basis
so as to avoid penalizing all of the participants in the trading
program for the excess banking of individual participants. One
commenter stated that if EPA concludes that there is an adequate basis
for imposing some type of restriction, it should avoid placing any
absolute limit on the amount of banked allowances that can be used in a
given season.
The NOX SIP call established that flow control should be
set at the 10 percent level. The effect of setting flow control at 10
percent of the trading program budget is that on a season-by-season
basis, sources may use banked allowances or credits for compliance
without restrictions in an amount up to 10 percent of the
NOX budget for those sources in the trading program. Banked
allowances or credits that are used in an amount greater than 10
percent of the NOX budget for those sources will have
restrictions on their use.
The following provides a brief description of exactly how the flow
control mechanism will operate in the NOX Budget Trading
Program. The number of banked allowances held by all participants in
the multi-state trading program will be tabulated each year following
the compliance certification process to determine what percentage
banked allowances are of the overall multi-state trading budget for the
next year. If this percentage is equal to or below 10 percent, all
banked allowances may be used in the upcoming control season on a one
allowance for one ton basis. If this percentage is greater than 10
percent, flow control will be triggered. In years when flow control is
triggered, a withdrawal ratio will be established prior to the control
period for which it would apply. The withdrawal ratio will be
calculated by dividing 10 percent of the total trading program budget
by the total number of banked allowances. This ratio will be applied to
each compliance or overdraft account (only accounts used for
compliance) holding banked allowances as of the allowance transfer
deadline at the end of the control period for which it applies. Banked
allowances in each account may be used for compliance on a one-for-one
basis in an amount not exceeding the amount established by the
withdrawal ratio. Banked allowances used in an amount exceeding that
established by the withdrawal ratio must be used on a two-for-one
basis. By setting the withdrawal ratio prior to the applicable control
period (in years flow control is triggered) and applying it at the time
of compliance certification at the end of the applicable control
period, sources have one full control period to incorporate the value
of using banked allowances into their operations.
As described above, the NOX Budget Trading Program
applies the flow control mechanism on a regional basis and establishes
a 2-for-1 discount for banked allowances that are used in an amount
greater than the flow control limit. The regional approach for applying
flow control was selected over the source-by-source approach for the
following reasons:
EPA believes this option provides more flexibility to
individual sources than the source-by-source approach. If the 10
percent limit were placed on each source based on the source's
allocation, the limit would be in effect every year for every source,
even when the amount of banked allowances throughout the entire trading
region was below 10 percent of the regional trading budget. In
contrast, the regional approach only applies flow control when the
amount of banked allowances throughout the region (entire multi-state
trading area) exceeds the 10 percent limit. In response to the
commenter suggesting that the regional approach penalizes all
participants in the trading program for the excess banking of
individual participants, EPA notes that it would be difficult for a few
sources to cause the entire regional bank to exceed 10 percent of the
budget. In addition, based on the analyses presented in the RIA, EPA
does not anticipate that flow control is likely to be triggered.
Consequently, flow control is more of an insurance policy, rather than
a provision that is routinely expected to be operational.
The regional approach also provides flexibility to sources
if and when it is triggered. Because the withdrawal ratio is set before
the applicable control period but not applied until the control
period's allowance transfer deadline, sources have over seven months to
manage the amount of banked allowances they use on a 1-for-1 basis
versus a 2-for-1 basis.
EPA believes the regional approach is also a more
universal approach than the source-by-source approach under a variety
of allocation programs that States may use in the NOX Budget
Trading Program. To apply the flow control mechanism on a source-by-
source basis, the 10 percent limit would be applied to each source's
allocation. In this way, a source could use an amount of banked
allowances up to 10 percent of it's allocation without restrictions.
Restrictions would be placed on banked allowances that the source uses
in an amount greater than 10 percent of its allocation. Under certain
allocation programs, States may choose not to allocate NOX
allowances to new sources and require that these sources obtain the
necessary amount of NOX allowances for compliance from the
market. By not having an allocation of NOX allowances, new
sources would be prevented from using banked allowances under the
source-by-source approach. EPA believes that approaches to accommodate
sources without a fixed allocation under the source-by-source flow
control approach would overly complicate the system.
The regional approach for applying flow control is also
the approach used in the Ozone Transport Commission's (OTC) trading
program. Because the NOX Budget Trading Program is designed
to include States currently operating in the OTC program, using the
same approach for flow control will minimize the disruption for these
sources to convert to the NOX Budget Trading Program.
The other issue for flow control is the type of restriction to
place on banked allowances used in an amount greater than the 10
percent limit. The NOX Budget Trading Program includes the
2-for-1 discount as the applicable
[[Page 57474]]
restriction. EPA agrees with the commenters that favored this approach
over using an absolute limit. The EPA believes the 2-for-1 discount
provides more flexibility for sources to achieve compliance than is
offered by the absolute limit. The discount is also beneficial to the
environment, when triggered, by allowing only one ton of NOX
emissions for every two tons removed. Additionally, the OTC program
uses the 2-for-1 discount.
The following example illustrates how flow control will be used.
For the year 2006, assume the total trading program budget across all
States equals 300,000 allowances and 35,000 allowances are banked from
control periods prior to the 2006 control period. Since more than 10
percent (35,000/300,000 = 11.7%) of the total trading program budget is
banked, a withdrawal ratio will be established prior to the 2006
control period and will apply to all compliance and overdraft accounts
(only accounts that may be used for compliance) holding banked
allowances at the end of the 2006 control period. In this case, the
withdrawal ratio 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 the 2006 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 allowances for compliance in the 2006 control period, the 1,000
banked allowances could be used to cover only 930 tons of
NOX emissions (860 + 140/2). Of course, a source could buy
additional current year allowances to cover emissions on a 1-for-1
basis or buy additional banked allowances (allowances not needed by
other sources for compliance) to increase the amount of banked
allowances it may use on a 1-for-1 basis.
3. Early Reduction Credits
As described in section III.F.7.c., the majority of commenters
generally supported the option of awarding early reduction credits. EPA
is allowing, but not requiring, States to grant early reduction credits
to sources for reductions in ozone season NOX emissions
prior to the 2003 ozone season. States may issue early reduction
credits in an amount not exceeding the State's compliance supplement
pool. The compliance supplement pool is further explained in section
III.F.6.
Based on the support the commenters on the NOX Budget
Trading Program expressed for early reduction credits, EPA is including
optional provisions in the trading program that States may use for
issuing credits. States participating in the NOX Budget
Trading Program that choose to issue early reduction credits may follow
the methodology included in part 96 or may develop their own
methodology, provided the State's program meets the following
requirements. The State program must ensure that early reduction
credits will not be issued in an amount exceeding the State's
compliance supplement pool. The State program must also meet the
criteria for early reduction credits discussed in section III.F.7.c.
Finally, the State should notify EPA of the amount of credits issued to
particular NOX Budget units by no later than May 1, 2003.
Early reduction credits shall be issued to units as allowances for the
2003 control period. For purposes of the banking provisions, the
allowances will not be considered banked in the 2003 control period.
However, any unused allowances carried from the 2003 control period to
the 2004 control period shall be considered banked as will be the case
for all unused allowances carried over to the next control period. Per
the requirements discussed in section III.F.7.c., allowances issued for
early reduction credits may be used for compliance by sources in the
2003 and 2004 control periods. Any of these allowances that are not
used for compliance in the 2003 or 2004 control periods shall be
retired by EPA from the account in which they are held.
As discussed in Section III.F.6.b.ii., States also have the option
of issuing some or all of the State's compliance supplement pool
directly to sources according to the criteria for direct distribution.
Consequently, States participating in the NOX Budget Trading
Program may also use the direct distribution option for issuing the
compliance supplement pool. In this case, the State must notify EPA by
May 1, 2003 of the specific NOX Budget units that will be
receiving the direct distribution.
4. Optional Methodology for Issuing Early Reduction Credits
The methodology described below is an optional methodology included
in part 96 that States participating in the NOX budget
Trading Program and choosing to issue early reduction credits may
follow. States participating in the NOX Budget Trading
Program may also choose to develop their own methodology as discussed
above. The following methodology is designed to meet the criteria for
issuing early reduction credits discussed in section III.F.7.c. and to
provide incentives for a State's NOX budget units to
generate early credits in an amount no greater than the size of the
State's compliance supplement pool. The State may choose to issue the
entire compliance supplement pool as early reduction credits through
this methodology, or the State may choose to reserve some of the
compliance supplement pool to be issued to sources according to the
direct distribution criteria as described above.
This methodology is applicable for reductions made during the 2001
and 2002 ozone seasons. NOX budget units that request early
reduction credits will be required to monitor ozone season
NOX emissions according to the monitoring provisions of part
75, subpart H by the 2000 ozone season. The information from the 2000
ozone season shall be used to establish a baseline emission rate for
the NOX budget unit. To be eligible for early reduction
credits, a NOX budget unit shall reduce its emissions rate
in the 2001 and/or 2002 control period(s) no less than 20 percent below
its baseline emissions rate established for the 2000 ozone season. The
size of the early reduction credit request shall equal the difference
between 0.25 lb/mmBtu and the unit's actual emissions rate multiplied
by the unit's actual heat input for the applicable control period.
NOX Budget units requesting early reduction credits should
submit the request to the State by no later than October 30 of the year
for which the early reductions were generated.
The methodology conforms with the NOX SIP call's
criteria for early reduction credits. By requiring that the reductions
be measured using provisions in part 75, the reductions will be
verified as having actually occurred and will be quantified according
to the same procedures as required for compliance with the general
requirements of the NOX Budget Trading Program. The
procedure for calculating the credit request is intended to ensure that
the reductions are surplus. Phase II of the title IV NOX
emissions limits are required to be installed at specific coal-fired
boilers by January 1, 2000. By requiring that an early reduction credit
must be generated by no less than a 20 percent reduction below the 2000
baseline emission rate, credits will only be issued for reductions that
go below emissions levels achieved for compliance with title IV
requirements. This provision ensures that the early reduction credits
are only issued for reductions below existing requirements (i.e.,
surplus).
Calculating the early credit based on the difference between 0.25
lb/mmBtu
[[Page 57475]]
and the unit's actual emissions rate establishes a standard emissions
rate from which all early reduction credits are calculated. This
approach ensures that sources with higher NOX emissions
rates prior to the 2001 ozone season are not provided an opportunity to
generate more early reduction credits than relatively cleaner sources.
In this way, all sources have an equal opportunity to generate early
reduction credits below a standard emissions rate.
According to the requirements in the NOX SIP call,
States may not issue early reduction credits in an amount greater than
the State's compliance supplement pool. To ensure this provision is
met, the optional methodology is designed for States to issue all early
reduction credits following the 2002 ozone season. By October 30, 2002,
a State will have received all early reduction requests for both the
2001 and 2002 ozone seasons. After review of the requests, the State
would issue credit to all valid requests according to the following
procedure. If the amount of valid requests is less than the size of the
State's compliance supplement pool, the State would issue one allowance
for each ton of early reduction credit requested. If the amount of
valid requests is more than the size of the State's pool, the State
would reduce the amount in the credit requests on a pro-rata basis so
that the requests equal the size of the State's pool. After the
requests have been reduced, the State would then issue allowances based
on the remaining size of each credit request. States would complete the
issuance of allowances for the early reduction credit requests as soon
as possible following October 30, 2002, but no later than May 1, 2003.
5. Integrating the OTC Program With the NOX Budget Trading
Program's Banking Provisions
The OTC NOX Budget Program is a multi-state, capped
NOX trading program that begins in 1999 and includes many
States subject to today's action. By the start of the NOX
Budget Trading Program under the NOX SIP call, sources in
the OTC program will potentially hold banked NOX allowances
resulting from early reductions and/or overcontrol with program
requirements. At issue is the ability of OTC sources to use these
banked allowances in the NOX Budget Trading Program.
Commenters have supported allowing OTC sources to use banked
allowances (i.e., early reductions from the 1997 and 1998 ozone seasons
and unused allowances from the 1999 through 2002 ozone seasons) from
the OTC program for compliance in the NOX Budget Trading
Program. Commenters have stated that because OTC sources will be
subject to a market-based cap-and-trade program prior to the 2003 ozone
season, it is important to create a smooth transition from the OTC
program to the NOX Budget Trading Program. They have
suggested discounting OTC Phase II allowances to make them equivalent
to those achieved under the NOX SIP call. One OTC State
suggested accomplishing this by adjusting the OTC banked allowances by
a ratio of the Phase II OTC control requirement to the Phase III OTC
control requirement, working with EPA to determine the exact ratio. A
few OTC States suggested that OTC allowances banked in Phase II could
be used as early reduction credits in the NOX Budget Trading
Program. A commenter from outside the OTC voiced concern that the use
of OTC allowances banked by sources for the years 1999 through 2002
could distort the larger trading market established under the SIP call.
The EPA believes that the compliance supplement pool provides the
opportunity to integrate the OTC program into the NOX Budget
Trading Program by allowing OTC States to bring their banked allowances
into the NOX Budget Trading Program as early reduction
credits after the 2002 ozone season. The EPA established two primary
criteria for the generation of early reduction credits in III.F.7.c.:
first, the credits must be surplus, verifiable, and quantifiable; and
second, a State may not grant an amount of early reduction credits in
excess of a State's compliance supplement pool. EPA believes that
banked allowances held by sources in the OTC program would qualify as
being surplus, verifiable, and quantifiable. The banked allowances
would be surplus because they would represent emissions reductions that
go beyond what is required by the emissions limitations established by
the OTC program in the applicable ozone seasons. The banked allowances
would also be verified and quantified according to the procedures in
the OTC program which are essentially identical to the requirements
that will be in place under the NOX Budget Trading Program.
As for the second criterion that a State issue no more early
reduction credits than provided through the compliance supplement pool,
EPA believes this could be addressed according to the following
procedure. If the number of banked allowances held by an OTC State's
NOX Budget units, after the compliance certification process
for the 2002 ozone season, is less than the number of credits available
in the pool for that State, the NOX budget units in that
State may carry all of their banked allowances from the OTC program
into the NOX Budget Trading Program. The banked allowances
brought in from the OTC program would be subtracted from the State's
compliance supplement pool. Any remaining credits in the compliance
supplement pool could be distributed by the OTC State through the
direct distribution option, if necessary. If, on the other hand, an OTC
State's NOX Budget units hold banked allowances from the OTC
program in excess of the amount of credits in the State's pool, after
the compliance certification process for the 2002 ozone season, the
State would need to reduce the amount of allowances eligible for being
carried into the NOX Budget Trading Program. This could be
achieved by reducing the amount of banked allowances held by the units
on a pro rata basis so that the number of allowances carried into the
NOX Budget Trading Program is less than or equal to the size
of the State's compliance supplement pool.
The process described above provides a mechanism for OTC States to
use the compliance supplement pool to carry banked allowances from the
OTC program as of the end of the compliance period in 2002 over into
the NOX Budget Trading Program. The EPA believes this
integration acknowledges the important reductions made in the OTC
program prior to 2003 while providing similar opportunities for sources
outside the OTC to generate credits for early reductions. Since all
States in the NOX Budget Trading Program will have an
opportunity to receive credit for early reductions, EPA does not
believe any market distortion will occur.
G. New Source Review
Under the New Source Review (NSR) provisions of section 173 of the
CAA, a new major source or a major modification to an existing major
source of a particular pollutant that proposes to locate in an area
designated nonattainment for that pollutant must offset its new
emissions. In the SNPR, the EPA solicited comment on whether and how
the offset requirement could be met by sources' participation in the
NOX Budget Trading Program. The Agency stated its belief
that sources obligated to obtain NOX offsets under the NSR
program should be able to do so by acquiring NOX allowances
through the trading program. In essence, the EPA reasoned that, where a
trading program is a capped system, a new source's acquisition of
allowances to cover its increased emissions would necessarily
[[Page 57476]]
result in actual emissions reductions elsewhere in the system.
The EPA continues to believe that nonattainment NSR offset
requirements of the CAA can be met using the mechanism of the
NOX Budget Trading Program. However, there are a number of
complex issues involved with integrating these programs, for example,
the statutory requirements to obtain offsets from certain geographic
areas and, depending on the classification of the 1-hour ozone
nonattainment area, at certain offset ratios. Because the Agency is
continuing to evaluate these issues, it will not be providing guidance
at this time on integrating these programs; however, the EPA intends to
provide such guidance as soon as possible. At that time, the EPA will
respond to the comments received on this topic in the course of this
rulemaking.
VIII. Interaction With Title IV NOX Rule
The EPA proposed, in the May 11, 1998 supplemental notice, to add a
new Sec. 76.16 to part 76, the Acid Rain NOX Emission
Reduction Program regulations. The purpose of the proposed Sec. 76.16
was to increase utilities' flexibility in situations where units owned
or operated by a utility were subject to both a NOX cap-and-
trade program and the Phase II NOX emission limitations
under the Acid Rain NOX Emission Reduction Program. Under
proposed Sec. 76.16, a State or group of States could request that the
Administrator relieve all units located in the State or States and
otherwise subject to the Phase II NOX emission limitations
(under Secs. 76.6 and 76.7) of the requirement to comply with such
emission limitations. The Administrator could also take this action on
his or her own motion. All Group 1 boilers (i.e., tangentially fired or
dry bottom wall fired boilers) would remain subject to the Phase I
NOX emission limitations (under Sec. 76.5), while Group 2
boilers (i.e., cell burner boilers, cyclones, wet bottom boilers, and
vertically fired boilers) would have no NOX limits under the
Acid Rain Program. This relief would be available if all such units
were subject, under a SIP or a FIP, to a NOX cap-and-trade
program meeting certain requirements. The NOX cap-and-trade
program had to include, inter alia, either an annual cap or seasonal
caps that together limited total annual emissions and a requirement
that each unit use authorizations to emit (or allowances) to account
for all NOX emissions. In addition, there had to be a
demonstration that total annual NOX emissions from all units
otherwise subject to the Acid Rain NOX emission limitations
and located in the State or group of States would, under the
NOX cap-and-trade program, be equal to or lower than the
total number of annual NOX emissions if the units remained
subject to the Acid Rain NOX emission limitations.
Alternative emission limitations and NOX averaging plans
under part 76 would not be taken into account in such a demonstration.
Although the purpose of proposed Sec. 76.16 was to provide more
flexibility to utilities consistent with the requirements of section
407, almost all utility commenters and many State and State agency
commenters opposed the proposal. Many commenters argued that relieving
a utility's units in one State of the applicability of the Phase II
NOX emission limitation would prevent the utility from using
those units, along with units that the utility owns or operates in
other States, in an interstate averaging plan under the Acid Rain
Nitrogen Oxides Emission Reduction Program. Under section 407(e) of the
CAA, as implemented under Sec. 76.11, a utility may comply with the
Acid Rain NOX emission limitations by averaging the
emissions of units that the utility owns or operates in the same State
or other States. Many utilities have complied, or plan to comply, with
the Acid Rain NOX Emission Reduction Program by using
averaging plans, including some interstate averaging plans. However, a
unit that has no Acid Rain emission limitation obviously cannot be
included in an averaging plan since EPA would have no authority under
title IV to limit the unit's emissions, whether on an individual-unit
or a group-average basis. Further, as a practical matter, the group
average limit for any given year, which must be calculated based on the
limit applicable to each individual unit in the averaging plan, could
not reflect any limit for such a unit. See 40 CFR 76.11(a) (1) and (2)
(allowing only units with Acid Rain NOX emission limitations
in effect to participate in an averaging plan) and (d)(1)(ii)(A)
(showing calculation of the group average limit using each unit's Acid
Rain NOX emission limitation).
In the proposal, EPA attempted to address the issue of the
potential impact of proposed Sec. 76.16 on averaging plans. Proposed
Sec. 76.16(b)(1)(ii) required that, in determining whether a
NOX cap-and-trade program met the requirements for granting
units relief from the Phase II NOX emission limitations, the
Administrator must consider ``whether the cost savings from trading
will be offset by elimination of the ability of an owner or operator of
a unit in the State or the group of States to use a NOX
averaging plan under Sec. 76.11.'' 63 FR 25974. However, commenters
were still concerned that the Administrator could, even after taking
this into consideration, grant the relief over a utility's objections
and prevent the utility from using an averaging plan that included the
units for which the Administrator made the Phase II NOX
emission limitations inapplicable. In light of the utilities' concerns
that proposed Sec. 76.16 would actually reduce utilities' compliance
flexibility, albeit under title IV, and prevent the use of averaging
plans authorized under section 407(e), EPA has decided not to revise
part 76 as proposed and is not adopting proposed Sec. 76.16 as a final
rule.
Suggestions by some commenters that, instead of adopting proposed
Sec. 76.16, EPA extend the compliance date under the Acid Rain Program
for the Phase II NOX emission limitations are rejected as
outside the scope of this rulemaking. As acknowledged by commenters,
that issue was raised in the rulemaking adopting the Phase II
NOX emission limitations, and the compliance deadline of
January 1, 2000 set in that rulemaking was recently upheld by the
courts in Appalachian Power v. EPA, 135 F.3d 791 (D.C. Cir. 1998). The
SIP call rulemaking did not include any proposal to alter that date. On
the contrary, EPA stated in the SIP call:
Obviously, in proposing a new 40 CFR 76.16, EPA is not requesting
comment on any aspect of the December 19, 1996 final rule [i.e., the
rule that set the Phase II NOX emission limitations and that
included an earlier, proposed version of Sec. 76.16], including any
issues addressed by the Court in Appalachian Power. 63 FR 25951.
Similarly, commenters' suggestions concerning other revisions to
the Acid Rain NOX Emission Reduction Program regulations
(e.g., revisions to change the averaging provisions in the Acid Rain
regulations to allow averaging among units that lack common owners or
operators) are rejected as outside the scope of this rulemaking.
IX. Non-Ozone Benefits of NOX Emissions Decreases
A. Summary of Comments
One commenter suggested that drinking water nitrate is not affected
by atmospheric emissions and that the impacts of eutrophication are
unknown, although no evidence was presented. Another commenter stated
that EPA should estimate in the RIA the benefits of the SIP call with
respect to the non-ozone impacts. One comment was received stating that
EPA should not consider non-ozone benefits as
[[Page 57477]]
justification for the proposed emission reductions.
B. Response to Comments and Conclusion
1. Drinking Water Nitrate
There is no disagreement that high levels of nitrate in drinking
water is a health hazard, especially for infants. The contribution of
atmospheric nitrogen (N) deposition to elevated levels of nitrate in
drinking water supplies can be described as an evolving impact area.
The Ecological Society of America has included discussion of this
impact in a recent major review of causes and consequences of human
alteration of the global N cycle in its Issues in Ecology series
(Vitousek, Peter M., John Aber, Robert W. Howarth, Gene E. Likens, et
al. 1997. Human Alteration of the Global Nitrogen Cycle: Causes and
Consequences. Issues in Ecology. Published by Ecological Society of
America, Number 1, Spring 1997). For decades, N concentrations in major
rivers and drinking water supplies have been monitored in the United
States, Europe, and other developed regions of the world. Analysis of
these data confirms a substantial rise of N levels in surface waters,
which are highly correlated with human-generated inputs of N to their
watersheds. These N inputs are dominated by fertilizers and atmospheric
deposition.
Increases in atmospheric N deposition to sensitive forested
watersheds approaching N saturation would be expected to result in
increased nitrate concentrations in stream water. This phenomenon has
been documented in the Los Angeles, California area and has been well-
established for areas in Germany and the Netherlands (Riggan, P.J.,
R.N. Lockwood, and E.N. Lopez, ``Deposition and Processing of Airborne
Nitrogen Pollutants in Mediterranean-Type Ecosystems of Southern
California'' Environmental Science and Technology, vol. 19, 1985).
Stream water nitrate concentrations in watersheds subject to chronic
air pollution in the Los Angeles area were two to three orders of
magnitude greater than in chaparral regions outside the air basin.
2. Eutrophication
The EPA believes that the eutrophication problem associated with
atmospheric nitrogen deposition is well established. The National
Research Council recently identified eutrophication as the most serious
pollution problem facing the estuarine waters of the United States
(NRC, 1993). NOX emissions contribute directly to the
widespread accelerated eutrophication of United States coastal waters
and estuaries. Atmospheric nitrogen deposition onto surface waters and
deposition to watershed and subsequent transport into the tidal waters
has been documented to contribute from 12 to 44 percent of the total
nitrogen loadings to United States coastal water bodies. Nitrogen is
the nutrient limiting growth of algae in most coastal waters and
estuaries. Thus, addition of nitrogen results in accelerated algae and
aquatic plant growth causing adverse ecological effects and economic
impacts that range from nuisance algal blooms to oxygen depletion and
fish kills.
3. Regulatory Impact Analysis
The EPA believes it is important to note the potential impacts of
the rulemaking, including the substantial benefits to the environment
of several non-ozone impacts. As described in the November 7 proposal,
in addition to contributing to attainment of the ozone NAAQS, decreases
of NOX emissions will also likely help improve the
environment in several important ways: (1) On a national scale,
decreases in NOX emissions will also decrease acid
deposition, nitrates in drinking water, excessive nitrogen loadings to
aquatic and terrestrial ecosystems, and ambient concentrations of
nitrogen dioxide, particulate matter and toxics; and (2), on a global
scale, decreases in NOX emissions will, to some degree,
reduce greenhouse gases and stratospheric ozone depletion. These
benefits were also specifically recognized by OTAG, which in its July
8, 1997 final recommendations, stated that it ``recognizes that
NOX controls for ozone reductions purposes have collateral
public health and environmental benefits, including reductions in acid
deposition, eutrophication, nitrification, fine particle pollution, and
regional haze.'' However, the benefits of some of these impacts are
very difficult to estimate. Where possible, EPA provides estimates of
the impacts of the rulemaking--both ozone and non-ozone--in the RIA.
4. Justification for Rulemaking
While EPA believes this information is important for the public to
understand and, thus, needs to be described as part of the rulemaking
and RIA, there should be no misunderstanding as to the legal basis for
the rulemaking, which is described in Section I, Background, of this
notice and does not depend on the non-ozone benefits. The non-ozone
benefits did not affect the method in which EPA determined significant
contribution nor the calculation of the emissions budgets.
X. Administrative Requirements
A. Executive Order 12866: Regulatory Impacts Analysis
Under Executive Order 12866 (58 FR 51735, October 4, 1993), the
Agency must determine whether a regulatory action is ``significant''
and therefore subject to Office of Management and Budget (OMB) review
and the requirements of the Executive Order. The Order defines
``significant regulatory action'' as one that is likely to result in a
rule that may:
1. Have an annual effect on the economy of $100 million or more or
adversely affect in a material way the economy, a sector of the
economy, productivity, competition, jobs, the environment, public
health or safety, or State, local, or tribal governments or
communities;
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.
In view of its important policy implications and potential effect
on the economy of over $100 million, this action has been judged to be
a ``significant regulatory action'' within the meaning of the Executive
Order. As a result, the final rulemaking was submitted to OMB for
review, and EPA has prepared a Regulatory Impact Analysis (RIA)
entitled ``Regulatory Impact Analysis for the Regional NOX
SIP Call (September 1998).''
This RIA assesses the costs, benefits, and economic impacts
associated with potential State implementation strategies for complying
with this rulemaking. Any written comments from OMB to EPA and any
written EPA response to those comments are included in the docket. The
docket is available for public inspection at the EPA's Air Docket
Section, which is listed in the ADDRESSES Section of this preamble. The
RIA is available in hard copy by contacting the EPA Library at the
address under ``Availability of Related Information'' and in electronic
form as discussed above under ``Availability of Related Information.''
The RIA attempts to simulate a possible set of State implementation
strategies and estimates the costs and benefits associated with that
set of
[[Page 57478]]
strategies. The RIA concludes that the national annual cost of possible
State actions to comply with the SIP call are approximately $1.7
billion (1990 dollars). The associated benefits, in terms of
improvements in health, crop yields, visibility, and ecosystem
protection, that EPA has quantified and monetized range from $1.1
billion to $4.2 billion. Due to practical analytical limitations, the
EPA is not able to quantify and/or monetize all potential benefits of
this action.
B. Regulatory Flexibility Act: Small Entity Impacts
The Regulatory Flexibility Act (5 U.S.C. 601 et seq.) (RFA), as
amended by the Small Business Regulatory Enforcement Fairness Act (Pub.
L. No. 104-121) (SBREFA), provides that whenever an agency is required
to publish a general notice of proposed rulemaking, it must prepare and
make available an initial regulatory flexibility analysis, unless it
certifies that the proposed rule, if promulgated, will not have ``a
significant economic impact on a substantial number of small
entities.'' 5 U.S.C. 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, Motor and Equip. Mfrs.
Ass'n v. Nichols, 142 F.3d 449 (D.C. Cir. 1998); United Distribution
Cos. v. FERC, 88 F.3d 1105, 1170 (D.C. Cir. 1996); Mid-Tex Elec. Co-op,
Inc. v. FERC, 773 F.2d 327, 342 (D.C. Cir. 1985) (agency's
certification need only consider the rule's impact on entities subject
to the rule).
The NOX SIP Call would not establish requirements
applicable to small entities. Instead, it would require States to
develop, adopt, and submit SIP revisions that would achieve the
necessary NOX emissions reductions, and would leave to the
States the task of determining how to obtain those reductions,
including which entities to regulate. Moreover, 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 predict the effect of the rule on small entities.
For these reasons, EPA appropriately certified that the rule would
not have a significant impact on a substantial number of small
entities. Accordingly, the Agency did not prepare an initial RFA for
the proposed rule.
For the final rule, EPA is confirming its initial certification.
However, the Agency did conduct a more general analysis of the
potential impact on small entities of possible State implementation
strategies. This analysis is documented in the RIA. The EPA did receive
comments regarding the impact on small entities. These comments will be
addressed in the Response to Comment document.
This final rule will not have a significant impact on a substantial
number of small entities because the rule does not establish
requirements applicable to small entities. Therefore, I certify that
this action will not have a significant impact on a substantial number
of small entities.
C. Unfunded Mandates Reform Act
Title II of the Unfunded Mandates Reform Act of 1995 (Pub. L. 104-
4) (UMRA), 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.
The EPA has prepared a written statement consistent with the
requirements of section 202 of the UMRA and placed that statement in
the docket for this rulemaking. Furthermore, as EPA stated in the
proposal, EPA is not directly establishing any regulatory requirements
that may significantly or uniquely affect small governments, including
tribal governments. Thus, EPA is not obligated to develop under section
203 of the UMRA a small government agency plan. Furthermore, as
described in the proposal, in a manner consistent with the
intergovernmental consultation provisions of section 204 of the UMRA
and Executive Order 12875, EPA carried out consultations with the
governmental entities affected by this rule. Finally, the written
statement placed in the docket also contains a discussion consistent
with the requirements of section 205 of the UMRA.
For several reasons, however, EPA is not reaching a final
conclusion as to the applicability of the requirements of UMRA to this
rulemaking action. First, it is questionable whether a requirement to
submit a SIP revision would constitute a federal mandate in any case.
The obligation for a state to revise its SIP that arises out of
sections 110(a) and 110(k)(5) of the CAA is not legally enforceable by
a court of law, and at most is a condition for continued receipt of
highway funds. Therefore, it is possible to view an action requiring
such a submittal as not creating any enforceable duty within the
meaning of section 421(5)(9a)(I) of UMRA (2 U.S.C. 658 (a)(I)). Even if
it did, the duty could be viewed as falling within the exception for a
condition of Federal assistance under section 421(5)(a)(i)(I) of UMRA
(2 U.S.C. 658(5)(a)(i)(I)).
As noted earlier, however, notwithstanding these issues EPA has
prepared the statement that would be required by UMRA if its statutory
provisions applied and has consulted with governmental entities as
would be required by UMRA. Consequently, it is not necessary for EPA to
reach a conclusion as to the applicability of the UMRA requirements.
The analysis assumes that states would adopt the control strategies
that EPA assumed in its analyses underlying this action. The EPA
further notes that in two related proposals also signed today--one
concerning federal implementation plans if States do not comply with
the SIP call and one concerning the petitions submitted to the Agency
under section 126 of the CAA--EPA is taking the position that the
requirements of UMRA apply because both of those actions could result
in the establishment of enforceable mandates directly applicable to
sources (including sources owned by state and local governments).
D. Paperwork Reduction Act
The information collection requirements in this rule have been
submitted for approval to the Office of
[[Page 57479]]
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. 1857.02) and a copy may be obtained
from Sandy Farmer by mail at Regulatory Information Division; U.S.
Environmental Protection Agency (2137); 401 M St., SW., Washington, DC
20460, by email at farmer.sandy@epa.gov, or by calling (202) 260-2740.
A copy may also be downloaded from the internet at http://www.epa.gov/
icr. The information requirements are not effective until OMB approves
them.
The EPA believes that it is essential that compliance with the
regional control strategy be verified. Tracking emissions is the
principal mechanism to ensure compliance with the budget and to assure
the downwind affected States and EPA that the ozone transport problem
is being mitigated. If tracking and periodic reports indicate that a
State is not implementing all of its NOX control measures
beginning with the compliance date for NOX controls or is
off track to meet its statewide budget by September 30, 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 reporting requirements resides in section 110(a) and 301(a) of
the CAA. Emissions data being requested in today's rule is not be
considered confidential by EPA. Certain process data may be identified
as sensitive by a State and are then treated as ``State-sensitive'' by
EPA.
The reporting and record keeping burden for this collection of
information is described below:
Respondents/Affected Entities: States, along with the District of
Columbia, which are included in the NOX SIP call.
Number of Respondents: 23.
Frequency of Response: annually, triennially.
Estimated Annual Hour Burden per Respondent: 269.
Estimated Annual Cost per Respondent: $7,140.00.
Estimated Total Annual Hour Burden: 6,197.
Estimated Total Annualized Cost: $164,190.00.
There are no additional capital or operating and maintenance costs
for the States, along with the District of Columbia, associated with
the reporting requirements of this 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, Office of Policy,
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 November 27, 1998. Include
the ICR number in any correspondence.
E. Executive Order 13045: Protection of Children From Environmental
Health Risks and Safety Risks
1. Applicability of E.O. 13045
The Executive Order 13045 applies to any rule that EPA determines
(1) ``economically significant'' as defined under Executive Order
12866, and (2) the environmental health or safety risk addressed by the
rule has a disproportionate effect on children. If the regulatory
action meets both criteria, the Agency must evaluate the environmental
health or safety effects of the planned rule on children; and explain
why the planned regulation is preferable to other potentially effective
and reasonably feasible alternatives considered by the Agency. This
proposed rule is not subject to E.O. 13045, entitled ``Protection of
Children from Environmental Health Risks and Safety Risks (62 FR 19885,
April 23, 1997), because it does not involve decisions on environmental
health risks or safety risks that may disproportionately affect
children.
2. Children's Health Protection
In accordance with section 5(501), the Agency has evaluated the
environmental health or safety effects of the rule on children, and
found that the rule does not separately address any age groups.
However, the Agency has conducted a general analysis of the potential
changes in ozone and particulate matter levels experienced by children
as a result of the NOX SIP call; these findings are
presented in the Regulatory Impact Analysis. The findings include
population-weighted exposure characterizations for projected 2007 ozone
and PM concentrations. The population includes a census-derived
subdivision for the under 18 group.
F. Executive Order 12898: Environmental Justice
Executive Order 12898 requires that each Federal agency make
achieving environmental justice part of its mission by identifying and
addressing, as appropriate, disproportionately high and adverse human
health or environmental effects of its programs, policies, and
activities on minorities and low-income populations. The Agency has
conducted a general analysis of the potential changes in ozone and
particulate matter levels that may be experienced by minority and low-
income populations as a result of the NOX SIP call; these
findings are presented in the Regulatory Impact Analysis. The findings
include population-weighted exposure characterizations for projected
ozone concentrations and PM concentrations. The population includes
census-derived subdivisions for whites and non-whites, and for low-
income groups.
G. Executive Order 12875: Enhancing the Intergovernmental Partnerships
Under Executive Order 12875, EPA may not issue a regulation that is
not required by statute and that creates a mandate upon a State, local
or tribal government, unless the Federal
[[Page 57480]]
government provides the funds necessary to pay the direct compliance
costs incurred by those governments. If the mandate is unfunded, EPA
must provide to the Office of Management and Budget a description of
the extent of EPA's prior consultation with representatives of affected
State, local and tribal governments, the nature of their concerns,
copies of any written communications from the governments, and a
statement supporting the need to issue the regulation. In addition,
Executive Order 12875 requires EPA to develop an effective process
permitting elected officials and other representatives of State, local
and tribal governments ``to provide meaningful and timely input in the
development of regulatory proposals containing significant unfunded
mandates.''
Today's rule does not create a mandate on State, local or tribal
governments. As explained in the discussion of UMRA (Section X.C), this
rule does not impose an enforceable duty on these entities.
Accordingly, the requirements of section 1(a) of Executive Order 12875
do not apply to this rule.
H. Executive Order 13084: Consultation and Coordination With Indian
Tribal Governments
Under Executive Order 13084, EPA may not issue a regulation that is
not required by statute, that significantly or uniquely affects the
communities of Indian tribal governments, and that imposes substantial
direct compliance costs on those communities, unless the government
provides the funds necessary to pay the direct compliance costs
incurred by the tribal governments. If the mandate is unfunded, EPA
must provide to the Office of Management and Budget, in a separately
identified section of the preamble to the rule, a description of the
extent of EPA's prior consultation with representatives of affected
tribal governments, a summary of the nature of their concerns, and a
statement supporting the need to issue the regulation. In addition,
Executive Order 13084 requires EPA to develop an effective process
permitting elected and other representatives of Indian tribal
governments ``to provide meaningful and timely input in the development
of regulatory policies on matters that significantly or uniquely affect
their communities.''
Today's rule does not significantly or uniquely affect the
communities of Indian tribal governments. The rule applies only to
certain States, and does not require Indian tribal governments to take
any action. Moreover, EPA does not, by today's rule, call on States to
regulate NOX sources located on tribal lands. Accordingly,
the requirements of section 3(b) of Executive Order 13084 do not apply
to this rule.
The only circumstance in which the rule might even indirectly
affect sources on tribal lands would be if the budget set for one or
more of the 23 jurisdictions reflects assumed emissions reductions from
NOX sources on tribal lands located within the exterior
boundaries of those States. The EPA is not aware of any such sources.
However, to address the possibility that one or more of the State
budgets reflects reductions from such sources, and because any such
State generally would not have jurisdiction over such sources (see
EPA's rule promulgated under CAA section 301(d), 63 FR 7254, February
12, 1998), EPA will consider any request to revise as appropriate the
budget and base year 2007 emissions inventory for such a State, based
on a demonstration that the State does not have authority to regulate
those sources.
I. Judicial Review
Section 307(b)(1) of the CAA indicates which Federal Courts of
Appeal have venue for petitions of review of final actions by EPA. This
Section provides, in part, that petitions for review must be filed in
the Court of Appeals for the District of Columbia Circuit if (i) the
agency action consists of ``nationally applicable regulations
promulgated, or final action taken, by the Administrator,'' or (ii)
such action is locally or regionally applicable, if ``such action is
based on a determination of nationwide scope or effect and if in taking
such action the Administrator finds and publishes that such action is
based on such a determination.''
Any final action related to the NOX SIP call is
``nationally applicable'' within the meaning of section 307(b)(1). As
an initial matter, through this rule, EPA interprets section 110 of the
CAA in a way that could affect future actions regulating the transport
of pollutants. In addition, the NOX SIP call, as proposed,
would require 22 States and the District of Columbia to decrease
emissions of NOX. The NOX 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 NOX SIP call. Finally, EPA has established
uniform approvability criteria that would be applied to all States
subject to the NOX SIP call. For these reasons, the
Administrator also is determining that any final action regarding the
NOX SIP call is of nationwide scope and effect for purposes
of section 307(b)(1). Thus, any petitions for review of final actions
regarding the NOX 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 published in the Federal Register.
J. Congressional Review Act
The Congressional Review Act, 5 U.S.C. 801 et seq., as added by the
Small Business Regulatory Enforcement Fairness Act of 1996, generally
provides that before a rule may take effect, the agency promulgating
the rule must submit a rule report, which includes a copy of the rule,
to each House of the Congress and to the Comptroller General of the
United States. The EPA will submit a report containing this rule and
other required information to the U.S. Senate, the U.S. House of
Representatives, and the Comptroller General of the United States prior
to publication of the rule in the Federal Register. A ``major rule''
cannot take effect until 60 days after it is published in the Federal
Register. This action is a ``major rule'' as defined by 5 U.S.C.
Sec. 804(2). This rule will be effective December 28, 1998.
K. National Technology Transfer and Advancement Act
Section 12(d) of the National Technology Transfer and Advancement
Act of 1995 (NTTAA), Pub. L. No. 104-113, section 12(d) (15 U.S.C. 272
note) directs EPA to use voluntary consensus standards in its
regulatory activities unless to do so would be inconsistent with
applicable law or otherwise impractical. Voluntary consensus standards
are technical standards (e.g., materials specifications, test methods,
sampling procedures, and business practices) that are developed or
adopted by voluntary consensus standards bodies. The NTTAA directs EPA
to provide Congress, through OMB, explanations when the Agency decides
not to use available and applicable voluntary consensus standards.
This final rulemaking sets forth a model trading program including
environmental monitoring and measurement provisions that States are
encouraged to adopt as part of their SIPs. If States adopt those
provisions, sources that participate in the trading program would be
required to meet the applicable monitoring requirements of part 75. In
addition, this final rulemaking requires States that choose to regulate
certain large stationary sources to meet the requirements of the SIP
call to use part 75 to ensure compliance with their regulations. Part
75 already incorporates a number of voluntary consensus standards. In
[[Page 57481]]
addition, EPA's proposed revisions to part 75 proposed to add two more
voluntary consensus standards to the rule (see 63 FR at 28116-17,
discussing ASTM D5373-93 ``Standard Methods for Instrumental
Determination of Carbon, Hydrogen and Nitrogen in laboratory samples of
Coal and Coke,'' and API Section 2 ``Conventional Pipe Provers'' from
Chapter 4 of the Manual for Petroleum Measurement Standards, October
1988 edition). The EPA's proposed revisions to part 75 also requested
comments on the inclusion of additional voluntary consensus standards.
The EPA is finalizing some revisions to part 75 now, including the
incorporation of two voluntary consensus standards, in response to
comments submitted on the proposed part 75 rulemaking:
(1) American Petroleum Institute (API) Petroleum Measurement
Standards, Chapter 3, Tank Gauging: Section 1A, Standard Practice for
the Manual Gauging of Petroleum and Petroleum Products, December 1994;
Section 1B, Standard Practice for Level Measurement of Liquid
Hydrocarbons in Stationary Tanks by Automatic Tank Gauging, April 1992
(reaffirmed January 1997); Section 2, Standard Practice for Gauging
Petroleum and Petroleum Products in Tank Cars, September 1995; Section
3, Standard Practice for Level Measurement of Liquid Hydrocarbons in
Stationary Pressurized Storage Tanks by Automatic Tank Gauging, June
1996; Section 4, Standard Practice for Level Measurement of Liquid
Hydrocarbons on Marine Vessels by Automatic Tank Gauging, April 1995;
and Section 5, Standard Practice for Level Measurement of Light
Hydrocarbon Liquids Onboard Marine Vessels by Automatic Tank Gauging,
March 1997; for Sec. 75.19 and,
(2) Shop Testing of Automatic Liquid Level Gages, Bulletin 2509 B,
December 1961 (Reaffirmed October 1992), for Sec. 75.19.
These materials are available for purchase from the following
address: American Petroleum Institute, Publications Department, 1220 L
Street NW, Washington, DC 20005-4070.
These standards are used to quantify fuel use from units that have
low emissions of NOX and SOX.
The EPA intends to finalize other revisions to part 75 in the near
future and address comments related to the proposed voluntary consensus
standards and to additional voluntary consensus standards at that time.
Consistent with the Agency's Performance Based Measurement System,
part 75 sets forth performance criteria that allow the use of
alternative methods to the ones set forth in part 75. The PBMS approach
is intended to be more flexible and cost effective for the regulated
community; it is also intended to encourage innovation in analytical
technology and improved data quality. The EPA is not precluding the use
of any method, whether it constitutes a voluntary consensus standard or
not, as long as it meets the performance criteria specified, however
any alternative methods must be approved in advance before they may be
used under part 75.
List of Subjects
40 CFR Part 51
Air pollution control, Administrative practice and procedure,
Carbon monoxide, Environmental protection, Intergovernmental relations,
Nitrogen dioxide, Ozone, Particulate matter, Reporting and
recordkeeping requirements, Sulfur oxides, Transportation, Volatile
organic compounds.
40 CFR Parts 72 and 75
Air pollution control, Carbon dioxide, Continuous emissions
monitors, Electric utilities, Environmental protection, Incorporation
by reference, Nitrogen oxides, Reporting and recordkeeping
requirements, Sulfur dioxide.
40 CFR Part 96
Environmental protection, Administrative practice and procedure,
Air pollution control, Nitrogen dioxide, Reporting and recordkeeping
requirements.
Dated: September 24, 1998.
Carol M. Browner,
Administrator.
Appendix A to the Preamble--Detailed Discussion of Changes to Part
75
The following discussion addresses the comments received both on
the SNPR (68 FR 25902) and the proposed part 75 revisions (68 FR 28032)
that relate to the monitoring of NOX mass emissions. In
addition, it addresses the comments received on the excepted monitoring
methodology for low mass emitting units that would apply to both units
affected by title IV of the CAA and to units affected by a State or
Federal NOX mass reduction program that adopted or
incorporated the requirements of this part.
I. NOX Mass Monitoring and Reporting Provisions
Commenters raised four main issues with the proposed NOX
mass monitoring and reporting provisions in subpart H. The first issue
has to do with the appropriate monitoring requirements necessary to
support a NOX mass monitoring program, particularly in light
of the fact that many of the units that would be subject to a program
based on Part 96 are not currently monitoring NOX mass
emissions. The second has to do with using a NOX
concentration CEMS and a flow CEMS to calculate NOX mass.
The third has to do with the requirement to report NOX mass
emissions year round even though the ozone season is only 5 months
long. The final issue has to do with the requirement to have petitions
for alternatives to part 75 be approved by both the state permitting
authority and by EPA.
A. Background on Use of Part 75 to Monitor and Report NOX
Mass Emissions
Subpart H of the proposed part 75 rule set forth general monitoring
and reporting requirements that sources subject to a State or Federal
NOX mass emission reduction program could incorporate or
adopt into that program. Several commenters argued that it was
inappropriate to require sources, who were not already required to meet
the requirements of part 75, to meet those requirements for purposes of
a state program.
Commenters who suggested that it was inappropriate to require a
source that is not already subject to part 75 to meet the requirements
of part 75 for purposes of a state program suggested that the State
should decide what requirements the source needs to meet. The EPA
agrees that this would be appropriate in the case of a program that
only affected that state. For instance, if a State was developing a
NOX reduction program to address its own non-attainment
problem, it would not be necessary to adopt requirements that were
consistent across a larger geographic area. However, in a multi-state
program, particularly a multi-state trading program which engages in
interstate commerce like the one set forth in part 96, EPA believes it
is necessary to account for emissions in a consistent manner across the
whole region. This ensures that all sources that participate in the
trading program account for their emissions in a consistent manner,
ensuring both integrity in the trading program and a level playing
field for all program participants. Therefore, EPA believes that it is
necessary to create one set of consistent monitoring and reporting
requirements that can be used for such a program. This is consistent
with the way the Act mandated that a multi-state trading program be
implemented under Title IV. It is also consistent with the
[[Page 57482]]
approach taken in implementing other emissions standards, such as the
new source performance standards that affect many states. This approach
also makes it easier for states designing their programs since they
would not have to reinvent the monitoring requirements in each case.
Commenters who suggested that part 75 did not provide enough
flexibility focused on three areas: they suggested that other programs
such as RECLAIM or the OTC trading program provided more flexible non-
CEMS options for units that operated infrequently or had low
NOX mass emissions; they suggested that sources should be
allowed to use predictive emissions monitoring systems (PEMS); and they
suggested that sources should be allowed to use coal sampling and
weighting to determine heat input.
The EPA believes that the flexibilities offered by part 75 are
consistent with the type of flexibilities offered in RECLAIM and the
OTC Program. RECLAIM requires CEMS on all units that emit more than 10
tons of any individual pollutant per year. The OTC Program requires
CEMS on all units that do not qualify as peaking units that are larger
than 250 mmBtu or serve generators greater than 25 MWs. Subpart H of
part 75 allows non-CEMS alternatives for units that have emissions less
than 50 tons per year of NOX. If a unit is not required to
report SO2 and CO2 for Acid Rain compliance, then
the unit may use the low mass emissions provisions of Part 75 if its
NOX emissions are less than 50 tons per year. Part 75 also
allows non-CEMS alternatives for units that qualify as peaking units.
In both the OTC Program and part 75, a peaking unit is defined as a
unit that has a capacity factor of no more than 10 percent per year
averaged over a three year period and no more than 20 percent in any
one year. The EPA believes that these options provide cost effective
monitoring methodologies for small or infrequently used units.
While commenters who supported the use of PEMS and the use of coal
sampling and weighting asserted that these methodologies would provide
data equivalent to that provided by the methodologies in Part 75, none
of the commenters provided any data to justify this claim. Therefore
EPA is not adding specific requirements that would allow either of
these methodologies. It should be noted that subpart E of part 75 does
provide a means for a source to demonstrate that an alternative
methodology such as PEMS or coal sampling and weighting is equivalent
to CEMS. Subpart E of part 75 is consistent with Performance Based
Measurement Systems criteria. Any source wishing to use an alterative
methodology may petition the agency under subpart E of part 75.
B. Background on Use of a NOX Concentration CEMS and a Flow
CEMS to Calculate NOX Mass
Subpart H of the proposed part 75 rule called for sources in the
NOX Budget Program to monitor NOX emission rate
in lb/mmBtu using a NOX concentration monitor and a diluent
monitor, and then to multiply this by heat input, calculated using a
flow monitor and a diluent monitor. Under this proposal, sources would
then calculate NOX mass emissions by multiplying the hourly
NOX emission rate by the hourly heat input to obtain the
pounds of NOX emitted during the hour. The EPA also
requested comment on whether it would be appropriate for sources in the
NOX Budget Program to use the NOX concentration
monitor and flow monitor without a diluent monitor to calculate
NOX mass emissions. This is analogous to the Acid Rain
Program's current approach to monitoring SO2 mass emissions.
Commenters recommended that the Agency require sources to determine
NOX mass emissions from pollutant concentration and stack
gas volumetric flow. The commenters stated that this approach would be
more accurate, more familiar to sources, and more consistent with the
SO2 mass emissions monitoring in the existing part 75.
The Agency agrees that using NOX pollutant concentration
and volumetric flow is an appropriate method for monitoring
NOX mass emissions. Today's final rule includes provisions
in Subpart H and Section 8 of Appendix F of part 75 to allow sources to
choose one of several options for monitoring and calculating
NOX mass emissions. Sources may monitor NOX mass
emissions by using either:
All Units
A NOX pollutant concentration monitor and a
volumetric flow monitor, or a NOX concentration monitor and
a diluent monitor to calculate NOX emission rate in lb/
mmBtu, and a flow monitor and a diluent monitor to calculate heat
input; or
A NOX concentration monitor and a diluent
monitor to calculate NOX emission rate in lb/mmBtu, and a
fuel flow meter and oil or gas sampling and analysis to calculate heat
input; or
Oil/Natural Gas Fired Units
Peaking units may use NOX to load correlation
procedures from Appendix E of part 75 for NOX emission rate,
and a fuel flow meter and oil or gas sampling and analysis to calculate
heat input; or
Units with less than 50 tons of Nox and 25 tons of
SO2 may use emission rates multiplied by either the maximum
rated heat input capacity of the unit or by the actual heat input of
the unit which may be determined on a longer term basis than a single
hour.
The EPA decided to allow sources several options so that they could
use monitoring equipment that is already installed under part 75 to the
greatest extent possible.
In implementing these options, a source would need to designate a
primary approach to calculating NOX mass emissions. For
example, the designated representative of a coal-fired unit could
choose to designate a primary monitoring approach under Option 1
(pollutant concentration monitor and diluent monitor, and diluent
monitor and flow monitor). The designated representative could then use
a (pollutant concentration monitor and flow monitor) as a backup
monitoring approach. This would be useful for periods when the diluent
monitor is not operating properly, where NOX emission rate
data in lb/mmBtu would not be available, but NOX mass
emission data in lb could still be available. The OTC NOX
Budget Program allows this approach (see docket A-97-35 item II-I-7).
In order to make monitoring as consistent as possible between the
first two approaches for monitoring NOX mass emissions using
continuous emission monitoring systems (CEMS), EPA is making additional
changes to part 75. First, the Agency is adding language in Section 8
of Appendix F that specifies the calculations for NOX mass
emissions using either approach. Second, EPA is requiring sources that
use a NOX pollutant concentration monitor and a flow monitor
as the primary method for calculating NOX mass emissions to
substitute for missing NOX pollutant concentration data
using the same missing data procedures as for NOX CEMS (lb/
mmBtu) under Secs. 75.31(c), 75.33(c) and Appendix C. Third, the Agency
is establishing a relative accuracy testing requirement for
NOX pollutant concentration monitors that are used to
calculate NOX mass emissions independently of a
NOX CEMS (lb/mmBtu). The NOX pollutant
concentration monitors will need to meet a relative accuracy of 10.0
percent to pass the relative accuracy test audit (RATA). They will need
to meet a relative accuracy of 7.5 percent to perform a RATA on an
annual basis instead of a semi-annual basis. Because the vast majority
of NOX CEMS (lb/
[[Page 57483]]
mmBtu) and SO2 pollutant concentration monitors routinely
meet a relative accuracy of 7.5 percent or less, the Agency concludes
that it will also be possible for a NOX pollutant
concentration monitor, which is part of a NOX CEMS, to meet
this standard. Fourth, EPA requires these sources to test their
NOX pollutant concentration monitor and flow monitor for
bias. If the monitor is found to be biased low, then the source must
either fix the monitor and retest it to show it is not biased, or apply
a bias adjustment factor to hourly data. These changes to part 75 make
monitoring consistent between the different monitoring approaches using
CEMS, prevent underestimation of emissions, preserve monitoring
accuracy, and take advantage of approaches already developed for other
monitoring systems that will be familiar to sources.
The EPA decided to allow sources to calculate NOX mass
emissions using NOX concentration and flow rate for several
reasons:
This approach would allow sources to remove bias due to
the diluent monitor from calculations of NOX mass emissions.
Sources affected by the NOX Budget Program, but
not by the Acid Rain Program, such as industrial boilers, may be able
to simplify their recordkeeping and reporting because they will not
need to calculate or report NOX emission rate in lb/mmBtu
for each hour for the trading program.
Sources will be able to maintain higher availability of
quality-assured NOX mass emission data, because they will
not need to substitute missing data for purposes of NOX mass
emissions when data are not available from the diluent monitor.
As the commenters suggested, this approach is more
analogous to monitoring for SO2 mass emissions in the Acid
Rain Program.
Because this approach is already allowed under the OTC
NOX Budget Program, EPA already has accounted for this
possibility in the electronic data reporting format and in its
computerized Emission Tracking System.
For these reasons, the Agency believes that it is appropriate to
allow sources the option of monitoring and calculating NOX
mass emissions using NOX pollutant concentration and flow
monitors.
Sources using this approach may still be required to install
maintain and operate a diluent monitor to calculate heat input if
required to do so by their state for purposes of obtaining data needed
to support allocation of NOX allowances.
C. Background on Year Round Reporting of NOX Mass Emissions
The proposal would have required all units to report NOX
mass emissions on an annual basis rather than on an ozone season basis.
One commenter noted that since the proposed SIP call would not require
emission reductions outside of the ozone season it is not necessary to
report NOX mass emissions outside of the ozone season. The
EPA agrees that solely for the purposes of an ozone program, it may not
be necessary to report NOX mass emissions outside of the
ozone season except if a source wants to qualify for the low mass
emissions provision. However the requirements of subpart H could be
used to support NOX mass emission reduction programs where
reductions would be required annually. In addition, the monitoring and
reporting requirements could be used to help consolidate other State or
Federal reporting that would be required on an annual basis. Therefore
in the final rule the requirements of subpart H have been modified so
that they no longer require annual reporting of NOX mass
emissions, but rather defer to the State or Federal rule that is
incorporating these requirements to define the applicable time period
for reporting.
In addition a new section has been added to subpart H that details
how the requirements of part 75, which are designed to be used
annually, should be used if monitoring and reporting is being done for
only part of the year.
Some of the most significant differences include:
Owners and operators of units using the fuel sampling
procedures in Appendix D must ensure that they have accurate fuel
sampling information at the beginning of the ozone season. This
requires either sampling the fuel tank itself before the start of the
ozone season or meeting the requirements to sample fuel deliveries on a
year round basis.
Historical lookback periods for missing data periods only
need to include data from the ozone season. However, if a monitor is
out of control at the beginning of the season, historical data from
seven months ago may represent significantly different operating
conditions (e.g. fuel burned or use of control equipment). Therefore
the AAR would have to certify that the operating conditions are
representative of the previous years operating conditions. If the
conditions are not representative, the standard missing data procedures
could not be used. In this case maximum potential NOX mass
emissions would have to be substituted.
The owner or operator of a unit must ensure that the
monitors used for monitoring and reporting are in control. Since CEMS
require ongoing quality assurance to ensure that they are operating
properly, owners and operators of units that do not meet this
requirement during the non-ozone season will have to recertify their
monitors before the start of the ozone season.
D. Background on Requiring EPA and the State Permitting Authority to
Approve Alternatives to Part 75
The proposal would have required owners and operators of units that
are not subject to the requirements of title IV of the CAA that wish to
petition for an alternative to any of the requirements of part 75 to
petition both the state permitting authority and the Administrator.
Several commenters suggested that approval of one or the other should
suffice. Some of the commenters also noted that the requirements were
different for units affected by title IV, who are only required to
petition the Administrator.
The EPA agrees that the requirements for units affected by title IV
and units not affected by title IV are inconsistent. Because of
different requirements of the Act this inconsistency is necessary. The
EPA has the sole authority to grant petitions to units affected by
title IV under Sec. 75.66 of part 75. If a State incorporates those
monitoring requirements into its State rules, this still does not give
it the authority to change or waive the monitoring requirements for a
unit subject to title IV. However, recognizing that granting a petition
affects the accounting of NOX mass emissions for a State
program, EPA does intend to work cooperatively with State agencies on
petition requests that could affect monitoring and reporting of
NOX mass emissions.
For sources not affected by title IV that are complying with the
requirements of subpart H because they have been adopted or
incorporated into a State SIP, neither EPA nor the State has sole
authority to approve a petition for an alternative. While the State
does have the authority to set forth specific monitoring and reporting
requirements in a SIP and submit those requirements for EPA approval, a
State does not have the discretion to modify the SIP by changing or
waiving those monitoring and reporting requirements without obtaining
EPA approval. Likewise, EPA does not have sole authority to revise a
SIP since the primary responsibility to develop and implement a SIP is
granted
[[Page 57484]]
to the States under the CAA. The EPA is however required by the CAA to
review and approve or disapprove SIP revisions. Since a petition to
change or waive unspecified requirements related to monitoring and
reporting can not be approved as part of the original SIP approval
process, EPA must be involved in any approvals of alternatives to the
SIP.
In addition to the title I requirements for EPA to be involved in
approval of petitions for alternatives to part 75, there are several
other reasons that EPA needs to be involved. The first is that since
EPA is administering the emissions data collection system under part
75, EPA must ensure that any changes to the reporting requirements can
be handled by the emissions tracking system that EPA maintains.
Secondly, in order to ensure the integrity of a multi-state market
based system and to ensure that participants in the system are treated
equitably, it is important to ensure that sources are treated equitably
from State to State. Therefore, if interstate trading is taking place
EPA clearly has a role in approving petitions for alternatives to
ensure that sources are treated consistently from state to state when
engaging in such interstate commerce.
II. Low Mass Emissions Excepted Monitoring Methodology
A. Background
In the January 11, 1993 Acid Rain permitting rule, EPA provided for
a conditional exemption from the emissions reduction, permitting, and
emissions monitoring requirements of the Acid Rain Program for new
units having a nameplate capacity of 25 MWe or less that burn fuels
with a sulfur content no greater than 0.05 percent by weight, because
of the de minimis nature of their potential SO2,
CO2 and NOX emissions (see 58 FR 3593-94 and
3645-46). Moreover, in the January 11, 1993 monitoring rule, EPA
allowed gas-fired and oil-fired peaking units to use the provisions of
Appendix E, instead of CEMS, to determine the NOX emission
rate, stating that this was a de minimis exception. The EPA allowed
this exception from the requirements of section 412 of the CAA because
the NOX emissions from these units would be extremely low,
both collectively and individually (see 58 FR 3644-45). One utility
wrote to the Agency, suggesting that the Agency consider further
regulatory relief for other units with extremely low emissions that do
not fall under the categories of small new units burning fuels with a
sulfur content less than or equal to 0.05 percent by weight or gas-
fired and oil-fired peaking units (see Docket A-97-35, Item II-D-31).
The utility specifically suggested that the Agency consider an
exemption, the ability to use Appendix E, or some other simplified
methods which are more cost effective.
In the process of implementing part 75, other utilities also have
suggested to EPA that it provide regulatory relief to low mass emitting
units (see Docket A-97-35, Items II-D-29, II-E-25). These units might
be low mass emitting because they use a clean fuel, such as natural
gas, and/or because they operate relatively infrequently. Some
utilities stated that they spend a great deal of time reviewing the
emissions data when preparing quarterly reports for these units. Others
argued that it would be important to reduce monitoring and quality
assurance (QA) requirements in order to save time and money currently
devoted to units with minimal emissions (see Docket A-97-35, Item II-E-
25).
In response to the requests for simplified monitoring and
recordkeeping requirements for units which both operate infrequently
and have low mass emissions on May 21, 1998 the Agency proposed, under
Sec. 75.19 of part 75, changes to the monitoring requirements that
would allow a new excepted methodology for low mass emission units. The
proposed low mass emissions methodology would have allowed units which
have emissions less than 25 tons of both NOX and
SO2 to use a methodology with reduced monitoring, reporting
and quality assurance requirements than the use of CEMS or either
appendix D or E methodologies. The methodology proposed used a unit's
maximum rated hourly heat input and generic defaults for
SO2, NOX and CO2 mass emissions. The
proposed methodology was a less accurate methodology for determining
emissions for SO2, NOX and CO2 but
would significantly reduce the burden on industry for these sources.
The allowance of this methodology was justified using the de minimis
individual and aggregate emissions represented by the units who would
qualify for the methodology.
While the proposed methodology did not contain an explicit cutoff
for CO2, EPA believes that the limited applicability of the
proposal ensured that emissions of CO2 from units that would
qualify to use the proposal was also de minimis. This is important,
because under section 821 of the Act, the agency is also required to
collect CO2 emissions data from sources subject to title IV.
This data is required to be collected ``in the same manner and to the
same extent'' as required under title IV.
The Agency solicited comments on both the proposed methodology for
determining emissions and the proposed applicability limits of 25 tons
for both NOX and SO2 as well as any other
comments related to the proposed low mass emission methodology. In
reviewing the comments submitted on the proposal, the Agency noted that
several commenters suggested the methodology was too restrictive and
would only allow reduced monitoring to a limited number of units. The
commenters suggested various methods for expanding applicability to the
low mass emission methodology the most common which are; (i) remove the
requirement for units to have both SO2 and NOX
emissions of less than 25 tons and instead to allow units to use the
methodology on a pollutant specific basis; (ii) increase the 25 ton
limit for NOX and SO2 to 50, 100 or 250 tons;
(iii) allow additional methods for calculating heat input; and (iv)
allow the use of unit-specific NOX emission rates. One other
significant comment was received which indicated that the default
values for NOX emission rate in table 1b of proposed
Sec. 75.19 (c) could significantly underestimate emissions from certain
types of units.
In response to the comments, which generally advocating the
applicability of the low mass emissions methodology to more units, the
Agency is adopting the proposed low mass emissions methodology with the
following changes: (1) the NOX applicability limit is being
raised to 50 tons which will increase the number of units that can use
the methodology; (2) units are being allowed an optional procedure for
heat input which will increase the number of units that can use the
methodology and provide more accurate emission estimates; (3) units are
being allowed to use unit-specific NOX emission rates
determined through testing which will allow increased applicability and
more accurate emissions estimates for NOX; and (4) the
values for NOX emission rate in table 1b of proposed 75.19
(c) are being changed to prevent underestimation of emissions using the
methodology.
B. Discussion of Low Mass Emissions Methodology
Today's new Low Mass Emissions methodology incorporates optional
reduced monitoring, quality assurance, and reporting requirements into
part 75 for units that burn only natural gas or fuel oil, emit no more
than 25 tons of SO2 and no more than 50 tons of
NOX annually, and have calculated annual
[[Page 57485]]
SO2 and NOX emissions that do not exceed such
limits. Units that are not subject to Title IV of the Act and that are
only subject to subpart H of part 75 are not required to meet the
SO2 limit to qualify to use the methodology. In addition, if
allowed by their State, they may qualify as low mass emission units
during the ozone season if they emit less than 25 tons of
NOX per ozone season.
A unit may initially qualify for the reduced requirements by
demonstrating to the Administrator's satisfaction that the unit meets
the applicability criteria in Sec. 75.19(a). Section 75.19(a) requires
facilities to submit historical actual (or projections, as described
below) and calculated emissions data from the previous three calendar
years demonstrating that a unit falls below the 25-ton cutoff for
SO2 and the 50 ton cutoff for NOX. The calculated
SO2 mass emissions data for the previous three calendar
years will be determined by choosing one of the two heat input options
in Sec. 75.19(c) and the appropriate emission rate from table 1a in
Sec. 75.19(c). The calculated NOX mass emissions data for
the previous three calendar years will be determined by choosing one of
the two heat input options in Sec. 75.19(c) and either the appropriate
emission rate from table 1b in Sec. 75.19(c) or a unit-specific
NOX emission rate as allowed under Sec. 75.19(c). The data
demonstrating that a unit meets the applicability requirements of
Sec. 75.19(a) will be submitted in a certification application for
approval by the Administrator to use the low mass emissions excepted
methodology.
For units that lack historical data for one or more of the previous
three calendar years (including new units that lack any historical
data), Sec. 75.19(a) will require the facility to provide (1) any
historical emissions and operating data, beginning with the unit's
first calendar year of commercial operation, that demonstrates that the
unit falls under the 25-ton cutoffs for SO2 and the 50 ton
cutoff for NOX, both with actual emissions and with
calculated emissions using the proposed methodology, as described
below; and (2) a demonstration satisfactory to the Administrator that
the unit will continue to emit below the tonnage cutoffs (e.g., for a
new unit, applying the applicable emission rates and applicable hourly
heat input, under Sec. 75.19(c), to a projection of annual operation
and fuel usage to determine the projected mass emissions).
For units with historical actual (or projections, as described
above) emissions and calculated emissions falling below the tonnage
cutoffs, facilities allowed to use the optional methodology in
Sec. 75.19(c) in lieu of either CEMS or, where applicable, in lieu of
the excepted methods under Appendix D, E, or G for the purpose of
determining and reporting heat input, NOX emission rate, and
NOX, SO2, and CO2 mass emissions. The
facility will no longer be required to keep monitoring equipment
installed on low mass emissions units, nor will it be required to meet
the quality assurance test requirements or QA/QC program requirements
of Appendix B to part 75. Moreover, emissions reporting requirements
will be reduced by requiring only that the facility report the unit's
hourly mass emissions of SO2, CO2, and
NOX, the fuel type(s) burned for each hour of operation, and
report the quarterly total and year-to-date cumulative mass emissions,
heat input, and operating time, in addition to the unit's quarterly
average and year-to-date average NOX emission rate for each
quarter. Owners and operators may also choose to report partial hour
operating time and use the operating time to obtain a more accurate
estimate of heat input determined using the maximum hourly heat input
option. For units which use the optional long term fuel flow
methodology for heat input the source will report hourly and cumulative
quarterly and yearly output in either megawatts electrical output or
thousands of pounds of steam. For units which use unit-specific
NOX emission rates determined through testing, reporting of
the Part 75 Appendix E test results will be required. For units that
have NOX controls, data demonstrating that these controls
are operating properly will have to be kept on site. Facilities will
continue to be required to monitor, record, and report opacity data for
oil-fired units, as specified under Secs. 75.14(a), 75.57(f), and
75.64(a)(iii) respectively. Under Sec. 75.14(c) and (d), however, gas-
fired, diesel-fired, and dual-fuel reciprocating engine units will
continue to be exempt from opacity monitoring requirements.
If an initially qualified unit subsequently burns fuel other than
natural gas or fuel oil, the unit will be disqualified from using the
reduced requirements starting the first date on which the fuel (other
than natural gas or fuel oil) burned.
In addition, if an initially qualified unit subsequently exceeds
the 25-ton cutoff for either SO2 or the 50 ton cutoff for
NOX while using the adopted methodology, the facility will
no longer be allowed to use the reduced requirements in Sec. 75.19(c)
for determining the affected unit's heat input, NOX emission
rate, or SO2, CO2, and NOX mass
emissions (unless at a future time the unit can again meet the
applicability requirements based on the recent three years of data).
Adopted Sec. 75.19(b) allows the facility two quarters from the end of
the quarter in which the exceedance of the relevant ton cutoff(s)
occurred to install, certify, and report SO2,
CO2, and NOX data from a monitoring system that
meets the requirements of Secs. 75.11, 75.12, and 75.13, respectively.
Under the low mass emission excepted methodologies in
Sec. 75.19(c), a facility will calculate and report hourly
SO2, NOX and CO2 mass emissions by
multiplying hourly unit heat input by an appropriate emission rate.
Unit heat input is determined using one of two heat input
methodologies, maximum rated hourly heat input or long term fuel flow;
unit SO2 and CO2 emission rates are determined
using generic defaults; and unit NOX emission rate is
determined using one of two methodologies, generic defaults or unit-
specific NOX emission rate testing.
Commenters raised three major issues, which have led EPA to modify
its proposal. The three major issues raised were: (i) Should the
proposed initial and ongoing applicability criteria of 25 tons of both
NOX and SO2 be modified; (ii) was the proposed
methodology for estimating emissions appropriate and, should other
options for calculating emissions be allowed; and (iii) what should the
reduced monitoring and quality assurance requirements be for these
units?
1. Applicability Criteria
a. Approach. Based on the rationale described in the preamble to
the May 12, 1998 proposal (63 FR 28037) and in the absence of
significant adverse comment, the Agency is using both actual and
calculated emissions as the basis for determining initial
applicability.
b. Cutoff Limit for Applicability. Several commenters requested
that the cutoff limit for applicability of the low mass emission
provision be increased. These comments fell into two broad categories:
(1) decouple the NOX and SO2 requirements and
allow units which qualify as a low mass emissions unit for only one
pollutant to monitor that pollutant using the low mass emissions
methodology (see Docket A-97-35, Items, IV-D-24, IV-D-11, IV-D-23, IV-
G-03, IV-D-20); and (2) raise the tonnage cutoff for NOX and
SO2 (see Docket A-97-35, Items, IV-G-03, IV-D-24, IV-D-22,
IV-D-23, IV-D-07, IV-G-02).
c. Determining the Criteria for Low Mass Emitters. Based on
comments received the Agency believes that the
[[Page 57486]]
low mass emission provision is appropriate for units which have low
mass emissions because: (i) a unit has a low capacity factor usage or
operates infrequently; or (ii) a unit has low mass emissions despite a
relatively high capacity factor due to the small size of the unit. For
these units, the cost of installing and maintaining CEMS would
represent a relatively large portion of the total value of the
electricity or steam produced by the unit. The Agency, also reasoned
that the types of units identified above can use the excepted
methodology without any significant risk to the environment or
impairment of the Agency's ability to meet its obligations under the
CAA.
The Agency also determined the types of units which were not
appropriate candidates for use of the low mass emissions excepted
methodology. In particular, the Agency has concerns about allowing
large numbers of controlled units to use an estimation methodology such
as the low mass emission methodology. Because many of these units have
low mass emissions not because they operate infrequently, but rather
because they have controls which reduce their emission rates, their
continued low mass emissions is dependent on continued proper operation
of the controls on the unit. The EPA believes that monitoring actual
emission rates is necessary to ensure that installed emission controls
are operating properly and that actual emissions remain low. On the
other hand, EPA believes that it is appropriate to allow small or
infrequently operated units with controls, such as peaking turbines
with water or fuel injection, to use the low mass emissions provision.
This is appropriate because as long as these units continue to limit
their operation, their potential to emit still remains low, even if
their controls are not working. Therefore, while EPA believes it is
appropriate to allow small infrequently operated units with controls
that have both low actual emissions and a low potential to emit (as
long as they continue to operate at low levels), EPA does not believe
that it is appropriate to allow controlled units that have large
potential to emit if their controls are not operating properly to use
this methodology.
The low mass emission excepted methodology is a new exception, in
addition to the exceptions in the existing rule, from the requirement
for a NOX CEMS. The determination of whether individual and
collective emissions covered by the exceptions from CEMS are de minimis
must include consideration of emissions from both new and existing
units that will qualify to use the new low mass emissions excepted
methodology and also new and existing units that will qualify to use
other exceptions from the NOX CEM requirement, i.e. units
using the existing appendix E excepted methodology and units with new
unit exemptions under Sec. 72.7.
The EPA has first considered the level of projected aggregate
emissions determined to be de minimis for purposes of developing the
new unit exemption promulgated in the January 11, 1993 Acid Rain
permitting rule (58 FR 3593-94 and 3645-46). Aggregate emissions
projected for units under the exemption were approximately 138
cumulative tons of SO2 and 1934 cumulative tons of
NOX emitted per year from an estimated 170 new units which
might qualify for the exception before the year 2000. As of September
of 1998, 278 exemptions have actually been granted under the new unit
exemption. The Agency estimates that the level of SO2 and
NOX mass emissions from these units is 226 tons of
NOX and 3163 tons of SO2. The Agency further
believes that this group of excepted units will continue to increase at
the current rate.
The EPA has also considered the level of emissions projected to be
covered by appendix E. The EPA, in the January 11, 1993 Acid Rain
monitoring rule, allowed gas-fired and oil-fired peaking units to use
the provisions of appendix E, instead of CEMS, to determine the
NOX emission rate. The Agency stated that, even though this
method was less accurate than CEMS, this was a de minimis exception
because emissions from all units that qualify to use the appendix E
reporting methodology were projected to be extremely low, the units did
not have a NOX compliance obligation, and the cost of
installing and operating CEMS for these units would be high (see 58 FR
3644-45). The preamble to the January 11, 1993 rule estimated the
emissions from oil and gas units which operated with a capacity factor
of less than 10 percent to be 40,000 tons of NOX per year.
The Agency has analyzed existing appendix E units to determine the
actual NOX mass emissions reported by these units in 1997.
This analysis indicates that in 1997 approximately 235 units used the
appendix E methodology and had total emissions of approximately 11,000
tons of NOX in 1997. (see Docket A-97-35, Items, IV-A-1).
The Agency has then considered what level of total NOX
emissions would be de minimis for all units that may be covered by de
minimis exceptions from the requirement to use CEMS i.e. all units
using the new unit exemption, appendix E, and the new low mass
emissions methodology. The Agency maintains that a de minimis level of
total NOX emissions should not be more than one percent of
the total NOX emission inventory currently or in the future
for all units. This approach is supported by the treatment of 40,000
tons of NOX as de minimis in the January 11, 1993 rule
preamble concerning appendix E, which is somewhat less than 1 percent
of the total NOX emissions estimated for 1993. However, the
40,000 tons of NOX determined to be de minimis emissions in
1993 is not an appropriate de minimis level with regard to current and
future levels of NOX emissions. Several factors have
increased the importance of monitoring lower levels of NOX
emissions including: (i) The new more stringent NAAQS for ozone
(NOX is an ozone precursor); (ii) title IV Phase II
NOX reductions which will reduce the total NOX
inventory; (iii) today's NOX SIP call which may result in
NOX compliance obligations for gas-and oil-fired units and
will reduce the NOX emission inventory; and (iv) State and
regional NOX reduction programs, such as the OTC program,
State RACT rules and the RECLAIM program in California, which result in
NOX compliance obligations for gas-and oil-fired units and
reduced NOX emission inventory. As a result, EPA views about
20,000 tons (close to 1 percent of projected NOX emission
inventory) as the de minimis level of NOX emissions for the
present and foreseeable future. Given that appendix E units and new
unit exemption units currently account for about 14,100 tons of
NOX there is not a large margin left for establishing
additional exception to the CEM requirements. The Agency has considered
potential future growth in the number of units using the new unit
exemption or appendix E in order to estimate what level of additional
NOX, SO2 and CO2 emissions might be
appropriate to allow under the low mass emissions methodology. Taking
account of the uncertainty inherent in such estimates EPA has set the
applicability criteria for the low mass emission methodology so that
the NOX emissions covered by the methodology plus future
growth in NOX emissions covered by the other current de
minimis exceptions (appendix E and the new unit exemption) will not
exceed 5000 tons of NOX per year in the future.
The Agency has analyzed SO2, NOX and
CO2 emissions and determined that, as long as the cutoffs
for NOX and SO2 are coupled so that a unit must
meet both the 50 tons of NOX and 25 tons of
[[Page 57487]]
SO2 limits, that SO2, NOX and
CO2 emissions under all exceptions from CEMS requirements
will remain de minimus. Additionally decoupling the NOX and
SO2 tons would allow only marginal simplification in
monitoring while significantly complicating the low mass emissions
methodology.
d. Determining the Tonnage Cutoffs for SO2 and
NOX. The Agency has conducted a study of actual emissions
data from 1997 quarterly reports under part 75 and evaluated potential
tonnage cutoffs for SOX and NOX (see Docket A-97-
35, Item IV-A-1). The analysis was based on the assumption that
reported 1997 emissions of NOX and SO2 will be
more representative of calculated emissions under the final low mass
emissions methodology than they would have been under the proposed
methodology. The assumption is considered valid because the final low
mass emissions methodology allows more accurate heat input
determination using long term fuel flow and the use of fuel and unit
specific NOX emission rates. These options allow more
accurate emissions estimates than the proposed methodology would have.
This differs from the analysis performed for the proposed low mass
emission methodology which calculated emissions based on operating
hours and maximum rated heat input.
Based on this analysis, EPA estimates that the existing Acid Rain
affected sources that would qualify for the low mass emissions excepted
methodology using a coupled 50 tons NOX and 25 tons
SO2 limit would represent aggregate emissions of
approximately 3100 tons of NOX and approximately 260 tons of
SO2 in 1997 from 224 units. The analysis indicates that the
applicability has been substantially increased in response to the
comments received.
For the proposed 25 ton NOX cutoff , which is the
limiting factor for applicability in nearly all instances, the Agency
has considered increasing the tons of NOX to 50 tons, 75
tons, 100 tons, and 250 tons as suggested by various commenters. In its
analysis, the Agency kept SO2 at 25 tons, as discussed
above.
The analysis showed that by increasing the NOX limit to
250 tons coupled to 25 tons of SO2, the aggregate tons of
NOX and SO2 emitted by units which could
currently qualify for the low mass emissions methodology increased to
approximately 23124 tons NOX and 4503 tons of
SO2; this is without considering potential future growth in
the number of units that could qualify to use this exemption.
Increasing the cutoff for NOX to 250 tons could also allow
many units with highly effective NOX controls to use the low
mass emissions provision. As explained previously, units with effective
NOX controls and high operating capacity should not use the
low mass emission provision. The EPA concludes that with a 250 ton
NOX mass emissions applicability cutoff, the aggregate
NOX tons and percentage of inventory potentially covered by
all the exceptions encompassed would easily exceed the de minimis level
of emissions. The EPA has therefore, not adopted an increased cutoff
limit for NOX of 250 tons. Similarly, EPA concludes that an
increased cutoff of 100 tons of NOX would not be consistent
with the type of source which the Agency has identified for use of the
low mass emission excepted methodology or fit under the de minimis
level of emissions defined for NOX by the Agency. At the 100
ton cutoff for NOX coupled to a 25 ton cutoff for
SO2 the aggregate NOX emissions are 8841 tons of
NOX and 540 tons of SO2 from 408 qualifying
units. The analysis performed by the Agency indicates that 50 tons of
NOX coupled to 25 tons of SO2 is the appropriate
cutoff limit for applicability to the low mass emissions excepted
methodology. The approximate aggregate emissions of 3600 tons of
NOX and 250 tons of SO2 from 240 sources allows
the appropriate type of units to use the provisions without great
potential of exceeding a de-minimus level of NOX emissions.
In choosing the 50 ton NOX mass emission cutoff limit over
other limits, the Agency evaluated the available data and applied the
following criteria: (1) The NOX tons limit should allow
reduced monitoring for the units which EPA determined were appropriate
candidates for the low mass emissions provisions during the rulemaking
process, namely units with low mass emissions both collectively and
individually due to low operating levels or small size but not highly
controlled units which operate at higher levels; (2) the NOX
tons limit should allow reduced monitoring for a group of units
consistent with the level of de minimis emissions inventory for all
exceptions for the CEMS requirement; and (3) the limit should not
jeopardize the Agency's ability to effectively fulfill its obligations
under of the CAA.
From the analysis performed, the Agency has demonstrated that
increasing the 25 ton limit for SO2 would result in allowing
few additional sources the option to use the low mass emissions
methodology. For example at a coupled 50 tons of NOX and 25
tons of SO2 increasing the SO2 tonnage cutoff to
50 tons would allow only 7 additional units to use the methodology. The
additional units identified all combusted oil as the primary fuel which
has a very high sulfur content in comparison to natural gas. While
natural gas fired units could easily increase operations without
substantial increases in SO2 emissions oil fired units could
not. The additional units which burn oil and qualify are considered
inappropriate candidates for use of the low mass emission provision.
Therefore, the Agency has chosen to leave the tonnage limit at the
proposed level of 25 tons for SO2. Leaving the cutoff for
applicability for SO2 at 25 tons also reflected the opinion
of commenters who suggested raising only the NOX tonnage.
When considering the size cutoffs, EPA also took into account both
the effect that the use of this methodology could have on other
regulatory actions and the effect that other regulatory actions could
have on the number of units and percentage of emissions that could be
covered by units using this methodology. In particular, EPA was
concerned about the SIP call. Units that could qualify to use the low
mass emission methodology do not have a NOX emission limit
under title IV. However, under the SIP call, units that are using the
monitoring requirements of part 75 to comply with the requirements of
the SIP call, including units that could qualify to use the low mass
emitter methodology, would have an emission limit. As explained in
Section VI.A.2.c and VII.D.3 of today's preamble, EPA believes that it
is important that large sources of NOX mass emissions
accurately account for their emissions. Because EPA is expecting
substantial reductions in NOX emissions from the title IV
phase II NOX emission rate limits, the SIP call and other
similar programs, EPA believes that even if the total NOX
emissions coming from units that could qualify for the low mass emitter
methodology does not increase, the percentage of emissions coming from
these units will increase. The EPA also believes that the incentives
provided under a trading program could encourage smaller oil and gas
fired units that may not currently qualify under the low mass emission
methodology to install controls. As a result, this could increase the
number of units, the amount of emissions and the percentage of
emissions that could be accounted for by units using this methodology.
EPA believes that the 50 ton cutoff is adequate to ensure that
emissions from units that qualify for the low mass
[[Page 57488]]
emitter methodology are de-minimis today. In the future however, growth
in the number of units may cause the level of NOX,
SO2 or CO2 emissions from units qualifying for
and using the new unit exemption, appendix E, the low mass emitter
provision and other programs such as the SIP call to exceed a de-
minimis level and the agency reserves the right to re-assess any and
all of these exceptions in the future if the need arises.
e. Decoupling NOX and SO2. In order to
qualify for the low mass emissions excepted methodology, the
applicability criteria require a unit to meet annual tonnage cutoffs of
25 tons for SO2 and 50 tons for NOX. The EPA has
considered whether the excepted methodology should be available on a
pollutant specific level so that, for example, a unit which falls below
the tonnage cutoff for SO2 but not for NOX could
use the excepted methodology under Sec. 75.19 to measure SO2
emissions but use a NOX CEM or the excepted methodology
under appendix E, where applicable, to measure NOX
emissions. All analysis the Agency has done indicates that the
NOX tonnage is the limiting factor for greater than 90
percent of all units when applicability is for units to meet a coupled
50 ton NOX and 25 ton SO2 limit (see Docket A-97-
35, Items, II-A-10, IV-A-1) For example, approximately 20 units were
identified which would potentially be qualified to use the low mass
emission methodology for a 50 tons of NOX cutoff who would
not meet the 25 tons of SO2 cutoff and therefore be
disqualified from using the methodology. Conversely, the agency's
analysis indicated that leaving the tonnage cutoff for SO2
mass emissions at 25 tons and decoupling NOX and
SO2 would potentially allow approximately 650 units in the
program to use the low mass emissions methodology for SO2
(see Docket A-97-35, Items, II-A-10, IV-A-1). In particular allowing
decoupling could impair the Agency's ability to collect data on
CO2 emissions as required under the CAA section 821. The
analysis performed by the Agency indicates, that even with a 25 ton
limit on SO2, 652 units could qualify for the use of the low
mass emissions methodology for SO2 only. The 652 units
identified represent approximately 10 percent of the total program heat
input and greater than 6 percent of the total program CO2
emissions. If a unit which qualified for the use of only SO2
were allowed to use the low mass emissions methodology for
CO2 the result could be overestimation of CO2
emissions from a sizeable percentage of the total CO2
inventory. Future decisions based on such data might draw incorrect
conclusions.
For the reason stated above, if a unit were allowed to qualify for
a single pollutant the unit would be allowed to use the low mass
emissions methodology for that pollutant only and not for
CO2 or heat input estimations. Therefore, no practical
benefit for industry would result from decoupling SO2 and
NOX. Decoupling would not be particularly beneficial because
qualifying for one pollutant only allows only minimal monitoring
reductions when CO2 and heat input are not simplified. In
addition decoupling would dramatically increase the complexity of the
low mass emissions methodology. The added complications which would
benefit a limited number of sources in only a limited way would
increase the time and effort needed for all other sources in
understanding and implementing the methodology. The agency concludes
that the burden from the increased rule complexity outweighs the
benefit from decoupling SO2 and NOX.
The following discussions further explain the Agencies position.
One of the prime benefits of the low mass emissions excepted
methodology will be the simplified reporting which will require less
time and a less sophisticated Data Acquisition and Handling System
(DAHS). In particular, the need for a DAHS that could calculate
substitute data using the current missing data algorithms will be
removed because there are no missing data algorithms for the low mass
emissions excepted methodology. If the excepted methodology is only
applied to one of the pollutants, much of the benefit would be negated
because the DAHS will still need to be capable of calculating
substitute data for the measured pollutant and close to the full
quarterly report would still be required.
Another prime benefit of the low mass emissions excepted
methodology will be the reduction of monitoring and quality assurance
requirements. A unit which would qualify for SO2 only would
still need to determine CO2 mass emissions using a fuel flow
meter. Additionally the units which would qualify are primarily gas
fired units which would be allowed to use appendix D for
SO2. In this case no benefit is allowed by using the low
mass emissions methodology. A limited number of oil fired units would
be granted some reduced sampling requirements.
The agency's analysis indicates that most units which would qualify
for NOX only can use the excepted methodology under appendix
E.
As stated before the analysis indicates that the benefits of
decoupling are outweighed by the complications of allowing decoupling.
f. The use of the Low Mass Emitter Methodology with fuels other
than oil and natural gas. One commenter suggested that the
applicability should be expanded to include other fuels including low
sulfur solid fuels such as wood. EPA disagrees with the commenter who
claims that the methodology should be irrespective of fuel type. The
fuel type is an integral part of the emissions calculations and insures
that emissions are not underestimated. The Agency does not have, and
the commenter did not provide, sufficient data to justify including
wood fired solid fuel units into the low mass emission methodology. The
limited data EPA has does not provide assurance that wood is always low
in sulfur or that it results in low mass emissions of NOX.
The use of AP 42 emission factors was considered but rejected based on
the possibility of underestimation of NOX emissions using
the AP 42 factors, as stated in the January 11, 1993 rule preamble at
58 FR 364445. If EPA is provided with information addressing this issue
in the future, EPA will consider expanding the applicability to units
that burn wood in the future.
2. Method for Determining Emissions
On May 21, 1998 the Agency proposed a low mass emissions
methodology which used maximum rated heat input as the only heat input
option and default emission rates for SO2, NOX,
and CO2. The Agency requested comment on whether this
methodology was appropriate or whether an alternate approach should be
adopted for low mass emitting units. In response, several commenters
suggested changing the method for determining emissions. One commenter
suggested allowing the use of unit-specific NOX testing (see
Docket A-97-35, Item IV-D-20). Another commenter suggested that long
term fuel flow heat input be allowed as an alternative to the proposed
maximum rated heat input (see Docket A-97-35, Item IV-D-13). Two other
commenters suggested that further unspecified options be allowed for
determining heat input (see Docket A-97-35, Items, IV-D-03, IV-G-02).
Additionally several commenters suggested that the reduced monitoring
under the low mass emission methodology was being limited to too few
sources (see Docket A-97-35, Items, IV-D-07, IV-D-22, IV-D-23, IV-D-24,
IV-G-03). Other commenters made the general suggestion that part 75
should
[[Page 57489]]
be more consistent with the monitoring requirements of the OTC
NOX Budget Program. Finally the Agency received both
comments and data which indicated that for uncontrolled gas fired
turbines combusting both oil and gas the default emission rates for
NOX in proposed table 1b of Sec. 75.19 (c) were potentially
substantial underestimations of actual emission from these types of
units (see Docket A-97-35, Item IV-D-22). Further analysis by the
Agency provided supporting evidence that the emission rates in proposed
75.19 (c), table 1b, might underestimate emissions significantly for
gas and oil fired turbines (see Docket A-97-35, Item IV-A-1). In
response to these comments which reflected a general desire to expand
the applicability of the low mass emission methodology through changes
in both the heat input and NOX emissions methodology, and in
light of no negative comments reflecting opposition to allowing the low
mass emission methodology, the Agency began analysis of what changes in
the methods for determining heat input and NOX emissions
could be allowed without risk of underestimation of emissions, or
negative environmental consequences. The Agency received no comments on
changing either the SO2 or CO2 methods for
determining emissions and therefore did not attempt to change these
methodologies.
a. Adoption of the Proposed Methodology. In the proposal, the
Agency considered several methods for determining the estimated
emissions as the basis for applicability of the reduced monitoring and
reporting excepted methodology. For each of the methods considered,
rather than using actual measured sulfur and carbon values,
CO2, SO2, and flow CEM readings, NOX
CEM readings, or NOX values from an Appendix E
NOX-versus-heat input correlation, a facility will calculate
the unit's emissions based on an emission rate factor and one of two
heat input methodologies. Since the units that will qualify for the
excepted methodology will still be accountable for reporting emissions
to the Agency and surrendering allowances based on those emissions,
where applicable, the emissions estimations will not just be used to
determine if the unit qualifies under the exception; the reported
estimations will also be used to determine compliance. Prior to the
proposal, some industry representatives suggested that facilities would
be willing to use a conservative emission estimate, such as a maximum
potential emission rate times the maximum heat input, if it would allow
them to save time and money currently spent on monitoring and quality
assurance (see Docket A-97-35, Items II-D-30, II-D-43, II-D-45, II-E-
13, and II-E-25). The Agency decided it was appropriate to retain the
proposed methodologies of maximum rated heat input and default
SO2, NOX and CO2 emission rates for
the final rule. It was also decided to allow increased applicability of
the low mass emissions methodology through optional unit-specific
NOX emission rate determinations and the use of an optional
heat input methodology (e.g., long term fuel flow).
b. Change in Table 1b, Default NOX Emission Rates. In
deciding to retain the proposed low mass emission methodology as part
of the final rule the Agency had to consider that some values for
NOX emission rate in proposed table 1b of Sec. 75.19 (c) had
a high potential for underestimating emissions in at least some cases.
The Agency acknowledged that increasing the default NOX
emission rates in table 1b of Sec. 75.19 (c) will reduce the number of
units allowed to use the low mass emissions methodology. Based on the
comments received (see Docket A-97-35, Item IV-D-20) and to both allow
increased applicability and increase the default rates to an
appropriate level, the use of NOX testing to determine
units-specific NOX emission rates will be allowed as an
alternative option to using the default NOX emission rates
in table 1b of Sec. 75.19 (c). Allowing the option of unit-specific
NOX emission rates will generate more realistic
NOX emission rates than the default NOX emission
rates in table 1b of Sec. 75.19 (c) and will maintain some of the
simplicity of the NOX mass methodology from the low mass
emissions methodology proposal.
The next issue was deciding which default NOX emission
rates in table 1b of Sec. 75.19 (c) to raise and what level to raise
the defaults to. As a first consideration the Agency noted that the
default NOX emission rates in table 1b of proposed
Sec. 75.19 (c) should be increased to the level at which it will be
highly unlikely that any unit that performed testing will have a higher
emission rate than the default. In this case, a source might opt to use
a default which would knowingly underestimate emissions under certain
operating conditions. Since all of the defaults used in table 1b of
proposed Sec. 75.19 (c) were based on the 90th percentile it is very
likely that some units would have a higher emission rate than the
NOX emission rates in table 1b of proposed 75.19 (c). For
this reason, all of the NOX emission rate values in proposed
table 1b were increased to a level which will ensure that units will
not have higher tested emission rates than the default rates in Table
1b. A commenter suggested that these provisions be more consistent with
the provisions for the Ozone Transport Commission (OTC), NOX
Budget Program (see Docket A-97-35, Item IV-D-13). The default emission
rates the Agency decided to adopt are the default rates used in the OTC
NOX Budget Program (see Docket A-97-35, Item II-I-7). In the
OTC NOX Budget Program, units similar in emission
characteristics to those who will qualify as low mass emission units
under today's rule have the option of unit specific testing or unit
generic default OTC NOX emission rates. In the OTC
NOX Budget Program units have chosen both options based on
owner or operator preference. Finally, adopting the NOX
Budget Program defaults creates consistency among programs which is a
supplementary benefit.
c. Unit-Specific NOX Emission Rate Testing. In
considering the options for unit-specific NOX emission rate
testing the Agency had to address several concerns, including the
following: (1) Units with NOX controls who performed unit
specific testing with the controls operating might have the potential
to grossly underestimate emissions if the controls failed; (2) what
sort of test would be appropriate for determining the low mass
emissions methodology fuel -and-unit-specific NOX emission
rate; (3) how long a period should a source be allowed to use the unit-
specific NOX rate once determined through testing; (4) under
what conditions should a source be required to retest for a new unit-
specific NOX emission rate; (5) for sources with historical
reported emissions data using CEMS under part 75, what historical
NOX emission rate value might be appropriate for use in lieu
of an initial test; and (6) if a source owns multiple identical units,
should representative testing be allowed at some of the units to
represent all units.
The first issue resolved was the use of Appendix E of Part 75
procedures for determination of a unit-specific NOX emission
rate for each fuel combusted by the unit. The unit-specific
NOX emission rate selected, for each fuel tested, will be
the highest recorded NOX emission rate from the test at any
test load or operating condition multiplied by 1.15. Units which
combust multiple fuels can use, for different fuels, either a unit-
specific NOX rate determined through testing or use the
default NOX emission rates listed in table 1b of Sec. 75.19
(c). For example, a unit which primarily combusts oil but occasionally
combusts natural gas could determine a unit-specific NOX
emission rate for oil
[[Page 57490]]
through Appendix E testing and use the default NOX emission
rate from table 1b of Sec. 75.19 (c) for gas. For hours in which a unit
combusts multiple fuels in one hour, the unit must use the highest
emission rate for that hour for all fuels combusted. In conducting the
Appendix E test, the requirement for monitoring heat input to the unit
during the test is removed as it is an unnecessary burden. The
multiplier of 1.15 is required because of Agency analysis which
indicates that appendix E testing is not representative of emissions at
a given load at all times. In particular, the analysis of units with
NOX emission rate CEMS indicated that the NOX
emission rate can vary an average of 15 percent at a given load during
different periods of operation. The most probable cause of the
difference noted is variations in atmospheric moisture content. The
agency notes that units which do appendix E testing during hot humid
conditions would likely underestimate emissions during cooler less
humid conditions. The Appendix E test was chosen for several reasons
including: (1) many current Acid Rain sources which might qualify for
the low mass emissions methodology already have performed Appendix E
testing and will be allowed to use their historical Appendix E test
data to determine a unit-specific NOX emission rate without
further requirements; (2) the requirements of Appendix E testing are
already familiar to sources and contractors who may perform the
testing, thus reducing further burden imposed by requiring new testing
methodologies; (3) The use of the Appendix E test and the multiplier of
1.15 ensures that a unit uses a NOX emission rate which will
not underestimate emissions at any normal operating condition.
Once the Appendix E test was chosen, the use of a five year testing
frequency was deemed appropriate as it matched the current Appendix E
test period and matches the current permit renewal cycle.
A special provision was included in the low mass emission
methodology to allow units with historical CEMS NOX emission
rate data to determine a unit-specific NOX emission rate
from historical certified CEMS data. Under this provision a unit will
analyze historical data from hours in which a unit combusted a
particular fuel. The analysis will determine the unit-specific
NOX emission rate which will yield a 95 percent confidence
that the unit will not emit at a higher NOX emission rate
while combusting the fuel being analyzed. The Agency also considered
using the highest NOX rate from historical data but reasoned
that the large data sets used to generate the unit-and fuel-specific
emission rate would contain outliers which would make the procedure
unfeasible for most units. The Agency considered several options for
units which used NOX controls and wished to use unit-
specific NOX emission rates determined through Appendix E
testing. One option was to allow units to test with the NOX
control devices not operating or minimized. This option was rejected
for the following two reasons: (1) the Agency does not support adopting
a rule which would require sources to operate in a manner that would
increase emissions; and (2) some sources which have controls are not
allowed to operate when the controls are not operating by permit
restrictions and these units would be disallowed from using the low
mass emission methodology unfairly. The Agency also considered not
allowing units with NOX emission controls to use the low
mass emission methodology. While the Agency does believe that it is not
appropriate to include large controlled units, the Agency does feel it
is appropriate to allow infrequently used controlled units, such as
peaking turbines with steam or water injection to benefit from the
reduced requirements of this methodology (as further explained above).
Therefore this solution was rejected as excluding many units for which
the Agency believes it is appropriate to allow reduced monitoring from
more accurate and more costly monitoring requirements.
The Agency also considered allowing only units with certain types
of controls to use the low mass emission methodology. This approach was
rejected because the Agency does not, at this time, have the necessary
information or expertise to make an appropriate determination on this
approach.
The Agency also considered allowing units to determine a unit-
specific NOX emission rate using NOX controls
with no restriction. In analyzing this option, the Agency identified
several units which would qualify for the low mass emission methodology
based on the applicability criteria of 50 tons of NOX and 25
tons of SO2 which the Agency did not believe were
appropriate to use the low mass emission methodology. The units
identified had advanced control technologies such as selective
catalytic reduction (SCR) and burned low sulfur fuels such as natural
gas. The units identified consistently reported hourly emission rates
as low as 0.01 lb/mmBtu as compared to uncontrolled rates which are
generally 10 to 100 times higher for these units. The best method of
continued assurance that a unit's NOX controls are operating
is monitoring with a NOX CEMS. These units also operated
during more than half the hours of a year at an average heat input of
greater than 1000 mmBtu/hr. While, for these units, the potential to
underestimate SO2 emissions was low, the potential to
grossly underestimate NOX mass emissions using the low mass
emission methodology was much greater. For this reason, the Agency
rejected allowing a controlled unit to use a single emission rate
determined through Appendix E testing once every five years while
NOX controls were operating.
The methodology the Agency adopted in this rule was the use of a
lower limit of 0.15 lb/mmBtu for a unit-specific NOX
emission rate for units which opt to perform unit-and fuel-specific
Appendix E testing while controls are operating. For units with
NOX emission controls, which perform unit-specific
NOX emission rate testing and whose test results in a
NOX emission rate of less than 0.15 lb/mmBtu, the source
will use the NOX emission rate limit of 0.15 lb/mmBtu for
the unit-specific NOX emission rate instead of the lower
tested NOX emission rate. Units with NOX emission
controls who perform unit-specific NOX emission rate testing
and whose results from the testing indicate a NOX emission
rate of higher than 0.15 lb/mmBtu will be required to use the higher
NOX emission rate as the fuel-and unit-specific
NOX emission rate. In considering this approach the Agency
considered using the lowest NOX emission rate proposed in
75.19 (c), Table 1b, of 0.172 lb/mmBtu, as well as 0.15 lb/mmBtu, 0.1
lb/mmBtu and 0.05 lb/mmBtu as lower limits for NOX emission
rate. The proposed gas fired turbine emission rate was 0.172 lb/mmBtu.
Using 0.172 lb/mmBtu as the lower limit for controlled units was
rejected as being an arbitrary choice based on a number representative
of only a single class of units and not representative of the
difference between controlled and uncontrolled units. An analysis was
performed to determine a reasonable lower cutoff between controlled and
uncontrolled units which would allow controlled units to qualify for
the reduced monitoring provisions of the excepted low mass emission
methodology without serious risk of underestimation of emissions. The
analysis indicated that a minimum allowable emission rate of 0.15 lb/
mmBtu for controlled units best allowed for fairness between controlled
and uncontrolled units and insured that very
[[Page 57491]]
large units with high operating hours and extremely low NOX
emission rates will not be allowed to use the low mass emission
excepted methodology. The Agency's decision was also heavily influenced
by the desire to insure that overall, the emission rate chosen would
insure that aggregate emissions of controlled units were indeed de
minimis. The Agency notes that the lower limit of 0.15 lb/mmBtu
NOX emission rate, when coupled with the annual limit of 50
tons of NOX, effectively limits the annual heat input of
units using the methodology to 666,666 mmBtu annual heat input.
Analysis done by EPA found this to be an appropriate limit on heat
input for the low mass emission excepted methodology (see Docket A-97-
35, Item IV-D-20). In general, the lower emission rate limit for
controlled units, and uncontrolled units inability to achieve such low
rates, combines to limit the low mass emission methodology to the
infrequently operated low mass emitting units the Agency was targeting
for use of the provision in today's new rule.
Controlled units that use this methodology are also subject to
additional requirements. The owner or operator of the unit must ensure
that the controls are being operated in the same manner that they were
operated during the unit specific testing. Documentation of this must
be kept on site. Any hour that the controls are not operating properly,
the owner or operator must use the default emission rates for
NOX in table 1.b of Sec. 75.19 (c), rather than the emission
rate determined through unit specific testing.
Based on experience gained working with the OTC in the
implementation of the OTC NOX budget program, EPA believes
that many of the units that may benefit from this new excepted
monitoring methodology are banks of identical small emission turbines.
The OTC has allowed these units to do representative sampling at a
number of units rather than requiring testing at all of the units.
While none of the commenters mentioned this specific flexibility of the
OTC NOX Budget program, EPA believes that this is one of the
flexibilities that commenters who suggested adopting some of the
methodologies that the OTC has allowed for smaller units were referring
to. Therefore this final rule contains a similar allowance for
identical units. If the owner or operator of a number of units that are
located at one facility can demonstrate that those units are identical,
this final rule will allow emission rate testing to be done at a
representative number of units.
d. The Adoption of Maximum Rated Heat Input as Proposed. While
several commenters suggested allowing alternative methods for
determining heat input, none directly suggested replacing or altering
the basic heat input approach as an option (as described in 68 FR
28037-8). For this reason the maximum rated hourly heat input option
from the proposal was retained as a less accurate but acceptable
approach.
e. Long Term Fuel Flow for Heat Input Determination. To allow
greater flexibility to units under the low mass emissions methodology
and to allow more realistic estimations of heat input as suggested by
several commenters the Agency is allowing the use of long term fuel
flow measurements to determine heat input to low mass emitting units as
described earlier. The Agency chose to adopt this methodology for the
following reasons: (1) The methodology allows more accurate
measurements of total heat input into a unit over the reporting period
than the use of maximum rated hourly heat input; (2) the methodology
has proven to be usable by sources who have chosen to use a similar
method in the Ozone Transport Commission, NOX Budget
Program; and (3) the methodology is straightforward and is optional for
sources which might be excluded from using the low mass emissions
methodology if allowed to use maximum rated hourly heat input only.
3. Reduced Monitoring and Quality Assurance Requirements. As
discussed above, today's rule allows facilities to use a maximum rated
hourly heat input value and an emission rate factor to determine the
mass emissions from a low-emitting unit for each hour of actual
operation. This approach involves no actual emissions monitoring and
minimal quality assurance activities. Instead, the facility will only
need to keep track of whether the unit combusted any fuel for a
particular hour and what type of fuel was combusted. In this way, the
revised rule significantly reduces the burden on affected facilities,
while still ensuring that emissions are not under reported.
For owners or operators which opt to use either the long term fuel
flow methodology or a fuel-and unit-specific NOX emission
rate, some additional quality assurance will be required. As these two
options under the low mass emission methodology are not required and
will allow units which would not otherwise qualify to use the low mass
emission methodology, the additional quality assurance requirements are
not burdensome to the sources using either long term fuel flow or unit-
specific NOX emission rates.
For the reasons set forth in the preamble, parts 51, 72, 75, and 96
of chapter I of title 40 of the Code of Federal Regulations are 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. 7401-7671q.
Subpart G--Control Strategy
2. Subpart G is amended to add Secs. 51.121 and 51.122 to read as
follows:
Sec. 51.121 Findings and requirements for submission of State
implementation plan revisions relating to emissions of oxides of
nitrogen.
(a)(1) The Administrator finds that the State implementation plan
(SIP) for each jurisdiction listed in paragraph (c) of this section is
substantially inadequate to comply with the requirements of section
110(a)(2)(D)(i)(I) of the Clean Air Act (CAA), 42 U.S.C.
7410(a)(2)(D)(i)(I), because the SIP does not include adequate
provisions to prohibit sources and other activities from emitting
nitrogen oxides (``NOX'') in amounts that will contribute
significantly to nonattainment in one or more other States with respect
to the 1-hour ozone national ambient air quality standards (NAAQS).
Each of the jurisdictions listed in paragraph (c) of this section must
submit to EPA a SIP revision that cures the inadequacy.
(2) Under section 110(a)(1) of the CAA, 42 U.S.C. 7410(a)(1), the
Administrator determines that each jurisdiction listed in paragraph (c)
of this section must submit a SIP revision to comply with the
requirements of section 110(a)(2)(D)(i)(I), 42 U.S.C.
7410(a)(2)(D)(i)(I), through the adoption of adequate provisions
prohibiting sources and other activities from emitting NOX
in amounts that will contribute significantly to nonattainment in, or
interfere with maintenance by, one or more other States with respect to
the 8-hour ozone NAAQS.
(b)(1) For each jurisdiction listed in paragraph (c) of this
section, the SIP revision required under paragraph (a) of this section
will contain adequate provisions, for purposes of complying with
section 110(a)(2)(D)(i)(I) of the CAA, 42 U.S.C. 7410(a)(2)(D)(i)(I),
only if the SIP revision:
[[Page 57492]]
(i) Contains control measures adequate to prohibit emissions of
NOX that would otherwise be projected, in accordance with
paragraph (g) of this section, to cause the jurisdiction's overall
NOX emissions to be in excess of the budget for that
jurisdiction described in paragraph (e) of this section (except as
provided in paragraph (b)(2) of this section),
(ii) Requires full implementation of all such control measures by
no later than May 1, 2003, and
(iii) Meets the other requirements of this section. The SIP
revision's compliance with the requirement of paragraph (b)(1)(i) of
this section shall be considered compliance with the jurisdiction's
budget for purposes of this section.
(2) The requirements of paragraph (b)(1)(i) of this section shall
be deemed satisfied, for the portion of the budget covered by an
interstate trading program, if the SIP revision:
(i) Contains provisions for an interstate trading program that EPA
determines will, in conjunction with interstate trading programs for
one or more other jurisdictions, prohibit NOX emissions in
excess of the sum of the portion of the budgets covered by the trading
programs for those jurisdictions; and
(ii) Conforms to the following criteria:
(A) Emissions reductions used to demonstrate compliance with the
revision must occur during the ozone season.
(B) Emissions reductions occurring prior to the year 2003 may be
used by a source to demonstrate compliance with the SIP revision for
the 2003 and 2004 ozone seasons, provided the SIP's provisions
regarding such use comply with the requirements of paragraph (e)(3) of
this section.
(C) Emissions reduction credits or emissions allowances held by a
source or other person following the 2003 ozone season or any ozone
season thereafter that are not required to demonstrate compliance with
the SIP for the relevant ozone season may be banked and used to
demonstrate compliance with the SIP in a subsequent ozone season.
(D) Early reductions created according to the provisions in
paragraph (b)(2)(ii)(B) of this section and used in the 2003 ozone
season are not subject to the flow control provisions set forth in
paragraph (b)(2)(ii)(E) of this section.
(E) Starting with the 2004 ozone season, the SIP shall include
provisions to limit the use of banked emissions reduction credits or
emissions allowances beyond a predetermined amount as calculated by one
of the following approaches:
(1) Following the determination of compliance after each ozone
season, if the total number of emissions reduction credits or banked
allowances held by sources or other persons subject to the trading
program exceeds 10 percent of the sum of the allowable ozone season
NOX emissions for all sources subject to the trading
program, then all banked allowances used for compliance for the
following ozone season shall be subject to the following:
(i) A ratio will be established according to the following formula:
(0.10) x (the sum of the allowable ozone season NOX
emissions for all sources subject to the trading program) (the
total number of banked emissions reduction credits or emissions
allowances held by all sources or other persons subject to the trading
program).
(ii) The ratio, determined using the formula specified in paragraph
(b)(2)(ii)(E)(1)(i) of this section, will be multiplied by the number
of banked emissions reduction credits or emissions allowances held in
each account at the time of compliance determination. The resulting
product is the number of banked emissions reduction credits or
emissions allowances in the account which can be used in the current
year's ozone season at a rate of 1 credit or allowance for every 1 ton
of emissions. The SIP shall specify that banked emissions reduction
credits or emissions allowances in excess of the resulting product
either may not be used for compliance, or may only be used for
compliance at a rate no less than 2 credits or allowances for every 1
ton of emissions.
(2) At the time of compliance determination for each ozone season,
if the total number of banked emissions reduction credits or emissions
allowances held by a source subject to the trading program exceeds 10
percent of the source's allowable ozone season NOX
emissions, all banked emissions reduction credits or emissions
allowances used for compliance in such ozone season by the source shall
be subject to the following:
(i) The source may use an amount of banked emissions reduction
credits or emissions allowances not greater than 10 percent of the
source's allowable ozone season NOX emissions for compliance
at a rate of 1 credit or allowance for every 1 ton of emissions.
(ii) The SIP shall specify that banked emissions reduction credits
or emissions allowances in excess of 10 percent of the source's
allowable ozone season NOX emissions may not be used for
compliance, or may only be used for compliance at a rate no less than 2
credits or allowances for every 1 ton of emissions.
(c) The following jurisdictions (hereinafter referred to as
``States'') are subject to the requirements of this section: 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 paragraph (a) of this
section must be submitted to EPA by no later than September 30, 1999.
(2) The State makes an official submission of its SIP revision to
EPA only when:
(i) The submission conforms to the requirements of appendix V to
this part; and
(ii) The State delivers five copies of the plan to the appropriate
Regional Office, with a letter giving notice of such action.
(e)(1) The NOX budget for a State listed in paragraph
(c) of this section is defined as the total amount of NOX
emissions from all sources in that State, as indicated in paragraph
(e)(2) of this section with respect to that State, which the State must
demonstrate that it will not exceed in the 2007 ozone season pursuant
to paragraph (g)(1) of this section.
(2) The State-by-State amounts of the NOX budget,
expressed in tons, are as follows:
------------------------------------------------------------------------
State Budget
------------------------------------------------------------------------
Alabama.................................................... 158,677
Connecticut................................................ 40,573
Delaware................................................... 18,523
District of Columbia....................................... 6,792
Georgia.................................................... 177,381
Illinois................................................... 210,210
Indiana.................................................... 202,584
Kentucky................................................... 155,698
Maryland................................................... 71,388
Massachusetts.............................................. 78,168
Michigan................................................... 212,199
Missouri................................................... 114,532
New Jersey................................................. 97,034
New York................................................... 179,769
North Carolina............................................. 151,847
Ohio....................................................... 239,898
Pennsylvania............................................... 252,447
Rhode Island............................................... 8,313
South Carolina............................................. 109,425
Tennessee.................................................. 182,476
Virginia................................................... 155,718
West Virginia.............................................. 92,920
Wisconsin.................................................. 106,540
------------
Total.................................................. 3,023,113
------------------------------------------------------------------------
[[Page 57493]]
(3)(i) Notwithstanding the State's obligation to comply with the
budgets set forth in paragraph (e)(2) of this section, a SIP revision
may allow sources required by the revision to implement NOX
emission control measures by May 1, 2003 to demonstrate compliance in
the 2003 and 2004 ozone seasons using credit issued from the State's
compliance supplement pool, as set forth in paragraph (e)(3)(iii) of
this section.
(ii) A source may not use credit from the compliance supplement
pool to demonstrate compliance after the 2004 ozone season.
(iii) The State-by-State amounts of the compliance supplement pool
are as follows:
------------------------------------------------------------------------
Compliance
supplement
State pool (tons
of NOX)
------------------------------------------------------------------------
Alabama.................................................... 10,361
Connecticut................................................ 559
Delaware................................................... 417
District of Columbia....................................... 0
Georgia.................................................... 10,919
Illinois................................................... 17,455
Indiana.................................................... 19,738
Kentucky................................................... 13,018
Maryland................................................... 3,662
Massachusetts.............................................. 285
Michigan................................................... 15,359
Missouri................................................... 10,469
New Jersey................................................. 1,722
New York................................................... 1,831
North Carolina............................................. 10,624
Ohio....................................................... 22,947
Pennsylvania............................................... 13,716
Rhode Island............................................... 0
South Carolina............................................. 5,062
Tennessee.................................................. 12,093
Virginia................................................... 6,108
West Virginia.............................................. 16,937
Wisconsin.................................................. 6,717
------------
Total.................................................. 200,000
------------------------------------------------------------------------
(iv) The SIP revision may provide for the distribution of the
compliance supplement pool to sources that are required to implement
control measures using one or both of the following two mechanisms:
(A) The State may issue some or all of the compliance supplement
pool to sources that implement emissions reductions during the ozone
season beyond all applicable requirements in years prior to the year
2003 according to the following provisions:
(1) The State shall complete the issuance process by no later than
May 1, 2003.
(2) The emissions reduction may not be required by the State's SIP
or be otherwise required by the CAA.
(3) The emissions reduction must be verified by the source as
actually having occurred during an ozone season between September 30,
1999 and May 1, 2003.
(4) The emissions reduction must be quantified according to
procedures set forth in the SIP revision and approved by EPA. Emissions
reductions implemented by sources serving electric generators with a
nameplate capacity greater than 25 MWe, or boilers, combustion turbines
or combined cycle units with a maximum design heat input greater than
250 mmBtu/hr, must be quantified according to the requirements in
paragraph (i)(4) of this section.
(5) If the SIP revision contains approved provisions for an
emissions trading program, sources that receive credit according to the
requirements of this paragraph may trade the credit to other sources or
persons according to the provisions in the trading program.
(B) The State may issue some or all of the compliance supplement
pool to sources that demonstrate a need for an extension of the May 1,
2003 compliance deadline according to the following provisions:
(1) The State shall initiate the issuance process by the later date
of September 30, 2002 or after the State issues credit according to the
procedures in paragraph (e)(3)(iv)(A) of this section.
(2) The State shall complete the issuance process by no later than
May 1, 2003.
(3) The State shall issue credit to a source only if the source
demonstrates the following:
(i) For a source used to generate electricity, compliance with the
SIP revision's applicable control measures by May 1, 2003, would create
undue risk for the reliability of the electricity supply. This
demonstration must include a showing that it would not be feasible to
import electricity from other electricity generation systems during the
installation of control technologies necessary to comply with the SIP
revision.
(ii) For a source not used to generate electricity, compliance with
the SIP revision's applicable control measures by May 1, 2003, would
create undue risk for the source or its associated industry to a degree
that is comparable to the risk described in paragraph
(e)(3)(iv)(B)(3)(i) of this section.
(iii) For a source subject to an approved SIP revision that allows
for early reduction credits in accordance with paragraph (e)(3)(iv)(A)
of this section, it was not possible for the source to comply with
applicable control measures by generating early reduction credits or
acquiring early reduction credits from other sources.
(iv) For a source subject to an approved emissions trading program,
it was not possible to comply with applicable control measures by
acquiring sufficient credit from other sources or persons subject to
the emissions trading program.
(4) The State shall ensure the public an opportunity, through a
public hearing process, to comment on the appropriateness of allocating
compliance supplement pool credits to a source under paragraph
(e)(3)(iv)(B) of this section.
(4) If, no later than November 23, 1998, any member of the public
requests revisions to the source-specific data used to establish the
State budgets set forth in paragraph (e)(2) of this section or the 2007
baseline sub-inventory information set forth in paragraph (g)(2)(ii) of
this section, then EPA will act on that request no later than January
22, 1999, provided:
(i) The request is submitted in electronic format;
(ii) Information is provided to corroborate and justify the need
for the requested modification;
(iii) The request includes the following data information regarding
any electricity-generating source at issue:
(A) Federal Information Placement System (FIPS) State Code;
(B) FIPS County Code;
(C) Plant name;
(D) Plant ID numbers (ORIS code preferred, State agency tracking
number also or otherwise);
(E) Unit ID numbers (a unit is a boiler or other combustion
device);
(F) Unit type;
(G) Primary fuel on a heat input basis;
(H) Maximum rated heat input capacity of unit;
(I) Nameplate capacity of the largest generator the unit serves;
(J) Ozone season heat inputs for the years 1995 and 1996;
(K) 1996 (or most recent) average NOX rate for the ozone
season;
(L) Latitude and longitude coordinates;
(M) Stack parameter information ;
(N) Operating parameter information;
(o) Identification of specific change to the inventory; and
(p) Reason for the change;
(iv) The request includes the following data information regarding
any non-electricity generating point source at issue:
(A) FIPS State Code;
(B) FIPS County Code;
(C) Plant name;
(D) Facility primary standard industrial classification code (SIC);
[[Page 57494]]
(E) Plant ID numbers (NEDS, AIRS/AFS, and State agency tracking
number also or otherwise);
(F) Unit ID numbers (a unit is a boiler or other combustion
device);
(G) Primary source classification code (SCC);
(H) Maximum rated heat input capacity of unit;
(I) 1995 ozone season or typical ozone season daily NOX
emissions;
(J) 1995 existing NOX control efficiency;
(K) Latitude and longitude coordinates;
(L) Stack parameter information;
(M) Operating parameter information;
(N) Identification of specific change to the inventory; and
(O) Reason for the change;
(v) The request includes the following data information regarding
any stationary area source or nonroad mobile source at issue:
(A) FIPS State Code;
(B) FIPS County Code;
(C) Primary source classification code (SCC);
(D) 1995 ozone season or typical ozone season daily NOX
emissions;
(E) 1995 existing NOX control efficiency;
(F) Identification of specific change to the inventory; and
(G) Reason for the change;
(vi) The request includes the following data information regarding
any highway mobile source at issue:
(A) FIPS State Code;
(B) FIPS County Code;
(C) Primary source classification code (SCC) or vehicle type;
(D) 1995 ozone season or typical ozone season daily vehicle miles
traveled (VMT);
(E) 1995 existing NOX control programs;
(F) identification of specific change to the inventory; and
(G) reason for the change.
(f) Each SIP revision must set forth control measures to meet the
NOX budget in accordance with paragraph (b)(1)(i) of this
section, 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.
(2) Should a State elect to impose control measures on fossil fuel-
fired NOX sources serving electric generators with a
nameplate capacity greater than 25 MWe or boilers, combustion turbines
or combined cycle units with a maximum design heat input greater than
250 mmBtu/hr as a means of meeting its NOX budget, then
those measures must:
(i)(A) Impose a NOX mass emissions cap on each source;
(B) Impose a NOX emissions rate limit on each source and
assume maximum operating capacity for every such source for purposes of
estimating mass NOX emissions; or
(C) Impose any other regulatory requirement which the State has
demonstrated to EPA provides equivalent or greater assurance than
options in paragraphs (f)(2)(i)(A) or (f)(2)(i)(B) of this section that
the State will comply with its NOX budget in the 2007 ozone
season; and
(ii) Impose enforceable mechanisms to assure that collectively all
such sources, including new or modified units, will not exceed in the
2007 ozone season the total NOX emissions projected for such
sources by the State pursuant to paragraph (g) of this section.
(3) For purposes of paragraph (f)(2) of this section, the term
``fossil fuel-fired'' means, with regard to a NOX source:
(i) The combustion of fossil fuel, alone or in combination with any
other fuel, where fossil fuel actually combusted comprises more than 50
percent of the annual heat input on a Btu basis during any year
starting in 1995 or, if a NOX source had no heat input
starting in 1995, during the last year of operation of the
NOX source prior to 1995; or
(ii) The combustion of fossil fuel, alone or in combination with
any other fuel, where fossil fuel is projected to comprise more than 50
percent of the annual heat input on a Btu basis during any year;
provided that the NOX source shall be ``fossil fuel-fired''
as of the date, during such year, on which the NOX source
begins combusting fossil fuel.
(g)(1) Each SIP revision must demonstrate that the control measures
contained in it are adequate to provide for the timely compliance with
the State's NOX budget during the 2007 ozone season.
(2) The demonstration must include the following:
(i) Each revision must contain a detailed baseline inventory of
NOX mass emissions from the following sources in the year
2007, absent the control measures specified in the SIP submission:
electric generating units (EGU), non-electric generating units (non-
EGU), area, nonroad and highway sources. The State must use the same
baseline emissions inventory that EPA used in calculating the State's
NOX budget, as set forth for the State in paragraph
(g)(2)(ii) of this section, except that EPA may direct the State to use
different baseline inventory information if the State fails to certify
that it has implemented all of the control measures assumed in
developing the baseline inventory.
(ii) The base year 2007 NOX emissions sub-inventories
for each State, expressed in tons per ozone season, are as follows:
--------------------------------------------------------------------------------------------------------------------------------------------------------
State EGU Non-EGU Area Nonroad Highway Total
--------------------------------------------------------------------------------------------------------------------------------------------------------
Alabama................................................. 76,900 49,781 25,225 16,594 50,111 218,610
Connecticut............................................. 5,600 5,273 4,588 9,584 18,762 43,807
Delaware................................................ 5,800 1,781 963 4,261 8,131 20,936
District of Columbia.................................... \1\ 0 310 741 3,470 2,082 6,603
Georgia................................................. 86,500 33,939 11,902 21,588 86,611 240,540
Illinois................................................ 119,300 55,721 7,822 47,035 81,297 311,174
Indiana................................................. 136,800 71,270 25,544 22,445 60,694 316,753
Kentucky................................................ 107,800 18,956 38,773 19,627 45,841 230,997
Maryland................................................ 32,600 10,982 4,105 17,249 27,634 92,570
Massachusetts........................................... 16,500 9,943 10,090 18,911 24,371] 79,815
Michigan................................................ 86,600 79,034 28,128 23,495 83,784 301,042
Missouri................................................ 82,100 13,433 6,603 17,723 55,230 175,089
New Jersey.............................................. 18,400 22,228 11,098 21,163 34,106 106,995
New York................................................ 39,200 25,791 15,587 29,260 80,521 190,358
North Carolina.......................................... 84,800 34,027 10,651 17,799 66,019 213,296
Ohio.................................................... 163,100 53,241 19,425 37,781 99,079 372,626
Pennsylvania............................................ 123,100 73,748 17,103 25,554 92,280 331,785
[[Page 57495]]
Rhode Island............................................ 1,100 327 420 2,073 4,375 8,295
South Carolina.......................................... 36,300 34,740 8,359 11,903 47,404 138,706
Tennessee............................................... 70,900 60,004 11,990 44,567 64,965 252,426
Virginia................................................ 40,900 39,765 18,622 21,551 70,212 191,050
West Virginia........................................... 115,500 40,192 4,790 10,220 20,185 190,887
Wisconsin............................................... 52,000 22,796 8,160 12,965 49,470 145,391
-----------------------------------------------------------------------------------------------
Total............................................. 1,501,800 757,281 290,689 456,818 1,173,163 4,179,751
--------------------------------------------------------------------------------------------------------------------------------------------------------
\1\ The base case for the District of Columbia is actually projected to be 30 tons per season. The base case values in this table are rounded to the
nearest 100 tons.
(iii) Each revision must contain a summary of NOX mass
emissions in 2007 projected to result from implementation of each of
the control measures specified in the SIP submission and from all
NOX sources together following implementation of all such
control measures, compared to the baseline 2007 NOX
emissions inventory for the State described in paragraph (g)(2)(i) of
this section. The State must provide EPA with a summary of the
computations, assumptions, and judgments used to determine the degree
of reduction in projected 2007 NOX emissions that will be
achieved from the implementation of the new control measures compared
to the baseline emissions inventory.
(iv) Each revision must identify the sources of the data used in
the projection of emissions.
(h) Each revision must comply with Sec. 51.116 of this part
(regarding data availability).
(i) Each revision must provide for monitoring the status of
compliance with any control measures adopted to meet the NOX
budget. Specifically, the revision must meet the following
requirements:
(1) 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:
(i) Information on the amount of NOX emissions from the
stationary sources; and
(ii) 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;
(2) The revision must comply with Sec. 51.212 of this part
(regarding testing, inspection, enforcement, and complaints);
(3) If the revision contains any transportation control measures,
then the revision must comply with Sec. 51.213 of this part (regarding
transportation control measures);
(4) If the revision contains measures to control fossil fuel-fired
NOX sources serving electric generators with a nameplate
capacity greater than 25 MWe or boilers, combustion turbines or
combined cycle units with a maximum design heat input greater than 250
mmBtu/hr, then the revision must require such sources to comply with
the monitoring provisions of part 75, subpart H.
(5) For purposes of paragraph (i)(4) of this section, the term
``fossil fuel-fired'' means, with regard to a NOX source:
(i) The combustion of fossil fuel, alone or in combination with any
other fuel, where fossil fuel actually combusted comprises more than 50
percent of the annual heat input on a Btu basis during any year
starting in 1995 or, if a NOX source had no heat input
starting in 1995, during the last year of operation of the
NOX source prior to 1995; or
(ii) The combustion of fossil fuel, alone or in combination with
any other fuel, where fossil fuel is projected to comprise more than 50
percent of the annual heat input on a Btu basis during any year,
provided that the NOX source shall be ``fossil fuel-fired''
as of the date, during such year, on which the NOX source
begins combusting fossil fuel.
(j) Each revision must show that the State has legal authority to
carry out the revision, including authority to:
(1) Adopt emissions standards and limitations and any other
measures necessary for attainment and maintenance of the State's
NOX budget specified in paragraph (e) of this section;
(2) Enforce applicable laws, regulations, and standards, and seek
injunctive relief;
(3) Obtain information necessary to determine whether air pollution
sources are in compliance with applicable laws, regulations, and
standards, including authority to require recordkeeping and to make
inspections and conduct tests of air pollution sources;
(4) Require owners or operators of stationary sources to install,
maintain, and use emissions monitoring devices and to make periodic
reports to the State on the nature and amounts of emissions from such
stationary sources; also authority for the State to make such data
available to the public as reported and as correlated with any
applicable emissions standards or limitations.
(k)(1) The provisions of law or regulation which the State
determines provide the authorities required under this section must be
specifically identified, and copies of such laws or regulations must 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 CAA.
(l)(1) A revision may assign legal authority to local agencies in
accordance with Sec. 51.232 of this part.
(2) Each revision must comply with Sec. 51.240 of this part
(regarding general plan requirements).
(m) Each revision must comply with Sec. 51.280 of this part
(regarding resources).
(n) For purposes of the SIP revisions required by this section, EPA
may make a finding as applicable under section 179(a)(1)-(4) of the
CAA, 42 U.S.C. 7509(a)(1)-(4), starting the sanctions process set forth
in section 179(a) of the CAA. Any such finding will be deemed a finding
under Sec. 52.31(c) of this part and sanctions will be imposed in
accordance with the order of sanctions and the terms for such sanctions
established in Sec. 52.31 of this part.
(o) Each revision must provide for State compliance with the
reporting requirements set forth in Sec. 51.122 of this part.
(p)(1) Notwithstanding any other provision of this section, if a
State adopts regulations substantively identical to 40 CFR part 96 (the
model NOX budget trading program for SIPs), incorporates
such part by reference into its regulations, or adopts regulations that
differ substantively from such part only as set forth in paragraph
(p)(2) of this section, then that portion of the State's SIP revision
is automatically approved as satisfying the same portion of the State's
NOX emission reduction obligations as the State projects
such regulations will satisfy, provided that:
[[Page 57496]]
(i) The State has the legal authority to take such action and to
implement its responsibilities under such regulations, and
(ii) The SIP revision accurately reflects the NOX
emissions reductions to be expected from the State's implementation of
such regulations.
(2) If a State adopts an emissions trading program that differs
substantively from 40 CFR part 96 in only the following respects, then
such portion of the State's SIP revision is approved as set forth in
paragraph (p)(1) of this section:
(i) The State may expand the applicability provisions of the
trading program to include units (as defined in 40 CFR 96.2) that are
smaller than the size criteria thresholds set forth in 40 CFR 96.4(a);
(ii) The State may decline to adopt the exemption provisions set
forth in 40 CFR 96.4(b);
(iii) The State may decline to adopt the opt-in provisions set
forth in subpart I of 40 CFR part 96;
(iv) The State may decline to adopt the allocation provisions set
forth in subpart E of 40 CFR part 96 and may instead adopt any
methodology for allocating NOX allowances to individual
sources, provided that:
(A) The State's methodology does not allow the State to allocate
NOX allowances in excess of the total amount of
NOX emissions which the State has assigned to its trading
program; and
(B) The State's methodology conforms with the timing requirements
for submission of allocations to the Administrator set forth in 40 CFR
96.41; and
(v) The State may decline to adopt the early reduction credit
provisions set forth in 40 CFR 96.55(c) and may instead adopt any
methodology for issuing credit from the State's compliance supplement
pool that complies with paragraph (e)(3) of this section.
(3) If a State adopts an emissions trading program that differs
substantively from 40 CFR part 96 other than as set forth in paragraph
(p)(2) of this section, then such portion of the State's SIP revision
is not automatically approved as set forth in paragraph (p)(1) of this
section but will be reviewed by the Administrator for approvability in
accordance with the other provisions of this section.
Sec. 51.122 Emissions reporting requirements for SIP revisions
relating to budgets for NOX emissions
(a) For its transport SIP revision under Sec. 51.121 of this part,
each State must submit to EPA NOX emissions data as
described in this section.
(b) Each revision must provide for periodic reporting by the State
of NOX emissions data to demonstrate whether the State's
emissions are consistent with the projections contained in its approved
SIP submission.
(1) Annual reporting. Each revision must provide for annual
reporting of NOX emissions data as follows:
(i) The State must report to EPA emissions data from all
NOX sources within the State for which the State specified
control measures in its SIP submission under Sec. 51.121(g) of this
part. This would include all sources for which the State has adopted
measures that differ from the measures incorporated into the baseline
inventory for the year 2007 that the State developed in accordance with
Sec. 51.121(g) of this part.
(ii) If sources report NOX emissions data to EPA
annually pursuant to a trading program approved under Sec. 51.121(p) of
this part or pursuant to the monitoring and reporting requirements of
subpart H of 40 CFR part 75, then the State need not provide annual
reporting to EPA for such sources.
(2) Triennial reporting. Each plan must provide for triennial
(i.e., every third year) reporting of NOX emissions data
from all sources within the State.
(3) Year 2007 reporting. Each plan must provide for reporting of
year 2007 NOX emissions data from all sources within the
State.
(4) The data availability requirements in Sec. 51.116 of this part
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 Federal Information Placement System code.
(iii) County Federal Information Placement System 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) Ozone season emissions.
(xii) 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) Spring throughput (%).
(viii) Summer throughput (%).
(ix) Fall throughput (%).
(x) Work weekday emissions.
(xi) Emission factor.
(xii) Source of emission factor.
(xiii) Hour/day in operation.
(xiv) Operations Start time (hour).
(xv) Day/week in operation.
(xvi) Week/year 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) Hour/day in operation.
(xviii) Day/week in operation.
(xix) Week/year in operations.
(2) The triennial and 2007 inventories must contain, at a minimum,
all the data required in paragraph (d)(1) of this section.
[[Page 57497]]
(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) SCC.
(v) Emission factor.
(vi) Source of emission factor.
(vii) Activity (this must be reported for both highway and nonroad
activity. Submit nonroad activity in the form of hours of activity at
standard load (either full load or average load) for each engine type,
application, and horsepower range. Submit highway activity in the form
of vehicle miles traveled (VMT) by vehicle class on each roadway type.
Report both highway and nonroad activity for a typical ozone season
weekday day, if the State uses EPA's default weekday/weekend activity
ratio. If the State uses a different weekday/weekend activity ratio,
submit separate activity level information for weekday days and weekend
days).
(viii) Source of activity data.
(ix) Pollutant code.
(x) Summer work weekday emissions.
(xi) Ozone season emissions.
(xii) 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 emissions occurring in the year 2003.
(2) Triennial reports are to begin with data for emissions
occurring in the year 2002.
(3) Year 2007 data are to be submitted for emissions occurring in
the year 2007.
(4) States must submit data for a required year no later than 12
months after the end of the calendar year for which the data are
collected.
(h) Data reporting procedures. When submitting a formal
NOX budget emissions report and associated data, States
shall notify the appropriate EPA Regional Office.
(1) States are required to report emissions data in an electronic
format to one of the locations listed in this paragraph (h). 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 to the extent the sources
are subject to a trading program that qualifies for approval under
Sec. 51.121(q) of this part, and the State has agreed to accept 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.
(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 NAAQS. 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 reductions 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) Day/week in operations. Days per week that the emitting process
operates.
(8) Emission factor. Ratio relating emissions of a specific
pollutant to an activity or material throughput level.
(9) Exit gas flow rate. Numeric value of stack gas flow rate.
(10) Exit gas temperature. Numeric value of an exit gas stream
temperature.
(11) Exit gas velocity. Numeric value of an exit gas stream
velocity.
(12) Fall throughput (%). Portion of throughput for the 3 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).
(13) Federal ID code (plant). Unique codes for a plant or facility,
containing one or more pollutant-emitting sources.
(14) Federal ID code (point). Unique codes for the point of
generation of emissions, typically a physical piece of equipment.
(15) Federal ID code (stack number). Unique codes for the point
where emissions from one or more processes are released into the
atmosphere.
(16) 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.
(17) 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.
(18) Hr/day in operations. Hours per day that the emitting process
operates.
(19) Maximum design rate. Maximum fuel use rate based on the
equipment's or process' physical size or operational capabilities.
(20) Maximum nameplate capacity. A measure of the size of a
generator which is put on the unit's nameplate by the manufacturer. The
data element is reported in megawatts (MW) or kilowatts (KW).
[[Page 57498]]
(21) Mobile source. A motor vehicle, nonroad engine or nonroad
vehicle, where:
(i) Motor vehicle means any self-propelled vehicle designed for
transporting persons or property on a street or highway;
(ii) Nonroad engine means an internal combustion engine (including
the fuel system) that is not used in a motor vehicle or a vehicle used
solely for competition, or that is not subject to standards promulgated
under section 111 or section 202 of the CAA;
(iii) Nonroad vehicle means a vehicle that is powered by a nonroad
engine and that is not a motor vehicle or a vehicle used solely for
competition.
(22) Ozone season. The period May 1 through September 30 of a year.
(23) Physical address. Street address of facility.
(24) Point source. A non-mobile source which emits 100 tons of
NOX or more per year unless the State designates as a point
source a non-mobile source emitting at a specified level lower than 100
tons of NOX per year. A non-mobile source which emits less
NOX per year than the point source threshold 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 storage and
retrieval of aerometric data (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 emissions reductions
efficiency of a secondary control device, which shows the amount of
reductions 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 3 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) Summer throughput (%). Portion of throughput or activity for
the 3 summer months (June, July, August). See the definition of Fall
Throughput.
(37) Summer work weekday emissions. Average day's emissions for a
typical day.
(38) VMT by Roadway Class. This 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.
(39) Week/year in operation. Weeks per year that the emitting
process operates.
(40) Work Weekday. Any day of the week except Saturday or Sunday.
(41) X coordinate (latitude). East-west geographic coordinate of an
object.
(42) Y coordinate (longitude). North-south geographic coordinate of
an object.
PART 72--PERMITS REGULATION
1. The authority for part 72 continues to read as follows:
Authority: 42 U.S.C. 7601 and 7651, et seq.
2. Section 72.2 is amended by revising the definition for
``excepted monitoring system,'' and adding new definitions in
alphabetical order for ``low mass emissions unit'', ``maximum potential
hourly heat input'', ``maximum rated hourly heat input,'' and ``ozone
season'' to read as follows:
Sec. 72.2 Definitions.
* * * * *
Excepted monitoring system means a monitoring system that follows
the procedures and requirements of Sec. 75.19 of this chapter or of
appendix D or E to part 75 for approved exceptions to the use of
continuous emission monitoring systems.
* * * * *
Low mass emissions unit means an affected unit that is a gas-fired
or oil-fired unit, burns only natural gas or fuel oil and qualifies
under Sec. 75.19 of this chapter.
* * * * *
Maximum potential hourly heat input means an hourly heat input used
for reporting purposes when a unit lacks certified monitors to report
heat input. If the unit intends to use appendix D of part 75 of this
chapter to report heat input, this value should be calculated, in
accordance with part 75 of this chapter, using the maximum fuel flow
rate and the maximum gross calorific value. If the unit intends to use
a flow monitor and a diluent gas monitor, this value should be
reported, in accordance with part 75 of this chapter, using the maximum
potential flow rate and either the maximum carbon dioxide concentration
(in percent CO2) or the minimum oxygen concentration (in
percent O2).
* * * * *
Maximum rated hourly heat input means a unit-specific maximum
hourly heat input (mmBtu) which is the higher of the manufacturer's
maximum rated hourly heat input or the highest observed hourly heat
input.
* * * * *
Ozone season means the period of time beginning May 1 of a year and
ending on September 30 of the same year, inclusive.
* * * * *
PART 75--CONTINUOUS EMISSION MONITORING
3. The authority citation for part 75 continues to read as follows:
Authority: 42 U.S.C. 7601 and 7651k, 7651 and note.
4. Section 75.1 is amended by revising paragraph (a) to read as
follows:
Sec. 75.1 Purpose and scope.
(a) Purpose. The purpose of this part is to establish requirements
for the monitoring, recordkeeping, and reporting of sulfur dioxide
(SO2), nitrogen oxides (NOX), and carbon dioxide
(CO2) emissions, volumetric flow, and opacity data from
affected units under the Acid Rain Program pursuant to sections 412 and
821 of the CAA, 42 U.S.C. 7401-7671q as amended by Public Law 101-549
(November 15, 1990). In addition, this part sets forth
[[Page 57499]]
provisions for the monitoring, recordkeeping, and reporting of
NOX mass emissions with which EPA, individual States, or
groups of States may require sources to comply in order to demonstrate
compliance with a NOX mass emission reduction program, to
the extent these provisions are adopted as requirements under such a
program.
* * * * *
5. Section 75.2 is amended by revising paragraph (a) and adding a
new paragraph (c) to read as follows:
Sec. 75.2 Applicability.
(a) Except as provided in paragraphs (b) and (c) of this section,
the provisions of this part apply to each affected unit subject to Acid
Rain emission limitations or reduction requirements for SO2
or NOX.
* * * * *
(c) The provisions of this part apply to sources subject to a State
or federal NOX mass emission reduction program, to the
extent these provisions are adopted as requirements under such a
program.
6. Section 75.4 is amended by revising paragraph (a) introductory
text to read as follows:
Sec. 75.4 Compliance dates.
(a) The provisions of this part apply to each existing Phase I and
Phase II unit on February 10, 1993. For substitution or compensating
units that are so designated under the Acid Rain permit which governs
that unit and contains the approved substitution or reduced utilization
plan, pursuant to Sec. 72.41 or Sec. 72.43 of this chapter, the
provisions of this part become applicable upon the issuance date of the
Acid Rain permit. For combustion sources seeking to enter the Opt-in
Program in accordance with part 74 of this chapter, the provisions of
this part become applicable upon the submission of an opt-in permit
application in accordance with Sec. 74.14 of this chapter. The
provisions of this part for the monitoring, recording, and reporting of
NOX mass emissions become applicable on the deadlines
specified in the applicable State or federal NOX mass
emission reduction program, to the extent these provisions are adopted
as requirements under such a program. In accordance with Sec. 75.20,
the owner or operator of each existing affected unit shall ensure that
all monitoring systems required by this part for monitoring
SO2, NOX, CO2, opacity, and volumetric
flow are installed and that all certification tests are completed no
later than the following dates (except as provided in paragraphs (d)
through (h) of this section):
* * * * *
7. Section 75.6 is amended by adding paragraph (f) to read as
follows:
Sec. 75.6 Incorporation by reference.
* * * * *
(f) The following materials are available for purchase from the
following address: American Petroleum Institute, Publications
Department, 1220 L Street NW, Washington, DC 20005-4070.
(1) American Petroleum Institute (API) Petroleum Measurement
Standards, Chapter 3, Tank Gauging: Section 1A, Standard Practice for
the Manual Gauging of Petroleum and Petroleum Products, December 1994;
Section 1B, Standard Practice for Level Measurement of Liquid
Hydrocarbons in Stationary Tanks by Automatic Tank Gauging, April 1992
(reaffirmed January 1997); Section 2, Standard Practice for Gauging
Petroleum and Petroleum Products in Tank Cars, September 1995; Section
3, Standard Practice for Level Measurement of Liquid Hydrocarbons in
Stationary Pressurized Storage Tanks by Automatic Tank Gauging, June
1996; Section 4, Standard Practice for Level Measurement of Liquid
Hydrocarbons on Marine Vessels by Automatic Tank Gauging, April 1995;
and Section 5, Standard Practice for Level Measurement of Light
Hydrocarbon Liquids Onboard Marine Vessels by Automatic Tank Gauging,
March 1997; for Sec. 75.19.
(2) Shop Testing of Automatic Liquid Level Gages, Bulletin 2509 B,
December 1961 (Reaffirmed August 1987, October 1992), for Sec. 75.19.
8. Section 75.11 is amended by removing the period at the end of
paragraph (d)(2) and replacing it with ``; or'' and adding paragraph
(d)(3), to read as follows:
Sec. 75.11 Specific provisions for monitoring SO2 emissions
(SO2 and flow monitors).
* * * * *
(d)* * *
(3) By using the low mass emissions excepted methodology in
Sec. 75.19(c) for estimating hourly SO2 mass emissions if
the affected unit qualifies as a low mass emissions unit under
Sec. 75.19(a) and (b).
* * * * *
9. Section 75.12 is amended by revising the section heading, by
redesignating paragraph (d) as paragraph (e), and by adding new
paragraph (d) to read as follows:
Sec. 75.12 Specific provisions for monitoring NOX emission
rate (NOX and diluent gas monitors).
* * * * *
(d) Low mass emissions units. Notwithstanding the requirements of
paragraphs (a) and (c) of this section, the owner or operator of an
affected unit that qualifies as a low mass emissions unit under
Sec. 75.19(a) and (b) shall comply with one of the following:
(1) Meet the general operating requirements in Sec. 75.10 for a
NOX continuous emission monitoring system;
(2) Meet the requirements specified in paragraph (d)(2) of this
section for using the excepted monitoring procedures in appendix E to
this part, if applicable; or
(3) Use the low mass emissions excepted methodology in
Sec. 75.19(c) for estimating hourly NOX emission rate and
hourly NOX mass emissions, if applicable under Sec. 75.19(a)
and (b).
* * * * *
10. Section 75.13 is amended by adding paragraph (d) to read as
follows:
Sec. 75.13 Specific provisions for monitoring CO2
emissions.
* * * * *
(d) Determination of CO2 mass emissions from low mass
emissions units. The owner or operator of a unit that qualifies as a
low mass emissions unit under Sec. 75.19(a) and (b) shall comply with
one of the following:
(1) Meet the general operating requirements in Sec. 75.10 for a
CO2 continuous emission monitoring system and flow
monitoring system;
(2) Meet the requirements specified in paragraph (b) or (c) of this
section for use of the methods in appendix G or F to this part,
respectively; or
(3) Use the low mass emissions excepted methodology in
Sec. 75.19(c) for estimating hourly CO2 mass emissions, if
applicable under Sec. 75.19(a) and (b).
* * * * *
11. Section 75.17 is amended by adding introductory text before
paragraph (a) to read as follows:
Sec. 75.17 Specific provisions for monitoring emissions from common,
by-pass, and multiple stacks for NOX emission rate.
Notwithstanding the provisions of paragraphs (a), (b), and (c) of
this section, the owner or operator of an affected unit that is using
the procedures in this part to meet the monitoring and reporting
requirements of a State or federal NOX mass emission
reduction program must also meet the provisions for monitoring
NOX emission rate in Secs. 75.71 and 75.72.
* * * * *
12. Section 75.19 is added to subpart B to read as follows:
[[Page 57500]]
Sec. 75.19 Optional SO2, NOX, and CO2
emissions calculation for low mass emissions units.
(a) Applicability. (1) Consistent with the requirements of
paragraphs (a)(2) and (b) of this section, the low mass emissions
excepted methodology in paragraph (c) of this section may be used in
lieu of continuous emission monitoring systems or, if applicable, in
lieu of excepted methods under appendix D or E to this part, for the
purpose of determining hourly heat input and hourly NOX,
SO2, and CO2 mass emissions from a low mass
emissions unit.
(i) A low mass emissions unit is an affected unit that is gas-
fired, or oil-fired unit, that burns only natural gas or fuel oil and
for which:
(A) An initial demonstration is provided, in accordance with
paragraph (a)(2) of this section, which shows that the unit emits no
more than 25 tons of SO2 annually and no more than 50 tons
of NOX annually; and
(B) An annual demonstration is provided thereafter, using one of
the allowable methodologies in paragraph (c) of this section, showing
that the low mass emission unit continues to emit no more than 25 tons
of SO2 annually and no more than 50 tons of NOX
annually.
(ii) Any qualifying unit must start using the low mass emissions
excepted methodology in the first hour in which the unit operates in a
calendar year. Notwithstanding, the earliest date for which a unit that
meets the eligibility requirements of this section may begin to use
this methodology is January 1, 2000.
(2) A unit may initially qualify as a low mass emissions unit only
under the following circumstances:
(i) If the designated representative submits a certification
application to use the low mass emissions excepted methodology and the
Administrator certifies the use of such methodology. The certification
application must contain:
(A) Actual SO2 and NOX mass emissions data
for each of the three calendar years prior to the calendar year in
which the certification application is submitted demonstrating to the
satisfaction of the Administrator that the unit emits less than 25 tons
of SO2 and less than 50 tons of NOX annually; and
(B) Calculated SO2 and NOX mass emissions,
for each of the three calendar years prior to the calendar year in
which the certification application is submitted, demonstrating to the
satisfaction of the Administrator that the unit emits less than 25 tons
of SO2 and less than 50 tons of NOX annually. The
calculated emissions for each year shall be determined using either the
maximum rated heat input methodology described in paragraph (c)(3)(i)
of this section or the long term fuel flow heat input methodology
described in paragraph (c)(3)(ii) of this section, in conjunction with
the appropriate SO2, NOX, and CO2
emission rate from paragraph (c)(1)(i) of this section for
SO2, paragraph (c)(1)(ii) or (c)(1)(iv) of this section for
NOX and paragraph (c)(1)(iii) of this section for
CO2; or
(ii) When the three full years of actual, historical SO2
and NOX mass emissions data required under paragraph
(a)(2)(i) of this section are not available, the designated
representative may submit an application to use the low mass emissions
excepted methodology based upon a combination of historical
SO2 and NOX mass emissions data and projected
SO2 and NOX mass emissions, totaling three years.
Historical data must be used for any years in which historical data
exists and projected data should be used for any remaining future years
needed to provide capacity factor data for three consecutive calender
years. For example, if a unit commenced operation two years ago, the
designated representative may submit actual, historical data for the
previous two years and one year of projected emissions for the current
calendar year or, for unit that commenced operation after January 1,
1997, the designated representative may submit three years of projected
emissions, beginning with the current calendar year. Any actual or
projected annual emissions must demonstrate to the satisfaction of the
Administrator that the unit will emit less than 25 tons of
SO2 and less than 50 tons of NOX annually.
Projected emissions shall be calculated using either the default
emission rates in tables 1,2 and 3 of this section, or for
NOX emission rate a fuel-and-unit-specific NOX
emission rate determined in accordance with the testing procedures in
paragraph (c)(1)(iv) of this section, in conjunction with projections
of unit operating hours or fuel type and fuel usage, according to one
of the allowable calculation methodologies in paragraph (c) of this
section.
(b) On-going qualification and disqualification. (1) Once a low
mass emission unit has qualified for and has started using the low mass
emissions excepted methodology, an annual demonstration is required,
showing that the unit continues to emit less than 25 tons of
SO2 annually and less than 50 tons of NOX
annually. The calculation methodology used for the annual demonstration
shall be the same methodology, from paragraph (c) of this section, by
which the unit initially qualified to use the low mass emissions
excepted methodology.
(2) If any low mass emission unit fails to provide the required
annual demonstration under paragraph (b)(1) of this section, such that
the calculated cumulative year-to-date emissions for the unit exceed 25
tons of SO2 or 50 tons of NOX in any calendar
quarter of any calendar year, then;
(i) The low mass emission unit shall be disqualified from using the
low mass emissions excepted methodology as of the end of the second
calendar quarter following such quarter in which either the 25 ton
limit for SO2 or the 50 ton limit for NOX was
exceeded; and
(ii) The owner or operator of the low mass emission unit shall have
two calendar quarters from the end of the quarter in which the unit
exceeded the 25 ton limit for SO2 or the 50 ton limit for
NOX to install, certify, and report SO2,
NOX, and CO2 emissions from monitoring systems
that meet the requirements of Secs. 75.11, 75.12, and 75.13.
(3) If a low mass emission unit that initially qualifies to use the
low mass emissions excepted methodology under this section changes
fuels, such that a fuel other than those allowed for use in the low
mass emissions methodology (e.g. natural gas or fuel oil) is combusted
in the unit, the unit shall be disqualified from using the low mass
emissions excepted methodology as of the first hour that the new fuel
is combusted in the unit. The owner or operator shall install, certify,
and report SO2, NOX, and CO2 from
monitoring systems that meet the requirements of Secs. 75.11, 75.12,
and 75.13 prior to a change to such fuel. The owner or operator must
notify the Administrator in the case where a unit switches fuels
without previously having installed and certified a SO2,
NOX and CO2 monitoring system meeting the
requirements of Secs. 75.11, 75.12, and 75.13.
(4) If a unit commencing operation after January 1, 1997 initially
qualifies to use the low mass emissions excepted methodology under this
section and the owner or operator wants to use a low mass emissions
methodology for the unit, he or she must:
(i) Keep the records specified in paragraph (c)(2) of this section,
beginning with the date and hour of commencement of commercial
operation, for a unit subject to an Acid Rain emission limitation, and
beginning with the date and hour of the commencement of operation, for
a unit subject to a NOX mass reduction program;
[[Page 57501]]
(ii) Use these records to determine the cumulative heat input and
SO2, NOX, and CO2 mass emissions in
order to continue to qualify as a low mass emission unit; and
(iii) Determine the cumulative SO2 and NOX
mass emissions according to paragraph (c) of this section using the
same procedures used after the certification deadline for the unit, for
purposes of demonstrating eligibility to use the excepted methodology
set forth in this section. For example, use the default emission rates
in tables 1, 2 and 3 of this section or use the fuel-and-unit-specific
NOX emission rate determined according to paragraph
(c)(1)(iv) of this section. The Administrator will not count
SO2 mass emissions calculated for the period between
commencement of commercial operation and the certification deadline for
the unit under Sec. 75.4 against SO2 allowances to be held
in the unit account.
(5) A low mass emission unit that has been disqualified from using
the low mass emissions excepted methodology may subsequently qualify
again to use the low mass emissions methodology under paragraph (a)(2)
of this section, provided that if such unit qualified under paragraph
(a)(2)(ii) of this section, the unit may subsequently qualify again
only if the unit meets the requirements of paragraph (a)(2)(i) of this
section.
(c) Low mass emissions excepted methodology, calculations, and
values.
(1) Determination of SO2, NOX, and
CO2 emission rates.
(i) Use Table 1 of this section to determine the appropriate
SO2 emission rate for use in calculating hourly
SO2 mass emissions under this section.
(ii) Use either the appropriate NOX emission factor from
Table 2 of this section, or a fuel-and-unit-specific NOX
emission rate determined according to paragraph (c)(1)(iv) of this
section, to calculate hourly NOX mass emissions under this
section.
(iii) Use Table 3 of this section to determine the appropriate
CO2 emission rate for use in calculating hourly
CO2 mass emissions under this section.
(iv) In lieu of using the default NOX emission rate from
Table 2 of this section, the owner or operator may, for each fuel
combusted by a low mass emission unit, determine a fuel-and-unit-
specific NOX emission rate for the purpose of calculating
NOX mass emissions under this section. This option may be
used by any unit which qualifies to use the low mass emission excepted
methodology under paragraph (a) of this section, and also by groups of
units which combust fuel from a common source of supply and which use
the long term fuel flow methodology under paragraph (c)(3)(ii) of this
section to determine heat input. If this option is chosen, the
following procedures shall be used.
(A) Except as otherwise provided in paragraphs (c)(1)(iv)(F) and
(G) of this paragraph, determine a fuel-and-unit-specific
NOX emission rate by conducting a four load NOX
emission rate test procedure as specified in section 2.1 of appendix E
to this part, for each type of fuel combusted in the unit. For a group
of units sharing a common fuel supply, the appendix E testing must be
performed on each individual unit in the group, unless some or all of
the units in the group belong to an identical group of units, as
defined in paragraph (c)(1)(iv)(B) of this section, in which case,
representative testing may be conducted on units in the identical group
of units, as described in paragraph (c)(1)(iv)(B) of this section. For
the purposes of this section, make the following modifications to the
appendix E test procedures:
(1) Do not measure the heat input as required under 2.1.3 of
appendix E to this part.
(2) Do not plot the test results as specified under 2.1.6 of
appendix E to this part.
(B) Representative appendix E testing may be done on low mass
emission units in a group of identical units. All of the units in a
group of identical units must combust the same fuel type but do not
have to share a common fuel supply.
(1) To be considered identical, all low mass emission units must be
of the same size (based on maximum rated hourly heat input),
manufacturer and model, and must have the same history of modifications
(e.g., have the same controls installed, the same types of burners and
have undergone major overhauls at the same frequency (based on hours of
operation)). Also, under similar operating conditions, the stack or
turbine outlet temperature of each unit must be within 50
degrees Fahrenheit of the average stack or turbine outlet temperature
for all of the units.
(2) If all of the low mass emission units in the group qualify as
identical, then representative testing of the units in the group may be
performed according to Table 4 of this section.
(3) If there are only two low mass emission units in the group of
identical units, the results of the representative testing under
paragraph (c)(1)(iv)(B)(1) of this section may be used to establish the
fuel-and-unit-specific NOX emission rate(s) for the units.
However, if there are more than two low mass emission units in the
group, the testing must confirm that the units are identical by meeting
the following criteria. The results of the representative testing may
only be used to establish the fuel-and-unit-specific NOX
emission rate(s) for such units if the following criteria are met:
(i) at each of the four load levels tested, the NOX
emission rate for each tested low mass emission unit does not differ by
more than 10% from the average of the NOX
emission rates for all units tested, or;
(ii) if the average NOX emission rate of all low mass
emission units tested at all four load levels is less than 0.20 lb/
mmBtu, an alternative criteria of 0.020 lb/mmBtu may be use
in lieu of the 10% criteria. Units must all be within +0.020 lb/mmBtu
of the average from the test to be considered identical units under
this section.
(4) If the acceptance criteria in paragaph (c)(1)(iv)(B)(3) of this
section are not met then the group of low mass emission units is not
considered an identical group of units and individual appendix E
testing of each unit is required.
(5) Fuel and unit specific NOX emission rates determined
according to paragraphs (c)(1)(iv)(F) and (c)(1)(iv)(G) of this section
may be used in lieu of appendix E testing for one or more low mass
emission units in a group of identical units.
(C) Based on the results of the appendix E testing, determine the
fuel-and-unit-specific NOX emission rate as follows:
(1) For an individual low mass emission unit with no NOX
emissions controls of any kind, the highest NOX emission
rate obtained for a particular type of fuel in the appendix E test
multiplied by 1.15 shall be the fuel-and-unit-specific NOX
emission rate, for that type of fuel.
(2) For a group of low mass emission units sharing a common fuel
supply with no NOX controls of any kind on any of the units,
the highest NOX emission rate obtained for a particular type
of fuel in all of the appendix E tests of all units in the group of
units sharing a common fuel supply multiplied by 1.15 shall be the
fuel-and-unit-specific NOX emission rate for each unit in
the group, for that type of fuel.
(3) For a group of identical low mass emission units which perform
representative testing according to paragraph (c)(1)(iv)(B) of this
section with no NOX controls of any kind on any of the
units, the fuel-and-unit-specific NOX emission rate for all
units, for a particular type of fuel, multiplied by 1.15 shall be the
highest NOX
[[Page 57502]]
emission rate from any unit tested in the group, for that type of fuel.
(4) For an individual low mass emission unit which has
NOX emission controls of any kind, the fuel-and-unit-
specific NOX emission rate for each type of fuel combusted
in the unit shall be the higher of:
(i) The highest emission rate from the appendix E test for that
type of fuel multiplied by 1.15; or
(ii) 0.15 lb/mmBtu.
(5) For a group of low mass emission units sharing a common fuel
supply, one or more of which has NOX controls of any kind,
the fuel-and-unit-specific NOX emission rate for each unit
in the group of units sharing a common fuel supply shall, for a
particular type of fuel combusted by the group of units sharing a
common fuel supply, shall be the higher of:
(i) The highest NOX emission rate from all appendix E
tests of all low mass emission units in the group for that type of fuel
multiplied by 1.15; or
(ii) 0.15 lb/mmBtu.
(6) For a group of identical low mass emission units, which perform
representative testing according to paragraph (c)(1)(iv)(B) of this
section and have identical NOX controls, the fuel-and-unit-
specific NOX emission rate for each unit in the group of
units, for a particular type of fuel, shall be the higher of:
(i) The highest NOX emission rate from all appendix E
tests of all tested low mass emission units in the group of identical
units for that type of fuel multiplied by 1.15; or
(ii) 0.15 lb/mmBtu.
(D) For each low mass emission unit, each unit in a group of units
sharing a common fuel supply, or identical units for which the
provisions of paragraph (c)(1)(iv) of this section are used to account
for NOX emission rate, the owner or operator shall determine
a new fuel-and-unit-specific NOX emission rate every five
years, unless changes in the fuel supply, physical changes to the unit,
changes in the manner of unit operation, or changes to the emission
controls occur which may cause a significant increase in the unit's
actual NOX emission rate. If such changes occur, the fuel-
and-unit-specific NOX emission rate(s) shall be re-
determined according to paragraph (c)(1)(iv) of this section. If a low
mass emission unit belongs to a group of identical units and it is
required to retest to determine a new fuel-and-unit-specific
NOX emission rate because of changes in the fuel supply,
physical changes to the unit, changes in the manner of unit operation
or changes to the emission controls occur which may cause a significant
increase in the unit's actual NOX emission rate, any other
unit in that group of identical units is not required to re-determine
the fuel-and-unit-specific NOX emission rate unless such
unit also undergoes changes in the fuel supply, physical changes to the
unit, changes in the manner of unit operation or changes to the
emission controls occur which may cause a significant increase in the
unit's actual NOX emission rates.
(E) Each low mass emission unit, each low mass emission unit in a
group of units combusting a common fuel, or each low mass emission unit
in a group of identical units for which a fuel-and-unit-specific
NOX emission rate(s) are determined shall meet the quality
assurance and quality control provisions of paragraph (e) of this
section.
(F) Low mass emission units may use the results of appendix E
testing, if such test results are available from a test conducted no
more than five years prior to the time of initial certification, to
determine the appropriate fuel-and-unit-specific NOX
emission rate(s). However, fuel-and-unit-specific NOX
emission rates from historical testing may not be used longer than five
years after the appendix E testing was conducted.
(G) Low mass emission units for which at least 3 years of
NOX emission rate continuous emissions monitoring system
data and corresponding fuel usage data are available may determine
fuel-and-unit-specific NOX emission rates from the actual
data using the following procedure. Separate the actual NOX
emission rate data into groups, according to the type of fuel
combusted. Discard data from periods when multiple fuels were
combusted. Each fuel-specific data set must contain at least 168 hours
of data and must represent all normal operating ranges of the unit when
combusting the fuel. Sort the data in each fuel-specific data set in
ascending order according to NOX emission rate. Determine
the 95th percentile NOX emission rate for each data set as
defined in Sec. 72.2 of this chapter. Use the 95th percentile value for
each data set as the fuel-and-unit-specific NOX emission
rate, except that for a unit with NOX emission controls of
any kind, if the 95th percentile value is less than 0.15 lb/mmBtu, a
value of 0.15 lb/mmBtu shall be used as the fuel-and-unit-specific
NOX emission rate.
(H) For low mass emission units with NOX emission
controls, the owner or operator shall, during every hour of unit
operation during the test period, monitor and record parameters, as
required under paragraph (e)(5) of this section, which indicate that
the NOX emission controls are operating properly. After the
test period, these same parameters shall be monitored and recorded and
kept for all operating hours in order to determine whether the
NOX controls are operating properly and to allow the
determination of the correct NOX emission rate as required
under paragraph (c)(1)(iv) of this section.
(1) For low mass emission units with steam or water injection, the
steam-to-fuel or water-to-fuel ratio used during the testing must be
documented. The water-to-fuel or steam-to-fuel ratio must be maintained
during unit operations for a unit to use the fuel and unit specific
NOX emission rate determined during the test. Owners or
operators must include in the monitoring plan the acceptable range of
the water-to-fuel or steam-to-fuel ratio, which will be used to
indicate hourly, proper operation of the NOX controls for
each unit. The water-to-fuel or steam-to-fuel ratio shall be monitored
and recorded during each hour of unit operation. If the water-to-fuel
or steam-to-fuel ratio is not within the acceptable range in a given
hour the fuel and unit specific NOX emission rate may not be
used for that hour.
(2) For low mass emission units with other types of NOX
controls, appropriate parameters and the acceptable range of the
parameters which indicate hourly proper operation of the NOX
controls must be specified in the monitoring plan. These parameters
shall be monitored during each subsequent operating hour. If any of
these parameters are not within the acceptable range in a given
operating hour, the fuel and unit specific NOX emission
rates may not be used in that hour.
(2) Records of operating time, fuel usage, unit output and
NOX emission control operating status. The owner or operator
shall keep the following records on-site, for three years, in a form
suitable for inspection:
(i) For each low mass emission unit, the owner or operator shall
keep hourly records which indicate whether or not the unit operated
during each clock hour of each calendar year. The owner or operator may
report partial operating hours or may assume that for each hour the
unit operated the operating time is a whole hour. Units using partial
operating hours and the maximum rated hourly heat input to calculate
heat input for each hour must report partial operating hours.
(ii) For each low mass emissions unit, the owner or operator shall
keep hourly records indicating the type(s) of fuel(s) combusted in the
unit during each hour of unit operation.
(iii) For each low mass emission unit using the long term fuel flow
methodology under paragraph (c)(3)(ii)
[[Page 57503]]
of this section to determine hourly heat input, the owner or operator
shall keep hourly records of unit output (in megawatts or thousands of
pounds of steam), for the purpose of apportioning heat input to the
individual unit operating hours.
(iv) For each low mass emission unit with NOX emission
controls of any kind, the owner or operator shall keep hourly records
of the hourly value of the parameter(s) specified in (c)(1)(iv)(H) of
this section used to indicate proper operation of the unit's
NOX controls.
(3) Heat input. Hourly, quarterly and annual heat input for a low
mass emission unit shall be determined using either the maximum rated
hourly heat input method under paragraph (c)(3)(i) of this section or
the long term fuel flow method under paragraph (c)(3)(ii) of this
section.
(i) Maximum rated hourly heat input method. (A) For the purposes of
the mass emission calculation methodology of paragraph (c)(3) of this
section, the hourly heat input (mmBtu) to a low mass emission unit
shall be deemed to equal the maximum rated hourly heat input, as
defined in Sec. 72.2 of this chapter, multiplied by the operating time
of the unit for each hour. The owner or operator may choose to record
and report partial operating hours or may assume that a unit operated
for a whole hour for each hour the unit operated. However, the owner or
operator of a unit may petition the Administrator under Sec. 75.66 for
a lower value for maximum rated hourly heat input than that defined in
Sec. 72.2 of this chapter. The Administrator may approve such lower
value if the owner or operator demonstrates that either the maximum
hourly heat input specified by the manufacturer or the highest observed
hourly heat input, or both, are not representative, and such a lower
value is representative, of the unit's current capabilities because
modifications have been made to the unit, limiting its capacity
permanently.
(B) The quarterly heat input, HIqtr, in mmBtu, shall be
determined using Equation LM-1:
HIqtr = Tqtr x HIhr (Eq. LM-1)
Where:
Tqtr = Actual number of operating hours in the quarter (hr).
HIhr = Hourly heat input under paragraph (c)(3)(i)(A) of
this section (mmBtu).
(C) The year-to-date cumulative heat input (mmBtu) shall be the sum
of the quarterly heat input values for all of the calendar quarters in
the year to date.
(ii) Long term fuel flow heat input method. The owner or operator
may, for the purpose of demonstrating that a low mass emission unit or
group of low mass emission units sharing a common fuel supply meets the
requirements of this section, use records of long-term fuel flow, to
calculate hourly heat input to a low mass emission unit.
(A) This option may be used for a group of low mass emission units
only if:
(1) The low mass emission units combust fuel from a common source
of supply; and
(2) Records are kept of the total amount of fuel combusted by the
group of low mass emission units and the hourly output (in megawatts or
pounds of steam) from each unit in the group; and
(3) All of the units in the group are low mass emission units.
(B) For each fuel used during the quarter, the volume in standard
cubic feet (for gas) or gallons (for oil) may be determined using any
of the following methods;
(1) Fuel billing records (for low mass emission units, or groups of
low mass emission units, which purchase fuel from non-affiliated
sources);
(2) American Petroleum Institute (API) standard, American Petroleum
Institute (API) Petroleum Measurement Standards, Chapter 3, Tank
Gauging: Section 1A, Standard Practice for the Manual Gauging of
Petroleum and Petroleum Products, December 1994; Section 1B, Standard
Practice for Level Measurement of Liquid Hydrocarbons in Stationary
Tanks by Automatic Tank Gauging, April 1992 (reaffirmed January 1997);
Section 2, Standard Practice for Gauging Petroleum and Petroleum
Products in Tank Cars, September 1995; Section 3, Standard Practice for
Level Measurement of Liquid Hydrocarbons in Stationary Pressurized
Storage Tanks by Automatic Tank Gauging, June 1996; Section 4, Standard
Practice for Level Measurement of Liquid Hydrocarbons on Marine Vessels
by Automatic Tank Gauging, April 1995; and Section 5, Standard Practice
for Level Measurement of Light Hydrocarbon Liquids Onboard Marine
Vessels by Automatic Tank Gauging, March 1997; Shop Testing of
Automatic Liquid Level Gages, Bulletin 2509 B, December 1961
(Reaffirmed August 1987, October 1992) (incorporated by reference under
Sec. 75.6); or;
(3) A fuel flow meter certified and maintained according to
appendix D to this part.
(C) For each fuel combusted during a quarter, the gross calorific
value of the fuel shall be determined by either:
(1) Using the applicable procedures for gas and oil analysis in
sections 2.2 and 2.3 of appendix D to this part. If this option is
chosen the highest gross calorific value recorded during the previous
calendar year shall be used; or
(2) Using the appropriate default gross calorific value listed in
Table 5 of this section.
(D) For each type of fuel oil combusted during the quarter, the
specific gravity of the oil shall be determined either by:
(1) Using the procedures in section 2.2.6 of appendix D to this
part. If this option is chosen, use the highest specific gravity value
recorded during the previous calendar year shall be used; or
(2) Using the appropriate default specific gravity value in Table 5
of this section.
(E) The quarterly heat input from each type of fuel combusted
during the quarter by a low mass emission unit or group of low mass
emission units sharing a common fuel supply shall be determined using
Equation LM-2 for oil and LM-3 for natural gas.
[GRAPHIC] [TIFF OMITTED] TR27OC98.001
Eq LM-2 (for fuel oil or diesel fuel)
Where:
HIfuel-qtr = Quarterly total heat input from oil (mmBtu).
Mqtr = Mass of oil consumed during the entire quarter,
determined as the product of the volume of oil under paragraph
(c)(3)(ii)(B) of this section and the specific gravity under paragraph
(c)(3)(ii)(D) of this section (lb)
GCVmax = Gross calorific value of oil, as determined under
paragraph (c)(3)(ii)(C) of this section (Btu/lb)
10\6\ = Conversion of Btu to mmBtu.
[GRAPHIC] [TIFF OMITTED] TR27OC98.002
Eq LM-3 (for natural gas)
Where:
HIfuel-qtr = Quarterly heat input from natural gas (mmBtu).
Qg = Value of natural gas combusted during the quarter, as
determined under paragraph (c)(3)(ii)(B) of this section standard cubic
feet (scf).
GCVg = Gross calorific value of the natural gas combusted
during the quarter, as determined under paragraph (c)(3)(ii)(C) of this
section (Btu/scf)
10\6\ = Conversion of Btu to mmBtu.
(F) The quarterly heat input (mmBtu) for all fuels for the quarter,
HIqtr-total, shall be the sum of the
HIfuel-qtr values determined using Equations LM-2 and LM-3.
[[Page 57504]]
[GRAPHIC] [TIFF OMITTED] TR27OC98.003
(Eq. LM-4)
(G) The year-to-date cumulative heat input (mmBtu) for all fuels
shall be the sum of all quarterly total heat input
(HIqtr-total) values for all calendar quarters in the year
to date.
(H) For each low mass emission unit, each low mass emission unit of
an identical group of units, or each low mass emission unit in a group
of units sharing a common fuel supply, the owner or operator shall
determine the quarterly unit output in megawatts or pounds of steam.
The quarterly unit output shall be the sum of the hourly unit output
values recorded under paragraph (c)(2) of this section and shall be
determined using Equations LM-5 or LM-6.
[GRAPHIC] [TIFF OMITTED] TR27OC98.004
Eq LM-5 (for MW output)
[GRAPHIC] [TIFF OMITTED] TR27OC98.005
Eq LM-6 (for steam output)
Where:
MWqtr = the power produced during all hours of operation
during the quarter by the unit (MW)
STfuel-qtr = the total quarterly steam output produced
during all hours of operation during the quarter by the unit (klb)
MW = the power produced during each hour in which the unit operated
during the quarter (MW).
ST = the steam output produced during each hour in which the unit
operated during the quarter (klb)
(I) For a low mass emission unit that is not included in a group of
low mass emission units sharing a common fuel supply, apportion the
total heat input for the quarter, HIqtr-total to each hour
of unit operation using either Equation LM-7 or LM-8:
[GRAPHIC] [TIFF OMITTED] TR27OC98.006
(Eq LM-7 for MW output)
[GRAPHIC] [TIFF OMITTED] TR27OC98.007
(Eq LM-8 for steam output)
Where:
HIhr = hourly heat input to the unit (mmBtu)
MWhr = hourly output from the unit (MW)
SThr = hourly steam output from the unit (klb)
(J) For each low mass emission unit that is included in a group of
units sharing a common fuel supply, apportion the total heat input for
the quarter, HIqtr-total to each hour of operation using
either Equation LM-7a or LM-8a:
[GRAPHIC] [TIFF OMITTED] TR27OC98.008
(Eq LM-7a for MW output)
[GRAPHIC] [TIFF OMITTED] TR27OC98.009
(Eq LM-8a for steam output)
Where:
HIhr = hourly heat input to the individual unit (mmBtu)
MWhr = hourly output from the individual unit (MW)
SThr = hourly steam output from the individual unit (klb)
[GRAPHIC] [TIFF OMITTED] TR27OC98.010
(4) Calculation of SO2, NOX and
CO2 mass emissions. The owner or operator shall, for the
purpose of demonstrating that a low mass emission unit meets the
requirements of this section, calculate SO2, NOX
and CO2 mass emissions in accordance with the following.
(i) SO2 mass emissions. (A) The hourly SO2
mass emissions (lbs) for a low mass emission unit shall be determined
using Equation LM-9 and the appropriate fuel-based SO2
emission factor from Table 1 of this section for the fuels combusted in
that hour. If more than one fuel is combusted in the hour, use the
highest emission factor for all of the fuels combusted in the hour. If
records are missing as to which fuel was combusted in the hour, use the
highest emission factor for all of the fuels capable of being combusted
in the unit.
WSO2=EFSO2 x HIhr (Eq. LM-9)
where:
WSO2=Hourly SO2 mass emissions (lbs).
EFSO2=SO2 emission factor from Table 1 of this
section (lb/mmBtu).
HIhr=Either the maximum rated hourly heat input under
paragraph (c)(3)(i)(A) of this section or the hourly heat input under
paragraph (c)(3)(ii) of this section (mmBtu).
(B) The quarterly SO2 mass emissions (tons) for the low
mass emission unit shall be the sum of all the hourly SO2
mass emissions in the quarter, as determined under paragraph
(c)(4)(i)(A) of this section, divided by 2000 lb/ton.
(C) The year-to-date cumulative SO2 mass emissions
(tons) for the low mass emission unit shall be the sum of the quarterly
SO2 mass emissions, as determined under paragraph
(c)(4)(i)(B) of this section, for all of the calendar quarters in the
year to date.
(ii) NOX mass emissions. (A) The hourly NOX
mass emissions for the low mass emission unit (lbs) shall be determined
using Equation LM-10. If more than one fuel is combusted in the hour,
use the highest emission rate for all of the fuels combusted in the
hour. If records are missing as to which fuel was combusted in the
hour, use the highest emission factor for all of the fuels capable of
being combusted in the unit. For low mass emission units with
NOX emission controls of any kind and for which a fuel-and-
unit-specific NOX emission rate is determined under
paragraph (c)(1)(iv) of this section, for any hour in which the
parameters under paragraph (c)(1)(iv)(A) of this section do not show
that the NOX emission controls are operating properly, use
the NOX emission rate from Table 2 of this section for the
fuel combusted during the hour with the highest NOX emission
rate.
WNOx=EFNOx x HIhr (Eq. LM-10)
Where:
WNOX=Hourly NOX mass emissions (lbs).
EFNOX=Either the NOX emission factor from Table
1b of paragraph (c)(1)(ii) of this section of this section or the fuel-
and-unit-specific NOX emission rate determined under
paragraph (c)(1)(iv) of this section (lb/mmBtu).
HIhr=Either the maximum rated hourly heat input from
paragraph (c)(3)(i)(A) of this section or the hourly heat input as
determined under paragraph(c)(3)(ii) of this section (mmBtu).
(B) The quarterly NOX mass emissions (tons) for the low
mass emission unit shall be the sum of all of the hourly NOX
mass emissions in the quarter, as determined under paragraph
(c)(4)(ii)(A) of this section, divided by 2000 lb/ton.
(C) The year-to-date cumulative NOX mass emissions
(tons) for the low mass emission unit shall be the sum of the
[[Page 57505]]
quarterly NOX mass emissions, as determined under paragraph
(c)(4)(ii)(B) of this section, for all of the calendar quarters in the
year to date.
(iii) CO2 Mass Emissions. (A) The hourly CO2
mass emissions (tons) for the affected low mass emission unit shall be
determined using Equation LM-11 and the appropriate fuel-based
CO2 emission factor from Table 3 of this section for the
fuel being combusted in that hour. If more than one fuel is combusted
in the hour, use the highest emission factor for all of the fuels
combusted in the hour. If records are missing as to which fuel was
combusted in the hour, use the highest emission factor for all of the
fuels capable of being combusted in the unit.
WCO2 = EFCO2 x HIhr (Eq. LM-11)
Where:
WCO2 = Hourly CO mass emissions (tons).
EFCO2 = Fuel-based CO2 emission factor from Table
3 of this section (ton/mmBtu).
HIhr = Either the maximum rated hourly heat input from
paragraph (c)(3)(i)(A) of this section or the hourly heat input as
determined under paragraph (c)(3)(ii) of this section (mmBtu).
(B) The quarterly CO2 mass emissions (tons) for the low
mass emission unit shall be the sum of all of the hourly CO2
mass emissions in the quarter, as determined under paragraph
(c)(4)(iii)(A)of this section.
(C) The year-to-date cumulative CO2 mass emissions
(tons) for the low mass emission unit shall be the sum of all of the
quarterly CO2 mass emissions, as determined under paragraph
(c)(4)(iii)(B) of this section, for all of the calendar quarters in the
year to date.
(d) Each unit that qualifies under this section to use the low mass
emissions methodology must follow the recordkeeping and reporting
requirements pertaining to low mass emissions units in subparts F and G
of this part.
(e) The quality control and quality assurance requirements in
Sec. 75.21 are not applicable to a low mass emissions unit for which
the low mass emissions excepted methodology under paragraph (c) of this
section is being used in lieu of a continuous emission monitoring
system or an excepted monitoring system under appendix D or E to this
part, except for fuel flowmeters used to meet the provisions in
paragraph (c)(3)(ii) of this section. However, the owner or operator of
a low mass emissions unit shall implement the following quality
assurance and quality control provisions:
(1) For low mass emission units or groups of units which use the
long term fuel flow methodology under paragraph (c)(3)(ii) of this
section and which use fuel billing records to determine fuel usage, the
owner or operator shall keep, at the facility, for three years, the
records of the fuel billing statements used for long term fuel flow
determinations.
(2) For low mass emission units or groups of units which use the
long term fuel flow methodology under paragraph (c)(3)(ii) of this
section and which use American Petroleum Institute (API) standard,
American Petroleum Institute (API) Petroleum Measurement Standards,
Chapter 3, Tank Gauging: Section 1A, Standard Practice for the Manual
Gauging of Petroleum and Petroleum Products, December 1994; Section 1B,
Standard Practice for Level Measurement of Liquid Hydrocarbons in
Stationary Tanks by Automatic Tank Gauging, April 1992 (reaffirmed
January 1997); Section 2, Standard Practice for Gauging Petroleum and
Petroleum Products in Tank Cars, September 1995; Section 3, Standard
Practice for Level Measurement of Liquid Hydrocarbons in Stationary
Pressurized Storage Tanks by Automatic Tank Gauging, June 1996; Section
4, Standard Practice for Level Measurement of Liquid Hydrocarbons on
Marine Vessels by Automatic Tank Gauging, April 1995; and Section 5,
Standard Practice for Level Measurement of Light Hydrocarbon Liquids
Onboard Marine Vessels by Automatic Tank Gauging, March 1997, Shop
Testing of Automatic Liquid Level Gages, Bulletin 2509 B, December 1961
(Reaffirmed August 1987, October 1992) (incorporated by reference under
Sec. 75.6), to determine fuel usage, the owner or operator shall keep,
at the facility, a copy of the standard used and shall keep records,
for three years, of all measurements obtained for each quarter using
the methodology.
(3) For low mass emission units or groups of units which use the
long term fuel flow methodology under paragraph (c)(3)(ii) of this
section and which use a certified fuel flow meter to determine fuel
usage, the owner or operator shall comply with the quality control
quality assurance requirements for a fuel flow meter under section
2.1.6 of appendix D of this part.
(4) For each low mass emission unit for which fuel-and-unit-
specific NOX emission rates are determined in accordance
with paragraph (c)(1)(iv) of this section, the owner or operator shall
keep, at the facility, records which document the results of all
NOX emission rate tests conducted according to appendix E to
this part. If CEMS data are used to determine the fuel-and-unit-
specific NOX emission rates under paragraph (c)(1)(iv)(G) of
this section, the owner or operator shall keep, at the facility,
records of the CEMS data and the data analysis performed to determine a
fuel-and-unit-specific NOX emission rate. The appendix E
test records and historical CEMS data records shall be kept until the
fuel and unit specific NOX emission rates are re-determined.
(5) For each low mass emission unit for which fuel-and-unit-
specific NOX emission rates are determined in accordance
with paragraph (c)(1)(iv) of this section and which have NOX
emission controls of any kind, the owner or operator shall develop and
keep on-site a quality assurance plan which explains the procedures
used to document proper operation of the NOX emission
controls. The plan shall include the parameters monitored (e.g., water-
to-fuel ratio) and the acceptable ranges for each parameter used to
determine proper operation of the unit's NOX controls.
Table 1 of Sec. 75.19: SO2 Emission Factors (lb/mmBtu) for Various Fuel
Types
------------------------------------------------------------------------
Fuel type SO2 emission factors
------------------------------------------------------------------------
Pipeline Natural Gas...................... 0.0006 lb/mmBtu.
Other Natural Gas......................... 0.06 lb/mmBtu.
Residual Oil.............................. 2.1 lb/mmBtu.
Diesel Fuel............................... 0.5 lb/mmBtu.
------------------------------------------------------------------------
Table 2 of Sec. 75.19: NOX Emission Rates (lb/mmBtu) for Various Boiler/
Fuel Types
------------------------------------------------------------------------
NOX
Boiler type Fuel type emission
rate
------------------------------------------------------------------------
Turbine................................ Gas................. 0.7
Turbine................................ Oil................. 1.2
Boiler................................. Gas................. 1.5
Boiler................................. Oil................. 2
------------------------------------------------------------------------
Table 3 of Sec. 75.19: CO2 Emission Factors (ton/mmBtu) for Gas and Oil
------------------------------------------------------------------------
Fuel type CO2 emission factors
------------------------------------------------------------------------
Natural Gas............................... 0.059 ton/mmBtu.
Oil....................................... 0.081 ton/mmBtu.
------------------------------------------------------------------------
Table 4 of Sec. 75.19: Identical Unit Testing Requirements
------------------------------------------------------------------------
Number of appendix E tests
Number of identical units in the group required
------------------------------------------------------------------------
2......................................... 1
3 to 6.................................... 2
[[Page 57506]]
7......................................... 3
> 7....................................... n tests; wheren n = number
of units divided by 3 and
rounded to nearest integer.
------------------------------------------------------------------------
Table 5 of Sec. 75.19: Default Gross Calorific Values (GCVs) for
Various Fuels
------------------------------------------------------------------------
GCV for use in equation LM-2
Fuel or LM-3
------------------------------------------------------------------------
Pipeline Natural Gas...................... 1051 Btu/scf.
Natural Gas............................... 1118 Btu/scf.
Residual Oil.............................. 19,708 Btu/gallon.
Diesel Fuel............................... 20,500 Btu/gallon.
------------------------------------------------------------------------
Table 6 of Sec. 75.19: Default Specific Gravity Values for Fuel Oil
------------------------------------------------------------------------
Specific
Fuel gravity
(lb/gal)
------------------------------------------------------------------------
Residual Oil................................................ 8.5
Diesel Fuel................................................. 7.4
------------------------------------------------------------------------
13. Section 75.20 is amended by adding new paragraph (h) to read as
follows:
Sec. 75.20 Certification and recertification procedures.
* * * * *
(h) Initial certification and recertification procedures for low
mass emission units using the excepted methodologies under Sec. 75.19.
The owner or operator of a gas-fired or oil-fired unit using the low
mass emissions excepted methodology under Sec. 75.19 shall meet the
applicable general operating requirements of Sec. 75.10, the applicable
requirements of Sec. 75.19, and the applicable certification
requirements of this paragraph.
(1) Monitoring plan. The designated representative shall submit a
monitoring plan in accordance with Secs. 75.53 and 75.62. The
designated representative for an owner or operator who wishes to use
fuel-and unit-specific NOX emission rate testing for units
with NOX controls under Sec. 75.19(c)(1)(iv) must submit in
the monitoring plan the parameters monitored which will be used to
determine operation of the NOX emission controls. For units
using water or steam injection to control NOX, the water-to-
fuel or steam-to-fuel range of values must be documented.
(2) Certification application. [reserved]
(3) Approval of certification applications. The provisions for the
certification application formal approval process in the introductory
text of paragraph (a)(4) and in paragraphs (a)(4)(i), (ii), and (iv) of
this section shall apply, except that ``continuous emission or opacity
monitoring system'' shall be replaced with ``excepted methodology.''
The excepted methodology shall be deemed provisionally certified for
use under the Acid Rain Program, as of the following dates:
(i) For a unit that commenced operation on or before January 1,
1997, from January 1 of the year following submission of the
certification application until the completion of the period for the
Administrator's review; or
(ii) For a unit that commenced operation after January 1, 1997,
from the date of submission of a certification application for approval
to use the low mass emissions excepted methodology under Sec. 75.19
until the completion of the period for the Administrator's review,
except that the methodology may be used retrospectively until the date
and hour that the unit commenced operation for purposes of
demonstrating that the unit qualified to use the methodology under
Sec. 75.19(b)(4)(iii).
(4) Disapproval of certification applications. If the Administrator
determines that the certification application does not demonstrate that
the unit meets the requirements of Secs. 75.19(a) and (b), the
Administrator shall issue a written notice of disapproval of the
certification application within 120 days of receipt. By issuing the
notice of disapproval, the provisional certification is invalidated by
the Administrator, and the data recorded under the excepted methodology
shall not be considered valid. The owner or operator shall follow the
procedures for loss of certification:
(i) The owner or operator shall substitute the following values, as
applicable, for each hour of unit operation during the period of
invalid data specified in paragraph (a)(4)(iii) of this section or in
Secs. 75.21(e) (introductory paragraph) and 75.21(e)(1): the maximum
potential concentration of SO2, as defined in section
2.1.1.1 of appendix A to this part to report SO2
concentration; the maximum potential NOX emission rate, as
defined in Sec. 72.2 of this chapter to report NOX emission
rate; the maximum potential flow rate, as defined in section 2.1 of
appendix A to this part to report volumetric flow; or the maximum
CO2 concentration used to determine the maximum potential
concentration of SO2 in section 2.1.1.1 of appendix A to
this part to report CO2 concentration data. For a unit
subject to a State or federal NOX mass reduction program
where the owner or operator intends to monitor NOX mass
emissions with a NOX pollutant concentration monitor and a
flow monitoring system, substitute for NOX concentration
using the maximum potential concentration of NOX, as defined
in section 2.1.2.1 of appendix A to this part, and substitute for
volumetric flow using the maximum potential flow rate, as defined in
section 2.1 of appendix A to this part. The owner or operator shall
substitute these values until such time, date, and hour as a continuous
emission monitoring system or excepted monitoring system, where
applicable, is installed and provisionally certified;
(ii) The designated representative shall submit a notification of
certification test dates, as specified in Sec. 75.61(a)(1)(ii), and a
new certification application according to the procedures in paragraph
(a)(2) of this section; and
(iii) The owner or operator shall install and provisionally certify
continuous emission monitoring systems or excepted monitoring systems,
where applicable, two calendar quarters from the end of the quarter in
which the unit no longer qualifies as a low mass emissions unit.
14. Section 75.24 is amended by revising paragraph (d) to read as
follows:
Sec. 75.24 Out-of-control periods.
* * * * *
(d) When the bias test indicates that an SO2 monitor, a
volumetric flow monitor, a NOX continuous emission
monitoring system or a NOX concentration monitoring system
used to determine NOX mass emissions, as defined in
Sec. 75.71(a)(2), is biased low (i.e., the arithmetic mean of the
differences between the reference method value and the monitor or
monitoring system measurements in a relative accuracy test audit exceed
the bias statistic in section 7 of appendix A to this part), the owner
or operator shall adjust the monitor or continuous emission monitoring
system to eliminate the cause of bias such that it passes the bias
test, or calculate and use the bias adjustment factor as specified in
section 2.3.3 of appendix B to this part and in accordance with
Sec. 75.7.
* * * * *
16. Subpart H is added to part 75 to read as follows:
[[Page 57507]]
Subpart H--NOX Mass Emissions Provisions
Sec.
75.70 NOX mass emissions provisions.
75.71 Specific provisions for monitoring NOX emission
rate and heat input for the purpose of calculating NOX
mass emissions.
75.72 Determination of NOX mass emissions.
75.73 Recordkeeping and reporting [Reserved].
75.74 Annual and ozone season monitoring and reporting
requirements.
75.75 Additional ozone season calculation procedures for special
circumstances.
Subpart H--NOX Mass Emissions Provisions
Sec. 75.70 NOX mass emissions provisions.
(a) Applicability. The owner or operator of a unit shall comply
with the requirements of this subpart to the extent that compliance is
required by an applicable State or federal NOX mass emission
reduction program that incorporates by reference, or otherwise adopts
the provisions of, this subpart.
(1) For purposes of this subpart, the term ``affected unit'' shall
mean any unit that is subject to a State or federal NOX mass
emission reduction program requiring compliance with this subpart, the
term ``nonaffected unit'' shall mean any unit that is not subject to
such a program, the term ``permitting authority'' shall mean the
permitting authority under an applicable State or federal
NOX mass emission reduction program that adopts the
requirements of this subpart, and the term ``designated
representative'' shall mean the responsible party under the applicable
State or federal NOX mass emission reduction program that
adopts the requirements of this subpart.
(2) In addition, the provisions of subparts A, C, D, E, F, and G
and appendices A through G of this part applicable to NOX
concentration, flow rate, NOX emission rate and heat input,
as set forth and referenced in this subpart, shall apply to the owner
or operator of a unit required to meet the requirements of this subpart
by a State or federal NOX mass emission reduction program.
When applying these requirements, the term ``affected unit'' shall mean
any unit that is subject to a State or federal NOX mass
emission reduction program requiring compliance with this subpart, the
term ``permitting authority'' shall mean the permitting authority under
an applicable State or federal NOX mass emission reduction
program that adopts the requirements of this subpart, and the term
``designated representative'' shall mean the responsible party under
the applicable State or federal NOX mass emission reduction
program that adopts the requirements of this subpart. The requirements
of this part for SO2, CO2 and opacity monitoring,
recordkeeping and reporting do not apply to units that are subject to a
State or federal NOX mass emission reduction program only
and are not affected units with an Acid Rain emission limitation.
(b) Compliance dates. The owner or operator of an affected unit
shall meet the compliance deadlines established by an applicable State
or federal NOX mass emission reduction program that adopts
the requirements of this subpart.
(c) Prohibitions. (1) No owner or operator of an affected unit or a
non-affected unit under Sec. 75.72(b)(2)(ii) shall use any alternative
monitoring system, alternative reference method, or any other
alternative for the required continuous emission monitoring system
without having obtained prior written approval in accordance with
paragraph (h) of this section.
(2) No owner or operator of an affected unit or a non-affected unit
under Sec. 75.72(b)(2)(ii) shall operate the unit so as to discharge,
or allow to be discharged emissions of NOX to the atmosphere
without accounting for all such emissions in accordance with the
applicable provisions of this part, except as provided in Sec. 75.74.
(3) No owner or operator of an affected unit or a non-affected unit
under Sec. 75.72(b)(2)(ii) shall disrupt the continuous emission
monitoring system, any portion thereof, or any other approved emission
monitoring method, and thereby avoid monitoring and recording
NOX mass emissions discharged into the atmosphere, except
for periods of recertification or periods when calibration, quality
assurance testing, or maintenance is performed in accordance with the
provisions of this part applicable to monitoring systems under
Sec. 75.71, except as provided in Sec. 75.74.
(4) No owner or operator of an affected unit or a non-affected unit
under Sec. 75.72(b)(2)(ii) shall retire or permanently discontinue use
of the continuous emission monitoring system, any component thereof, or
any other approved emission monitoring system under this part, except
under any one of the following circumstances:
(i) During the period that the unit is covered by a retired unit
exemption that is in effect under the State or federal NOX
mass emission reduction program that adopts the requirements of this
subpart;
(ii) The owner or operator is monitoring NOX mass
emissions from the affected unit with another certified monitoring
system approved, in accordance with the provisions of paragraph (d) of
this section; or
(iii) The designated representative submits notification of the
date of certification testing of a replacement monitoring system in
accordance with Sec. 75.61.
(d) Initial certification and recertification procedures. (1) The
owner or operator of an affected unit that is subject to an Acid Rain
emissions limitation shall comply with the initial certification and
recertification procedures of this part, except that the owner or
operator shall meet any additional requirements set forth in an
applicable State or federal NOX mass emission reduction
program that adopts the requirements of this subpart.
(2) The owner or operator of an affected unit that is not subject
to an Acid Rain emissions limitation shall comply with the initial
certification and recertification procedures established by an
applicable State or federal NOX mass emission reduction
program that adopts the requirements of this subpart. The owner or
operator of an affected unit that is subject to an Acid Rain emissions
limitation shall comply with the initial certification and
recertification procedures established by an applicable State or
federal NOX mass emission reduction program that adopts the
requirements of this subpart for any additional NOX-diluent
CEMS, flow monitors, diluent monitors or NOX concentration
monitoring system required under the NOX mass emissions
provisions of Sec. 75.71 or the common stack provisions in Sec. 75.72.
(e) Quality assurance and quality control requirements. For units
that use continuous emission monitoring systems to account for
NOX mass emissions, the owner or operator shall meet the
quality assurance and quality control requirements in Sec. 75.21 that
apply to NOX-diluent continuous emission monitoring systems,
flow monitoring systems, NOX concentration monitoring
systems, and diluent monitors under Sec. 75.71. A NOX
concentration monitoring system for determining NOX mass
emissions in accordance with Sec. 75.71 shall meet the same
certification testing requirements, quality assurance requirements, and
bias test requirements as are specified in this part for an
SO2 pollutant concentration monitor. Units using excepted
methods under Sec. 75.19 shall meet the applicable quality assurance
requirements of that section, and units using excepted monitoring
methods under appendix D and E to this part shall meet the applicable
quality
[[Page 57508]]
assurance requirements of those appendices.
(f) Missing data procedures. Except as provided in Sec. 75.34 and
paragraph (g) of this section, the owner or operator shall provide
substitute data from monitoring systems required under Sec. 75.71 for
each affected unit as follows:
(1) For an owner or operator using a continuous emissions
monitoring system, substitute for missing data in accordance with the
missing data procedures in subpart D of this part whenever the unit
combusts fuel and:
(i) A valid quality assured hour of NOX emission rate
data (in lb/mmBtu) has not been measured and recorded for a unit by a
certified NOX-diluent continuous emission monitoring system
or by an approved monitoring system under subpart E of this part;
(ii) A valid quality assured hour of flow data (in scfh) has not
been measured and recorded for a unit from a certified flow monitor or
by an approved alternative monitoring system under subpart E of this
part; or
(iii) A valid quality assured hour of heat input data (in mmBtu)
has not been measured and recorded for a unit from a certified flow
monitor and a certified diluent (CO2 or O2)
monitor or by an approved alternative monitoring system under subpart E
of this part or by an accepted monitoring system under appendix D to
this part, where heat input is required either for calculating
NOX mass or allocating allowances under the applicable State
or federal NOX mass emission reduction program that adopts
the requirements of this subpart; or
(iv) A valid, quality-assured hour of NOX concentration
data (in ppm) has not been measured and recorded by a certified
NOX concentration monitoring system, or by an approved
alternative monitoring method under subpart E of this part, where the
owner or operator chooses to use a NOX concentration
monitoring system with a volumetric flow monitor, and without a diluent
monitor, to calculate NOX mass emissions. The initial
missing data procedures for determining monitor data availability and
the standard missing data procedures for a NOX concentration
monitoring system shall be the same as the procedures specified for a
NOX-diluent continuous emission monitoring system under
Secs. 75.31, 75.32 and 75.33, except that the phrase ``NOX
concentration monitoring system'' shall be substituted for the phrase
``NOX continuous emission monitoring system'', the phrase
``NOX concentration'' shall be substituted for
``NOX emission rate'; and the phrase ``maximum potential
NOX concentration, as defined in section 2.1.2.1 of appendix
A of this part'' shall be substituted for the phrase ``maximum
potential NOX emission rate, as defined in Sec. 72.2 of this
chapter''.
(2) For an owner or operator using an excepted monitoring system
under appendix D or E of this part, substitute for missing data in
accordance with the missing data procedures in section 2.4 of appendix
D to this part or in section 2.5 of appendix E to this part whenever
the unit combusts fuel and:
(i) A valid, quality-assured hour of fuel flow rate data has not
been measured and recorded by a certified fuel flowmeter that is part
of an excepted monitoring system under appendix D or E of this part; or
(ii) A fuel sample value for gross calorific value, or if
necessary, density or specific gravity, from a sample taken an analyzed
in accordance with appendix D of this part is not available; or
(iii) A valid, quality-assured hour of NOX emission rate
data has not been obtained according to the procedures and
specifications of appendix E to this part.
(g) Reporting data prior to initial certification. If the owner or
operator of an affected unit has not successfully completed all
certification tests required by the State or federal NOX
mass emission reduction program that adopts the requirements of this
subpart by the applicable date required by that program, he or she
shall determine, record and report hourly data prior to initial
certification using one of the following procedures, consistent with
the monitoring equipment to be certified:
(1) For units that the owner or operator intends to monitor for
NOX mass emissions using NOX emission rate and
heat input, the maximum potential NOX emission rate and the
maximum potential hourly heat input of the unit, as defined in
Sec. 72.2 of this chapter.
(2) For units that the owner or operator intends to monitor for
NOX mass emissions using a NOX concentration
monitoring system and a flow monitoring system, the maximum potential
concentration of NOX and the maximum potential flow rate of
the unit under section 2.1 of Appendix A of this part;
(3) For any unit, the reference methods under Sec. 75.22 of this
part.
(4) For any unit using the low mass emission excepted monitoring
methodology under Sec. 75.19, the procedures in paragraphs (g)(1) or
(2) of this section.
(5) Any unit using the procedures in paragraph (g)(2) of this
section that is required to report heat input for purposes of
allocating allowances shall also report the maximum potential hourly
heat input of the unit, as defined in Sec. 72.2 of this chapter.
(h) Petitions. (1) The designated representative of an affected
unit that is subject to an Acid Rain emissions limitation may submit a
petition to the Administrator requesting an alternative to any
requirement of this subpart. Such a petition shall meet the
requirements of Sec. 75.66 and any additional requirements established
by an applicable State or federal NOX mass emission
reduction program that adopts the requirements of this subpart. Use of
an alternative to any requirement of this subpart is in accordance with
this subpart and with such State or federal NOX mass
emission reduction program only to the extent that the petition is
approved by the Administrator, in consultation with the permitting
authority.
(2) Notwithstanding paragraph (h)(1) of this section, petitions
requesting an alternative to a requirement concerning any additional
CEMS required solely to meet the common stack provisions of Sec. 75.72
shall be submitted to the permitting authority and the Administrator
and shall be governed by paragraph (h)(3)(ii) of this section. Such a
petition shall meet the requirements of Sec. 75.66 and any additional
requirements established by an applicable State or federal
NOX mass emission reduction program that adopts the
requirements of this subpart.
(3)(i) The designated representative of an affected unit that is
not subject to an Acid Rain emissions limitation may submit a petition
to the permitting authority and the Administrator requesting an
alternative to any requirement of this subpart. Such a petition shall
meet the requirements of Sec. 75.66 and any additional requirements
established by an applicable State or federal NOX mass
emission reduction program that adopts the requirements of this
subpart.
(ii) Use of an alternative to any requirement of this subpart is in
accordance with this subpart only to the extent that it is approved by
the Administrator and by the permitting authority if required by an
applicable State or federal NOX mass emission reduction
program that adopts the requirements of this subpart.
Sec. 75.71 Specific provisions for monitoring NOX emission
rate and heat input for the purpose of calculating NOX mass
emissions.
(a) Coal-fired units. The owner or operator of a coal-fired
affected unit shall either:
[[Page 57509]]
(1) Meet the general operating requirements in Sec. 75.10 for a
NOX-diluent continuous emission monitoring system
(consisting of a NOX pollutant concentration monitor, an
O2- or CO2-diluent gas monitor, and a data
acquisition and handling system) to measure NOX emission
rate and for a flow monitoring system and an O2- or
CO2-diluent gas monitor to measure heat input, except as
provided in accordance with subpart E of this part; or
(2) Meet the general operating requirements in Sec. 75.10 for a
NOX concentration monitoring system (consisting of a
NOX pollutant concentration monitor and a data acquisition
and handling system) to measure NOX concentration and for a
flow monitoring system. In addition, if heat input is required to be
reported under the applicable State or federal NOX mass
emission reduction program that adopts the requirements of this
subpart, the owner or operator also must meet the general operating
requirements for a flow monitoring system and an O2- or
CO2-diluent gas monitor to measure heat input, or, if
applicable, use the procedures in appendix D to this part. These
requirements must be met, except as provided in accordance with subpart
E of this part.
(b) Moisture correction. If a correction for the stack gas moisture
content is needed to properly calculate the NOX emission
rate in lb/mmBtu (i.e., if the NOX pollutant concentration
monitor measures on a different moisture basis from the diluent
monitor) or NOX mass emissions in tons (i.e., if the
NOX concentration monitoring system or diluent monitor
measures on a different moisture basis from the flow rate monitor), the
owner or operator of an affected unit shall account for the moisture
content of the flue gas on a continuous basis in accordance with
Sec. 75.11(b) except that the term ``SO2'' shall be replaced
by the term ``NOX'.
(c) Gas-fired nonpeaking units or oil-fired nonpeaking units. The
owner or operator of an affected unit that, based on information
submitted by the designated representative in the monitoring plan,
qualifies as a gas-fired or oil-fired unit but not as a peaking unit,
as defined in Sec. 72.2 of this chapter, shall either:
(1) Meet the requirements of paragraph (a) of this section and, if
applicable, paragraph (b) of this section; or
(2) Meet the general operating requirements in Sec. 75.10 for a
NOX-diluent continuous emission monitoring system, except as
provided in accordance with subpart E of this part, and use the
procedures specified in appendix D to this part for determining hourly
heat input. However, the heat input apportionment provisions in section
2.1.2 of appendix D to this part shall not be used to meet the
NOX mass reporting provisions of this subpart, except as
provided in Sec. 75.72(a); or
(3) Meet the requirements of the low mass emission excepted
methodology under paragraph (e)(2) of this section and under
Sec. 75.19, if applicable.
(d) Gas-fired or oil-fired peaking units. The owner or operator of
an affected unit that qualifies as a peaking unit and as either gas-
fired or oil-fired, as defined in Sec. 72.2 of this chapter, based on
information submitted by the designated representative in the
monitoring plan, shall either:
(1) Meet the requirements of paragraph (c) of this section; or
(2) Use the procedures in appendix D to this part for determining
hourly heat input and the procedures specified in appendix E to this
part for estimating hourly NOX emission rate. However, the
heat input apportionment provisions in section 2.1.2 of appendix D to
this part shall not be used to meet the NOX mass reporting
provisions of this subpart except for units using an excepted
monitoring system under appendix E to this part and except as provided
in Sec. 75.72(a). In addition, if after certification of an excepted
monitoring system under appendix E to this part, a unit's operations
exceed a capacity factor of 20.0 percent in any calender year or exceed
a capacity factor of 10.0 percent averaged over three years, the owner
or operator shall meet the requirements of paragraph (c) of this
section or, if applicable, paragraph (e) of this section, by no later
than December 31 of the following calender year.
(e) Low mass emissions units. Notwithstanding the requirements of
paragraphs (c) and (d) of this section, the owner or operator of an
affected unit that qualifies as a low mass emissions unit under
Sec. 75.19(a) shall comply with one of the following:
(1) Meet the applicable requirements specified in paragraphs (c) or
(d) of this section; or
(2) Use the low mass emissions excepted methodology in
Sec. 75.19(c) for estimating hourly emission rate, hourly heat input,
and hourly NOX mass emissions.
(f) Other units. The owner or operator of an affected unit that
combusts wood, refuse, or other materials shall comply with the
monitoring provisions specified in paragraph (a) of this section and,
where applicable, paragraph (b) of this section.
Sec. 75.72 Determination of NOX mass emissions.
Except as provided in paragraphs (e) and (f) of this section, the
owner or operator of an affected unit shall calculate hourly
NOX mass emissions (in lbs) by multiplying the hourly
NOX emission rate (in lbs/mmBtu) by the hourly heat input
(in mmBtu/hr) and the hourly operating time (in hr). The owner or
operator shall also calculate quarterly and cumulative year-to-date
NOX mass emissions and cumulative NOX mass
emissions for the ozone season (in tons) by summing the hourly
NOX mass emissions according to the procedures in section 8
of appendix F to this part.
(a) Unit utilizing common stack with other affected unit(s). When
an affected unit utilizes a common stack with one or more affected
units, but no nonaffected units, the owner or operator shall either:
(1) Record the combined NOX mass emissions for the units
exhausting to the common stack, install, certify, operate, and maintain
a NOX-diluent continuous emissions monitoring system in the
common stack, and either:
(i) Install, certify, operate, and maintain a flow monitoring
system at the common stack. The owner or operator also shall provide
heat input values for each unit, either by monitoring each unit
individually using a flow monitor and a diluent monitor or by
apportioning heat input according to the procedures in
Sec. 75.16(e)(5); or
(ii) If any of the units using the common stack are eligible to use
the procedures in appendix D to this part,
(A) Use the procedures in appendix D to this part to determine heat
input for that unit; and
(B) Install, certify, operate, and maintain a flow monitoring
system in the duct to the common stack for each remaining unit; or
(2) Install, certify, operate, and maintain a NOX-
diluent continuous emissions monitoring system in the duct to the
common stack from each unit and either:
(i) Install, certify, operate, and maintain a flow monitoring
system in the duct to the common stack from each unit; or
(ii) For any unit using the common stack and eligible to use the
procedures in appendix D to this part,
(A) Use the procedures in appendix D to determine heat input for
that unit; and
(B) Install, certify, operate, and maintain a flow monitoring
system in the duct to the common stack for each remaining unit.
[[Page 57510]]
(b) Unit utilizing common stack with nonaffected unit(s). When one
or more affected units utilizes a common stack with one or more
nonaffected units, the owner or operator shall either:
(1) Install, certify, operate, and maintain a NOX-
diluent continuous emission monitoring system in the duct to the common
stack from each affected unit; and
(i) Install, certify, operate, and maintain a flow monitoring
system in the duct to the common stack from each affected unit; or
(ii) For any affected unit using the common stack and eligible to
use the procedures in appendix D to this part,
(A) Use the procedures in appendix D to determine heat input for
that unit; however, the heat input apportionment provisions in section
2.1.2 of appendix D to this part shall not be used to meet the
NOX mass reporting provisions of this subpart; and
(B) Install, certify, operate, and maintain a flow monitoring
system in the duct to the common stack for each remaining affected unit
that exhausts to the common stack; or
(2) Install, certify, operate, and maintain a NOX-
diluent continuous emission monitoring system in the common stack; and
(i) Designate the nonaffected units as affected units in accordance
with the applicable State or federal NOX mass emissions
reduction program and meet the requirements of paragraph (a)(1) of this
section; or
(ii) Install, certify, operate, and maintain a flow monitoring
system in the common stack and a NOX-diluent continuous
emission monitoring system in the duct to the common stack from each
nonaffected unit. The designated representative shall submit a petition
to the permitting authority and the Administrator to allow a method of
calculating and reporting the NOX mass emissions from the
affected units as the difference between NOX mass emissions
measured in the common stack and NOX mass emissions measured
in the ducts of the nonaffected units, not to be reported as an hourly
value less than zero. The permitting authority and the Administrator
may approve such a method whenever the designated representative
demonstrates, to the satisfaction of the permitting authority and the
Administrator, that the method ensures that the NOX mass
emissions from the affected units are not underestimated. In addition,
the owner or operator shall also either:
(A) Install, certify, operate, and maintain a flow monitoring
system in the duct from each nonaffected unit or,
(B) For any nonaffected unit exhausting to the common stack and
otherwise eligible to use the procedures in appendix D to this part,
determine heat input using the procedures in appendix D for that unit.
However, the heat input apportionment provisions in section 2.1.2 of
appendix D to this part shall not be used to meet the NOX
mass reporting provisions of this subpart. For any remaining
nonaffected unit that exhausts to the common stack, install, certify,
operate, and maintain a flow monitoring system in the duct to the
common stack; or
(iii) Install a flow monitoring system in the common stack and
record the combined emissions from all units as the combined
NOX mass emissions for the affected units for recordkeeping
and compliance purposes; or
(iv) Submit a petition to the permitting authority and the
Administrator to allow use of a method for apportioning NOX
mass emissions measured in the common stack to each of the units using
the common stack and for reporting the NOX mass emissions.
The permitting authority and the Administrator may approve such a
method whenever the designated representative demonstrates, to the
satisfaction of the permitting authority and the Administrator, that
the method ensures that the NOX mass emissions from the
affected units are not underestimated.
(c) Unit with bypass stack. Whenever any portion of the flue gases
from an affected unit can be routed to avoid the installed
NOX-diluent continuous emissions monitoring system or
NOX concentration monitoring system, the owner and operator
shall either:
(1) Install, certify, operate, and maintain a NOX-
diluent continuous emissions monitoring system and a flow monitoring
system on the bypass flue, duct, or stack gas stream and calculate
NOX mass emissions for the unit as the sum of the emissions
recorded by all required monitoring systems; or
(2) Monitor NOX mass emissions on the bypass flue, duct,
or stack gas stream using the reference methods in Sec. 75.22(b) for
NOX concentration, flow, and diluent, or NOX
concentration and flow, and calculate NOX mass emissions for
the unit as the sum of the emissions recorded by the installed
monitoring systems on the main stack and the emissions measured by the
reference method monitoring systems.
(d) Unit with multiple stacks. Notwithstanding Sec. 75.17(c), when
the flue gases from a affected unit discharge to the atmosphere through
more than one stack, or when the flue gases from a unit subject to a
NOX mass emission reduction program utilize two or more
ducts feeding into two or more stacks (which may include flue gases
from other affected or nonaffected unit(s)), or when the flue gases
from an affected unit utilize two or more ducts feeding into a single
stack and the owner or operator chooses to monitor in the ducts rather
than in the stack, the owner or operator shall either:
(1) Install, certify, operate, and maintain a NOX-
diluent continuous emission monitoring system and a flow monitoring
system in each duct feeding into the stack or stacks and determine
NOX mass emissions from each affected unit using the stack
or stacks as the sum of the NOX mass emissions recorded for
each duct; or
(2) Install, certify, operate, and maintain a NOX-
diluent continuous emissions monitoring system and a flow monitoring
system in each stack, and determine NOX mass emissions from
the affected unit using the sum of the NOX mass emissions
recorded for each stack, except that where another unit also exhausts
flue gases to one or more of the stacks, the owner or operator shall
also comply with the applicable requirements of paragraphs (a) and (b)
of this section to determine and record NOX mass emissions
from the units using that stack; or
(3) If the unit is eligible to use the procedures in appendix D to
this part, install, certify, operate, and maintain a NOX-
diluent continuous emissions monitoring system in one of the ducts
feeding into the stack or stacks and use the procedures in appendix D
to this part to determine heat input for the unit, provided that:
(i) There are no add-on NOX controls at the unit;
(ii) The unit is not capable of emitting solely through an
unmonitored stack (e.g., has no dampers); and
(iii) The owner or operator of the unit demonstrates to the
satisfaction of the permitting authority and the Administrator that the
NOX emission rate in the monitored duct or stack is
representative of the NOX emission rate in each duct or
stack.
(e) Units using a NOX concentration monitoring system
and a flow monitoring system to determine NOX mass. The
owner or operator may use a NOX concentration monitoring
system and a flow monitoring system to determine NOX mass
emissions in paragraphs (a) through (d) of this section (in place of a
NOX-diluent continuous emission monitoring system and a flow
monitoring system). When using this approach, calculate NOX
mass according to sections 8.2 and 8.3 in appendix F of this part. In
addition, if an applicable
[[Page 57511]]
State or federal NOX mass reduction program requires
determination of a unit's heat input, the owner or operator must
either:
(1) Install, certify, operate, and maintain a CO2 or
O2 diluent monitor in the same location as each flow
monitoring system. In addition, the owner or operator must provide heat
input values for each unit utilizing a common stack by either:
(i) Apportion heat input from the common stack to each unit
according to Sec. 75.16(e)(5), where all units utilizing the common
stack are affected units, or
(ii) Measure heat input from each affected unit, using a flow
monitor and a CO2 or O2 diluent monitor in the
duct from each affected unit; or
(2) For units that are eligible to use appendix D to this part, use
the procedures in appendix D to this part to determine heat input for
the unit. However, the use of a fuel flowmeter in a common pipe header
and the provisions of sections 2.1.2.1 and 2.1.2.2 of appendix D of
this part are not applicable to any unit that is using the provisions
of this subpart to monitor, record, and report NOX mass
emissions under a State or federal NOX mass emission
reduction program and that shares a common pipe or a common stack with
a nonaffected unit.
(f) Units using the low mass emitter excepted methodology under
Sec. 75.19. For units that are using the low mass emitter excepted
methodology under Sec. 75.19, calculate ozone season NOX
mass emissions by summing all of the hourly NOX mass
emissions in the ozone season, as determined under paragraph
Sec. 75.19(c)(4)(ii)(A) of this section, divided by 2000 lb/ton.
(g) Procedures for apportioning heat input to the unit level. If
the owner or operator of a unit using the common stack monitoring
provisions in paragraphs (a) or (b) of this section does not monitor
and record heat input at the unit level and the owner or operator is
required to do so under an applicable State or federal NOX
mass emission reduction program, the owner or operator should apportion
heat input from the common stack to each unit according to
Sec. 75.16(e)(5).
Sec. 75.73 Recordkeeping and reporting. [Reserved]
Sec. 75.74 Annual and ozone season monitoring and reporting
requirements.
(a) Annual monitoring requirement. (1) The owner or operator of an
affected unit subject both to an Acid Rain emission limitation and to a
State or federal NOX mass reduction program that adopts the
provisions of this part must meet the requirements of this part during
the entire calendar year.
(2) The owner or operator of an affected unit subject to a State or
federal NOX mass reduction program that adopts the
provisions of this part and that requires monitoring and reporting of
hourly emissions on an annual basis must meet the requirements of this
part during the entire calendar year.
(b) Ozone season monitoring requirements. The owner or operator of
an affected unit that is not required to meet the requirements of this
subpart on an annual basis under paragraph (a) of this section may
either:
(1) Meet the requirements of this subpart on an annual basis; or
(2) Meet the requirements of this part during the ozone season,
except as specified in paragraph (c) of this section.
(c) If the owner or operator of an affected unit chooses to meet
the requirements of this subpart on less than an annual basis in
accordance with paragraph (b)(2) of this section, then:
(1) The owner or operator of a unit that uses continuous emissions
monitoring systems to meet any of the requirements of this subpart must
perform recertification testing of all continuous emission monitoring
systems under Sec. 75.20(b). If the owner or operator has not
successfully completed all recertification tests by the first hour of
unit operation during the ozone season each year, the owner or operator
must substitute for data following the procedures of Sec. 75.20(b).
(2) The owner or operator is required to operate and maintain
continuous emission monitoring systems and perform quality assurance
and quality control procedures under Sec. 75.21 and appendix B of this
part each year from the time the continuous emission monitoring system
is initially certified or is recertified under paragraph (c)(1) of this
section through September 30. Records related to the quality assurance/
quality control program must be kept in a form suitable for inspection
on a year-round basis.
(3) The owner or operator of a unit using the procedures in
appendix D of this part to determine heat input is required to operate
or maintain fuel flowmeters only during the ozone season, except that
for purposes of determining the deadline for the next periodic quality
assurance test on the fuel flowmeter, the owner or operator shall count
all quarters during the year when the fuel flowmeter is used, not just
quarters in the ozone season. The owner or operator shall record and
the designated representative shall report the number of quarters when
a fuel is combusted for each fuel flowmeter.
(4) The owner or operator of a unit using the procedures in
appendix D of this part to determine heat input is only required to
sample fuel during the ozone season, except that:
(i) The owner or operator of a diesel-fired unit that performs
sampling from the fuel storage tank upon delivery must sample the tank
between the date and hour of the most recent delivery before the first
date and hour that the unit operates in the ozone season and the first
date and hour that the unit operates in the ozone season.
(ii) The owner or operator of a diesel-fired unit that performs
sampling upon delivery from the delivery vehicle must ensure that all
shipments received during the calendar year are sampled.
(iii) The owner or operator of a unit that performs sampling on
each day the unit combusts fuel oil or that performs oil sampling
continuously must sample the fuel oil starting on the first day the
unit operates during the ozone season. The owner or operator then shall
use that sampled value for all hours of combustion during the first day
of unit operation, continuing until the date and hour of the next
sample.
(5) The owner or operator is required to record and report the
hourly data required by this subpart for the longer of:
(i) The period of time that the owner or operator of the unit is
required to perform the quality assurance and quality control
procedures of Sec. 75.21 and appendix B of this part under paragraph
(c)(2) of this section; or
(ii) The period of time of May 1 through September 30.
(6) The owner or operator shall use quality-assured data, in
accordance with paragraph (c)(2) or (c)(3) of this section, in the
substitute data procedures under subpart D of this part and section 2.4
of appendix D of this part.
(i) The lookback periods (e.g., 2160 quality-assured monitor
operating hours for a NOX-diluent continuous emission
monitoring system, a NOX concentration monitoring system, or
a flow monitoring system) used to calculate missing data must include
only data from periods when the monitors were quality assured under
paragraph (c)(2) or (c)(3) of this section.
(ii) If the NOX emission rate or NOX
concentration of the unit was consistently lower in the previous ozone
season because the unit combusted a fuel that produces less
NOX than the fuel currently being combusted or because the
unit's add-on emission controls are not operating properly, then the
owner or operator shall not use the
[[Page 57512]]
missing data procedures of Secs. 75.31 through 75.33. Instead, the
owner or operator shall substitute the maximum potential NOX
emission rate, as defined in Sec. 72.2 of this chapter, from a
NOX-diluent continuous emission monitoring system, or the
maximum potential concentration of NOX, as defined in
section 2.1.2.1 of appendix A to this part, from a NOX
concentration monitoring system. The owner or operator shall substitute
these maximum potential values for each hour of missing NOX
data, from completion of recertification testing until the earliest of:
(A) 720 quality-assured monitor operating hours after the
completion of recertification testing (not to go beyond September 30 of
that ozone season), or
(B) For a unit that changed fuels, the first hour when the unit
combusts a fuel that produces the same or less NOX than the
fuel combusted in the previous ozone season, or
(C) For a unit with add-on emission controls that are not operating
properly, the first hour when the add-on emission controls operate
properly.
(7) The owner or operator of a unit with NOX add-on
emission controls or a unit capable of combusting more than one fuel
shall keep records during ozone season in a form suitable for
inspection to demonstrate that the typical NOX emission rate
or NOX concentration during the prior ozone season(s)
included in the missing data lookback period is representative of the
ozone season in which missing data are substituted and that use of the
missing data procedures will not systematically underestimate
NOX mass emissions. These records shall include:
(i) For units that can combust more than one fuel, the fuel or
fuels combusted each hour; and
(ii) For units with add-on emission controls, the range of
operating parameters for add-on emission controls, as described in
Sec. 75.34(a) and information for verifying proper operation of the
add-on emission controls, as described in Sec. 75.34(d).
(8) The designated representative shall certify with each quarterly
report that NOX emission rate values or NOX
concentration values substituted for missing data under subpart D of
this part are calculated using only values from an ozone season, that
substitute values measured during the prior ozone season(s) included in
the missing data lookback period are representative of the ozone season
in which missing data are substituted, and that NOX
emissions are not systematically underestimated.
(9) Units may qualify to use the low mass emission excepted
monitoring methodology in Sec. 75.19 on an ozone season basis. In order
to be allowed to use this methodology, a unit may not emit more than 25
tons of NOX per ozone season. The owner or operator of the
unit shall meet the requirements of Sec. 75.19, with the following
exceptions:
(i) The phrase ``50 tons of NOX annually'' shall be
replaced by the phrase ``25 tons of NOX during the ozone
season.''
(ii) If any low mass emission unit fails to provide a demonstration
that its ozone season NOX mass emissions are less than 25
tons, than the unit is disqualified from using the methodology. The
owner or operator must install and certify any equipment needed to
ensure that the unit is monitoring using an acceptable methodology by
May 1 of the following year.
(10) Units may qualify to use the optional NOX mass
emissions estimation protocol for gas-fired peaking units and oil-fired
peaking units in appendix E to this part on an ozone season basis. In
order to be allowed to use this methodology, the unit must meet the
definition of peaking unit in Sec. 72.2 of this part, except that the
word ``calender year'' shall be replaced by the word ``ozone season''
and the word annual in the definition of the term ``capacity factor''
in Sec. 72.2 of this part, shall be replaced by the word ``ozone
season''.
Sec. 75.75 Additional ozone season calculation procedures for special
circumstances.
(a) The owner or operator of a unit that is required to calculate
ozone season heat input for purposes of providing data needed for
determining allocations, shall do so by summing the unit's hourly heat
input determined according to the procedures in this part for all hours
in which the unit operated during the ozone season.
(b) The owner or operator of a unit that is required to determine
ozone season NOX emission rate (in lbs/mmBtu) shall do so by
dividing ozone season NOX mass emissions(in lbs) determined
in accordance with this subpart, by heat input determined in accordance
with paragraph (a) of this section.
17. Section 3 of appendix A to part 75 is amended by revising the
title of section 3.3.2 and by adding and reserving section 3.3.6, by
adding new section 3.3.7 and by revising section 3.4.1 to read as
follows:
APPENDIX A TO PART 75--SPECIFICATIONS AND TEST PROCEDURES
* * * * *
3. PERFORMANCE SPECIFICATIONS
* * * * *
3.3.2 RELATIVE ACCURACY FOR NOX DILUENT CONTINUOUS
EMISSION MONITORING SYSTEMS
* * * * *
3.3.6 [Reserved]
3.3.7 RELATIVE ACCURACY FOR NOX CONCENTRATION
MONITORING SYSTEMS
The following requirement applies only to NOX
concentration monitoring systems (i.e., NOX pollutant
concentration monitors) that are used to determine NOX
mass emissions, where the owner or operator elects to monitor and
report NOX mass emissions using a NOX
concentration monitoring system and a flow monitoring system.
The relative accuracy for NOX concentration
monitoring systems shall not exceed 10.0 percent.
* * * * *
3.4.1 SO2 POLLUTANT CONCENTRATION MONITORS,
NOX CONCENTRATION MONITORING SYSTEMS AND NOX-
DILUENT CONTINUOUS EMISSION MONITORING SYSTEMS
SO2 pollutant concentration monitors and
NOX emission rate continuous emissions monitoring systems
shall not be biased low as determined by the test procedure in
section 7.6 of this appendix. NOX concentration
monitoring systems used to determine NOX mass emissions,
as defined in Sec. 75.71, shall not be biased low as determined by
the test procedure in section 7.6 of this appendix. The bias
specification applies to all SO2 pollutant concentration
monitors, including those measuring an average SO2
concentration of 250.0 ppm or less, and to all NOX-
diluent continuous emission monitoring systems, including those
measuring an average NOX emission rate of 0.20 lb/mmBtu
or less.
* * * * *
18. Section 6 of appendix A to part 75 is amended by revising the
first sentence of the introductory text of section 6.5 and by adding a
new sentence after the first sentence, to read as follows:
* * * * *
6.5 Relative Accuracy and Bias Tests
Perform relative accuracy test audits for each CO2
and SO2 pollutant concentration monitor; each
NOX concentration monitoring system used to determine
NOX mass emissions; each O2 monitor used to
calculate heat input or CO2 concentration; each
SO2-diluent continuous emission monitoring system (lb/
mmBtu) used by units with a qualifying Phase I technology for the
period during which the units are required to monitor SO2
emission removal efficiency, from January 1, 1997 through December
31, 1999; each flow monitor; and each NOX-diluent
continuous emission monitoring system. Perform relative accuracy
test audits for each NOX concentration monitoring system
used to determine NOX mass emissions, as defined in
Sec. 75.71(a)(2), using the same general procedures as for
CO2 and
[[Page 57513]]
SO2 pollutant concentration monitors; however, use the
reference methods for NOX concentration listed in section
6.5.10 of this appendix. * * *
* * * * *
19. Section 7 of appendix A is amended by revising the introductory
text of section 7.6 and by adding three sentences to the end of section
7.6.5 to read as follows:
* * * * *
7.6 Bias Test and Adjustment Factor
Test the relative accuracy test audit data sets for bias for
SO2 pollutant concentration monitors; flow monitors;
NOX concentration monitoring systems used to determine
NOX mass emissions, as defined in Sec. 75.71(a)(2); and
NOX-diluent continuous emission monitoring systems using
the procedures outlined below.
* * * * *
7.6.5 Bias Adjustment
* * * In addition, use the adjusted NOX
concentration and flow rate values in computing substitution values
in the missing data procedure, as specified in subpart D of this
part, and in reporting the NOX concentration and the flow
rate when used to calculate NOX mass emissions, as
specified in subpart H of this part. Do not use an adjusted
NOX concentration value to calculate NOX
emission rate using Equations F-5 or F-6 of Appendix F of this part.
When monitoring NOX emission rate and heat input, use the
adjusted NOX emission rate and flow rate values in
computing substitution values in the missing data procedure, as
specified in subpart D of this part, and in reporting the
NOX emission rate and the heat input.
* * * * *
20. Appendix C to part 75 is amended by revising sections 2.1,
2.2.2, 2.2.3, 2.2.5, and 2.2.6 to read as follows:
APPENDIX C TO PART 75--MISSING DATA ESTIMATION PROCEDURES
* * * * *
2.1 Applicability
This procedure is applicable for data from all affected units
for use in accordance with the provisions of this part to provide
substitute data for volumetric flow rate (scfh), NOX
emission rate (in lb/mmBtu), and NOX concentration data
(in ppm) from NOX concentration monitoring systems used
to determine NOX mass emissions.
2.2 Procedure
2.2.1 * * *
2.2.2 Beginning with the first hour of unit operation after
installation and certification of the flow monitor or the
NOX continuous emission monitoring system (or a
NOX concentration monitoring system used to determine
NOX mass emissions, as defined in Sec. 75.71, for each
hour of unit operation record a number, 1 through 10 (or 1 through
20 for flow at common stacks), that identifies the operating load
range corresponding to the integrated hourly gross load of the
unit(s) recorded for each unit operating hour.
2.2.3 Beginning with the first hour of unit operation after
installation and certification of the flow monitor or the
NOX continuous emission monitoring system (or a
NOX concentration monitoring system used to determine
NOX mass emissions, as defined in Sec. 75.71 and
continuing thereafter, the data acquisition and handling system must
be capable of calculating and recording the following information
for each unit operating hour of missing flow or NOX data
within each identified load range during the shorter of: (1) the
previous 2,160 quality assured monitor operating hours (on a rolling
basis), or (2) all previous quality assured monitor operating hours.
2.2.3.1 Average of the hourly flow rates reported by a flow
monitor, in scfh.
2.2.3.2 The 90th percentile value of hourly flow rates, in
scfh.
2.2.3.3 The 95th percentile value of hourly flow rates, in
scfh.
2.2.3.4 The maximum value of hourly flow rates, in scfh.
2.2.3.5 Average of the hourly NOX emission rate, in
lb/mmBtu, reported by a NOX continuous emission
monitoring system.
2.2.3.6 The 90th percentile value of hourly NOX
emission rates, in lb/mmBtu.
2.2.3.7 The 95th percentile value of hourly NOX
emission rates, in lb/mmBtu.
2.2.3.8 The maximum value of hourly NOX emission
rates, in lb/mmBtu.
2.2.3.9 Average of the hourly NOX pollutant
concentration, in ppm, reported by a NOX concentration
monitoring system used to determine NOX mass emissions,
as defined in Sec. 75.71.
2.2.3.10 The 90th percentile value of hourly NOX
pollutant concentration, in ppm.
2.2.3.11 The 95th percentile value of hourly NOX
pollutant concentration, in ppm.
2.2.3.12 The maximum value of hourly NOX pollutant
concentration, in ppm.
2.2.4 * * *
2.2.5 When a bias adjustment is necessary for the flow monitor
or the NOX continuous emission monitoring system (or the
NOX concentration monitoring system used to determine
NOX mass emissions, as defined in Sec. 75.71), apply the
adjustment factor to all monitor or continuous emission monitoring
system data values placed in the load ranges.
2.2.6 Use the calculated monitor or monitoring system data
averages, maximum values, and percentile values to substitute for
missing flow rate and NOX emission rate data (and where
applicable, NOX concentration data) according to the
procedures in subpart D of this part.
* * * * *
21. Section 2 of appendix D to part 75 is amended by revising the
introductory text of section 2.1.2 to read as follows:
APPENDIX D TO PART 75--OPTIONAL SO2 EMISSIONS DATA PROTOCOL
FOR GAS-FIRED AND OIL-FIRED UNITS
* * * * *
2.1.2 Install and use fuel flowmeters meeting the requirements
of this appendix in a pipe going to each unit, or install and use a
fuel flowmeter in a common pipe header (i.e., a pipe carrying fuel
for multiple units). However, the use of a fuel flowmeter in a
common pipe header and the provisions of sections 2.1.2.1 and
2.1.2.2 of this appendix are not applicable to any unit that is
using the provisions of subpart H of this part to monitor, record,
and report NOX mass emissions under a State or federal
NOX mass emission reduction program, except as provided
in Sec. 75.72(a) for units with a NOX CEMS installed in a
common stack or except as provided for units monitored with an
excepted monitoring system under appendix E to this part. For all
other units, if the fuel flowmeter is installed in a common pipe
header, do one of the following:
* * * * *
22. Section 8 of appendix F to part 75 is added to read as follows:
APPENDIX F TO PART 75--CONVERSION PROCEDURES
* * * * *
8. Procedures for NOX Mass Emissions
The owner or operator of a unit that is required to monitor,
record, and report NOX mass emissions under a State or
federal NOX mass emission reduction program must use the
procedures in section 8.1 to account for hourly NOX mass
emissions, and the procedures in section 8.2 to account for
quarterly, seasonal, and annual NOX mass emissions to the
extent that the provisions of subpart H of this part are adopted as
requirements under such a program.
8.1 Use the following procedures to calculate hourly
NOX mass emissions in lbs for the hour using hourly
NOX emission rate and heat input.
8.1.1 If both NOX emission rate and heat input are
monitored at the same unit or stack level (e.g, the NOX
emission rate value and heat input value both represent all of the
units exhausting to the common stack), use the following equation:
[GRAPHIC] [TIFF OMITTED] TR27OC98.011
where:
M(NOx)h = NOX mass emissions in lbs for the
hour.
E(NOx)h = Hourly average NOX emission rate for
hour h, lb/mmBtu, from section 3 of this appendix, from method 19 of
appendix A to part 60 of this chapter, or from section 3.3 of
appendix E to this part. (Include bias-adjusted NOX
emission rate values, where the bias-test procedures in appendix A
to this part shows a bias-adjustment factor is necessary.)
HIh = Hourly average heat input rate for hour h, mmBtu/
hr. (Include bias-adjusted flow rate values, where the bias-test
procedures in appendix A to this part shows a bias-adjustment factor
is necessary.)
[[Page 57514]]
th = Monitoring location operating time for hour h, in
hours or fraction of an hour (in equal increments that can range
from one hundredth to one quarter of an hour, at the option of the
owner or operator). If the combined NOX emission rate and
heat input are monitored for all of the units in a common stack, the
monitoring location operating time is equal to the total time when
any of those units was exhausting through the common stack.
8.1.2 If NOX emission rate is measured at a common
stack and heat input is measured at the unit level, sum the hourly
heat inputs at the unit level according to the following formula:
[GRAPHIC] [TIFF OMITTED] TR27OC98.012
where:
HICS = Hourly average heat input rate for hour h for the
units at the common stack, mmBtu/hr.
tCS = Common stack operating time for hour h, in hours or
fraction of an hour (in equal increments that can range from one
hundredth to one quarter of an hour, at the option of the owner or
operator)(e.g., total time when any of the units which exhaust
through the common stack are operating).
HIu = Hourly average heat input rate for hour h for the
unit, mmBtu/hr.
tu = Unit operating time for hour h, in hours or fraction
of an hour (in equal increments that can range from one hundredth to
one quarter of an hour, at the option of the owner or operator).
Use the hourly heat input rate at the common stack level and the
hourly average NOX emission rate at the common stack
level and the procedures in section 8.1.1 of this appendix to
determine the hourly NOX mass emissions at the common
stack.
8.1.3 If a unit has multiple ducts and NOX emission
rate is only measured at one duct, use the NOX emission
rate measured at the duct, the heat input measured for the unit, and
the procedures in section 8.1.1 of this appendix to determine
NOX mass emissions.
8.1.4 If a unit has multiple ducts and NOX emission
rate is measured in each duct, heat input shall also be measured in
each duct and the procedures in section 8.1.1 of this appendix shall
be used to determine NOX mass emissions.
8.2 If a unit calculates NOX mass emissions using a
NOX concentration monitoring system and a flow monitoring
system, calculate hourly NOX mass rate during unit (or
stack) operation, in lb/hr, using Equation F-1 or F-2 in this
appendix (as applicable to the moisture basis of the monitors). When
using Equation F-1 or F-2, replace ``SO2'' with
``NOX'' and replace the value of K with 1.194 x
10-7 (lb NOX /scf)/ppm. (Include
bias-adjusted flow rate or NOX concentration values,
where the bias-test procedures in appendix A to this part shows a
bias-adjustment factor is necessary.)
8.3 If a unit calculates NOX mass emissions using a
NOX concentration monitoring system and a flow monitoring
system, calculate NOX mass emissions for the hour (lb) by
multiplying the hourly NOX mass emission rate during unit
operation (lb/hr) by the unit operating time during the hour, as
follows:
[GRAPHIC] [TIFF OMITTED] TR27OC98.013
Where:
M(NOx)h = NOX mass emissions in lbs for the
hour.
Eh = Hourly NOX mass emission rate during unit
(or stack) operation, lb/hr, from section 8.2 of this appendix.
th = Monitoring location operating time for hour h, in
hours or fraction of an hour (in equal increments that can range
from one hundredth to one quarter of an hour, at the option of the
owner or operator). If the NOX mass emission rate is
monitored for all of the units in a common stack, the monitoring
location operating time is equal to the total time when any of those
units was exhausting through the common stack.
8.4 Use the following procedures to calculate quarterly,
cumulative ozone season, and cumulative yearly NOX mass
emissions, in tons:
[GRAPHIC] [TIFF OMITTED] TR27OC98.014
Where:
M(NOx) time period = NOX mass emissions in
tons for the given time period (quarter, cumulative ozone season,
cumulative year-to-date).
M(NOx)h = NOX mass emissions in lbs for the
hour. p = The number of hours in the given time period (quarter,
cumulative ozone season, cumulative year-to-date).
8.5 Specific provisions for monitoring NOX mass
emissions from common stacks. The owner or operator of a unit
utilizing a common stack may account for NOX mass
emissions using either of the following methodologies, if the
provisions of subpart H are adopted as requirements of a State or
federal NOX mass reduction program:
8.5.1 The owner or operator may determine both NOX
emission rate and heat input at the common stack and use the
procedures in section 8.1.1 of this appendix to determine hourly
NOX mass emissions at the common stack.
8.5.2 The owner or operator may determine the NOX
emission rate at the common stack and the heat input at each of the
units and use the procedures in section 8.1.2 of this appendix to
determine the hourly NOX mass emissions at each unit.
23. Part 96 is added to read as follows:
PART 96--NOX Budget Trading Program for State
Implementation Plans
Subpart A--NOX Budget Trading Program General Provisions
Sec.
96.1 Purpose.
96.2 Definitions.
96.3 Measurements, abbreviations, and acronyms.
96.4 Applicability.
96.5 Retired unit exemption.
96.6 Standard requirements.
96.7 Computation of time.
Subpart B--Authorized Account Representative for NOX Budget
Sources
96.10 Authorization and responsibilities of the NOX
authorized account representative.
96.11 Alternate NOX authorized account representative.
96.12 Changing the NOX authorized account representative
and the alternate NOX authorized account representative;
changes in the owners and operators.
96.13 Account certificate of representation.
96.14 Objections concerning the NOX authorized account
representative.
Subpart C--Permits
96.20 General NOX Budget permit requirements.
96.21 Submission of NOX Budget permit applications.
96.22 Information requirements for NOX Budget permit
applications.
96.23 NOX Budget permit contents.
96.24 Effective date of initial NOX Budget permit.
96.25 NOX Budget permit revisions.
Subpart D--Compliance Certification
96.30 Compliance certification report.
96.31 Permitting authority's and Administrator's action on
compliance certifications.
Subpart E--NOX Allowance Allocations
96.40 State trading program budget.
96.41 Timing requirements for NOX allowance allocations.
96.42 NOX allowance allocations.
Subpart F--NOX Allowance Tracking System
96.50 NOX Allowance Tracking System accounts.
96.51 Establishment of accounts.
96.52 NOX Allowance Tracking System responsibilities of
NOX authorized account representative.
96.53 Recordation of NOX allowance allocations.
96.54 Compliance.
96.55 Banking.
96.56 Account error.
96.57 Closing of general accounts.
[[Page 57515]]
Subpart G--NOX Allowance Transfers
96.60 Scope and submission of NOX allowance transfers.
96.61 EPA recordation.
96.62 Notification.
Subpart H--Monitoring and Reporting
96.70 General requirements.
96.71 Initial certification and recertification procedures.
96.72 Out of control periods.
96.73 Notifications.
96.74 Recordkeeping and reporting.
96.75 Petitions.
96.76 Additional requirements to provide heat input data for
allocations purposes.
Subpart I--Individual Unit Opt-ins
96.80 Applicability.
96.81 General.
96.82 NOX authorized account representative.
96.83 Applying for NOX Budget opt-in permit.
96.84 Opt-in process.
96.85 NOX Budget opt-in permit contents.
96.86 Withdrawal from NOX Budget Trading Program.
96.87 Change in regulatory status.
96.88 NOX allowance allocations to opt-in units.
Subpart J--Mobile and Area Sources [Reserved]
Authority: 42 U.S.C. 7401, 7403, 7410, and 7601
Subpart A--NOX Budget Trading Program General Provisions
Sec. 96.1 Purpose.
This part establishes general provisions and the applicability,
permitting, allowance, excess emissions, monitoring, and opt-in
provisions for the NOX Budget Trading Program for State
implementation plans 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 requirements of this
part as a matter of federal law only to the extent a State that has
jurisdiction over the unit incorporates by reference provisions of this
part, or otherwise adopts such requirements of this part, and requires
compliance, the State submits to the Administrator a State
implementation plan including such adoption and such compliance
requirement, and the Administrator approves the portion of the State
implementation plan including such adoption and such compliance
requirement. To the extent a State adopts requirements of this part,
including at a minimum the requirements of subpart A (except for
Sec. 96.4(b)), subparts B through D, subpart F (except for
Sec. 96.55(c)), and subparts G and H of this part, the State authorizes
the Administrator to assist the State in implementing the
NOX Budget Trading Program by carrying out the functions set
forth for the Administrator in such requirements.
Sec. 96.2 Definitions.
The terms used in this part shall have the meanings set forth in
this section as follows:
Account certificate of representation means the completed and
signed submission required by subpart B of this part for certifying the
designation of a NOX authorized account representative for a
NOX Budget source or a group of identified NOX
Budget sources who is authorized to represent the owners and operators
of such source or sources and of the NOX Budget units at
such source or sources with regard to matters under the NOX
Budget Trading Program.
Account number means the identification number given by the
Administrator to each NOX Allowance Tracking System account.
Acid Rain emissions limitation means, as defined in Sec. 72.2 of
this chapter, a limitation on emissions of sulfur dioxide or nitrogen
oxides under the Acid Rain Program under title IV of the CAA.
Administrator means the Administrator of the United States
Environmental Protection Agency or the Administrator's duly authorized
representative.
Allocate or allocation means the determination by the permitting
authority or the Administrator of the number of NOX
allowances to be initially credited to a NOX Budget unit or
an allocation set-aside.
Automated data acquisition and handling system or DAHS means that
component of the CEMS, or other emissions monitoring system approved
for use under subpart H of this part, designed to interpret and convert
individual output signals from pollutant concentration monitors, flow
monitors, diluent gas monitors, and other component parts of the
monitoring system to produce a continuous record of the measured
parameters in the measurement units required by subpart H of this part.
Boiler means an enclosed fossil or other fuel-fired combustion
device used to produce heat and to transfer heat to recirculating
water, steam, or other medium.
CAA means the CAA, 42 U.S.C. 7401, et seq., as amended by Pub. L.
No. 101-549 (November 15, 1990).
Combined cycle system means a system comprised of one or more
combustion turbines, heat recovery steam generators, and steam turbines
configured to improve overall efficiency of electricity generation or
steam production.
Combustion turbine means an enclosed fossil or other fuel-fired
device that is comprised of a compressor, a combustor, and a turbine,
and in which the flue gas resulting from the combustion of fuel in the
combustor passes through the turbine, rotating the turbine.
Commence commercial operation means, with regard to a unit that
serves a generator, to have begun to produce steam, gas, or other
heated medium used to generate electricity for sale or use, including
test generation. Except as provided in Sec. 96.5, for a unit that is a
NOX Budget unit under Sec. 96.4 on the date the unit
commences commercial operation, such date shall remain the unit's date
of commencement of commercial operation even if the unit is
subsequently modified, reconstructed, or repowered. Except as provided
in Sec. 96.5 or subpart I of this part, for a unit that is not a
NOX Budget unit under Sec. 96.4 on the date the unit
commences commercial operation, the date the unit becomes a
NOX Budget unit under Sec. 96.4 shall be the unit's date of
commencement of commercial operation.
Commence operation means to have begun any mechanical, chemical, or
electronic process, including, with regard to a unit, start-up of a
unit's combustion chamber. Except as provided in Sec. 96.5, for a unit
that is a NOX Budget unit under Sec. 96.4 on the date of
commencement of operation, such date shall remain the unit's date of
commencement of operation even if the unit is subsequently modified,
reconstructed, or repowered. Except as provided in Sec. 96.5 or subpart
I of this part, for a unit that is not a NOX Budget unit
under Sec. 96.4 on the date of commencement of operation, the date the
unit becomes a NOX Budget unit under Sec. 96.4 shall be the
unit's date of commencement of operation.
Common stack means a single flue through which emissions from two
or more units are exhausted.
Compliance account means a NOX Allowance Tracking System
account, established by the Administrator for a NOX Budget
unit under subpart F of this part, in which the NOX
allowance allocations for the unit are initially recorded and in which
are held NOX allowances available for use by the unit for a
control period for the purpose of meeting the unit's NOX
Budget emissions limitation.
Compliance certification means a submission to the permitting
authority
[[Page 57516]]
or the Administrator, as appropriate, that is required under subpart D
of this part to report a NOX Budget source's or a
NOX Budget unit's compliance or noncompliance with this part
and that is signed by the NOX authorized account
representative in accordance with subpart B of this part.
Continuous emission monitoring system or CEMS means the equipment
required under subpart H of this part to sample, analyze, measure, and
provide, by readings taken at least once every 15 minutes of the
measured parameters, a permanent record of nitrogen oxides emissions,
expressed in tons per hour for nitrogen oxides. The following systems
are component parts included, consistent with part 75 of this chapter,
in a continuous emission monitoring system:
(1) Flow monitor;
(2) Nitrogen oxides pollutant concentration monitors;
(3) Diluent gas monitor (oxygen or carbon dioxide) when such
monitoring is required by subpart H of this part;
(4) A continuous moisture monitor when such monitoring is required
by subpart H of this part; and
(5) An automated data acquisition and handling system.
Control period means the period beginning May 1 of a year and
ending on September 30 of the same year, inclusive.
Emissions means air pollutants exhausted from a unit or source into
the atmosphere, as measured, recorded, and reported to the
Administrator by the NOX authorized account representative
and as determined by the Administrator in accordance with subpart H of
this part.
Energy Information Administration means the Energy Information
Administration of the United States Department of Energy.
Excess emissions means any tonnage of nitrogen oxides emitted by a
NOX Budget unit during a control period that exceeds the
NOX Budget emissions limitation for the unit.
Fossil fuel means natural gas, petroleum, coal, or any form of
solid, liquid, or gaseous fuel derived from such material.
Fossil fuel-fired means, with regard to a unit:
(1) The combustion of fossil fuel, alone or in combination with any
other fuel, where fossil fuel actually combusted comprises more than 50
percent of the annual heat input on a Btu basis during any year
starting in 1995 or, if a unit had no heat input starting in 1995,
during the last year of operation of the unit prior to 1995; or
(2) The combustion of fossil fuel, alone or in combination with any
other fuel, where fossil fuel is projected to comprise more than 50
percent of the annual heat input on a Btu basis during any year;
provided that the unit shall be ``fossil fuel-fired'' as of the date,
during such year, on which the unit begins combusting fossil fuel.
General account means a NOX Allowance Tracking System
account, established under subpart F of this part, that is not a
compliance account or an overdraft account.
Generator means a device that produces electricity.
Heat input means the product (in mmBtu/time) of the gross calorific
value of the fuel (in Btu/lb) and the fuel feed rate into a combustion
device (in mass of fuel/time), as measured, recorded, and reported to
the Administrator by the NOX authorized account
representative and as determined by the Administrator in accordance
with subpart H of this part, and does not include the heat derived from
preheated combustion air, recirculated flue gases, or exhaust from
other sources.
Life-of-the-unit, firm power contractual arrangement means a unit
participation power sales agreement under which a utility or industrial
customer reserves, or is entitled to receive, a specified amount or
percentage of nameplate capacity and associated energy from any
specified unit and pays its proportional amount of such unit's total
costs, pursuant to a contract:
(1) For the life of the unit;
(2) For a cumulative term of no less than 30 years, including
contracts that permit an election for early termination; or
(3) For a period equal to or greater than 25 years or 70 percent of
the economic useful life of the unit determined as of the time the unit
is built, with option rights to purchase or release some portion of the
nameplate capacity and associated energy generated by the unit at the
end of the period.
Maximum design heat input means the ability of a unit to combust a
stated maximum amount of fuel per hour on a steady state basis, as
determined by the physical design and physical characteristics of the
unit.
Maximum potential hourly heat input means an hourly heat input used
for reporting purposes when a unit lacks certified monitors to report
heat input. If the unit intends to use appendix D of part 75 of this
chapter to report heat input, this value should be calculated, in
accordance with part 75 of this chapter, using the maximum fuel flow
rate and the maximum gross calorific value. If the unit intends to use
a flow monitor and a diluent gas monitor, this value should be
reported, in accordance with part 75 of this chapter, using the maximum
potential flowrate and either the maximum carbon dioxide concentration
(in percent CO2) or the minimum oxygen concentration (in
percent O2).
Maximum potential NOX emission rate means the emission
rate of nitrogen oxides (in lb/mmBtu) calculated in accordance with
section 3 of appendix F of part 75 of this chapter, using the maximum
potential nitrogen oxides concentration as defined in section 2 of
appendix A of part 75 of this chapter, and either the maximum oxygen
concentration (in percent O2) or the minimum carbon dioxide
concentration (in percent CO2), under all operating
conditions of the unit except for unit start up, shutdown, and upsets.
Maximum rated hourly heat input means a unit-specific maximum
hourly heat input (mmBtu) which is the higher of the manufacturer's
maximum rated hourly heat input or the highest observed hourly heat
input.
Monitoring system means any monitoring system that meets the
requirements of subpart H of this part, including a continuous
emissions monitoring system, an excepted monitoring system, or an
alternative monitoring system.
Most stringent State or Federal NOX emissions limitation
means, with regard to a NOX Budget opt-in source, the lowest
NOX emissions limitation (in terms of lb/mmBtu) that is
applicable to the unit under State or Federal law, regardless of the
averaging period to which the emissions limitation applies.
Nameplate capacity means the maximum electrical generating output
(in MWe) that a generator can sustain over a specified period of time
when not restricted by seasonal or other deratings as measured in
accordance with the United States Department of Energy standards.
Non-title V permit means a federally enforceable permit
administered by the permitting authority pursuant to the CAA and
regulatory authority under the CAA, other than title V of the CAA and
part 70 or 71 of this chapter.
NOX allowance means an authorization by the permitting
authority or the Administrator under the NOX Budget Trading
Program to emit up to one ton of nitrogen oxides during the control
period of the specified year or of any year thereafter.
NOX allowance deduction or deduct NOX
allowances means the permanent withdrawal of NOX allowances
by the
[[Page 57517]]
Administrator from a NOX Allowance Tracking System
compliance account or overdraft account to account for the number of
tons of NOX emissions from a NOX Budget unit for
a control period, determined in accordance with subpart H of this part,
or for any other allowance surrender obligation under this part.
NOX allowances held or hold NOX allowances
means the NOX allowances recorded by the Administrator, or
submitted to the Administrator for recordation, in accordance with
subparts F and G of this part, in a NOX Allowance Tracking
System account.
NOX Allowance Tracking System means the system by which
the Administrator records allocations, deductions, and transfers of
NOX allowances under the NOX Budget Trading
Program.
NOX Allowance Tracking System account means an account
in the NOX Allowance Tracking System established by the
Administrator for purposes of recording the allocation, holding,
transferring, or deducting of NOX allowances.
NOX allowance transfer deadline means midnight of
November 30 or, if November 30 is not a business day, midnight of the
first business day thereafter and is the deadline by which
NOX allowances may be submitted for recordation in a
NOX Budget unit's compliance account, or the overdraft
account of the source where the unit is located, in order to meet the
unit's NOX Budget emissions limitation for the control
period immediately preceding such deadline.
NOX authorized account representative means, for a
NOX Budget source or NOX Budget unit at the
source, the natural person who is authorized by the owners and
operators of the source and all NOX Budget units at the
source, in accordance with subpart B of this part, to represent and
legally bind each owner and operator in matters pertaining to the
NOX Budget Trading Program or, for a general account, the
natural person who is authorized, in accordance with subpart F of this
part, to transfer or otherwise dispose of NOX allowances
held in the general account.
NOX Budget emissions limitation means, for a
NOX Budget unit, the tonnage equivalent of the
NOX allowances available for compliance deduction for the
unit and for a control period under Sec. 96.54(a) and (b), adjusted by
any deductions of such NOX allowances to account for actual
utilization under Sec. 96.42(e) for the control period or to account
for excess emissions for a prior control period under Sec. 96.54(d) or
to account for withdrawal from the NOX Budget Program, or
for a change in regulatory status, for a NOX Budget opt-in
source under Sec. 96.86 or Sec. 96.87.
NOX Budget opt-in permit means a NOX Budget
permit covering a NOX Budget opt-in source.
NOX Budget opt-in source means a unit that has been
elected to become a NOX Budget unit under the NOX
Budget Trading Program and whose NOX Budget opt-in permit
has been issued and is in effect under subpart I of this part.
NOX Budget permit means the legally binding and
federally enforceable written document, or portion of such document,
issued by the permitting authority under this part, including any
permit revisions, specifying the NOX Budget Trading Program
requirements applicable to a NOX Budget source, to each
NOX Budget unit at the NOX Budget source, and to
the owners and operators and the NOX authorized account
representative of the NOX Budget source and each
NOX Budget unit.
NOX Budget source means a source that includes one or
more NOX Budget units.
NOX Budget Trading Program means a multi-state nitrogen
oxides air pollution control and emission reduction program established
in accordance with this part and pursuant to Sec. 51.121 of this
chapter, as a means of mitigating the interstate transport of ozone and
nitrogen oxides, an ozone precursor.
NOX Budget unit means a unit that is subject to the
NOX Budget Trading Program emissions limitation under
Sec. 96.4 or Sec. 96.80.
Operating means, with regard to a unit under Secs. 96.22(d)(2) and
96.80, having documented heat input for more than 876 hours in the 6
months immediately preceding the submission of an application for an
initial NOX Budget permit under Sec. 96.83(a).
Operator means any person who operates, controls, or supervises a
NOX Budget unit, a NOX Budget source, or unit for
which an application for a NOX Budget opt-in permit under
Sec. 96.83 is submitted and not denied or withdrawn and shall include,
but not be limited to, any holding company, utility system, or plant
manager of such a unit or source.
Opt-in means to be elected to become a NOX Budget unit
under the NOX Budget Trading Program through a final,
effective NOX Budget opt-in permit under subpart I of this
part.
Overdraft account means the NOX Allowance Tracking
System account, established by the Administrator under subpart F of
this part, for each NOX Budget source where there are two or
more NOX Budget units.
Owner means any of the following persons:
(1) Any holder of any portion of the legal or equitable title in a
NOX Budget unit or in a unit for which an application for a
NOX Budget opt-in permit under Sec. 96.83 is submitted and
not denied or withdrawn; or
(2) Any holder of a leasehold interest in a NOX Budget
unit or in a unit for which an application for a NOX Budget
opt-in permit under Sec. 96.83 is submitted and not denied or
withdrawn; or
(3) Any purchaser of power from a NOX Budget unit or
from a unit for which an application for a NOX Budget opt-in
permit under Sec. 96.83 is submitted and not denied or withdrawn under
a life-of-the-unit, firm power contractual arrangement. However, unless
expressly provided for in a leasehold agreement, owner shall not
include a passive lessor, or a person who has an equitable interest
through such lessor, whose rental payments are not based, either
directly or indirectly, upon the revenues or income from the
NOX Budget unit or the unit for which an application for a
NOX Budget opt-in permit under Sec. 96.83 is submitted and
not denied or withdrawn; or
(4) With respect to any general account, any person who has an
ownership interest with respect to the NOX allowances held
in the general account and who is subject to the binding agreement for
the NOX authorized account representative to represent that
person's ownership interest with respect to NOX allowances.
Permitting authority means the State air pollution control agency,
local agency, other State agency, or other agency authorized by the
Administrator to issue or revise permits to meet the requirements of
the NOX Budget Trading Program in accordance with subpart C
of this part.
Receive or receipt of means, when referring to the permitting
authority or the Administrator, to come into possession of a document,
information, or correspondence (whether sent in writing or by
authorized electronic transmission), as indicated in an official
correspondence log, or by a notation made on the document, information,
or correspondence, by the permitting authority or the Administrator in
the regular course of business.
Recordation, record, or recorded means, with regard to
NOX allowances, the movement of NOX allowances by
the Administrator from one NOX Allowance Tracking System
account to another, for purposes of allocation, transfer, or deduction.
[[Page 57518]]
Reference method means any direct test method of sampling and
analyzing for an air pollutant as specified in appendix A of part 60 of
this chapter.
Serial number means, when referring to NOX allowances,
the unique identification number assigned to each NOX
allowance by the Administrator, under Sec. 96.53(c).
Source means any governmental, institutional, commercial, or
industrial structure, installation, plant, building, or facility that
emits or has the potential to emit any regulated air pollutant under
the CAA. For purposes of section 502(c) of the CAA, 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 of this chapter, or any non-federal
authority in or including such States or the District of Columbia
(including local agencies, and Statewide agencies) or any eligible
Indian tribe in an area of such State or the District of Columbia, that
adopts a NOX Budget Trading Program pursuant to Sec. 51.121
of this chapter. To the extent a State incorporates by reference the
provisions of this part, the term ``State'' shall mean the
incorporating State. The term ``State'' shall have its conventional
meaning where such meaning is clear from the context.
State trading program budget means the total number of
NOX tons apportioned to all NOX Budget units in a
given State, in accordance with the NOX Budget Trading
Program, for use in a given control period.
Submit or serve means to send or transmit a document, information,
or correspondence to the person specified in accordance with the
applicable regulation:
(1) In person;
(2) By United States Postal Service; or
(3) By other means of dispatch or transmission and delivery.
Compliance with any ``submission,'' ``service,'' or ``mailing''
deadline shall be determined by the date of dispatch, transmission, or
mailing and not the date of receipt.
Title V operating permit means a permit issued under title V of the
CAA and part 70 or part 71 of this chapter.
Title V operating permit regulations means the regulations that the
Administrator has approved or issued as meeting the requirements of
title V of the CAA and part 70 or 71 of this chapter.
Ton or tonnage means any ``short ton'' (i.e., 2,000 pounds). For
the purpose of determining compliance with the NOX Budget
emissions limitation, total tons for a control period shall be
calculated as the sum of all recorded hourly emissions (or the tonnage
equivalent of the recorded hourly emissions rates) in accordance with
subpart H of this part, with any remaining fraction of a ton equal to
or greater than 0.50 ton deemed to equal one ton and any fraction of a
ton less than 0.50 ton deemed to equal zero tons.
Unit means a fossil fuel-fired stationary boiler, combustion
turbine, or combined cycle system.
Unit load means the total (i.e., gross) output of a unit in any
control period (or other specified time period) produced by combusting
a given heat input of fuel, expressed in terms of:
(1) The total electrical generation (MWe) produced by the unit,
including generation for use within the plant; or
(2) In the case of a unit that uses heat input for purposes other
than electrical generation, the total steam pressure (psia) produced by
the unit, including steam for use by the unit.
Unit operating day means a calendar day in which a unit combusts
any fuel.
Unit operating hour or hour of unit operation means any hour (or
fraction of an hour) during which a unit combusts any fuel.
Utilization means the heat input (expressed in mmBtu/time) for a
unit. The unit's total heat input for the control period in each year
will be determined in accordance with part 75 of this chapter if the
NOX Budget unit was otherwise subject to the requirements of
part 75 of this chapter for the year, or will be based on the best
available data reported to the Administrator for the unit if the unit
was not otherwise subject to the requirements of part 75 of this
chapter for the year.
Sec. 96.3 Measurements, abbreviations, and acronyms.
Measurements, abbreviations, and acronyms used in this part are
defined as follows:
Btu--British thermal unit.
hr--hour.
Kwh--kilowatt hour.
lb--pounds.
mmBtu--million Btu.
MWe--megawatt electrical.
ton--2000 pounds.
CO2--carbon dioxide.
NOX--nitrogen oxides.
O2--oxygen.
Sec. 96.4 Applicability.
(a) The following units in a State shall be NOX Budget
units, and any source that includes one or more such units shall be a
NOX Budget source, subject to the requirements of this part:
(1) Any unit that, any time on or after January 1, 1995, serves a
generator with a nameplate capacity greater than 25 MWe and sells any
amount of electricity; or
(2) Any unit that is not a unit under paragraph (a) of this section
and that has a maximum design heat input greater than 250 mmBtu/hr.
(b) Notwithstanding paragraph (a) of this section, a unit under
paragraph (a) of this section shall be subject only to the requirements
of this paragraph (b) if the unit has a federally enforceable permit
that meets the requirements of paragraph (b)(1) of this section and
restricts the unit to burning only natural gas or fuel oil during a
control period in 2003 or later and each control period thereafter and
restricts the unit's operating hours during each such control period to
the number of hours (determined in accordance with paragraph (b)(1)(ii)
and (iii) of this section) that limits the unit's potential
NOX mass emissions for the control period to 25 tons or
less. Notwithstanding paragraph (a) of this section, starting with the
effective date of such federally enforceable permit, the unit shall not
be a NOX Budget unit.
(1) For each control period under paragraph (b) of this section,
the federally enforceable permit must:
(i) Restrict the unit to burning only natural gas or fuel oil.
(ii) Restrict the unit's operating hours to the number calculated
by dividing 25 tons of potential NOX mass emissions by the
unit's maximum potential hourly NOX mass emissions.
(iii) Require that the unit's potential NOX mass
emissions shall be calculated as follows:
(A) Select the default NOX emission rate in Table 2 of
Sec. 75.19 of this chapter that would otherwise be applicable assuming
that the unit burns only the type of fuel (i.e., only natural gas or
only fuel oil) that has the highest default NOX emission
factor of any type of fuel that the unit is allowed to burn under the
fuel use restriction in paragraph (b)(1)(i) of this section; and
(B) Multiply the default NOX emission rate under
paragraph (b)(1)(iii)(A) of this section by the unit's maximum rated
hourly heat input. The owner or operator of the unit may petition the
permitting authority to use a lower value for the unit's maximum rated
hourly heat input than the value as defined under Sec. 96.2. The
permitting authority may approve such lower value if the owner or
operator demonstrates that the maximum hourly heat input specified by
the manufacturer or the highest observed hourly heat input, or both,
are not representative, and that such lower value is representative, of
the unit's current capabilities because
[[Page 57519]]
modifications have been made to the unit, limiting its capacity
permanently.
(iv) Require that the owner or operator of the unit shall retain at
the source that includes the unit, for 5 years, records demonstrating
that the operating hours restriction, the fuel use restriction, and the
other requirements of the permit related to these restrictions were
met.
(v) Require that the owner or operator of the unit shall report the
unit's hours of operation (treating any partial hour of operation as a
whole hour of operation) during each control period to the permitting
authority by November 1 of each year for which the unit is subject to
the federally enforceable permit.
(2) The permitting authority that issues the federally enforceable
permit with the fuel use restriction under paragraph (b)(1)(i) and the
operating hours restriction under paragraphs (b)(1)(ii) and (iii) of
this section will notify the Administrator in writing of each unit
under paragraph (a) of this section whose federally enforceable permit
issued by the permitting authority includes such restrictions. The
permitting authority will also notify the Administrator in writing of
each unit under paragraph (a) of this section whose federally
enforceable permit issued by the permitting authority is revised to
remove any such restriction, whose federally enforceable permit issued
by the permitting authority includes any such restriction that is no
longer applicable, or which does not comply with any such restriction.
(3) If, for any control period under paragraph (b) of this section,
the fuel use restriction under paragraph (b)(1)(i) of this section or
the operating hours restriction under paragraphs (b)(1)(ii) and (iii)
of this section is removed from the unit's federally enforceable permit
or otherwise becomes no longer applicable or if, for any such control
period, the unit does not comply with the fuel use restriction under
paragraph (b)(1)(i) of this section or the operating hours restriction
under paragraphs (b)(1)(ii) and (iii) of this section, the unit shall
be a NOX Budget unit, subject to the requirements of this
part. Such unit shall be treated as commencing operation and, for a
unit under paragraph (a)(1) of this section, commencing commercial
operation on September 30 of the control period for which the fuel use
restriction or the operating hours restriction is no longer applicable
or during which the unit does not comply with the fuel use restriction
or the operating hours restriction.
Sec. 96.5 Retired unit exemption.
(a) This section applies to any NOX Budget unit, other
than a NOX Budget opt-in source, that is permanently
retired.
(b)(1) Any NOX Budget unit, other than a NOX
Budget opt-in source, that is permanently retired shall be exempt from
the NOX Budget Trading Program, except for the provisions of
this section, Secs. 96.2, 96.3, 96.4, 96.7 and subparts E, F, and G of
this part.
(2) The exemption under paragraph (b)(1) of this section shall
become effective the day on which the unit is permanently retired.
Within 30 days of permanent retirement, the NOX authorized
account representative (authorized in accordance with subpart B of this
part) shall submit a statement to the permitting authority otherwise
responsible for administering any NOX Budget permit for the
unit. A copy of the statement shall be submitted to the Administrator.
The statement shall state (in a format prescribed by the permitting
authority) that the unit is permanently retired and will comply with
the requirements of paragraph (c) of this section.
(3) After receipt of the notice under paragraph (b)(2) of this
section, the permitting authority will amend any permit covering the
source at which the unit is located to add the provisions and
requirements of the exemption under paragraphs (b)(1) and (c) of this
section.
(c) Special provisions. (1) A unit exempt under this section shall
not emit any nitrogen oxides, starting on the date that the exemption
takes effect. The owners and operators of the unit will be allocated
allowances in accordance with subpart E of this part.
(2)(i) A unit exempt under this section and located at a source
that is required, or but for this exemption would be required, to have
a title V operating permit shall not resume operation unless the
NOX authorized account representative of the source submits
a complete NOX Budget permit application under Sec. 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
for final action on a permit application) prior to the later of May 1,
2003 or the date on which the unit is to first resume operation.
(ii) A unit exempt under this section and located at a source that
is required, or but for this exemption would be required, to have a
non-title V permit shall not resume operation unless the NOX
authorized account representative of the source submits a complete
NOX Budget permit application under Sec. 96.22 for the unit
not less than 18 months (or such lesser time provided under the
permitting authority's non-title V permits regulations for final action
on a permit application) prior to the later of May 1, 2003 or the date
on which the unit is to first resume operation.
(3) The owners and operators and, to the extent applicable, the
NOX authorized account representative of a unit exempt under
this section shall comply with the requirements of the NOX
Budget Trading Program concerning all periods for which the exemption
is not in effect, even if such requirements arise, or must be complied
with, after the exemption takes effect.
(4) A unit that is exempt under this section is not eligible to be
a NOX Budget opt-in source under subpart I of this part.
(5) For a period of 5 years from the date the records are created,
the owners and operators of a unit exempt under this section shall
retain at the source that includes the unit, records demonstrating that
the unit is permanently retired. The 5-year period for keeping records
may be extended for cause, at any time prior to the end of the period,
in writing by the permitting authority or the Administrator. The owners
and operators bear the burden of proof that the unit is permanently
retired.
(6) Loss of exemption. (i) On the earlier of the following dates, a
unit exempt under paragraph (b) of this section shall lose its
exemption:
(A) The date on which the NOX authorized account
representative submits a NOX Budget permit application under
paragraph (c)(2) of this section; or
(B) The date on which the NOX authorized account
representative is required under paragraph (c)(2) of this section to
submit a NOX Budget permit application.
(ii) For the purpose of applying monitoring requirements under
subpart H of this part, a unit that loses its exemption under this
section shall be treated as a unit that commences operation or
commercial operation on the first date on which the unit resumes
operation.
Sec. 96.6 Standard requirements.
(a) Permit Requirements. (1) The NOX authorized account
representative of each NOX Budget source required to have a
federally enforceable permit and each NOX Budget unit
required to have a federally enforceable permit at the source shall:
(i) Submit to the permitting authority a complete NOX
Budget permit application under Sec. 96.22 in accordance
[[Page 57520]]
with the deadlines specified in Sec. 96.21(b) and (c);
(ii) Submit in a timely manner any supplemental information that
the permitting authority determines is necessary in order to review a
NOX Budget permit application and issue or deny a
NOX Budget permit.
(2) The owners and operators of each NOX Budget source
required to have a federally enforceable permit and each NOX
Budget unit required to have a federally enforceable permit at the
source shall have a NOX Budget permit issued by the
permitting authority and operate the unit in compliance with such
NOX Budget permit.
(3) The owners and operators of a NOX Budget source that
is not otherwise required to have a federally enforceable permit are
not required to submit a NOX Budget permit application, and
to have a NOX Budget permit, under subpart C of this part
for such NOX Budget source.
(b) Monitoring requirements. (1) The owners and operators and, to
the extent applicable, the NOX authorized account
representative of each NOX Budget source and each
NOX Budget unit at the source shall comply with the
monitoring requirements of subpart H of this part.
(2) The emissions measurements recorded and reported in accordance
with subpart H of this part shall be used to determine compliance by
the unit with the NOX Budget emissions limitation under
paragraph (c) of this section.
(c) Nitrogen oxides requirements. (1) The owners and operators of
each NOX Budget source and each NOX Budget unit
at the source shall hold NOX allowances available for
compliance deductions under Sec. 96.54, as of the NOX
allowance transfer deadline, in the unit's compliance account and the
source's overdraft account in an amount not less than the total
NOX emissions for the control period from the unit, as
determined in accordance with subpart H of this part, plus any amount
necessary to account for actual utilization under Sec. 96.42(e) for the
control period.
(2) Each ton of nitrogen oxides emitted in excess of the
NOX Budget emissions limitation shall constitute a separate
violation of this part, the CAA, and applicable State law.
(3) A NOX Budget unit shall be subject to the
requirements under paragraph (c)(1) of this section starting on the
later of May 1, 2003 or the date on which the unit commences operation.
(4) NOX allowances shall be held in, deducted from, or
transferred among NOX Allowance Tracking System accounts in
accordance with subparts E, F, G, and I of this part.
(5) A NOX allowance shall not be deducted, in order to
comply with the requirements under paragraph (c)(1) of this section,
for a control period in a year prior to the year for which the
NOX allowance was allocated.
(6) A NOX allowance allocated by the permitting
authority or the Administrator under the NOX Budget Trading
Program is a limited authorization to emit one ton of nitrogen oxides
in accordance with the NOX Budget Trading Program. No
provision of the NOX Budget Trading Program, the
NOX Budget permit application, the NOX Budget
permit, or an exemption under Sec. 96.5 and no provision of law shall
be construed to limit the authority of the United States or the State
to terminate or limit such authorization.
(7) A NOX allowance allocated by the permitting
authority or the Administrator under the NOX Budget Trading
Program does not constitute a property right.
(8) Upon recordation by the Administrator under subpart F, G, or I
of this part, every allocation, transfer, or deduction of a
NOX allowance to or from a NOX Budget unit's
compliance account or the overdraft account of the source where the
unit is located is deemed to amend automatically, and become a part of,
any NOX Budget permit of the NOX Budget unit by
operation of law without any further review.
(d) Excess emissions requirements. (1) The owners and operators of
a NOX Budget unit that has excess emissions in any control
period shall:
(i) Surrender the NOX allowances required for deduction
under Sec. 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).
(e) Recordkeeping and Reporting requirements.
(1) Unless otherwise provided, the owners and operators of the
NOX Budget source and each NOX Budget unit at the
source shall keep on site at the source each of the following documents
for a period of 5 years from the date the document is created. This
period may be extended for cause, at any time prior to the end of 5
years, in writing by the permitting authority or the Administrator.
(i) The account certificate of representation for the
NOX authorized account representative for the source and
each NOX Budget unit at the source and all documents that
demonstrate the truth of the statements in the account certificate of
representation, in accordance with Sec. 96.13; provided that the
certificate and documents shall be retained on site at the source
beyond such 5-year period until such documents are superseded because
of the submission of a new account certificate of representation
changing the NOX authorized account representative.
(ii) All emissions monitoring information, in accordance with
subpart H of this part; provided that to the extent that subpart H of
this part provides for a 3-year period for recordkeeping, the 3-year
period shall apply.
(iii) Copies of all reports, compliance certifications, and other
submissions and all records made or required under the NOX
Budget Trading Program.
(iv) Copies of all documents used to complete a NOX
Budget permit application and any other submission under the
NOX Budget Trading Program or to demonstrate compliance with
the requirements of the NOX Budget Trading Program.
(2) The NOX authorized account representative of a
NOX Budget source and each NOX Budget unit at the
source shall submit the reports and compliance certifications required
under the NOX Budget Trading Program, including those under
subparts D, H, or I of this part.
(f) Liability. (1) Any person who knowingly violates any
requirement or prohibition of the NOX Budget Trading
Program, a NOX Budget permit, or an exemption under
Sec. 96.5 shall be subject to enforcement pursuant to applicable State
or Federal law.
(2) Any person who knowingly makes a false material statement in
any record, submission, or report under the NOX Budget
Trading Program shall be subject to criminal enforcement pursuant to
the applicable State or Federal law.
(3) No permit revision shall excuse any violation of the
requirements of the NOX Budget Trading Program that occurs
prior to the date that the revision takes effect.
(4) Each NOX Budget source and each NOX
Budget unit shall meet the requirements of the NOX Budget
Trading Program.
(5) Any provision of the NOX Budget Trading Program that
applies to a NOX Budget source (including a provision
applicable to the NOX authorized account representative of a
NOX Budget source) shall also apply to the owners and
operators of such source and of the NOX Budget units at the
source.
(6) Any provision of the NOX Budget Trading Program that
applies to a NOX Budget unit (including a provision
applicable to the NOX authorized
[[Page 57521]]
account representative of a NOX budget unit) shall also
apply to the owners and operators of such unit. Except with regard to
the requirements applicable to units with a common stack under subpart
H of this part, the owners and operators and the NOX
authorized account representative of one NOX Budget unit
shall not be liable for any violation by any other NOX
Budget unit of which they are not owners or operators or the
NOX authorized account representative and that is located at
a source of which they are not owners or operators or the
NOX authorized account representative.
(g) Effect on other authorities. No provision of the NOX
Budget Trading Program, a NOX Budget permit application, a
NOX Budget permit, or an exemption under Sec. 96.5 shall be
construed as exempting or excluding the owners and operators and, to
the extent applicable, the NOX authorized account
representative of a NOX Budget source or NOX
Budget unit from compliance with any other provision of the applicable,
approved State implementation plan, a federally enforceable permit, or
the CAA.
Sec. 96.7 Computation of time.
(a) Unless otherwise stated, any time period scheduled, under the
NOX Budget Trading Program, to begin on the occurrence of an
act or event shall begin on the day the act or event occurs.
(b) Unless otherwise stated, any time period scheduled, under the
NOX Budget Trading Program, to begin before the occurrence
of an act or event shall be computed so that the period ends the day
before the act or event occurs.
(c) Unless otherwise stated, if the final day of any time period,
under the NOX Budget Trading Program, falls on a weekend or
a State or Federal holiday, the time period shall be extended to the
next business day.
Subpart B--NOX Authorized Account Representative for
NOX Budget Sources
Sec. 96.10 Authorization and responsibilities of the NOX
authorized account representative.
(a) Except as provided under Sec. 96.11, each NOX Budget
source, including all NOX Budget units at the source, shall
have one and only one NOX authorized account representative,
with regard to all matters under the NOX Budget Trading
Program concerning the source or any NOX Budget unit at the
source.
(b) The NOX authorized account representative of the
NOX Budget source shall be selected by an agreement binding
on the owners and operators of the source and all NOX Budget
units at the source.
(c) Upon receipt by the Administrator of a complete account
certificate of representation under Sec. 96.13, the NOX
authorized account representative of the source shall represent and, by
his or her representations, actions, inactions, or submissions, legally
bind each owner and operator of the NOX Budget source
represented and each NOX Budget unit at the source in all
matters pertaining to the NOX Budget Trading Program, not
withstanding any agreement between the NOX authorized
account representative and such owners and operators. The owners and
operators shall be bound by any decision or order issued to the
NOX authorized account representative by the permitting
authority, the Administrator, or a court regarding the source or unit.
(d) No NOX Budget permit shall be issued, and no
NOX Allowance Tracking System account shall be established
for a NOX Budget unit at a source, until the Administrator
has received a complete account certificate of representation under
Sec. 96.13 for a NOX authorized account representative of
the source and the NOX Budget units at the source.
(e)(1) Each submission under the NOX Budget Trading
Program shall be submitted, signed, and certified by the NOX
authorized account representative for each NOX Budget source
on behalf of which the submission is made. Each such submission shall
include the following certification statement by the NOX
authorized account representative: ``I am authorized to make this
submission on behalf of the owners and operators of the NOX
Budget sources or NOX Budget units for which the submission
is made. I certify under penalty of law that I have personally
examined, and am familiar with, the statements and information
submitted in this document and all its attachments. Based on my inquiry
of those individuals with primary responsibility for obtaining the
information, I certify that the statements and information are to the
best of my knowledge and belief true, accurate, and complete. I am
aware that there are significant penalties for submitting false
statements and information or omitting required statements and
information, including the possibility of fine or imprisonment.''
(2) The permitting authority and the Administrator will accept or
act on a submission made on behalf of owner or operators of a
NOX Budget source or a NOX Budget unit only if
the submission has been made, signed, and certified in accordance with
paragraph (e)(1) of this section.
Sec. 96.11 Alternate NOX authorized account representative.
(a) An account certificate of representation may designate one and
only one alternate NOX authorized account representative who
may act on behalf of the NOX authorized account
representative. The agreement by which the alternate NOX
authorized account representative is selected shall include a procedure
for authorizing the alternate NOX authorized account
representative to act in lieu of the NOX authorized account
representative.
(b) Upon receipt by the Administrator of a complete account
certificate of representation under Sec. 96.13, any representation,
action, inaction, or submission by the alternate NOX
authorized account representative shall be deemed to be a
representation, action, inaction, or submission by the NOX
authorized account representative.
(c) Except in this section and Secs. 96.10(a), 96.12, 96.13, and
96.51, whenever the term ``NOX authorized account
representative'' is used in this part, the term shall be construed to
include the alternate NOX authorized account representative.
Sec. 96.12 Changing the NOX authorized account
representative and the alternate NOX authorized account
representative; changes in the owners and operators.
(a) Changing the NOX authorized account representative.
The NOX authorized account representative may be changed at
any time upon receipt by the Administrator of a superseding complete
account certificate of representation under Sec. 96.13. Notwithstanding
any such change, all representations, actions, inactions, and
submissions by the previous NOX authorized account
representative prior to the time and date when the Administrator
receives the superseding account certificate of representation shall be
binding on the new NOX authorized account representative and
the owners and operators of the NOX Budget source and the
NOX Budget units at the source.
(b) Changing the alternate NOX authorized account
representative. The alternate NOX authorized account
representative may be changed at any time upon receipt by the
Administrator of a superseding complete account certificate of
representation under Sec. 96.13. Notwithstanding any such change, all
representations, actions, inactions, and submissions by the previous
alternate NOX authorized account representative prior to the
time and date when the Administrator receives the superseding account
certificate of representation shall be
[[Page 57522]]
binding on the new alternate NOX authorized account
representative and the owners and operators of the NOX
Budget source and the NOX Budget units at the source.
(c) Changes in the owners and operators. (1) In the event a new
owner or operator of a NOX Budget source or a NOX
Budget unit is not included in the list of owners and operators
submitted in the account certificate of representation, such new owner
or operator shall be deemed to be subject to and bound by the account
certificate of representation, the representations, actions, inactions,
and submissions of the NOX authorized account representative
and any alternate NOX authorized account representative of
the source or unit, and the decisions, orders, actions, and inactions
of the permitting authority or the Administrator, as if the new owner
or operator were included in such list.
(2) Within 30 days following any change in the owners and operators
of a NOX Budget source or a NOX Budget unit,
including the addition of a new owner or operator, the NOX
authorized account representative or alternate NOX
authorized account representative shall submit a revision to the
account certificate of representation amending the list of owners and
operators to include the change.
Sec. 96.13 Account certificate of representation.
(a) A complete account certificate of representation for a
NOX authorized account representative or an alternate
NOX authorized account representative shall include the
following elements in a format prescribed by the Administrator:
(1) Identification of the NOX Budget source and each
NOX Budget unit at the source for which the account
certificate of representation is submitted.
(2) The name, address, e-mail address (if any), telephone number,
and facsimile transmission number (if any) of the NOX
authorized account representative and any alternate NOX
authorized account representative.
(3) A list of the owners and operators of the NOX Budget
source and of each NOX Budget unit at the source.
(4) The following certification statement by the NOX
authorized account representative and any alternate NOX
authorized account representative: ``I certify that I was selected as
the NOX authorized account representative or alternate
NOX authorized account representative, as applicable, by an
agreement binding on the owners and operators of the NOX
Budget source and each NOX Budget unit at the source. I
certify that I have all the necessary authority to carry out my duties
and responsibilities under the NOX Budget Trading Program on
behalf of the owners and operators of the NOX Budget source
and of each NOX Budget unit at the source and that each such
owner and operator shall be fully bound by my representations, actions,
inactions, or submissions and by any decision or order issued to me by
the permitting authority, the Administrator, or a court regarding the
source or unit.''
(5) The signature of the NOX authorized account
representative and any alternate NOX authorized account
representative and the dates signed.
(b) Unless otherwise required by the permitting authority or the
Administrator, documents of agreement referred to in the account
certificate of representation shall not be submitted to the permitting
authority or the Administrator. Neither the permitting authority nor
the Administrator shall be under any obligation to review or evaluate
the sufficiency of such documents, if submitted.
Sec. 96.14 Objections concerning the NOX authorized account
representative.
(a) Once a complete account certificate of representation under
Sec. 96.13 has been submitted and received, the permitting authority
and the Administrator will rely on the account certificate of
representation unless and until a superseding complete account
certificate of representation under Sec. 96.13 is received by the
Administrator.
(b) Except as provided in Sec. 96.12(a) or (b), no objection or
other communication submitted to the permitting authority or the
Administrator concerning the authorization, or any representation,
action, inaction, or submission of the NOX authorized
account representative shall affect any representation, action,
inaction, or submission of the NOX authorized account
representative or the finality of any decision or order by the
permitting authority or the Administrator under the NOX
Budget Trading Program.
(c) Neither the permitting authority nor the Administrator will
adjudicate any private legal dispute concerning the authorization or
any representation, action, inaction, or submission of any
NOX authorized account representative, including private
legal disputes concerning the proceeds of NOX allowance
transfers.
Subpart C--Permits
Sec. 96.20 General NOX Budget trading program permit
requirements.
(a) For each NOX Budget source required to have a
federally enforceable permit, such permit shall include a
NOX Budget permit administered by the permitting authority.
(1) For NOX Budget sources required to have a title V
operating permit, the NOX Budget portion of the title V
permit shall be administered in accordance with the permitting
authority's title V operating permits regulations promulgated under
part 70 or 71 of this chapter, except as provided otherwise by this
subpart or subpart I of this part. The applicable provisions of such
title V operating permits regulations shall include, but are not
limited to, those provisions addressing operating permit applications,
operating permit application shield, operating permit duration,
operating permit shield, operating permit issuance, operating permit
revision and reopening, public participation, State review, and review
by the Administrator.
(2) For NOX Budget sources required to have a non-title
V permit, the NOX Budget portion of the non-title V permit
shall be administered in accordance with the permitting authority's
regulations promulgated to administer non-title V permits, except as
provided otherwise by this subpart or subpart I of this part. The
applicable provisions of such non-title V permits regulations may
include, but are not limited to, provisions addressing permit
applications, permit application shield, permit duration, permit
shield, permit issuance, permit revision and reopening, public
participation, State review, and review by the Administrator.
(b) Each NOX Budget permit (including a draft or
proposed NOX Budget permit, if applicable) shall contain all
applicable NOX Budget Trading Program requirements and shall
be a complete and segregable portion of the permit under paragraph (a)
of this section.
Sec. 96.21 Submission of NOX Budget permit applications.
(a) Duty to apply. The NOX authorized account
representative of any NOX Budget source required to have a
federally enforceable permit shall submit to the permitting authority a
complete NOX Budget permit application under Sec. 96.22 by
the applicable deadline in paragraph (b) of this section.
[[Page 57523]]
(b)(1) For NOX Budget sources required to have a title V
operating permit:
(i) For any source, with one or more NOX Budget units
under Sec. 96.4 that commence operation before January 1, 2000, the
NOX authorized account representative shall submit a
complete NOX Budget permit application under Sec. 96.22
covering such NOX Budget units to the permitting authority
at least 18 months (or such lesser time provided under the permitting
authority's title V operating permits regulations for final action on a
permit application) before May 1, 2003.
(ii) For any source, with any NOX Budget unit under
Sec. 96.4 that commences operation on or after January 1, 2000, the
NOX authorized account representative shall submit a
complete NOX Budget permit application under Sec. 96.22
covering such NOX Budget unit to the permitting authority at
least 18 months (or such lesser time provided under the permitting
authority's title V operating permits regulations for final action on a
permit application) before the later of May 1, 2003 or the date on
which the NOX Budget unit commences operation.
(2) For NOX Budget sources required to have a non-title
V permit:
(i) For any source, with one or more NOX Budget units
under Sec. 96.4 that commence operation before January 1, 2000, the
NOX authorized account representative shall submit a
complete NOX Budget permit application under Sec. 96.22
covering such NOX Budget units to the permitting authority
at least 18 months (or such lesser time provided under the permitting
authority's non-title V permits regulations for final action on a
permit application) before May 1, 2003.
(ii) For any source, with any NOX Budget unit under
Sec. 96.4 that commences operation on or after January 1, 2000, the
NOX authorized account representative shall submit a
complete NOX Budget permit application under Sec. 96.22
covering such NOX Budget unit to the permitting authority at
least 18 months (or such lesser time provided under the permitting
authority's non-title V permits regulations for final action on a
permit application) before the later of May 1, 2003 or the date on
which the NOX Budget unit commences operation.
(c) Duty to reapply. (1) For a NOX Budget source
required to have a title V operating permit, the NOX
authorized account representative shall submit a complete
NOX Budget permit application under Sec. 96.22 for the
NOX Budget source covering the NOX Budget units
at the source in accordance with the permitting authority's title V
operating permits regulations addressing operating permit renewal.
(2) For a NOX Budget source required to have a non-title
V permit, the NOX authorized account representative shall
submit a complete NOX Budget permit application under
Sec. 96.22 for the NOX Budget source covering the
NOX Budget units at the source in accordance with the
permitting authority's non-title V permits regulations addressing
permit renewal.
Sec. 96.22 Information requirements for NOX Budget permit
applications.
A complete NOX Budget permit application shall include
the following elements concerning the NOX Budget source for
which the application is submitted, in a format prescribed by the
permitting authority:
(a) Identification of the NOX Budget source, including
plant name and the ORIS (Office of Regulatory Information Systems) or
facility code assigned to the source by the Energy Information
Administration, if applicable;
(b) Identification of each NOX Budget unit at the
NOX Budget source and whether it is a NOX Budget
unit under Sec. 96.4 or under subpart I of this part;
(c) The standard requirements under Sec. 96.6; and
(d) For each NOX Budget opt-in unit at the
NOX Budget source, the following certification statements by
the NOX authorized account representative:
(1) ``I certify that each unit for which this permit application is
submitted under subpart I of this part is not a NOX Budget
unit under 40 CFR 96.4 and is not covered by a retired unit exemption
under 40 CFR 96.5 that is in effect.''
(2) If the application is for an initial NOX Budget opt-
in permit, ``I certify that each unit for which this permit application
is submitted under subpart I is currently operating, as that term is
defined under 40 CFR 96.2.''
Sec. 96.23 NOX Budget permit contents.
(a) Each NOX Budget permit (including any draft or
proposed NOX Budget permit, if applicable) will contain, in
a format prescribed by the permitting authority, all elements required
for a complete NOX Budget permit application under
Sec. 96.22 as approved or adjusted by the permitting authority.
(b) Each NOX Budget permit is deemed to incorporate
automatically the definitions of terms under Sec. 96.2 and, upon
recordation by the Administrator under subparts F, G, or I of this
part, every allocation, transfer, or deduction of a NOX
allowance to or from the compliance accounts of the NOX
Budget units covered by the permit or the overdraft account of the
NOX Budget source covered by the permit.
Sec. 96.24 Effective date of initial NOX Budget permit.
The initial NOX Budget permit covering a NOX
Budget unit for which a complete NOX Budget permit
application is timely submitted under Sec. 96.21(b) shall become
effective by the later of:
(a) May 1, 2003;
(b) May 1 of the year in which the NOX Budget unit
commences operation, if the unit commences operation on or before May 1
of that year;
(c) The date on which the NOX Budget unit commences
operation, if the unit commences operation during a control period; or
(d) May 1 of the year following the year in which the
NOX Budget unit commences operation, if the unit commences
operation on or after October 1 of the year.
Sec. 96.25 NOX Budget permit revisions.
(a) For a NOX Budget source with a title V operating
permit, except as provided in Sec. 96.23(b), the permitting authority
will revise the NOX Budget permit, as necessary, in
accordance with the permitting authority's title V operating permits
regulations addressing permit revisions.
(b) For a NOX Budget source with a non-title V permit,
except as provided in Sec. 96.23(b), the permitting authority will
revise the NOX Budget permit, as necessary, in accordance
with the permitting authority's non-title V permits regulations
addressing permit revisions.
Subpart D--Compliance Certification
Sec. 96.30 Compliance certification report.
(a) Applicability and deadline. For each control period in which
one or more NOX Budget units at a source are subject to the
NOX Budget emissions limitation, the NOX
authorized account representative of the source shall submit to the
permitting authority and the Administrator by November 30 of that year,
a compliance certification report for each source covering all such
units.
(b) Contents of report. The NOX authorized account
representative shall include in the compliance certification report
under paragraph (a) of this section the following elements, in a format
prescribed by the Administrator, concerning each unit at the source and
subject to the NOX Budget emissions limitation for the
control period covered by the report:
(1) Identification of each NOX Budget unit;
[[Page 57524]]
(2) At the NOX authorized account representative's
option, the serial numbers of the NOX allowances that are to
be deducted from each unit's compliance account under Sec. 96.54 for
the control period;
(3) At the NOX authorized account representative's
option, for units sharing a common stack and having NOX
emissions that are not monitored separately or apportioned in
accordance with subpart H of this part, the percentage of allowances
that is to be deducted from each unit's compliance account under
Sec. 96.54(e); and
(4) The compliance certification under paragraph (c) of this
section.
(c) Compliance certification. In the compliance certification
report under paragraph (a) of this section, the NOX
authorized account representative shall certify, based on reasonable
inquiry of those persons with primary responsibility for operating the
source and the NOX Budget units at the source in compliance
with the NOX Budget Trading Program, whether each
NOX Budget unit for which the compliance certification is
submitted was operated during the calendar year covered by the report
in compliance with the requirements of the NOX Budget
Trading Program applicable to the unit, including:
(1) Whether the unit was operated in compliance with the
NOX Budget emissions limitation;
(2) Whether the monitoring plan that governs the unit has been
maintained to reflect the actual operation and monitoring of the unit,
and contains all information necessary to attribute NOX
emissions to the unit, in accordance with subpart H of this part;
(3) Whether all the NOX emissions from the unit, or a
group of units (including the unit) using a common stack, were
monitored or accounted for through the missing data procedures and
reported in the quarterly monitoring reports, including whether
conditional data were reported in the quarterly reports in accordance
with subpart H of this part. If conditional data were reported, the
owner or operator shall indicate whether the status of all conditional
data has been resolved and all necessary quarterly report resubmissions
has been made;
(4) Whether the facts that form the basis for certification under
subpart H of this part of each monitor at the unit or a group of units
(including the unit) using a common stack, or for using an excepted
monitoring method or alternative monitoring method approved under
subpart H of this part, if any, has changed; and
(5) If a change is required to be reported under paragraph (c)(4)
of this section, specify the nature of the change, the reason for the
change, when the change occurred, and how the unit's compliance status
was determined subsequent to the change, including what method was used
to determine emissions when a change mandated the need for monitor
recertification.
Sec. 96.31 Permitting authority's and Administrator's action on
compliance certifications.
(a) The permitting authority or the Administrator may review and
conduct independent audits concerning any compliance certification or
any other submission under the NOX Budget Trading Program
and make appropriate adjustments of the information in the compliance
certifications or other submissions.
(b) The Administrator may deduct NOX allowances from or
transfer NOX allowances to a unit's compliance account or a
source's overdraft account based on the information in the compliance
certifications or other submissions, as adjusted under paragraph (a) of
this section.
Subpart E--NOX Allowance Allocations
Sec. 96.40 State trading program budget.
The State trading program budget allocated by the permitting
authority under Sec. 96.42 for a control period will equal the total
number of tons of NOX emissions apportioned to the
NOX Budget units under Sec. 96.4 in the State for the
control period, as determined by the applicable, approved State
implementation plan.
Sec. 96.41 Timing requirements for NOX allowance
allocations.
(a) By September 30, 1999, the permitting authority will submit to
the Administrator the NOX allowance allocations, in
accordance with Sec. 96.42, for the control periods in 2003, 2004, and
2005.
(b) By April 1, 2003 and April 1 of each year thereafter, the
permitting authority will submit to the Administrator the
NOX allowance allocations, in accordance with Sec. 96.42,
for the control period in the year that is three years after the year
of the applicable deadline for submission under this paragraph (b). If
the permitting authority fails to submit to the Administrator the
NOX allowance allocations in accordance with this paragraph
(b), the Administrator will allocate, for the applicable control
period, the same number of NOX allowances as were allocated
for the preceding control period.
(c) By April 1, 2004 and April 1 of each year thereafter, the
permitting authority will submit to the Administrator the
NOX allowance allocations, in accordance with Sec. 96.42,
for any NOX allowances remaining in the allocation set-aside
for the prior control period.
Sec. 96.42 NOX allowance allocations.
(a)(1) The heat input (in mmBtu) used for calculating
NOX allowance allocations for each NOX Budget
unit under Sec. 96.4 will be:
(i) For a NOX allowance allocation under Sec. 96.41(a),
the average of the two highest amounts of the unit's heat input for the
control periods in 1995, 1996, and 1997 if the unit is under
Sec. 96.4(a)(1) or the control period in 1995 if the unit is under
Sec. 96.4(a)(2); and
(ii) For a NOX allowance allocation under Sec. 96.41(b),
the unit's heat input for the control period in the year that is four
years before the year for which the NOX allocation is being
calculated.
(2) The unit's total heat input for the control period in each year
specified under paragraph (a)(1) of this section will be determined in
accordance with part 75 of this chapter if the NOX Budget
unit was otherwise subject to the requirements of part 75 of this
chapter for the year, or will be based on the best available data
reported to the permitting authority for the unit if the unit was not
otherwise subject to the requirements of part 75 of this chapter for
the year.
(b) For each control period under Sec. 96.41, the permitting
authority will allocate to all NOX Budget units under
Sec. 96.4(a)(1) in the State that commenced operation before May 1 of
the period used to calculate heat input under paragraph (a)(1) of this
section, a total number of NOX allowances equal to 95
percent in 2003, 2004, and 2005, or 98 percent thereafter, of the tons
of NOX emissions in the State trading program budget
apportioned to electric generating units under Sec. 96.40 in accordance
with the following procedures:
(1) The permitting authority will allocate NOX
allowances to each NOX Budget unit under Sec. 96.4(a)(1) in
an amount equaling 0.15 lb/mmBtu multiplied by the heat input
determined under paragraph (a) of this section, rounded to the nearest
whole NOX allowance as appropriate.
(2) If the initial total number of NOX allowances
allocated to all NOX Budget units under Sec. 96.4(a)(1) in
the State for a control period under paragraph (b)(1) of this section
does not equal 95 percent in 2003, 2004, and 2005, or 98 percent
thereafter, of the number of tons of NOX emissions in the
State trading program
[[Page 57525]]
budget apportioned to electric generating units, the permitting
authority will adjust the total number of NOX allowances
allocated to all such NOX Budget units for the control
period under paragraph (b)(1) of this section so that the total number
of NOX allowances allocated equals 95 percent in 2003, 2004,
and 2005, or 98 percent thereafter, of the number of tons of
NOX emissions in the State trading program budget
apportioned to electric generating units. This adjustment will be made
by: multiplying each unit's allocation by 95 percent in 2003, 2004, and
2005, or 98 percent thereafter, of the number of tons of NOX
emissions in the State trading program budget apportioned to electric
generating units divided by the total number of NOX
allowances allocated under paragraph (b)(1) of this section, and
rounding to the nearest whole NOX allowance as appropriate.
(c) For each control period under Sec. 96.41, the permitting
authority will allocate to all NOX Budget units under
Sec. 96.4(a)(2) in the State that commenced operation before May 1 of
the period used to calculate heat input under paragraph (a)(1) of this
section, a total number of NOX allowances equal to 95
percent in 2003, 2004, and 2005, or 98 percent thereafter, of the tons
of NOX emissions in the State trading program budget
apportioned to non-electric generating units under Sec. 96.40 in
accordance with the following procedures:
(1) The permitting authority will allocate NOX
allowances to each NOX Budget unit under Sec. 96.4(a)(2) in
an amount equaling 0.17 lb/mmBtu multiplied by the heat input
determined under paragraph (a) of this section, rounded to the nearest
whole NOX allowance as appropriate.
(2) If the initial total number of NOX allowances
allocated to all NOX Budget units under Sec. 96.4(a)(2) in
the State for a control period under paragraph (c)(1) of this section
does not equal 95 percent in 2003, 2004, and 2005, or 98 percent
thereafter, of the number of tons of NOX emissions in the
State trading program budget apportioned to non-electric generating
units, the permitting authority will adjust the total number of
NOX allowances allocated to all such NOX Budget
units for the control period under paragraph (c)(1) of this section so
that the total number of NOX allowances allocated equals 95
percent in 2003, 2004, and 2005, or 98 percent thereafter, of the
number of tons of NOX emissions in the State trading program
budget apportioned to non-electric generating units. This adjustment
will be made by: multiplying each unit's allocation by 95 percent in
2003, 2004, and 2005, or 98 percent thereafter, of the number of tons
of NOX emissions in the State trading program budget
apportioned to non-electric generating units divided by the total
number of NOX allowances allocated under paragraph (c)(1) of
this section, and rounding to the nearest whole NOX
allowance as appropriate.
(d) For each control period under Sec. 96.41, the permitting
authority will allocate NOX allowances to NOX
Budget units under Sec. 96.4 in the State that commenced operation, or
is projected to commence 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 one allocation set-
aside for each control period. Each allocation set-aside will be
allocated NOX allowances equal to 5 percent in 2003, 2004,
and 2005, or 2 percent thereafter, of the tons of NOX
emissions in the State trading program budget under Sec. 96.40, rounded
to the nearest whole NOX allowance as appropriate.
(2) The NOX authorized account representative of a
NOX Budget unit under paragraph (d) of this section may
submit to the permitting authority a request, in writing or in a format
specified by the permitting authority, to be allocated NOX
allowances for no more than five consecutive control periods under
Sec. 96.41, starting with the control period during which the
NOX Budget unit commenced, or is projected to commence,
operation and ending with the control period preceding the control
period for which it will receive an allocation under paragraph (b) or
(c) of this section. The NOX allowance allocation request
must be submitted prior to May 1 of the first control period for which
the NOX allowance allocation is requested and after the date
on which the permitting authority issues a permit to construct the
NOX Budget unit.
(3) In a NOX allowance allocation request under
paragraph (d)(2) of this section, the NOX authorized account
representative for units under Sec. 96.4(a)(1) may request for a
control period NOX allowances in an amount that does not
exceed 0.15 lb/mmBtu multiplied by the NOX Budget unit's
maximum design heat input (in mmBtu/hr) multiplied by the number of
hours remaining in the control period starting with the first day in
the control period on which the unit operated or is projected to
operate.
(4) In a NOX allowance allocation request under
paragraph (d)(2) of this section, the NOX authorized account
representative for units under Sec. 96.4(a)(2) may request for a
control period NOX allowances in an amount that does not
exceed 0.17 lb/mmBtu multiplied by the NOX Budget unit's
maximum design heat input (in mmBtu/hr) multiplied by the number of
hours remaining in the control period starting with the first day in
the control period on which the unit operated or is projected to
operate.
(5) The permitting authority will review, and allocate
NOX allowances pursuant to, each NOX allowance
allocation request under paragraph (d)(2) of this section in the order
that the request is received by the permitting authority.
(i) Upon receipt of the NOX allowance allocation
request, the permitting authority will determine whether, and will make
any necessary adjustments to the request to ensure that, for units
under Sec. 96.4(a)(1), the control period and the number of allowances
specified are consistent with the requirements of paragraphs (d)(2) and
(3) of this section and, for units under Sec. 96.4(a)(2), the control
period and the number of allowances specified are consistent with the
requirements of paragraphs (d)(2) and (4) of this section.
(ii) If the allocation set-aside for the control period for which
NOX allowances are requested has an amount of NOX
allowances not less than the number requested (as adjusted under
paragraph (d)(5)(i) of this section), the permitting authority will
allocate the amount of the NOX allowances requested (as
adjusted under paragraph (d)(5)(i) of this section) to the
NOX Budget unit.
(iii) If the allocation set-aside for the control period for which
NOX allowances are requested has a smaller amount of
NOX allowances than the number requested (as adjusted under
paragraph (d)(5)(i) of this section), the permitting authority will
deny in part the request and allocate only the remaining number of
NOX allowances in the allocation set-aside to the
NOX Budget unit.
(iv) Once an allocation set-aside for a control period has been
depleted of all NOX allowances, the permitting authority
will deny, and will not allocate any NOX allowances pursuant
to, any NOX allowance allocation request under which
NOX allowances have not already been allocated for the
control period.
(6) Within 60 days of receipt of a NOX allowance
allocation request, the permitting authority will take appropriate
action under paragraph (d)(5) of this section and notify the
NOX authorized account representative that submitted the
request and the Administrator of the number of NOX
[[Page 57526]]
allowances (if any) allocated for the control period to the
NOX Budget unit.
(e) For a NOX Budget unit that is allocated
NOX allowances under paragraph (d) of this section for a
control period, the Administrator will deduct NOX allowances
under Sec. 96.54(b) or (e) to account for the actual utilization of the
unit during the control period. The Administrator will calculate the
number of NOX allowances to be deducted to account for the
unit's actual utilization using the following formulas and rounding to
the nearest whole NOX allowance as appropriate, provided
that the number of NOX allowances to be deducted shall be
zero if the number calculated is less than zero:
NOX allowances deducted for actual utilization for units
under Sec. 96.4(a)(1) = (Unit's NOX allowances allocated
for control period)-(Unit's actual control period utilization x
0.15 lb/mmBtu); and
NOX allowances deducted for actual utilization for units
under Sec. 96.4(a)(2) = (Unit's NOX allowances allocated
for control period)-(Unit's actual control period utilization x
0.17 lb/mmBtu)
Where:
``Unit's NOX allowances allocated for control
period'' is the number of NOX allowances allocated to the
unit for the control period under paragraph (d) of this section; and
``Unit's actual control period utilization'' is the utilization
(in mmBtu), as defined in Sec. 96.2, of the unit during the control
period.
(f) After making the deductions for compliance under Sec. 96.54(b)
or (e) for a control period, the Administrator will notify the
permitting authority whether any NOX allowances remain in
the allocation set-aside for the control period. The permitting
authority will allocate any such NOX allowances to the
NOX Budget units in the State using the following formula
and rounding to the nearest whole NOX allowance as
appropriate:
Unit's share of NOX allowances remaining in allocation
set-aside = Total NOX allowances remaining in allocation
set-aside x (Unit's NOX allowance allocation
(State trading program budget excluding allocation set-aside)
Where:
``Total NOX allowances remaining in allocation set-
aside'' is the total number of NOX allowances remaining
in the allocation set-aside for the control period to which the
allocation set-aside applies;
``Unit's NOX allowance allocation'' is the number of
NOX allowances allocated under paragraph (b) or (c) of
this section to the unit for the control period to which the
allocation set-aside applies; and
``State trading program budget excluding allocation set-aside''
is the State trading program budget under Sec. 96.40 for the control
period to which the allocation set-aside applies multiplied by 95
percent if the control period is in 2003, 2004, or 2005 or 98
percent if the control period is in any year thereafter, rounded to
the nearest whole NOX allowance as appropriate.
Subpart F--NOX Allowance Tracking System
Sec. 96.50 NOX Allowance Tracking System accounts.
(a) Nature and function of compliance accounts and overdraft
accounts. Consistent with Sec. 96.51(a), the Administrator will
establish one compliance account for each NOX Budget unit
and one overdraft account for each source with one or more
NOX Budget units. Allocations of NOX allowances
pursuant to subpart E of this part or Sec. 96.88 and deductions or
transfers of NOX allowances pursuant to Sec. 96.31,
Sec. 96.54, Sec. 96.56, subpart G of this part, or subpart I of this
part will be recorded in the compliance accounts or overdraft accounts
in accordance with this subpart.
(b) Nature and function of general accounts. Consistent with
Sec. 96.51(b), the Administrator will establish, upon request, a
general account for any person. Transfers of allowances pursuant to
subpart G of this part will be recorded in the general account in
accordance with this subpart.
Sec. 96.51 Establishment of accounts.
(a) Compliance accounts and overdraft accounts. Upon receipt of a
complete account certificate of representation under Sec. 96.13, the
Administrator will establish:
(1) A compliance account for each NOX Budget unit for
which the account certificate of representation was submitted; and
(2) An overdraft account for each source for which the account
certificate of representation was submitted and that has two or more
NOX Budget units.
(b) General accounts. (1) Any person may apply to open a general
account for the purpose of holding and transferring allowances. A
complete application for a general account shall be submitted to the
Administrator and shall include the following elements in a format
prescribed by the Administrator:
(i) Name, mailing address, e-mail address (if any), telephone
number, and facsimile transmission number (if any) of the
NOX authorized account representative and any alternate
NOX authorized account representative;
(ii) At the option of the NOX authorized account
representative, organization name and type of organization;
(iii) A list of all persons subject to a binding agreement for the
NOX authorized account representative or any alternate
NOX authorized account representative to represent their
ownership interest with respect to the allowances held in the general
account;
(iv) The following certification statement by the NOX
authorized account representative and any alternate NOX
authorized account representative: ``I certify that I was selected as
the NOX authorized account representative or the
NOX alternate authorized account representative, as
applicable, by an agreement that is binding on all persons who have an
ownership interest with respect to allowances held in the general
account. I certify that I have all the necessary authority to carry out
my duties and responsibilities under the NOX Budget Trading
Program on behalf of such persons and that each such person shall be
fully bound by my representations, actions, inactions, or submissions
and by any order or decision issued to me by the Administrator or a
court regarding the general account.''
(v) The signature of the NOX authorized account
representative and any alternate NOX authorized account
representative and the dates signed.
(vi) Unless otherwise required by the permitting authority or the
Administrator, documents of agreement referred to in the account
certificate of representation shall not be submitted to the permitting
authority or the Administrator. Neither the permitting authority nor
the Administrator shall be under any obligation to review or evaluate
the sufficiency of such documents, if submitted.
(2) Upon receipt by the Administrator of a complete application for
a general account under paragraph (b)(1) of this section:
(i) The Administrator will establish a general account for the
person or persons for whom the application is submitted.
(ii) The NOX authorized account representative and any
alternate NOX authorized account representative for the
general account shall represent and, by his or her representations,
actions, inactions, or submissions, legally bind each person who has an
ownership interest with respect to NOX allowances held in
the general account in all matters pertaining to the NOX
Budget Trading Program, not withstanding any agreement between the
NOX authorized account representative or any alternate
NOX authorized account representative and such person. Any
such person shall be bound by any order or decision issued to the
NOX authorized account representative or any alternate
NOX authorized account representative by
[[Page 57527]]
the Administrator or a court regarding the general account.
(iii) Each submission concerning the general account shall be
submitted, signed, and certified by the NOX authorized
account representative or any alternate NOX authorized
account representative for the persons having an ownership interest
with respect to NOX allowances held in the general account.
Each such submission shall include the following certification
statement by the NOX authorized account representative or
any alternate NOX authorized account representative any: ``I
am authorized to make this submission on behalf of the persons having
an ownership interest with respect to the NOX allowances
held in the general account. I certify under penalty of law that I have
personally examined, and am familiar with, the statements and
information submitted in this document and all its attachments. Based
on my inquiry of those individuals with primary responsibility for
obtaining the information, I certify that the statements and
information are to the best of my knowledge and belief true, accurate,
and complete. I am aware that there are significant penalties for
submitting false statements and information or omitting required
statements and information, including the possibility of fine or
imprisonment.''
(iv) The Administrator will accept or act on a submission
concerning the general account only if the submission has been made,
signed, and certified in accordance with paragraph (b)(2)(iii) of this
section.
(3)(i) An application for a general account may designate one and
only one NOX authorized account representative and one and
only one alternate NOX authorized account representative who
may act on behalf of the NOX authorized account
representative. The agreement by which the alternate NOX
authorized account representative is selected shall include a procedure
for authorizing the alternate NOX authorized account
representative to act in lieu of the NOX authorized account
representative.
(ii) Upon receipt by the Administrator of a complete application
for a general account under paragraph (b)(1) of this section, any
representation, action, inaction, or submission by any alternate
NOX authorized account representative shall be deemed to be
a representation, action, inaction, or submission by the NOX
authorized account representative.
(4)(i) The NOX authorized account representative for a
general account may be changed at any time upon receipt by the
Administrator of a superseding complete application for a general
account under paragraph (b)(1) of this section. Notwithstanding any
such change, all representations, actions, inactions, and submissions
by the previous NOX authorized account representative prior
to the time and date when the Administrator receives the superseding
application for a general account shall be binding on the new
NOX authorized account representative and the persons with
an ownership interest with respect to the allowances in the general
account.
(ii) The alternate NOX authorized account representative
for a general account may be changed at any time upon receipt by the
Administrator of a superseding complete application for a general
account under paragraph (b)(1) of this section. Notwithstanding any
such change, all representations, actions, inactions, and submissions
by the previous alternate NOX authorized account
representative prior to the time and date when the Administrator
receives the superseding application for a general account shall be
binding on the new alternate NOX authorized account
representative and the persons with an ownership interest with respect
to the allowances in the general account.
(iii)(A) In the event a new person having an ownership interest
with respect to NOX allowances in the general account is not
included in the list of such persons in the account certificate of
representation, such new person shall be deemed to be subject to and
bound by the account certificate of representation, the representation,
actions, inactions, and submissions of the NOX authorized
account representative and any alternate NOX authorized
account representative of the source or unit, and the decisions,
orders, actions, and inactions of the Administrator, as if the new
person were included in such list.
(B) Within 30 days following any change in the persons having an
ownership interest with respect to NOX allowances in the
general account, including the addition of persons, the NOX
authorized account representative or any alternate NOX
authorized account representative shall submit a revision to the
application for a general account amending the list of persons having
an ownership interest with respect to the NOX allowances in
the general account to include the change.
(5)(i) Once a complete application for a general account under
paragraph (b)(1) of this section has been submitted and received, the
Administrator will rely on the application unless and until a
superseding complete application for a general account under paragraph
(b)(1) of this section is received by the Administrator.
(ii) Except as provided in paragraph (b)(4) of this section, no
objection or other communication submitted to the Administrator
concerning the authorization, or any representation, action, inaction,
or submission of the NOX authorized account representative
or any alternate NOX authorized account representative for a
general account shall affect any representation, action, inaction, or
submission of the NOX authorized account representative or
any alternate NOX authorized account representative or the
finality of any decision or order by the Administrator under the
NOX Budget Trading Program.
(iii) The Administrator will not adjudicate any private legal
dispute concerning the authorization or any representation, action,
inaction, or submission of the NOX authorized account
representative or any alternate NOX authorized account
representative for a general account, including private legal disputes
concerning the proceeds of NOX allowance transfers.
(c) Account identification. The Administrator will assign a unique
identifying number to each account established under paragraph (a) or
(b) of this section.
Sec. 96.52 NOX Allowance Tracking System responsibilities
of NOX authorized account representative.
(a) Following the establishment of a NOX Allowance
Tracking System account, all submissions to the Administrator
pertaining to the account, including, but not limited to, submissions
concerning the deduction or transfer of NOX allowances in
the account, shall be made only by the NOX authorized
account representative for the account.
(b) Authorized account representative identification. The
Administrator will assign a unique identifying number to each
NOX authorized account representative.
Sec. 96.53 Recordation of NOX allowance allocations.
(a) The Administrator will record the NOX allowances for
2003 in the NOX Budget units' compliance accounts and the
allocation set-asides, as allocated under subpart E of this part. The
Administrator will also record the NOX allowances allocated
under Sec. 96.88(a)(1) for each NOX Budget opt-in source in
its compliance account.
(b) Each year, after the Administrator has made all deductions from
a NOX Budget unit's compliance account and the overdraft
account pursuant to Sec. 96.54, the Administrator will record
[[Page 57528]]
NOX allowances, as allocated to the unit under subpart E of
this part or under Sec. 96.88(a)(2), in the compliance account for the
year after the last year for which allowances were previously allocated
to the compliance account. Each year, the Administrator will also
record NOX allowances, as allocated under subpart E of this
part, in the allocation set-aside for the year after the last year for
which allowances were previously allocated to an allocation set-aside.
(c) Serial numbers for allocated NOX allowances. When
allocating NOX allowances to and recording them in an
account, the Administrator will assign each NOX allowance a
unique identification number that will include digits identifying the
year for which the NOX allowance is allocated.
Sec. 96.54 Compliance.
(a) NOX allowance transfer deadline. The NOX
allowances are available to be deducted for compliance with a unit's
NOX Budget emissions limitation for a control period in a
given year only if the NOX allowances:
(1) Were allocated for a control period in a prior year or the same
year; and
(2) Are held in the unit's compliance account, or the overdraft
account of the source where the unit is located, as of the
NOX allowance transfer deadline for that control period or
are transferred into the compliance account or overdraft account by a
NOX allowance transfer correctly submitted for recordation
under Sec. 96.60 by the NOX allowance transfer deadline for
that control period.
(b) Deductions for compliance. (1) Following the recordation, in
accordance with Sec. 96.61, of NOX allowance transfers
submitted for recordation in the unit's compliance account or the
overdraft account of the source where the unit is located by the
NOX allowance transfer deadline for a control period, the
Administrator will deduct NOX allowances available under
paragraph (a) of this section to cover the unit's NOX
emissions (as determined in accordance with subpart H of this part), or
to account for actual utilization under Sec. 96.42(e), for the control
period:
(i) From the compliance account; and
(ii) Only if no more NOX allowances available under
paragraph (a) of this section remain in the compliance account, from
the overdraft account. In deducting allowances for units at the source
from the overdraft account, the Administrator will begin with the unit
having the compliance account with the lowest NOX Allowance
Tracking System account number and end with the unit having the
compliance account with the highest NOX Allowance Tracking
System account number (with account numbers sorted beginning with the
left-most character and ending with the right-most character and the
letter characters assigned values in alphabetical order and less than
all numeric characters).
(2) The Administrator will deduct NOX allowances first
under paragraph (b)(1)(i) of this section and then under paragraph
(b)(1)(ii) of this section:
(i) Until the number of NOX allowances deducted for the
control period equals the number of tons of NOX emissions,
determined in accordance with subpart H of this part, from the unit for
the control period for which compliance is being determined, plus the
number of NOX allowances required for deduction to account
for actual utilization under Sec. 96.42(e) for the control period; or
(ii) Until no more NOX allowances available under
paragraph (a) of this section remain in the respective account.
(c)(1) Identification of NOX allowances by serial
number. The NOX authorized account representative for each
compliance account may identify by serial number the NOX
allowances to be deducted from the unit's compliance account under
paragraph (b), (d), or (e) of this section. Such identification shall
be made in the compliance certification report submitted in accordance
with Sec. 96.30.
(2) First-in, first-out. The Administrator will deduct
NOX allowances for a control period from the compliance
account, in the absence of an identification or in the case of a
partial identification of NOX allowances by serial number
under paragraph (c)(1) of this section, or the overdraft account on a
first-in, first-out (FIFO) accounting basis in the following order:
(i) Those NOX allowances that were allocated for the
control period to the unit under subpart E or I of this part;
(ii) Those NOX allowances that were allocated for the
control period to any unit and transferred and recorded in the account
pursuant to subpart G of this part, in order of their date of
recordation;
(iii) Those NOX allowances that were allocated for a
prior control period to the unit under subpart E or I of this part; and
(iv) Those NOX allowances that were allocated for a
prior control period to any unit and transferred and recorded in the
account pursuant to subpart G of this part, in order of their date of
recordation.
(d) Deductions for excess emissions. (1) After making the
deductions for compliance under paragraph (b) of this section, the
Administrator will deduct from the unit's compliance account or the
overdraft account of the source where the unit is located a number of
NOX allowances, allocated for a control period after the
control period in which the unit has excess emissions, equal to three
times the number of the unit's excess emissions.
(2) If the compliance account or overdraft account does not contain
sufficient NOX allowances, the Administrator will deduct the
required number of NOX allowances, regardless of the control
period for which they were allocated, whenever NOX
allowances are recorded in either account.
(3) Any allowance deduction required under paragraph (d) of this
section shall not affect the liability of the owners and operators of
the NOX Budget unit for any fine, penalty, or assessment, or
their obligation to comply with any other remedy, for the same
violation, as ordered under the CAA or applicable State law. The
following guidelines will be followed in assessing fines, penalties or
other obligations:
(i) For purposes of determining the number of days of violation, if
a NOX Budget unit has excess emissions for a control period,
each day in the control period (153 days) constitutes a day in
violation unless the owners and operators of the unit demonstrate that
a lesser number of days should be considered.
(ii) Each ton of excess emissions is a separate violation.
(e) Deductions for units sharing a common stack. In the case of
units sharing a common stack and having emissions that are not
separately monitored or apportioned in accordance with subpart H of
this part:
(1) The NOX authorized account representative of the
units may identify the percentage of NOX allowances to be
deducted from each such unit's compliance account to cover the unit's
share of NOX emissions from the common stack for a control
period. Such identification shall be made in the compliance
certification report submitted in accordance with Sec. 96.30.
(2) Notwithstanding paragraph (b)(2)(i) of this section, the
Administrator will deduct NOX allowances for each such unit
until the number of NOX allowances deducted equals the
unit's identified percentage (under paragraph (e)(1) of this section)
of the number of tons of NOX emissions, as determined in
accordance with subpart H of this part, from the common stack for the
control period for which compliance is being determined or, if no
percentage is identified, an equal
[[Page 57529]]
percentage for each such unit, plus the number of allowances required
for deduction to account for actual utilization under Sec. 96.42(e) for
the control period.
(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.
(a) NOX allowances may be banked for future use or
transfer in a compliance account, an overdraft account, or a general
account, as follows:
(1) Any NOX allowance that is held in a compliance
account, an overdraft account, or a general account will remain in such
account unless and until the NOX allowance is deducted or
transferred under Sec. 96.31, Sec. 96.54, Sec. 96.56, subpart G of this
part, or subpart I of this part.
(2) The Administrator will designate, as a ``banked''
NOX allowance, any NOX allowance that remains in
a compliance account, an overdraft account, or a general account after
the Administrator has made all deductions for a given control period
from the compliance account or overdraft account pursuant to
Sec. 96.54.
(b) Each year starting in 2004, after the Administrator has
completed the designation of banked NOX allowances under
paragraph (a)(2) of this section and before May 1 of the year, the
Administrator will determine the extent to which banked NOX
allowances may be used for compliance in the control period for the
current year, as follows:
(1) The Administrator will determine the total number of banked
NOX allowances held in compliance accounts, overdraft
accounts, or general accounts.
(2) If the total number of banked NOX allowances
determined, under paragraph (b)(1) of this section, to be held in
compliance accounts, overdraft accounts, or general accounts is less
than or equal to 10% of the sum of the State trading program budgets
for the control period for the States in which NOX Budget
units are located, any banked NOX allowance may be deducted
for compliance in accordance with Sec. 96.54.
(3) If the total number of banked NOX allowances
determined, under paragraph (b)(1) of this section, to be held in
compliance accounts, overdraft accounts, or general accounts exceeds
10% of the sum of the State trading program budgets for the control
period for the States in which NOX Budget units are located,
any banked allowance may be deducted for compliance in accordance with
Sec. 96.54, except as follows:
(i) The Administrator will determine the following ratio: 0.10
multiplied by the sum of the State trading program budgets for the
control period for the States in which NOX Budget units are
located and divided by the total number of banked NOX
allowances determined, under paragraph (b)(1) of this section, to be
held in compliance accounts, overdraft accounts, or general accounts.
(ii) The Administrator will multiply the number of banked
NOX allowances in each compliance account or overdraft
account. The resulting product is the number of banked NOX
allowances in the account that may be deducted for compliance in
accordance with Sec. 96.54. Any banked NOX allowances in
excess of the resulting product may be deducted for compliance in
accordance with Sec. 96.54, except that, if such NOX
allowances are used to make a deduction, two such NOX
allowances must be deducted for each deduction of one NOX
allowance required under Sec. 96.54.
(c) Any NOX Budget unit may reduce its NOX
emission rate in the 2001 or 2002 control period, the owner or operator
of the unit may request early reduction credits, and the permitting
authority may allocate NOX allowances in 2003 to the unit in
accordance with the following requirements.
(1) Each NOX Budget unit for which the owner or operator
requests any early reduction credits under paragraph (c)(4) of this
section shall monitor NOX emissions in accordance with
subpart H of this part starting in the 2000 control period and for each
control period for which such early reduction credits are requested.
The unit's monitoring system availability shall be not less than 90
percent during the 2000 control period, and the unit must be in
compliance with any applicable State or Federal emissions or emissions-
related requirements.
(2) NOX emission rate and heat input under paragraphs
(c)(3) through (5) of this section shall be determined in accordance
with subpart H of this part.
(3) Each NOX Budget unit for which the owner or operator
requests any early reduction credits under paragraph (c)(4) of this
section shall reduce its NOX emission rate, for each control
period for which early reduction credits are requested, to less than
both 0.25 lb/mmBtu and 80 percent of the unit's NOX emission
rate in the 2000 control period.
(4) The NOX authorized account representative of a
NOX Budget unit that meets the requirements of paragraphs
(c)(1)and (3) of this section may submit to the permitting authority a
request for early reduction credits for the unit based on
NOX emission rate reductions made by the unit in the control
period for 2001 or 2002 in accordance with paragraph (c)(3) of this
section.
(i) In the early reduction credit request, the NOX
authorized account may request early reduction credits for such control
period in an amount equal to the unit's heat input for such control
period multiplied by the difference between 0.25 lb/mmBtu and the
unit's NOX emission rate for such control period, divided by
2000 lb/ton, and rounded to the nearest ton.
(ii) The early reduction credit request must be submitted, in a
format specified by the permitting authority, by October 31 of the year
in which the NOX emission rate reductions on which the
request is based are made or such later date approved by the permitting
authority.
(5) The permitting authority will allocate NOX
allowances, to NOX Budget units meeting the requirements of
paragraphs (c)(1) and (3) of this section and covered by early
reduction requests meeting the requirements of paragraph (c)(4)(ii) of
this section, in accordance with the following procedures:
(i) Upon receipt of each early reduction credit request, the
permitting authority will accept the request only if the requirements
of paragraphs (c)(1), (c)(3), and (c)(4)(ii) of this section are met
and, if the request is accepted, will make any necessary adjustments to
the request to ensure that the amount of the early reduction credits
requested meets the requirement of paragraphs (c)(2) and (4) of this
section.
(ii) If the State's compliance supplement pool has an amount of
NOX allowances not less than the number of early reduction
credits in all accepted early reduction credit requests for 2001 and
2002 (as adjusted under paragraph (c)(5)(i) of this section), the
permitting authority will allocate to each NOX Budget unit
covered by such accepted requests one allowance for each early
reduction credit requested (as adjusted under paragraph (c)(5)(i) of
this section).
(iii) If the State's compliance supplement pool has a smaller
amount of NOX allowances than the number of early reduction
credits in all accepted early reduction credit requests for 2001 and
2002 (as adjusted under paragraph (c)(5)(i) of this section), the
permitting authority will allocate NOX allowances to each
NOX Budget unit covered by
[[Page 57530]]
such accepted requests according to the following formula:
Unit's allocated early reduction credits = [(Unit's adjusted early
reduction credits) / (Total adjusted early reduction credits
requested by all units)] x (Available NOX allowances from
the State's compliance supplement pool)
where:
``Unit's adjusted early reduction credits'' is the number of
early reduction credits for the unit for 2001 and 2002 in accepted
early reduction credit requests, as adjusted under paragraph
(c)(5)(i) of this section.
``Total adjusted early reduction credits requested by all
units'' is the number of early reduction credits for all units for
2001 and 2002 in accepted early reduction credit requests, as
adjusted under paragraph (c)(5)(i) of this section.
``Available NOX allowances from the State's
compliance supplement pool'' is the number of NOX
allowances in the State's compliance supplement pool and available
for early reduction credits for 2001 and 2002.
(6) By May 1, 2003, the permitting authority will submit to the
Administrator the allocations of NOX allowances determined
under paragraph (c)(5) of this section. The Administrator will record
such allocations to the extent that they are consistent with the
requirements of paragraphs (c)(1) through (5) of this section.
(7) NOX allowances recorded under paragraph (c)(6) of
this section may be deducted for compliance under Sec. 96.54 for the
control periods in 2003 or 2004. Notwithstanding paragraph (a) of this
section, the Administrator will deduct as retired any NOX
allowance that is recorded under paragraph (c)(6) of this section and
is not deducted for compliance in accordance with Sec. 96.54 for the
control period in 2003 or 2004.
(8) NOX allowances recorded under paragraph (c)(6) of
this section are treated as banked allowances in 2004 for the purposes
of paragraphs (a) and (b) of this section.
Sec. 96.56 Account error.
The Administrator may, at his or her sole discretion and on his or
her own motion, correct any error in any NOX Allowance
Tracking System account. Within 10 business days of making such
correction, the Administrator will notify the NOX authorized
account representative for the account.
Sec. 96.57 Closing of general accounts.
(a) The NOX authorized account representative of a
general account may instruct the Administrator to close the account by
submitting a statement requesting deletion of the account from the
NOX Allowance Tracking System and by correctly submitting
for recordation under Sec. 96.60 an allowance transfer of all
NOX allowances in the account to one or more other
NOX Allowance Tracking System accounts.
(b) If a general account shows no activity for a period of a year
or more and does not contain any NOX allowances, the
Administrator may notify the NOX authorized account
representative for the account that the account will be closed and
deleted from the NOX Allowance Tracking System following 20
business days after the notice is sent. The account will be closed
after the 20-day period unless before the end of the 20-day period the
Administrator receives a correctly submitted transfer of NOX
allowances into the account under Sec. 96.60 or a statement submitted
by the NOX authorized account representative demonstrating
to the satisfaction of the Administrator good cause as to why the
account should not be closed.
Subpart G--NOX Allowance Transfers
Sec. 96.60 Submission of NOX allowance transfers.
The NOX authorized account representatives seeking
recordation of a NOX allowance transfer shall submit the
transfer to the Administrator. To be considered correctly submitted,
the NOX allowance transfer shall include the following
elements in a format specified by the Administrator:
(a) The numbers identifying both the transferor and transferee
accounts;
(b) A specification by serial number of each NOX
allowance to be transferred; and
(c) The printed name and signature of the NOX authorized
account representative of the transferor account and the date signed.
Sec. 96.61 EPA recordation.
(a) Within 5 business days of receiving a NOX allowance
transfer, except as provided in paragraph (b) of this section, the
Administrator will record a NOX allowance transfer by moving
each NOX allowance from the transferor account to the
transferee account as specified by the request, provided that:
(1) The transfer is correctly submitted under Sec. 96.60;
(2) The transferor account includes each NOX allowance
identified by serial number in the transfer; and
(3) The transfer meets all other requirements of this part.
(b) A NOX allowance transfer that is submitted for
recordation following the NOX allowance transfer deadline
and that includes any NOX allowances allocated for a control
period prior to or the same as the control period to which the
NOX allowance transfer deadline applies will not be recorded
until after completion of the process of recordation of NOX
allowance allocations in Sec. 96.53(b).
(c) Where a NOX allowance transfer submitted for
recordation fails to meet the requirements of paragraph (a) of this
section, the Administrator will not record such transfer.
Sec. 96.62 Notification.
(a) Notification of recordation. Within 5 business days of
recordation of a NOX allowance transfer under Sec. 96.61,
the Administrator will notify each party to the transfer. Notice will
be given to the NOX authorized account representatives of
both the transferror and transferee accounts.
(b) Notification of non-recordation. Within 10 business days of
receipt of a NOX allowance transfer that fails to meet the
requirements of Sec. 96.61(a), the Administrator will notify the
NOX authorized account representatives of both accounts
subject to the transfer of:
(1) A decision not to record the transfer, and (2) The reasons for
such non-recordation.
(c) Nothing in this section shall preclude the submission of a
NOX allowance transfer for recordation following
notification of non-recordation.
Subpart H--Monitoring and Reporting
Sec. 96.70 General requirements.
The owners and operators, and to the extent applicable, the
NOX authorized account representative of a NOX
Budget unit, shall comply with the monitoring and reporting
requirements as provided in this subpart and in subpart H of part 75 of
this chapter. For purposes of complying with such requirements, the
definitions in Sec. 96.2 and in Sec. 72.2 of this chapter shall apply,
and the terms ``affected unit,'' ``designated representative,'' and
``continuous emission monitoring system'' (or ``CEMS'') in part 75 of
this chapter shall be replaced by the terms ``NOX Budget
unit,'' ``NOX authorized account representative,'' and
``continuous emission monitoring system'' (or ``CEMS''), respectively,
as defined in Sec. 96.2.
(a) Requirements for installation, certification, and data
accounting. The owner or operator of each NOX Budget unit
must meet the following requirements. These provisions also apply to a
unit for which an application for a NOX Budget opt-in permit
is submitted and not denied or withdrawn, as provided in subpart I of
this part:
(1) Install all monitoring systems required under this subpart for
[[Page 57531]]
monitoring NOX mass. This includes all systems required to
monitor NOX emission rate, NOX concentration,
heat input, and flow, in accordance with Secs. 75.72 and 75.76.
(2) Install all monitoring systems for monitoring heat input, if
required under Sec. 96.76 for developing NOX allowance
allocations.
(3) Successfully complete all certification tests required under
Sec. 96.71 and meet all other provisions of this subpart and part 75 of
this chapter applicable to the monitoring systems under paragraphs
(a)(1) and (2) of this section.
(4) Record, and report data from the monitoring systems under
paragraphs (a)(1) and (2) of this section.
(b) Compliance dates. The owner or operator must meet the
requirements of paragraphs (a)(1) through (a)(3) of this section on or
before the following dates and must record and report data on and after
the following dates:
(1) NOX Budget units for which the owner or operator
intends to apply for early reduction credits under Sec. 96.55(d) must
comply with the requirements of this subpart by May 1, 2000.
(2) Except for NOX Budget units under paragraph (b)(1)
of this section, NOX Budget units under Sec. 96.4 that
commence operation before January 1, 2002, must comply with the
requirements of this subpart by May 1, 2002.
(3) NOX Budget units under Sec. 96.4 that commence
operation on or after January 1, 2002 and that report on an annual
basis under Sec. 96.74(d) must comply with the requirements of this
subpart by the later of the following dates:
(i) May 1, 2002; or
(ii) The earlier of:
(A) 180 days after the date on which the unit commences operation
or, (B) For units under Sec. 96.4(a)(1), 90 days after the date on
which the unit commences commercial operation.
(4) NOX Budget units under Sec. 96.4 that commence
operation on or after January 1, 2002 and that report on a control
season basis under Sec. 96.74(d) must comply with the requirements of
this subpart by the later of the following dates:
(i) The earlier of:
(A) 180 days after the date on which the unit commences operation
or,
(B) For units under Sec. 96.4(a)(1), 90 days after the date on
which the unit commences commercial operation.
(ii) However, if the applicable deadline under paragraph (b)(4)(i)
section does not occur during a control period, May 1; immediately
following the date determined in accordance with paragraph (b)(4)(i) of
this section.
(5) For a NOX Budget unit with a new stack or flue for
which construction is completed after the applicable deadline under
paragraph ( b)(1), (b)(2) or (b)(3) of this section or subpart I of
this part:
(i) 90 days after the date on which emissions first exit to the
atmosphere through the new stack or flue;
(ii) However, if the unit reports on a control season basis under
Sec. 96.74(d) and the applicable deadline under paragraph (b)(5)(i) of
this section does not occur during the control period, May 1
immediately following the applicable deadline in paragraph (b)(5)(i) of
this section.
(6) For a unit for which an application for a NOX Budget
opt in permit is submitted and not denied or withdrawn, the compliance
dates specified under subpart I of this part.
(c) Reporting data prior to initial certification. (1) The owner or
operator of a NOX Budget unit that misses the certification
deadline under paragraph (b)(1) of this section is not eligible to
apply for early reduction credits. The owner or operator of the unit
becomes subject to the certification deadline under paragraph (b)(2) of
this section.
(2) The owner or operator of a NOX Budget under
paragraphs (b)(3) or (b)(4) of this section must determine, record and
report NOX mass, heat input (if required for purposes of
allocations) and any other values required to determine NOX
Mass (e.g. NOX emission rate and heat input or
NOX concentration and stack flow) using the provisions of
Sec. 75.70(g) of this chapter, from the date and hour that the unit
starts operating until all required certification tests are
successfully completed.
(d) Prohibitions. (1) No owner or operator of a NOX
Budget unit or a non-NOX Budget unit monitored under
Sec. 75.72(b)(2)(ii) shall use any alternative monitoring system,
alternative reference method, or any other alternative for the required
continuous emission monitoring system without having obtained prior
written approval in accordance with Sec. 96.75.
(2) No owner or operator of a NOX Budget unit or a non-
NOX Budget unit monitored under Sec. 75.72(b)(2)(ii) shall
operate the unit so as to discharge, or allow to be discharged,
NOX emissions to the atmosphere without accounting for all
such emissions in accordance with the applicable provisions of this
subpart and part 75 of this chapter except as provided for in
Sec. 75.74 of this chapter.
(3) No owner or operator of a NOX Budget unit or a non-
NOX Budget unit monitored under Sec. 75.72(b)(2)(ii) shall
disrupt the continuous emission monitoring system, any portion thereof,
or any other approved emission monitoring method, and thereby avoid
monitoring and recording NOX mass emissions discharged into
the atmosphere, except for periods of recertification or periods when
calibration, quality assurance testing, or maintenance is performed in
accordance with the applicable provisions of this subpart and part 75
of this chapter except as provided for in Sec. 75.74 of this chapter.
(4) No owner or operator of a NOX Budget unit or a non-
NOX Budget unit monitored under Sec. 75.72(b)(2)(ii) shall
retire or permanently discontinue use of the continuous emission
monitoring system, any component thereof, or any other approved
emission monitoring system under this subpart, except under any one of
the following circumstances:
(i) During the period that the unit is covered by a retired unit
exemption under Sec. 96.5 that is in effect;
(ii) The owner or operator is monitoring emissions from the unit
with another certified monitoring system approved, in accordance with
the applicable provisions of this subpart and part 75 of this chapter,
by the permitting authority for use at that unit that provides emission
data for the same pollutant or parameter as the retired or discontinued
monitoring system; or
(iii) The NOX authorized account representative submits
notification of the date of certification testing of a replacement
monitoring system in accordance with Sec. 96.71(b)(2).
Sec. 96.71 Initial certification and recertification procedures
(a) The owner or operator of a NOX Budget unit that is
subject to an Acid Rain emissions limitation shall comply with the
initial certification and recertification procedures of part 75 of this
chapter, except that:
(1) If, prior to January 1, 1998, the Administrator approved a
petition under Sec. 75.17(a) or (b) of this chapter for apportioning
the NOX emission rate measured in a common stack or a
petition under Sec. 75.66 of this chapter for an alternative to a
requirement in Sec. 75.17 of this chapter, the NOX
authorized account representative shall resubmit the petition to the
Administrator under Sec. 96.75(a) to determine if the approval applies
under the NOX Budget Trading Program.
(2) For any additional CEMS required under the common stack
provisions in Sec. 75.72 of this chapter, or for any NOX
concentration CEMS used under the provisions of Sec. 75.71(a)(2) of
this chapter, the owner or operator shall
[[Page 57532]]
meet the requirements of paragraph (b) of this section.
(b) The owner or operator of a NOX Budget unit that is
not subject to an Acid Rain emissions limitation shall comply with the
following initial certification and recertification procedures, except
that the owner or operator of a unit that qualifies to use the low mass
emissions excepted monitoring methodology under Sec. 75.19 shall also
meet the requirements of paragraph (c) of this section and the owner or
operator of a unit that qualifies to use an alternative monitoring
system under subpart E of part 75 of this chapter shall also meet the
requirements of paragraph (d) of this section. The owner or operator of
a NOX Budget unit that is subject to an Acid Rain emissions
limitation, but requires additional CEMS under the common stack
provisions in Sec. 75.72 of this chapter, or that uses a NOX
concentration CEMS under Sec. 75.71(a)(2) of this chapter also shall
comply with the following initial certification and recertification
procedures.
(1) Requirements for initial certification. The owner or operator
shall ensure that each monitoring system required by subpart H of part
75 of this chapter (which includes the automated data acquisition and
handling system) successfully completes all of the initial
certification testing required under Sec. 75.20 of this chapter. The
owner or operator shall ensure that all applicable certification tests
are successfully completed by the deadlines specified in Sec. 96.70(b).
In addition, whenever the owner or operator installs a monitoring
system in order to meet the requirements of this part in a location
where no such monitoring system was previously installed, initial
certification according to Sec. 75.20 is required.
(2) Requirements for recertification. Whenever the owner or
operator makes a replacement, modification, or change in a certified
monitoring system that the Administrator or the permitting authority
determines significantly affects the ability of the system to
accurately measure or record NOX mass emissions or heat
input or to meet the requirements of Sec. 75.21 of this chapter or
appendix B to part 75 of this chapter, the owner or operator shall
recertify the monitoring system according to Sec. 75.20(b) of this
chapter. Furthermore, whenever the owner or operator makes a
replacement, modification, or change to the flue gas handling system or
the unit's operation that the Administrator or the permitting authority
determines to significantly change the flow or concentration profile,
the owner or operator shall recertify the continuous emissions
monitoring system according to Sec. 75.20(b) of this chapter. Examples
of changes which require recertification include: replacement of the
analyzer, change in location or orientation of the sampling probe or
site, or changing of flow rate monitor polynomial coefficients.
(3) Certification approval process for initial certifications and
recertification. (i) Notification of certification. The NOX
authorized account representative shall submit to the permitting
authority, the appropriate EPA Regional Office and the permitting
authority a written notice of the dates of certification in accordance
with Sec. 96.73.
(ii) Certification application. The NOX authorized
account representative shall submit to the permitting authority a
certification application for each monitoring system required under
subpart H of part 75 of this chapter. A complete certification
application shall include the information specified in subpart H of
part 75 of this chapter.
(iii) Except for units using the low mass emission excepted
methodology under Sec. 75.19 of this chapter, the provisional
certification date for a monitor shall be determined using the
procedures set forth in Sec. 75.20(a)(3) of this chapter. A
provisionally certified monitor may be used under the NOX
Budget Trading Program for a period not to exceed 120 days after
receipt by the permitting authority of the complete certification
application for the monitoring system or component thereof under
paragraph (b)(3)(ii) of this section. Data measured and recorded by the
provisionally certified monitoring system or component thereof, in
accordance with the requirements of part 75 of this chapter, will be
considered valid quality-assured data (retroactive to the date and time
of provisional certification), provided that the 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)(3)(ii) of this section. In the event the permitting
authority does not issue such a notice within such 120-day period, each
monitoring system which meets the applicable performance requirements
of part 75 of this chapter and is included in the certification
application will be deemed certified for use under the NOX
Budget Trading Program.
(A) Approval notice. If the certification application is complete
and shows that each 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)(3)(ii) of this section has been
received by the permitting authority. If the certification application
is not complete, then the permitting authority will issue a written
notice of incompleteness that sets a reasonable date by which the
NOX authorized account representative must submit the
additional information required to complete the certification
application. If the NOX authorized account representative
does not comply with the notice of incompleteness by the specified
date, then the permitting authority may issue a notice of disapproval
under paragraph (b)(3)(iv)(C) of this section.
(C) Disapproval notice. If the certification application shows that
any monitoring system or component thereof does not meet the
performance requirements of this part, or if the certification
application is incomplete and the requirement for disapproval under
paragraph (b)(3)(iv)(B) of this section has been met, the 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)(3)(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
[[Page 57533]]
(b)(3)(iv)(C) of this section or a notice of disapproval of
certification status under paragraph (b)(3)(iv)(D) of this section,
then:
(A) The owner or operator shall substitute the following values,
for each hour of unit operation during the period of invalid data
beginning with the date and hour of provisional certification and
continuing until the time, date, and hour specified under
Sec. 75.20(a)(5)(i) of this chapter:
(1) For units using or intending to monitor for NOX
emission rate and heat input or for units using the low mass emission
excepted methodology under Sec. 75.19 of this chapter, the maximum
potential NOX emission rate and the maximum potential hourly
heat input of the unit.
(2) For units intending to monitor for NOX mass
emissions using a NOX pollutant concentration monitor and a
flow monitor, the maximum potential concentration of NOX and
the maximum potential flow rate of the unit under section 2.1 of
appendix A of part 75 of this chapter;
(B) The NOX authorized account representative shall
submit a notification of certification retest dates and a new
certification application in accordance with paragraphs (b)(3)(i) and
(ii) of this section; and
(C) The owner or operator shall repeat all certification tests or
other requirements that were failed by the monitoring system, as
indicated in the permitting authority's notice of disapproval, no later
than 30 unit operating days after the date of issuance of the notice of
disapproval.
(c) Initial certification and recertification procedures for low
mass emission units using the excepted methodologies under Sec. 75.19
of this chapter. The owner or operator of a gas-fired or oil-fired unit
using the low mass emissions excepted methodology under Sec. 75.19 of
this chapter shall meet the applicable general operating requirements
of Sec. 75.10 of this chapter, the applicable requirements of
Sec. 75.19 of this chapter, and the applicable certification
requirements of Sec. 96.71 of this chapter, except that the excepted
methodology shall be deemed provisionally certified for use under the
NOX Budget Trading Program, as of the following dates:
(1) For units that are reporting on an annual basis under
Sec. 96.74(d);
(i) For a unit that has commences operation before its compliance
deadline under Sec. 96.71(b), from January 1 of the year following
submission of the certification application for approval to use the low
mass emissions excepted methodology under Sec. 75.19 of this chapter
until the completion of the period for the permitting authority review;
or
(ii) For a unit that commences operation after its compliance
deadline under Sec. 96.71(b), the date of submission of the
certification application for approval to use the low mass emissions
excepted methodology under Sec. 75.19 of this chapter until the
completion of the period for permitting authority review, or
(2) For units that are reporting on a control period basis under
Sec. 96.74(b)(3)(ii) of this part:
(i) For a unit that commenced operation before its compliance
deadline under Sec. 96.71(b), where the certification application is
submitted before May 1, from May 1 of the year of the submission of the
certification application for approval to use the low mass emissions
excepted methodology under Sec. 75.19 of this chapter until the
completion of the period for the permitting authority review; or
(ii) For a unit that commenced operation before its compliance
deadline under Sec. 96.71(b), where the certification application is
submitted after May 1, from May 1 of the year following submission of
the certification application for approval to use the low mass
emissions excepted methodology under Sec. 75.19 of this chapter until
the completion of the period for the permitting authority review; or
(iii) For a unit that commences operation after its compliance
deadline under Sec. 96.71(b), where the unit commences operation before
May 1, from May 1 of the year that the unit commenced operation, until
the completion of the period for the permitting authority's review.
(iv) For a unit that has not operated after its compliance deadline
under Sec. 96.71(b), where the certification application is submitted
after May 1, but before October 1st, from the date of submission of a
certification application for approval to use the low mass emissions
excepted methodology under Sec. 75.19 of this chapter until the
completion of the period for the permitting authority's review.
(d) Certification/recertification procedures for alternative
monitoring systems. The NOX authorized account
representative representing the owner or operator of each unit applying
to monitor using an alternative monitoring system approved by the
Administrator and, if applicable, the permitting authority under
subpart E of part 75 of this chapter shall apply for certification to
the permitting authority prior to use of the system under the
NOX Trading Program. The NOX authorized account
representative shall apply for recertification following a replacement,
modification or change according to the procedures in paragraph (b) of
this section. The owner or operator of an alternative monitoring system
shall comply with the notification and application requirements for
certification according to the procedures specified in paragraph (b)(3)
of this section and Sec. 75.20(f) of this chapter .
Sec. 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,
appendix D, or appendix E of part 75 of this chapter.
(b) Audit decertification. Whenever both an audit of a monitoring
system and a review of the initial certification or recertification
application reveal that any system or component should not have been
certified or recertified because it did not meet a particular
performance specification or other requirement under Sec. 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 of the audit, the permitting authority will issue a notice
of disapproval of the certification status of such system or component.
For the purposes of this paragraph, an audit shall be either a field
audit or an audit of any information submitted to the permitting
authority or the Administrator. By issuing the notice of disapproval,
the permitting authority revokes prospectively the certification status
of the system or component. The data measured and recorded by the
system or component shall not be considered valid quality-assured data
from the date of issuance of the notification of the revoked
certification status until the date and time that the owner or operator
completes subsequently approved initial certification or
recertification tests. The owner or operator shall follow the initial
certification or recertification procedures in Sec. 96.71 for each
disapproved system.
Sec. 96.73 Notifications.
The NOX authorized account representative for a
NOX Budget unit shall submit written notice to the
permitting authority and the Administrator in accordance with
Sec. 75.61 of this chapter, except that if the unit is not subject to
an Acid Rain emissions limitation, the notification is only required to
be sent to the permitting authority.
[[Page 57534]]
Sec. 96.74 Recordkeeping and reporting.
(a) General provisions. (1) The NOX authorized account
representative shall comply with all recordkeeping and reporting
requirements in this section and with the requirements of
Sec. 96.10(e).
(2) If the NOX authorized account representative for a
NOX Budget unit subject to an Acid Rain Emission limitation
who signed and certified any submission that is made under subpart F or
G of part 75 of this chapter and which includes data and information
required under this subpart or subpart H of part 75 of this chapter is
not the same person as the designated representative or the alternative
designated representative for the unit under part 72 of this chapter,
the submission must also be signed by the designated representative or
the alternative designated representative.
(b) Monitoring plans. (1) The owner or operator of a unit subject
to an Acid Rain emissions limitation shall comply with requirements of
Sec. 75.62 of this chapter, except that the monitoring plan shall also
include all of the information required by subpart H of part 75 of this
chapter.
(2) The owner or operator of a unit that is not subject to an Acid
Rain emissions limitation shall comply with requirements of Sec. 75.62
of this chapter, except that the monitoring plan is only required to
include the information required by subpart H of part 75 of this
chapter.
(c) Certification applications. The NOX authorized
account representative shall submit an application to the permitting
authority within 45 days after completing all initial certification or
recertification tests required under Sec. 96.71 including the
information required under subpart H of part 75 of this chapter.
(d) Quarterly reports. The NOX authorized account
representative shall submit quarterly reports, as follows:
(1) If a unit is subject to an Acid Rain emission limitation or if
the owner or operator of the NOX budget unit chooses to meet
the annual reporting requirements of this subpart H, the NOX
authorized account representative shall submit a quarterly report for
each calendar quarter beginning with:
(i) For units that elect to comply with the early reduction credit
provisions under Sec. 96.55 of this part, the calender quarter that
includes the date of initial provisional certification under
Sec. 96.71(b)(3)(iii). Data shall be reported from the date and hour
corresponding to the date and hour of provisional certification; or
(ii) For units commencing operation prior to May 1, 2002 that are
not required to certify monitors by May 1, 2000 under Sec. 96.70(b)(1),
the earlier of the calender quarter that includes the date of initial
provisional certification under Sec. 96.71(b)(3)(iii) or, if the
certification tests are not completed by May 1, 2002, the partial
calender quarter from May 1, 2002 through June 30, 2002. Data shall be
recorded and reported from the earlier of the date and hour
corresponding to the date and hour of provisional certification or the
first hour on May 1, 2002; or
(iii) For a unit that commences operation after May 1, 2002, the
calendar quarter in which the unit commences operation, Data shall be
reported from the date and hour corresponding to when the unit
commenced operation.
(2) If a NOX budget unit is not subject to an Acid Rain
emission limitation, then the NOX authorized account
representative shall either:
(i) Meet all of the requirements of part 75 related to monitoring
and reporting NOX mass emissions during the entire year and
meet the reporting deadlines specified in paragraph (d)(1) of this
section; or
(ii) Submit quarterly reports only for the periods from the earlier
of May 1 or the date and hour that the owner or operator successfully
completes all of the recertification tests required under
Sec. 75.74(d)(3) through September 30 of each year in accordance with
the provisions of Sec. 75.74(b) of this chapter. The NOX
authorized account representative shall submit a quarterly report for
each calendar quarter, beginning with:
(A) For units that elect to comply with the early reduction credit
provisions under Sec. 96.55, the calender quarter that includes the
date of initial provisional certification under Sec. 96.71(b)(3)(iii).
Data shall be reported from the date and hour corresponding to the date
and hour of provisional certification; or
(B) For units commencing operation prior to May 1, 2002 that are
not required to certify monitors by May 1, 2000 under Sec. 96.70(b)(1),
the earlier of the calender quarter that includes the date of initial
provisional certification under Sec. 96.71(b)(3)(iii), or if the
certification tests are not completed by May 1, 2002, the partial
calender quarter from May 1, 2002 through June 30, 2002. Data shall be
reported from the earlier of the date and hour corresponding to the
date and hour of provisional certification or the first hour of May 1,
2002; or
(C) For units that commence operation after May 1, 2002 during the
control period, the calender quarter in which the unit commences
operation. Data shall be reported from the date and hour corresponding
to when the unit commenced operation; or
(D) For units that commence operation after May 1, 2002 and before
May 1 of the year in which the unit commences operation, the earlier of
the calender quarter that includes the date of initial provisional
certification under Sec. 96.71(b)(3)(iii) or, if the certification
tests are not completed by May 1 of the year in which the unit
commences operation, May 1 of the year in which the unit commences
operation. Data shall be reported from the earlier of the date and hour
corresponding to the date and hour of provisional certification or the
first hour of May 1 of the year after the unit commences operation.
(E) For units that commence operation after May 1, 2002 and after
September 30 of the year in which the unit commences operation, the
earlier of the calender quarter that includes the date of initial
provisional certification under Sec. 96.71(b)(3)(iii) or, if the
certification tests are not completed by May 1 of the year after the
unit commences operation, May 1 of the year after the unit commences
operation. Data shall be reported from the earlier of the date and hour
corresponding to the date and hour of provisional certification or the
first hour of May 1 of the year after the unit commences operation.
(3) The NOX authorized account representative shall
submit each quarterly report to the Administrator within 30 days
following the end of the calendar quarter covered by the report.
Quarterly reports shall be submitted in the manner specified in subpart
H of part 75 of this chapter and Sec. 75.64 of this chapter.
(i) For units subject to an Acid Rain Emissions limitation,
quarterly reports shall include all of the data and information
required in subpart H of part 75 of this chapter for each
NOX Budget unit (or group of units using a common stack) as
well as information required in subpart G of part 75 of this chapter.
(ii) For units not subject to an Acid Rain Emissions limitation,
quarterly reports are only required to include all of the data and
information required in subpart H of part 75 of this chapter for each
NOX Budget unit (or group of units using a common stack).
(4) Compliance certification. The NOX authorized account
representative shall submit to the Administrator a compliance
certification in support of each quarterly report based on reasonable
inquiry of those persons with primary responsibility for ensuring that
all of the unit's emissions are correctly
[[Page 57535]]
and fully monitored. The certification shall state that:
(i) The monitoring data submitted were recorded in accordance with
the applicable requirements of this subpart and part 75 of this
chapter, including the quality assurance procedures and specifications;
and
(ii) For a unit with add-on NOX emission controls and
for all hours where data are substituted in accordance with
Sec. 75.34(a)(1) of this chapter, the add-on emission controls were
operating within the range of parameters listed in the monitoring plan
and the substitute values do not systematically underestimate
NOX emissions; and
(iii) For a unit that is reporting on a control period basis under
Sec. 96.74(d) the NOX emission rate and NOX
concentration values substituted for missing data under subpart D of
part 75 of this chapter are calculated using only values from a control
period and do not systematically underestimate NOX
emissions.
Sec. 96.75 Petitions.
(a) The NOX authorized account representative of a
NOX Budget unit that is subject to an Acid Rain emissions
limitation may submit a petition under Sec. 75.66 of this chapter to
the Administrator requesting approval to apply an alternative to any
requirement of this subpart.
(1) 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. 75.72 of this chapter, the petition is governed by
paragraph (b) of this section.
(b) The NOX authorized account representative of a
NOX Budget unit that is not subject to an Acid Rain
emissions limitation may submit a petition under Sec. 75.66 of this
chapter to the permitting authority and the Administrator requesting
approval to apply an alternative to any requirement of this subpart.
(1) The NOX authorized account representative of a
NOX Budget unit that is subject to an Acid Rain emissions
limitation may submit a petition under Sec. 75.66 of this chapter to
the 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. 75.72 of this
chapter or a NOX concentration CEMS used under 75.71(a)(2)
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) of this section is approved by both the
permitting authority and the Administrator.
Sec. 96.76 Additional requirements to provide heat input data for
allocations purposes.
(a) The owner or operator of a unit that elects to monitor and
report NOX Mass emissions using a NOX
concentration system and a flow system shall also monitor and report
heat input at the unit level using the procedures set forth in part 75
of this chapter for any source located in a state developing source
allocations based upon heat input.
(b) The owner or operator of a unit that monitor and report
NOX Mass emissions using a NOX concentration
system and a flow system shall also monitor and report heat input at
the unit level using the procedures set forth in part 75 of this
chapter for any source that is applying for early reduction credits
under Sec. 96.55.
Subpart I--Individual Unit Opt-ins
Sec. 96.80 Applicability.
A unit that is in the State, is not a NOX Budget unit
under Sec. 96.4, vents all of its emissions to a stack, and is
operating, may qualify, under this subpart, to become a NOX
Budget opt-in source. A unit that is a NOX Budget unit, is
covered by a retired unit exemption under Sec. 96.5 that is in effect,
or is not operating is not eligible to become a NOX Budget
opt-in source.
Sec. 96.81 General.
Except otherwise as provided in this part, a NOX Budget
opt-in source shall be treated as a NOX Budget unit for
purposes of applying subparts A through H of this part.
Sec. 96.82 NOX authorized account representative.
A unit for which an application for a NOX Budget opt-in
permit is submitted and not denied or withdrawn, or a NOX
Budget opt-in source, located at the same source as one or more
NOX Budget units, shall have the same NOX
authorized account representative as such NOX Budget units.
Sec. 96.83 Applying for NOX Budget opt-in permit.
(a) Applying for initial NOX Budget opt-in permit. In
order to apply for an initial NOX Budget opt-in permit, the
NOX authorized account representative of a unit qualified
under Sec. 96.80 may submit to the permitting authority at any time,
except as provided under Sec. 96.86(g):
(1) A complete NOX Budget permit application under
Sec. 96.22;
(2) A monitoring plan submitted in accordance with subpart H of
this part; and
(3) A complete account certificate of representation under
Sec. 96.13, if no NOX authorized account representative has
been previously designated for the unit.
(b) Duty to reapply. The NOX authorized account
representative of a NOX Budget opt-in source shall submit a
complete NOX Budget permit application under Sec. 96.22 to
renew the NOX Budget opt-in permit in accordance with
Sec. 96.21(c) and, if applicable, an updated monitoring plan in
accordance with subpart H of this part.
Sec. 96.84 Opt-in process.
The permitting authority will issue or deny a NOX Budget
opt-in permit for a unit for which an initial application for a
NOX Budget opt-in permit under Sec. 96.83 is submitted, in
accordance with Sec. 96.20 and the following:
(a) Interim review of monitoring plan. The permitting authority
will determine, on an interim basis, the sufficiency of the monitoring
plan accompanying the initial application for a NOX Budget
opt-in permit under Sec. 96.83. A monitoring plan is sufficient, for
purposes of interim review, if the plan appears to contain information
demonstrating that the NOX emissions rate and heat input of
the unit are monitored and reported in accordance with subpart H of
this part. A determination of sufficiency shall not be construed as
acceptance or approval of the unit's monitoring plan.
(b) If the permitting authority determines that the unit's
monitoring plan is sufficient under paragraph (a) of this section and
after completion of monitoring system certification under subpart H of
this part, the NOX emissions rate and the heat input of the
unit shall be monitored and reported in accordance with subpart H of
this part for one full control period during which monitoring system
availability is not less than 90 percent and during which the unit is
in full compliance with any applicable State or Federal emissions or
emissions-related requirements. Solely for purposes of applying the
requirements in the prior sentence, the unit shall be treated as a
``NOX Budget unit'' prior to issuance of a NOX
Budget opt-in permit covering the unit.
[[Page 57536]]
(c) Based on the information monitored and reported under paragraph
(b) of this section, the unit's baseline heat rate shall be calculated
as the unit's total heat input (in mmBtu) for the control period and
the unit's baseline NOX emissions rate shall be calculated
as the unit's total NOX emissions (in lb) for the control
period divided by the unit's baseline heat rate.
(d) After calculating the baseline heat input and the baseline
NOX emissions rate for the unit under paragraph (c) of this
section, the permitting authority will serve a draft NOX
Budget opt-in permit on the NOX authorized account
representative of the unit.
(e) Confirmation of intention to opt-in. Within 20 days after the
issuance of the draft NOX Budget opt-in permit, the
NOX authorized account representative of the unit must
submit to the permitting authority a confirmation of the intention to
opt in the unit or a withdrawal of the application for a NOX
Budget opt-in permit under Sec. 96.83. The permitting authority will
treat the failure to make a timely submission as a withdrawal of the
NOX Budget opt-in permit application.
(f) Issuance of draft NOX Budget opt-in permit. If the
NOX authorized account representative confirms the intention
to opt-in the unit under paragraph (e) of this section, the permitting
authority will issue the draft NOX Budget opt-in permit in
accordance with Sec. 96.20.
(g) Notwithstanding paragraphs (a) through (f) of this section, if
at any time before issuance of a draft NOX Budget opt-in
permit for the unit, the permitting authority determines that the unit
does not qualify as a NOX Budget opt-in source under
Sec. 96.80, the permitting authority will issue a draft denial of a
NOX Budget opt-in permit for the unit in accordance with
Sec. 96.20.
(h) Withdrawal of application for NOX Budget opt-in
permit. A NOX authorized account representative of a unit
may withdraw its application for a NOX Budget opt-in permit
under Sec. 96.83 at any time prior to the issuance of the final
NOX Budget opt-in permit. Once the application for a
NOX Budget opt-in permit is withdrawn, a NOX
authorized account representative wanting to reapply must submit a new
application for a NOX Budget permit under Sec. 96.83.
(i) Effective date. The effective date of the initial
NOX Budget opt-in permit shall be May 1 of the first control
period starting after the issuance of the initial NOX Budget
opt-in permit by the permitting authority. The unit shall be a
NOX Budget opt-in source and a NOX Budget unit as
of the effective date of the initial NOX Budget opt-in
permit.
Sec. 96.85 NOX Budget opt-in permit contents.
(a) Each NOX Budget opt-in permit (including any draft
or proposed NOX Budget opt-in permit, if applicable) will
contain all elements required for a complete NOX Budget opt-
in permit application under Sec. 96.22 as approved or adjusted by the
permitting authority.
(b) Each NOX Budget opt-in permit is deemed to
incorporate automatically the definitions of terms under Sec. 96.2 and,
upon recordation by the Administrator under subpart F, G, or I of this
part, every allocation, transfer, or deduction of NOX
allowances to or from the compliance accounts of each NOX
Budget opt-in source covered by the NOX Budget opt-in permit
or the overdraft account of the NOX Budget source where the
NOX Budget opt-in source is located.
Sec. 96.86 Withdrawal from NOX Budget Trading Program.
(a) Requesting withdrawal. To withdraw from the NOX
Budget Trading Program, the NOX authorized account
representative of a NOX Budget opt-in source shall submit to
the permitting authority a request to withdraw effective as of a
specified date prior to May 1 or after September 30. The submission
shall be made no later than 90 days prior to the requested effective
date of withdrawal.
(b) Conditions for withdrawal. Before a NOX Budget opt-
in source covered by a request under paragraph (a) of this section may
withdraw from the NOX Budget Trading Program and the
NOX Budget opt-in permit may be terminated under paragraph
(e) of this section, the following conditions must be met:
(1) For the control period immediately before the withdrawal is to
be effective, the NOX authorized account representative must
submit or must have submitted to the permitting authority an annual
compliance certification report in accordance with Sec. 96.30.
(2) If the NOX Budget opt-in source has excess emissions
for the control period immediately before the withdrawal is to be
effective, the Administrator will deduct or has deducted from the
NOX Budget opt-in source's compliance account, or the
overdraft account of the NOX Budget source where the
NOX Budget opt-in source is located, the full amount
required under Sec. 96.54(d) for the control period.
(3) After the requirements for withdrawal under paragraphs (b)(1)
and (2) of this section are met, the Administrator will deduct from the
NOX Budget opt-in source's compliance account, or the
overdraft account of the NOX Budget source where the
NOX Budget opt-in source is located, NOX
allowances equal in number to and allocated for the same or a prior
control period as any NOX allowances allocated to that
source under Sec. 96.88 for any control period for which the withdrawal
is to be effective. The Administrator will close the NOX
Budget opt-in source's compliance account and will establish, and
transfer any remaining allowances to, a new general account for the
owners and operators of the NOX Budget opt-in source. The
NOX authorized account representative for the NOX
Budget opt-in source shall become the NOX authorized account
representative for the general account.
(c) A NOX Budget opt-in source that withdraws from the
NOX Budget Trading Program shall comply with all
requirements under the NOX Budget Trading Program concerning
all years for which such NOX Budget opt-in source was a
NOX Budget opt-in source, even if such requirements arise or
must be complied with after the withdrawal takes effect.
(d) Notification. (1) After the requirements for withdrawal under
paragraphs (a) and (b) of this section are met (including deduction of
the full amount of NOX allowances required), the permitting
authority will issue a notification to the NOX authorized
account representative of the NOX Budget opt-in source of
the acceptance of the withdrawal of the NOX Budget opt-in
source as of a specified effective date that is after such requirements
have been met and that is prior to May 1 or after September 30.
(2) If the requirements for withdrawal under paragraphs (a) and (b)
of this section are not met, the permitting authority will issue a
notification to the NOX authorized account representative of
the NOX Budget opt-in source that the NOX Budget
opt-in source's request to withdraw is denied. If the NOX
Budget opt-in source's request to withdraw is denied, the
NOX Budget opt-in source shall remain subject to the
requirements for a NOX Budget opt-in source.
(e) Permit amendment. After the permitting authority issues a
notification under paragraph (d)(1) of this section that the
requirements for withdrawal have been met, the permitting authority
will revise the NOX Budget permit covering the
NOX Budget opt-in source to terminate the NOX
Budget opt-in permit as of the effective date specified under paragraph
(d)(1) of this section. A NOX Budget opt-in source shall
continue to be a NOX Budget opt-in source until the
effective date of the termination.
[[Page 57537]]
(f) Reapplication upon failure to meet conditions of withdrawal. If
the permitting authority denies the NOX Budget opt-in
source's request to withdraw, the NOX authorized account
representative may submit another request to withdraw in accordance
with paragraphs (a) and (b) of this section.
(g) Ability to return to the NOX Budget Trading Program.
Once a NOX Budget opt-in source withdraws from the
NOX Budget Trading Program and its NOX Budget
opt-in permit is terminated under this section, the NOX
authority account representative may not submit another application for
a NOX Budget opt-in permit under Sec. 96.83 for the unit
prior to the date that is 4 years after the date on which the
terminated NOX Budget opt-in permit became effective.
Sec. 96.87 Change in regulatory status.
(a) Notification. When a NOX Budget opt-in source
becomes a NOX Budget unit under Sec. 96.4, the
NOX authorized account representative shall notify in
writing the permitting authority and the Administrator of such change
in the NOX Budget opt-in source's regulatory status, within
30 days of such change.
(b) Permitting authority's and Administrator's action. (1)(i) When
the NOX Budget opt-in source becomes a NOX Budget
unit under Sec. 96.4, the permitting authority will revise the
NOX Budget opt-in source's NOX Budget opt-in
permit to meet the requirements of a NOX Budget permit under
Sec. 96.23 as of an effective date that is the date on which such
NOX Budget opt-in source becomes a NOX Budget
unit under Sec. 96.4.
(ii)(A) The Administrator will deduct from the compliance account
for the NOX Budget unit under paragraph (b)(1)(i) of this
section, or the overdraft account of the NOX Budget source
where the unit is located, NOX allowances equal in number to
and allocated for the same or a prior control period as:
(1) Any NOX allowances allocated to the NOX
Budget unit (as a NOX Budget opt-in source) under Sec. 96.88
for any control period after the last control period during which the
unit's NOX Budget opt-in permit was effective; and
(2) If the effective date of the NOX Budget permit
revision under paragraph (b)(1)(i) of this section is during a control
period, the NOX allowances allocated to the NOX
Budget unit (as a NOX Budget opt-in source) under Sec. 96.88
for the control period multiplied by the ratio of the number of days,
in the control period, starting with the effective date of the permit
revision under paragraph (b)(1)(i) of this section, divided by the
total number of days in the control period.
(B) The NOX authorized account representative shall
ensure that the compliance account of the NOX Budget unit
under paragraph (b)(1)(i) of this section, or the overdraft account of
the NOX Budget source where the unit is located, includes
the NOX allowances necessary for completion of the deduction
under paragraph (b)(1)(ii)(A) of this section. If the compliance
account or overdraft account does not contain sufficient NOX
allowances, the Administrator will deduct the required number of
NOX allowances, regardless of the control period for which
they were allocated, whenever NOX allowances are recorded in
either account.
(iii)(A) For every control period during which the NOX
Budget permit revised under paragraph (b)(1)(i) of this section is
effective, the NOX Budget unit under paragraph (b)(1)(i) of
this section will be treated, solely for purposes of NOX
allowance allocations under Sec. 96.42, as a unit that commenced
operation on the effective date of the NOX Budget permit
revision under paragraph (b)(1)(i) of this section and will be
allocated NOX allowances under Sec. 96.42.
(B) Notwithstanding paragraph (b)(1)(iii)(A) of this section, if
the effective date of the NOX Budget permit revision under
paragraph (b)(1)(i) of this section is during a control period, the
following number of NOX allowances will be allocated to the
NOX Budget unit under paragraph (b)(1)(i) of this section
under Sec. 96.42 for the control period: the number of NOX
allowances otherwise allocated to the NOX Budget unit under
Sec. 96.42 for the control period multiplied by the ratio of the number
of days, in the control period, starting with the effective date of the
permit revision under paragraph (b)(1)(i) of this section, divided by
the total number of days in the control period.
(2)(i) When the NOX authorized account representative of
a NOX Budget opt-in source does not renew its NOX
Budget opt-in permit under Sec. 96.83(b), the Administrator will deduct
from the NOX Budget opt-in unit's compliance account, or the
overdraft account of the NOX Budget source where the
NOX Budget opt-in source is located, NOX
allowances equal in number to and allocated for the same or a prior
control period as any NOX allowances allocated to the
NOX Budget opt-in source under Sec. 96.88 for any control
period after the last control period for which the NOX
Budget opt-in permit is effective. The NOX authorized
account representative shall ensure that the NOX Budget opt-
in source's compliance account or the overdraft account of the
NOX Budget source where the NOX Budget opt-in
source is located includes the NOX allowances necessary for
completion of such deduction. If the compliance account or overdraft
account does not contain sufficient NOX allowances, the
Administrator will deduct the required number of NOX
allowances, regardless of the control period for which they were
allocated, whenever NOX allowances are recorded in either
account.
(ii) After the deduction under paragraph (b)(2)(i) of this section
is completed, the Administrator will close the NOX Budget
opt-in source's compliance account. If any NOX allowances
remain in the compliance account after completion of such deduction and
any deduction under Sec. 96.54, the Administrator will close the
NOX Budget opt-in source's compliance account and will
establish, and transfer any remaining allowances to, a new general
account for the owners and operators of the NOX Budget opt-
in source. The NOX authorized account representative for the
NOX Budget opt-in source shall become the NOX
authorized account representative for the general account.
Sec. 96.88 NOX allowance allocations to opt-in units.
(a) NOX allowance allocation. (1) By December 31
immediately before the first control period for which the
NOX Budget opt-in permit is effective, the permitting
authority will allocate NOX allowances to the NOX
Budget opt-in source and submit to the Administrator the allocation for
the control period in accordance with paragraph (b) of this section.
(2) By no later than December 31, after the first control period
for which the NOX Budget opt-in permit is in effect, and
December 31 of each year thereafter, the permitting authority will
allocate NOX allowances to the NOX Budget opt-in
source, and submit to the Administrator allocations for the next
control period, in accordance with paragraph (b) of this section.
(b) For each control period for which the NOX Budget
opt-in source has an approved NOX Budget opt-in permit, the
NOX Budget opt-in source will be allocated NOX
allowances in accordance with the following procedures:
(1) The heat input (in mmBtu) used for calculating NOX
allowance allocations will be the lesser of:
(i) The NOX Budget opt-in source's baseline heat input
determined pursuant to Sec. 96.84(c); or
[[Page 57538]]
(ii) The NOX Budget opt-in source's heat input, as
determined in accordance with subpart H of this part, for the control
period in the year prior to the year of the control period for which
the NOX allocations are being calculated.
(2) The permitting authority will allocate NOX
allowances to the NOX Budget opt-in source in an amount
equaling the heat input (in mmBtu) determined under paragraph (b)(1) of
this section multiplied by the lesser of:
(i) The NOX Budget opt-in source's baseline
NOX emissions rate (in lb/mmBtu) determined pursuant to
Sec. 96.84(c); or
(ii) The most stringent State or Federal NOX emissions
limitation applicable to the NOX Budget opt-in source during
the control period.
Subpart J--Mobile and Area Sources [Reserved]
[FR Doc. 98-26773 Filed 10-26-98; 8:45 am]
BILLING CODE 6560-01-P
