[Federal Register Volume 76, Number 152 (Monday, August 8, 2011)]
[Rules and Regulations]
[Pages 48208-48483]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 2011-17600]
[[Page 48207]]
Vol. 76
Monday,
No. 152
August 8, 2011
Part II
Environmental Protection Agency
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40 CFR Parts 51, 52, 72 et al.
Federal Implementation Plans: Interstate Transport of Fine Particulate
Matter and Ozone and Correction of SIP Approvals; Final Rule
Federal Register / Vol. 76, No. 152 / Monday, August 8, 2011 / Rules
and Regulations
[[Page 48208]]
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ENVIRONMENTAL PROTECTION AGENCY
40 CFR Parts 51, 52, 72, 78, and 97
[EPA-HQ-OAR-2009-0491; FRL-9436-8]
RIN 2060-AP50
Federal Implementation Plans: Interstate Transport of Fine
Particulate Matter and Ozone and Correction of SIP Approvals
AGENCY: Environmental Protection Agency (EPA).
ACTION: Final rule.
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SUMMARY: In this action, EPA is limiting the interstate transport of
emissions of nitrogen oxides (NOX) and sulfur dioxide
(SO2) that contribute to harmful levels of fine particle
matter (PM2.5) and ozone in downwind states. EPA is
identifying emissions within 27 states in the eastern United States
that significantly affect the ability of downwind states to attain and
maintain compliance with the 1997 and 2006 fine particulate matter
national ambient air quality standards (NAAQS) and the 1997 ozone
NAAQS. Also, EPA is limiting these emissions through Federal
Implementation Plans (FIPs) that regulate electric generating units
(EGUs) in the 27 states. This action will substantially reduce adverse
air quality impacts in downwind states from emissions transported
across state lines. In conjunction with other federal and state
actions, it will help assure that all but a handful of areas in the
eastern part of the country achieve compliance with the current ozone
and PM2.5 NAAQS by the deadlines established in the Clean
Air Act (CAA or Act). The FIPs may not fully eliminate the prohibited
emissions from certain states with respect to the 1997 ozone NAAQS for
two remaining downwind areas and EPA is committed to identifying any
additional required upwind emission reductions and taking any necessary
action in a future rulemaking. In this action, EPA is also modifying
its prior approvals of certain State Implementation Plan (SIP)
submissions to rescind any statements that the submissions in question
satisfy the interstate transport requirements of the CAA or that EPA's
approval of the SIPs affects our authority to issue interstate
transport FIPs with respect to the 1997 fine particulate and 1997 ozone
standards for 22 states. EPA is also issuing a supplemental proposal to
request comment on its conclusion that six additional states
significantly affect downwind states' ability to attain and maintain
compliance with the 1997 ozone NAAQS.
DATES: This final rule is effective on October 7, 2011.
ADDRESSES: EPA has established a docket for this action under Docket ID
No. EPA-HQ-OAR-2009-0491. All documents in the docket are listed on the
http://www.regulations.gov Web site. Although listed in the index, some
information is not publicly available, e.g., CBI or other information
whose disclosure is restricted by statute. Certain other material, such
as copyrighted material, is not placed on the Internet and will be
publicly available only in hard copy form. Publicly available docket
materials are available either electronically through http://www.regulations.gov or in hard copy at the EPA Docket Center, EPA West,
Room B102, 1301 Constitution Avenue, NW., Washington, DC. The Public
Reading Room is open from 8:30 a.m. to 4:30 p.m., Monday through
Friday, excluding legal holidays. The telephone number for the Public
Reading Room is (202) 566-1744, and the telephone number for the Air
Docket is (202) 566-1742.
FOR FURTHER INFORMATION CONTACT: For general questions concerning this
action, please contact Ms. Meg Victor, Clean Air Markets Division,
Office of Atmospheric Programs, Mail Code 6204J, Environmental
Protection Agency, 1200 Pennsylvania Avenue, NW., Washington, DC 20460;
telephone number: (202) 343-9193; fax number: (202) 343-2359; e-mail
address: [email protected]. For legal questions, please contact Ms.
Sonja Rodman, U.S. EPA, Office of General Counsel, Mail Code 2344A,
1200 Pennsylvania Avenue, NW., Washington, DC 20460, telephone (202)
564-4079; e-mail address: [email protected].
SUPPLEMENTARY INFORMATION:
I. Preamble Glossary of Terms and Abbreviations
The following are abbreviations of terms used in the preamble.
AQAT Air Quality Assessment Tool
ARP Acid Rain Program
BART Best Available Retrofit Technology
BACT Best Available Control Technology
CAA or Act Clean Air Act
CAIR Clean Air Interstate Rule
CAMx Comprehensive Air Quality Model with Extensions
CBI Confidential Business Information
CCR Coal Combustion Residuals
CEM Continuous Emissions Monitoring
CENRAP Central Regional Air Planning Association
CFR Code of Federal Regulations
DEQ Department of Environmental Quality
DSI Dry Sorbent Injection
EGU Electric Generating Unit
FERC Federal Energy Regulatory Commission
FGD Flue Gas Desulfurization
FIP Federal Implementation Plan
FR Federal Register
EPA U.S. Environmental Protection Agency
GHG Greenhouse Gas
GW Gigawatts
Hg Mercury
ICR Information Collection Request
IPM Integrated Planning Model
km Kilometers
lb/mmBtu Pounds Per Million British Thermal Unit
LNB Low-NOX Burners
MACT Maximum Achievable Control Technology
MATS Modeled Attainment Test Software
[mu]g/m \3\ Micrograms Per Cubic Meter
MSAT Mobile Source Air Toxics
MOVES Motor Vehicle Emission Simulator
NAAQS National Ambient Air Quality Standards
NBP NOX Budget Trading Program
NEI National Emission Inventory
NESHAP National Emissions Standards for Hazardous Air Pollutants
NOX Nitrogen Oxides
NODA Notices of Data Availability
NSPS New Source Performance Standard
NSR New Source Review
OFA Overfire Air
OSAT Ozone Source Apportionment Technique
OTAG Ozone Transport Assessment Group
ppb Parts Per Billion
PM2.5 Fine Particulate Matter, Less Than 2.5 Micrometers
PM10 Fine and Coarse Particulate Matter, Less Than 10
Micrometers
PM Particulate Matter
ppm Parts Per Million
PUC Public Utility Commission
RIA Regulatory Impact Analysis
SCR Selective Catalytic Reduction
SIP State Implementation Plan
SMOKE Sparse Matrix Operator Kernel Emissions
SNCR Selective Non-catalytic Reduction
SO2 Sulfur Dioxide
SOX Sulfur Oxides, Including Sulfur Dioxide
(SO2) and Sulfur Trioxide (SO3)
TAF Terminal Area Forecast
TCEQ Texas Commission on Environmental Quality
TIP Tribal Implementation Plan
TLN3 Tangential Low NOX
TPY Tons Per Year
TSD Technical Support Document
WRAP Western Regional Air Partnership
II. General Information
A. Does this action apply to me?
This rule affects EGUs, and regulates the following groups:
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Industry group NAICS a
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Utilities (electric, natural gas, other systems.).... 2211, 2212, 2213
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a North American Industry Classification System.
This table is not intended to be exhaustive, but rather provides a
guide for readers regarding entities likely to be regulated by this
action. This table lists
[[Page 48209]]
the types of entities that EPA is aware of that could potentially be
regulated. Other types of entities not listed in the table could also
be regulated. To determine whether your facility would be regulated by
the proposed rule, you should carefully examine the applicability
criteria in proposed Sec. Sec. 97.404, 97.504, and 97,604.
B. How is the preamble organized?
I. Preamble Glossary of Terms and Abbreviations
II. General Information
A. Does this action apply to me?
B. How is the preamble organized?
III. Executive Summary
IV. Legal Authority, Environmental Basis, and Correction of CAIR SIP
Approvals
A. EPA's Authority for Transport Rule
B. Rulemaking History
C. Air Quality Problems and NAAQS Addressed
1. Air Quality Problems and NAAQS Addressed
2. FIP Authority for Each State and NAAQS Covered
3. Additional Information Regarding CAA Section
110(a)(2)(D)(i)(I) SIPs for States in the Transport Rule Modeling
Domain
D. Correction of CAIR SIP Approvals
V. Analysis of Downwind Air Quality and Upwind State Emissions
A. Pollutants Regulated
1. Background
2. Which pollutants did EPA propose to control for purposes of
PM2.5 and Ozone Transport?
3. Comments and Responses
B. Baseline for Pollution Transport Analysis
C. Air Quality Modeling to Identify Downwind Nonattainment and
Maintenance Receptors
1. Emission Inventories
2. Air Quality Basis for Identifying Receptors
3. How did EPA project future nonattainment and maintenance for
annual PM2.5, 24-hour PM2.5, and 8-hour ozone?
D. Pollution Transport From Upwind States
1. Choice of Air Quality Thresholds
2. Approach for Identifying Contributing Upwind States
VI. Quantification of State Emission Reductions Required
A. Cost and Air Quality Structure for Defining Reductions
1. Summary
2. Background
B. Cost of Available Emission Reductions (Step 1)
1. Development of Annual NOX and Ozone-Season
NOX Cost Curves
2. Development of SO2 Cost Curves
3. Amount of Reductions That Could Be Achieved by 2012 and 2014
C. Estimates of Air Quality Impacts (Step 2)
1. Development of the Air Quality Assessment Tool and Air
Quality Modeling Strategy
2. Utilization of AQAT to Evaluate Control Scenarios
3. Air Quality Assessment Results
D. Multi-Factor Analysis and Determination of State Emission
Budgets
1. Multi-Factor Analysis (Step 3)
2. State Emission Budgets (Step 4)
E. Approach to Power Sector Emission Variability
1. Introduction to Power Sector Variability
2. Transport Rule Variability Limits
F. Variability Limits and State Emission Budgets: State
Assurance Levels
G. How the State Emission Reduction Requirements Are Consistent
With Judicial Opinions Interpreting the Clean Air Act
VII. FIP Program Structure to Achieve Reductions
A. Overview of Air Quality-Assured Trading Programs
B. Applicability
C. Compliance Deadlines
1. Alignment With NAAQS Attainment Deadlines
2. Compliance and Deployment of Pollution Control Technologies
D. Allocation of Emission Allowances
1. Allocations to Existing Units
2. Allocations to New Units
E. Assurance Provisions
F. Penalties
G. Allowance Management System
H. Emissions Monitoring and Reporting
I. Permitting
1. Title V Permitting
2. New Source Review
J. How the Program Structure Is Consistent With Judicial
Opinions Interpreting the Clean Air Act
VIII. Economic Impacts of the Transport Rule
A. Emission Reductions
B. The Impacts on PM2.5 and Ozone of the Final
SO2 and NOX Strategy
C. Benefits
1. Human Health Benefit Analysis
2. Quantified and Monetized Visibility Benefits
3. Benefits of Reducing GHG Emissions
4. Total Monetized Benefits
5. How do the benefits in 2012 compare to 2014?
6. How do the benefits compare to the costs of this final rule?
7. What are the unquantified and non-monetized benefits of the
Transport Rule emission reductions?
D. Costs and Employment Impacts
1. Transport Rule Costs and Employment Impacts
2. End-Use Energy Efficiency
IX. Related Programs and the Transport Rule
A. Transition From the Clean Air Interstate Rule
1. Key Differences Between the Transport Rule and CAIR
2. Transition From the Clean Air Interstate Rule to the
Transport Rule
B. Interactions With NOX SIP Call
C. Interactions With Title IV Acid Rain Program
D. Other State Implementation Plan Requirements
X. Transport Rule State Implementation Plans
XI. Structure and Key Elements of Transport Rule Air Quality-Assured
Trading Program Rules
XII. Statutory and Executive Order Reviews
A. Executive Order 12866: Regulatory Planning and Review and
Executive Order 13563: Improving Regulation and Regulatory Review
B. Paperwork Reduction Act
C. Regulatory Flexibility Act
D. Unfunded Mandates Reform Act
E. Executive Order 13132: Federalism
F. Executive Order 13175: Consultation and Coordination With
Indian Tribal Governments
G. Executive Order 13045: Protection of Children From
Environmental Health and Safety Risks
H. Executive Order 13211: Actions That Significantly Affect
Energy Supply, Distribution, or Use
I. National Technology Transfer and Advancement Act
J. Executive Order 12898: Federal Actions To Address
Environmental Justice in Minority Populations and Low-Income
Populations
1. Consideration of Environmental Justice in the Transport Rule
Development Process and Response to Comments
2. Potential Environmental and Public Health Impacts Among
Populations Susceptible or Vulnerable to Air Pollution
3. Meaningful Public Participation
4. Summary
K. Congressional Review Act
L. Judicial Review
III. Executive Summary
The CAA section 110(a)(2)(D)(i)(I) requires states to prohibit
emissions that contribute significantly to nonattainment in, or
interfere with maintenance by, any other state with respect to any
primary or secondary NAAQS. In this final rule, EPA finds that
emissions of SO2 and NOX in 27 eastern,
midwestern, and southern states contribute significantly to
nonattainment or interfere with maintenance in one or more downwind
states with respect to one or more of three air quality standards--the
annual PM2.5 NAAQS promulgated in 1997, the 24-hour
PM2.5 NAAQS promulgated in 2006, and the ozone NAAQS
promulgated in 1997 (EPA uses the term ``states'' to include the
District of Columbia in this preamble).
These emissions are transported downwind either as SO2
and NOX or, after transformation in the atmosphere, as fine
particles or ozone. This final rule identifies emission reduction
responsibilities of upwind states, and also promulgates enforceable
FIPs to achieve the required emission reductions in each state through
cost-effective and flexible requirements for power plants. Each state
has the option of replacing these federal rules with state rules to
achieve the required amount of emission reductions from sources
selected by the state.
[[Page 48210]]
Section 110(a)(2)(D)(i)(I) of the CAA requires the elimination of
upwind state emissions that significantly contribute to nonattainment
or interfere with maintenance of a NAAQS in another state. Elimination
of these upwind state emissions may not necessarily, in itself, fully
resolve nonattainment or maintenance problems at downwind state
receptors. Downwind states also have control responsibilities because,
among other things, the Act requires each state to adopt enforceable
plans to attain and maintain air quality standards. Indeed, states have
put in place measures to reduce local emissions that contribute to
nonattainment within their borders. Section 110(a)(2)(D)(i)(I) only
requires the elimination of emissions that significantly contribute to
nonattainment or interfere with maintenance of the NAAQS in other
states; it does not shift to upwind states the responsibility for
ensuring that all areas in other states attain the NAAQS.
The reductions obtained through the Transport Rule will help all
but a few downwind areas come into attainment with and maintain the
1997 annual PM2.5 NAAQS, the 2006 24-hour PM2.5
NAAQS, and the 1997 ozone NAAQS. With respect to the annual
PM2.5 NAAQS, this rule finds that 18 states have
SO2 and annual NOX emission reduction
responsibilities, and this rule quantifies each state's full emission
reduction responsibility under section 110(a)(2)(D)(i)(I). See Table
III-1 for the list of these states. With these reductions, EPA projects
that no areas will have nonattainment or maintenance concerns with
respect to the annual PM2.5 NAAQS.
With respect to the 24-hour PM2.5 NAAQS, this rule finds
that 21 states have SO2 and annual NOX emission
reduction responsibilities, and this rule quantifies each state's full
emission reduction responsibility under 110(a)(2)(D)(i)(I). See Table
III-1 for the list of these states. In all, this rule requires emission
reductions related to interstate transport of fine particles in 23
states. With these reductions, as discussed in section VI.D of this
preamble, only one area (Liberty-Clairton) is projected to remain in
nonattainment, and three other areas (Chicago,\1\ Detroit, and
Lancaster) are projected to have remaining maintenance concerns for the
24-hour PM2.5 NAAQS.
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\1\ This area is not currently designated as nonattainment for
the 24-hour PM2.5 standard. EPA is portraying the
receptors and counties in this area as a single 24-hour maintenance
area based on the annual PM2.5 nonattainment designation
of Chicago-Gary-Lake County, IL-IN.
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With respect to the 1997 ozone NAAQS, this rule finds that 20
states have ozone-season NOX emission reduction
responsibilities. For 10 of these states this rule quantifies the
state's full emission reduction responsibility under section
110(a)(2)(D)(i)(I).\2\ For 10 additional states, EPA quantifies in this
rule the ozone-season NOX emission reductions that are
necessary but may not be sufficient to eliminate all significant
contribution to nonattainment and interference with maintenance in
other states.\3\ See Table III-1 for the complete list of 20 states
required to reduce ozone-season NOX emissions in this rule.
With the Transport Rule reductions, only one area (Houston) is
projected to remain in nonattainment, and one area (Baton Rouge) to
have a remaining maintenance concern with respect to the 1997 ozone
NAAQS. The 10 states upwind of either of these two areas are the states
for which additional reductions may be necessary to fully eliminate
each state's significant contribution to nonattainment and interference
with maintenance, as discussed in section VI of this preamble.\4\
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\2\ The 10 states for which this rule quantifies the state's
full responsibility under section 110(a)(2)(D)(i)(I) with respect to
the 1997 ozone NAAQS are Florida, Maryland, New Jersey, New York,
North Carolina, Ohio, Pennsylvania, South Carolina, Virginia, and
West Virginia.
\3\ The 10 states for which this rule quantifies reductions that
are necessary but may not be sufficient to satisfy the requirements
of 110(a)(2)(D)(i)(I) with respect to the 1997 ozone NAAQS are
Alabama, Arkansas, Georgia, Illinois, Indiana, Kentucky, Louisiana,
Mississippi, Tennessee, and Texas.
\4\ This preamble uses the term ``significant contribution''
only in the context of the CAA section 110(a)(2)(D)(i)(I)
requirement that states prohibit emissions that ``contribute
significantly to nonattainment'' in any other state with respect to
any primary or secondary NAAQS. Thus, a significant contribution, as
used in this preamble, is one that is significant for purposes of
CAA section 110(a)(2)(D)(i)(I) as coming from a particular state.
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As discussed further below, EPA's analysis also demonstrates that
six additional states should be required to reduce ozone-season
NOX emissions. EPA is issuing a supplemental proposal to
request comment on requiring ozone-season NOX reductions in
these six states. For five of these six states, EPA's analysis
identifies the state's full emission reduction responsibility under
section 110(a)(2)(D)(i)(I), and for the remaining one state EPA's
analysis identifies reductions that are necessary but may not be
sufficient to satisfy the requirements of 110(a)(2)(D)(i)(I).\5\
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\5\ The five states addressed in the supplemental proposal for
which EPA's analysis identifies the state's full reduction
responsibility under section 110(a)(2)(D)(i)(I) with respect to the
1997 ozone NAAQS are Iowa, Kansas, Michigan, Oklahoma, and
Wisconsin. The one state addressed in the supplemental proposal for
which EPA's analysis identifies reductions that are necessary but
may not be sufficient to satisfy section 110(a)(2)(D)(i)(I) with
respect to the 1997 ozone NAAQS is Missouri.
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On January 19, 2010, EPA proposed revisions to the 8-hour ozone
NAAQS that the Agency had issued March 12, 2008 (75 FR 2938); the
Agency intends to finalize its reconsideration in the summer of 2011.
EPA intends to propose a rule to address transport with respect to the
reconsidered 2008 ozone NAAQS as expeditiously as possible after
reconsideration is completed. EPA intends to include in that proposed
rule requirements to address any remaining significant contribution to
nonattainment and interference with maintenance with respect to the
1997 ozone NAAQS for the states identified in this final rule, or the
associated supplemental notice of proposed rulemaking, for which EPA
was unable to fully quantify the emissions that must be prohibited to
satisfy the requirements of 110(a)(2)(D)(i)(I) with respect to the 1997
ozone NAAQS.
The Act requires EPA to conduct periodic reviews of each of the
NAAQS. When NAAQS are set or revised, the CAA requires revision of SIPs
to ensure the standards are met expeditiously and within relevant
timetables in the Act. If more protective NAAQS are promulgated, in the
case of pollutants for which interstate transport is important,
additional emission reductions to address transported pollution may be
required from the power sector, from other sectors, and from sources in
additional states. EPA will act promptly to promulgate any future rules
addressing transport with respect to revised NAAQS.
The Transport Rule requires substantial near-term emission
reductions in every covered state to address each state's significant
contribution to nonattainment and interference with maintenance
downwind. This rule achieves these reductions through FIPs that
regulate the power sector using air quality-assured trading programs
whose assurance provisions ensure that necessary reductions will occur
within every covered state. This remedy structure is substantially
similar to the preferred trading remedy structure presented in the
proposal. The Transport Rule's air quality-assured trading approach
will assure
[[Page 48211]]
environmental results in each state while providing market-based
flexibility to covered sources through interstate trading. The final
rule includes four air quality-assured trading programs: An annual
NOX trading program, an ozone-season NOX trading
program, and two separate SO2 trading programs
(``SO2 Group 1'' and ``SO2 Group 2''), as
discussed further in sections VI and VII, below.
The first phase of Transport Rule compliance commences January 1,
2012, for SO2 and annual NOX reductions and May
1, 2012, for ozone-season NOX reductions. The second phase
of Transport Rule reductions, which commences January 1, 2014,
increases the stringency of SO2 reductions in a number of
states as discussed further below.
EPA projects that with the Transport Rule, covered EGU will
substantially reduce SO2, annual NOX and ozone-
season NOX emissions, as shown in Tables III-2 and III-3,
below. This rule generally covers electric generating units that are
fossil fuel-fired boilers and turbines producing electricity for sale,
as detailed in section VII.B.
EPA is promulgating the Transport Rule in response to the remand of
the Clean Air Interstate Rule (CAIR) by the U.S. Court of Appeals for
the District of Columbia Circuit (``Court'') in 2008. CAIR, promulgated
May 12, 2005 (70 FR 25162), required 29 states to adopt and submit
revisions to their State Implementation Plans (SIPs) to eliminate
SO2 and NOX emissions that contribute
significantly to downwind nonattainment of the PM2.5 and
ozone NAAQS promulgated in July 1997. CAIR covered a similar but not
identical set of states as the Transport Rule. CAIR FIPs were
promulgated April 26, 2006 (71 FR 25328) to regulate electric
generating units in the covered states and achieve the emission
reduction requirements established by CAIR until states could submit
and obtain approval of SIPs to achieve the reductions.
In July 2008, the Court found CAIR and the CAIR FIPs unlawful.
North Carolina v. EPA, 531 F.3d 896 (D.C. Cir. 2008), modified on
rehearing, North Carolina v. EPA, 550 F.3d 1176, 1178 (D.C. Cir. 2008).
The Court's original decision vacated CAIR. North Carolina, 531 F.3d at
929-30. However, the Court subsequently remanded CAIR to EPA without
vacatur because it found that ``allowing CAIR to remain in effect until
it is replaced by a rule consistent with our opinion would at least
temporarily preserve the environmental values covered by CAIR.'' North
Carolina, 550 F.3d at 1178. The CAIR requirements have remained in
place while EPA has developed the Transport Rule to replace them.
EPA's approach in the Transport Rule to measure and address each
state's significant contribution to downwind nonattainment and
interference with maintenance is guided by and consistent with the
Court's opinion in North Carolina and addresses the flaws in CAIR
identified by the Court therein. This final rule also responds to
extensive public comments and stakeholder input received during the
public comment periods in response to the proposal and subsequent
Notices of Data Availability (NODAs).
In this action, EPA both identifies and addresses emissions within
states that significantly contribute to nonattainment or interfere with
maintenance in other downwind states. In developing this rule, EPA used
a state-specific methodology to identify emission reductions that must
be made in covered states to address the CAA section 110(a)(2)(D)(i)(I)
prohibition on emissions that significantly contribute to nonattainment
or interfere with maintenance in a downwind state. EPA believes this
methodology addresses the Court's concern that the approach used in
CAIR was insufficiently state-specific. EPA used detailed air quality
analysis to determine whether a state's contribution to downwind air
quality problems is at or above specific thresholds. A state is covered
by the Transport Rule if its contribution meets or exceeds one of those
air quality thresholds and the Agency identifies, using a multi-factor
analysis that takes into account both air quality and cost
considerations, emissions within the state that constitute the state's
significant contribution to nonattainment and interference with
maintenance with respect to the 1997 ozone or the 1997 annual or 2006
24-hour PM2.5 NAAQS. Section 110(a)(2)(D)(i)(I) requires
states to eliminate the emissions that constitute this ``significant
contribution'' and ``interference with maintenance.'' \6\
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\6\ In this preamble, EPA uses the terms ``significant
contribution'' and ``interference with maintenance'' to refer to the
emissions that must be prohibited pursuant to section
110(a)(2)(D)(i)(I) because they significantly contribute to
nonattainment or interfere with maintenance of the NAAQS in another
state.
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In this final rule, EPA determined the emission reductions required
from all upwind states to eliminate significant contribution to
nonattainment and interference with maintenance with respect to the
1997 ozone, 1997 annual PM2.5, and 2006 24-hour
PM2.5 NAAQS, using, in part, an assessment of modeled air
quality in 2012 and 2014. EPA first identified the following two sets
of downwind receptors: (1) Receptors that EPA projects will have
nonattainment problems; and, (2) receptors that EPA projects may have
difficulty maintaining the NAAQS based on historic variation in air
quality. To identify areas that may have problems attaining or
maintaining these air quality standards, EPA projected a suite of
future air quality design values, based on measured data during the
period 2003 through 2007. EPA used the average of these future design
values to assess whether an area will be in nonattainment. EPA used the
maximum projected future design value to assess whether an area may
have difficulty maintaining the relevant NAAQS (i.e., whether an area
has a reasonable possibility of being in nonattainment under adverse
emission and weather conditions). Section V.C of this preamble details
the Transport Rule's approach to identify downwind nonattainment and
maintenance areas.
After identifying downwind nonattainment and/or maintenance areas,
EPA next used air quality modeling to determine which upwind states are
projected to contribute at or above threshold levels to the air quality
problems in those areas. Section V.D details the choice of air quality
thresholds and the approach to determine how much each upwind state
contributes. States whose contributions meet or exceed the threshold
levels were analyzed further, as detailed in section VI, to determine
whether they significantly contribute to nonattainment or interfere
with maintenance of a relevant NAAQS, and if so, the quantity of
emissions that constitute their significant contribution and
interference with maintenance.
When EPA proposed this air-quality and cost-based multi-factor
approach to identify emissions that constitute significant contribution
to nonattainment and interference with maintenance from upwind states
with respect to the 1997 ozone, annual PM2.5, and 2006 24-
hour PM2.5 NAAQS, the Agency indicated that the approach was
designed to be applicable to both current and potential future ozone
and PM2.5 NAAQS (75 FR 45214). EPA believes that the
Transport Rule's approach of using air-quality thresholds to determine
upwind-to-downwind-state linkages and using the air-quality and cost-
based multi-factor approach to determine the quantity of emissions that
each upwind state must eliminate, i.e., the state's significant
contribution to nonattainment and interference with maintenance, could
serve as a precedent for quantifying upwind state emission reduction
responsibilities with respect
[[Page 48212]]
to potential future NAAQS, as discussed further in section VI.A of this
preamble. The Agency further believes that the final Transport Rule
demonstrates the strong value of this approach for addressing the role
of interstate transport of air pollution in communities' ability to
comply with current and future NAAQS.
EPA thus identified specific emission reduction responsibilities
for each upwind state found to significantly contribute to
nonattainment or interfere with maintenance in other states. Using that
information, EPA developed individual state budgets for emissions from
covered units under the Transport Rule. The Transport Rule emission
budgets are based on EPA's state-by-state analysis of each upwind
state's significant contribution to nonattainment and interference with
maintenance. Because each state's budget is directly linked to this
state-specific analysis of the state's obligations pursuant to section
110(a)(2)(D)(i)(I), this approach addresses the Court's concerns about
the development of CAIR budgets.
In this rule, EPA is finalizing SO2 and annual
NOX budgets for each state covered for the 24-hour and/or
annual PM2.5 NAAQS and an ozone-season NOX budget
for each state covered for the ozone NAAQS. A state's emission budget
is the quantity of emissions that will remain from covered units under
the Transport Rule after elimination of significant contribution to
nonattainment and interference with maintenance in an average year
(i.e., before accounting for the inherent variability in power system
operations).\7\
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\7\ For the states discussed above for which EPA has quantified
the minimum amount of emission reductions needed to make measurable
progress toward satisfying the state's section 110(a)(2)(D)(i)(I)
responsibility, the emission budget is the quantity of emissions
that will remain from covered units after removal of those
emissions.
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Baseline power sector emissions from a state can be affected by
changing weather patterns, demand growth, or disruptions in electricity
supply from other units or from the transmission grid. As a
consequence, emissions could vary from year to year even in a state
where covered sources have installed all controls and taken all
measures necessary to eliminate the state's significant contribution to
nonattainment and interference with maintenance. As described in detail
in sections VI and VII of this preamble, the Transport Rule accounts
for the inherent variability in power system operations through
``assurance provisions'' based on state-specific variability limits
which extend above the state budgets to form each state's ``assurance
level.'' The state assurance levels take into account the inherent
variability in baseline emissions from year to year. The final
Transport Rule FIPs will implement assurance provisions starting in
2012 as discussed in section VII, below.
The emission reduction requirements (i.e., the ``remedy'') EPA is
promulgating in this rule respond to the Court's concerns that in CAIR,
EPA had not shown that the emission reduction requirements would get
all necessary reductions within the state as required by section
110(a)(2)(D)(i)(I). The Transport Rule FIPs include assurance
provisions specifically designed to ensure that no state's emissions
are allowed to exceed that specific state's budget plus the variability
limit (i.e., the state's assurance level).
Each state's Transport Rule SO2, annual NOX,
or ozone-season NOX emission budget is composed of a number
of emission allowances (``allowances'') equivalent to the tonnage of
that specific state budget. Under the Transport Rule FIPs, EPA is
distributing (``allocating'') allowances under each state's budget to
covered units in that state. In this rule, EPA analyzed each individual
state's significant contribution to nonattainment and interference with
maintenance and calculated budgets that represent each state's
emissions after the elimination of those prohibited emissions in an
average year. The methodology used to allocate allowances to individual
units in a particular state has no impact on that state's budget or on
the requirement that the state's emissions not exceed that budget plus
the variability limit; the allocation methodology therefore has no
impact on the rule's ability to satisfy the statutory mandate of CAA
section 110(a)(2)(D)(i)(I).
The Transport Rule's approach to allocate emission allowances to
existing units is based on historic heat-input data, as detailed in
section VII.D of this preamble. The Transport Rule SO2,
annual NOX, and ozone-season NOX emission
allowances each authorize the emission of one ton of SO2,
annual NOX, or ozone-season NOX emissions,
respectively, during a Transport Rule control period, and are the
currency in the Transport Rule's air quality-assured trading programs.
As discussed in section IX.A.2 below, EPA is creating these Transport
Rule allowances as distinct compliance instruments with no relation to
allowances from the CAIR trading programs. EPA agrees with the general
principle that it is desirable, where possible, to provide continuity
under successive regulatory trading programs, for example through the
carryover of allowances from one program into a subsequent one.
However, EPA is promulgating the Transport Rule as a court-ordered
replacement for (not a successor to) CAIR's trading programs. In light
of the specific circumstances of this case, including legal and
technical issues discussed in Section IX.A.2 below, the final rule will
not allow any carryover of banked SO2 or NOX
allowances from the Title IV or CAIR trading programs. EPA will
strongly consider administrative continuity of this rule's trading
programs under any future actions designed to address related problems
of interstate transport of air pollution. A state may submit a SIP
revision under which the state (rather than EPA) would determine
allocations for one or more of the Transport Rule trading programs
beginning with vintage year 2013 or later allowances.\8\ Section X of
this preamble discusses the final rule's provisions for SIP submissions
in detail.
---------------------------------------------------------------------------
\8\ This final rule allows states to make 2013 allowance
allocations through the use of a SIP revision that is narrower in
scope than the other SIP revisions states can use to replace the
FIPs and/or to make allocation decisions for 2014 and beyond, as
discussed in section X.
---------------------------------------------------------------------------
Table III-1 lists states covered by the Transport Rule for
PM2.5 and ozone. It also, with respect to PM2.5,
identifies whether EPA determined the state was significantly
contributing to nonattainment or interfering with maintenance of the
1997 annual PM2.5 NAAQS, the 2006 24-hour PM2.5
NAAQS, or both. As discussed below, the Transport Rule sorts the states
required to reduce SO2 emissions due to their contribution
to PM2.5 downwind into two groups of varying reduction
stringency, with ``Group 1'' states subject to greater SO2
reduction stringency than ``Group 2'' states starting in 2014. Table
III-1 also lists which SO2 Group each of the states is in.
[[Page 48213]]
Table III-1--States That Significantly Contribute to Nonattainment or Interfere With Maintenance of a NAAQS
Downwind in the Final Transport Rule
----------------------------------------------------------------------------------------------------------------
1997 Annual PM2.5 2006 24-Hour
State 1997 Ozone NAAQS NAAQS PM2.5 NAAQS SO2 group
----------------------------------------------------------------------------------------------------------------
Alabama............................. X X X 2
Arkansas............................ X ................. ................. .................
Florida............................. X ................. ................. .................
Georgia............................. X X X 2
Illinois............................ X X X 1
Indiana............................. X X X 1
Iowa................................ ................. X X 1
Kansas.............................. ................. ................. X 2
Kentucky............................ X X X 1
Louisiana........................... X ................. ................. .................
Maryland............................ X X X 1
Michigan............................ ................. X X 1
Minnesota........................... ................. ................. X 2
Mississippi......................... X ................. ................. .................
Missouri............................ ................. X X 1
Nebraska............................ ................. ................. X 2
New Jersey.......................... X ................. X 1
New York............................ X X X 1
North Carolina...................... X X X 1
Ohio................................ X X X 1
Pennsylvania........................ X X X 1
South Carolina...................... X X ................. 2
Tennessee........................... X X X 1
Texas............................... X X ................. 2
Virginia............................ X ................. X 1
West Virginia....................... X X X 1
Wisconsin........................... ................. X X 1
Number of States.................... 20 18 21 .................
----------------------------------------------------------------------------------------------------------------
As explained in this preamble, EPA has improved and updated both
steps of its significant contribution analysis. It updated and improved
the modeling platforms and modeling inputs used to identify states with
contributions to certain downwind receptors that meet or exceed
specified thresholds. It also updated and improved its analysis for
identifying any emissions within such states that constitute the
state's significant contribution to nonattainment or interference with
maintenance. Therefore, the results of the analysis conducted for the
final rule differ somewhat from the results of the analysis conducted
for the proposal.\9\
---------------------------------------------------------------------------
\9\ EPA updated its modeling platforms and modeling inputs in
response to public comments received on the proposed Transport Rule
and subsequent NODAs and performed other standard updates.
---------------------------------------------------------------------------
With respect to the 1997 ozone NAAQS, the analysis EPA conducted
for the proposal did not identify Wisconsin, Iowa and Missouri as
states that significantly contribute to nonattainment or interfere with
maintenance of the ozone NAAQS in another state. However, the analysis
conducted for the final rule shows that emissions from these states do
significantly contribute to nonattainment or interfere with maintenance
of the ozone NAAQS in another state. EPA is not issuing FIPs with
respect to the 1997 ozone NAAQS or finalizing ozone season
NOX budgets for these states in this rule. EPA is publishing
a supplemental notice of proposed rulemaking that will provide an
opportunity for public comment on our conclusion that these states
significantly contribute to nonattainment or interfere with maintenance
of the 1997 ozone NAAQS.
In the other direction, the analysis conducted for the proposal
supported EPA's conclusion at the time that Connecticut, Delaware, and
the District of Columbia significantly contributed to nonattainment or
interfered with maintenance with respect to the 1997 ozone NAAQS,
whereas the modeling for the final rule no longer supports that
conclusion for those states.
Additionally, the modeling conducted for the final rule identified
two ozone maintenance receptors that were not identified in the
modeling conducted for the proposal--Allegan County (MI) and Harford
County (MD). Five states that EPA identified as significantly
contributing to maintenance problems at the Allegan and/or Harford
County receptors in the modeling for the final rule uniquely contribute
to these receptors, i.e., absent these receptors the states would not
be covered by the Transport Rule ozone-season program. The five states
that uniquely contribute to these receptors are Iowa, Kansas, Michigan,
Oklahoma, and Wisconsin. EPA is not issuing FIPs with respect to the
1997 ozone NAAQS or finalizing ozone-season NOX budgets for
these states in this rule. EPA is publishing a supplemental notice of
proposed rulemaking that will provide an opportunity for public comment
on our conclusion that these states significantly contribute to
nonattainment or interfere with maintenance of the 1997 ozone NAAQS.
EPA did not change its methodology between the proposed Transport
Rule and the final Transport Rule for identifying upwind states that
significantly contribute to nonattainment or interfere with maintenance
in other states; nor did EPA change its methodology for identifying
receptors of concern with respect to maintenance of the 1997 ozone
NAAQS. The final rule's air quality modeling identifies the new states
and new receptors described above based on updated input information
(including emission inventories), much of which was provided to EPA
through public comment on the proposal and subsequent NODAs. Section V
of this preamble details the approach EPA used
[[Page 48214]]
to identify contributing states and receptors of concern.
With respect to the annual PM2.5 NAAQS, the analysis EPA
conducted for the proposal supported EPA's conclusion that the states
of Delaware, the District of Columbia, Florida, Louisiana, Minnesota,
New Jersey, and Virginia were significantly contributing to
nonattainment and interfering with maintenance of the annual
PM2.5 NAAQS while the final rule's analysis does not. Also,
with respect to the 24-hour PM2.5 NAAQS, the analysis
conducted for the proposal supported EPA's conclusion that the states
of Connecticut, Delaware, the District of Columbia, and Massachusetts
were significantly contributing to nonattainment or interfering with
maintenance in other states while the analysis conducted for the final
rule did not.
In the proposal EPA also requested comment on whether Texas should
be included in the Transport Rule for annual PM2.5. EPA's
analysis for the proposal showed that emissions in Texas would
significantly contribute to nonattainment or interfere with maintenance
of the annual PM2.5 NAAQS if Texas were not included in the
rule for PM2.5. The proposal did not include an illustrative
budget for Texas or illustrative allowance allocations. However, the
budgets and allowance allocations provided for other states in the
proposal were included solely to illustrate the result of applying
EPA's proposed methodology for quantifying significant contribution to
the data EPA proposed to use. EPA provided an ample opportunity for
comment on this methodology and on the data, including data regarding
emissions from Texas sources, used in the significant contribution
analysis. EPA received numerous comments on and corrections to Texas-
specific data. The modeling conducted for the final rule demonstrates
that Texas significantly contributes to nonattainment or interferes
with maintenance of the annual PM2.5 NAAQS in another state.
EPA provided a full opportunity for comment on whether Texas should be
included in the rule for annual PM2.5, as well as on the
methodology and data used for the significant contribution analysis for
the final rule. EPA therefore believes its determination that Texas
must be included in the rule for annual PM2.5 is a logical
outgrowth of its proposal.
With respect to the 24-hour PM2.5 NAAQS, the analysis
EPA conducted for the proposal did not identify Texas as a state that
significantly contributes to nonattainment or interferes with
maintenance of 24-hour PM2.5 in another state. However, the
analysis conducted for the final rule shows that emissions from Texas
do significantly contribute to nonattainment of the 24-hour
PM2.5 NAAQS in another state. EPA is not issuing a FIP for
Texas with respect to the 24-hour PM2.5 NAAQS in this rule.
However, EPA believes that the FIP for Texas with respect to the 1997
annual PM2.5 NAAQS also addresses the emissions in Texas
that significantly contribute to nonattainment and interference with
maintenance of the 2006 24-hour PM2.5 NAAQS in another
state.
The final rule, however, does not cover the states of Connecticut,
Delaware, the District of Columbia, Florida, Louisiana, or
Massachusetts for annual or 24-hour PM2.5 as the analysis
for the final rule does not support their inclusion.
The Transport Rule FIPs require the 23 states covered for purposes
of the 24-hour and/or annual PM2.5 NAAQS to reduce
SO2 and annual NOX emissions by specified
amounts. The FIPs require the 20 states covered for purposes of the
ozone NAAQS to reduce ozone-season NOX emissions by
specified amounts. As discussed in detail in section VI, below, the 23
states covered for the 24-hour and/or annual PM2.5 NAAQS are
grouped in two tiers reflecting the stringency of SO2
reductions required to eliminate that state's significant contribution
to nonattainment and interference with maintenance downwind. The more-
stringent SO2 tier (``Group 1'') is comprised of the 16
states indicated in Table III-1, above, and the less-stringent
SO2 tier (``Group 2'') is comprised of the 7 states
identified in the table. The two SO2 trading programs are
exclusive, i.e., a covered source in a Group 1 state may use only a
Group 1 allowance for compliance, and likewise a source in a Group 2
state may use only a Group 2 allowance for compliance. In Group 1
states, the SO2 reduction requirements become more stringent
in the second phase, which starts in 2014.
In response to the Court's opinion in North Carolina, EPA has
coordinated the Transport Rule's compliance deadlines with the NAAQS
attainment deadlines that apply to the downwind nonattainment and
maintenance areas. The Transport Rule requires that all significant
contribution to nonattainment and interference with maintenance
identified in this action with respect to the 1997 annual
PM2.5 NAAQS and the 2006 24-hour PM2.5 NAAQS be
eliminated by no later than 2014, with an initial phase of reductions
starting in 2012 to ensure that reductions are made as expeditiously as
practicable and, consistent with the Court's remand, to ``preserve the
environmental values covered by CAIR.'' Sources must comply by January
1, 2012 and January 1, 2014 for the first and second phases,
respectively.
With respect to the 1997 ozone NAAQS, the Transport Rule requires
NOX reductions starting in 2012 to ensure that reductions
are made as expeditiously as practicable to assist downwind state
attainment and maintenance of the standard. Sources must comply by May
1, 2012. The Transport Rule's compliance schedule and alignment with
downwind NAAQS attainment deadlines are discussed in detail in section
VII below.
Table III-2 shows projected Transport Rule emissions compared to
projected base case emissions, and Table III-3 shows projected
Transport Rule emissions compared to historical emissions (i.e., 2005
emissions), for the power sector in all Transport Rule states. The
ozone-season NOX results shown in Tables III-2 and III-3 are
based on analysis of the group of 26 states that would be covered for
the ozone-season program if EPA finalizes the supplemental proposal
regarding ozone-season requirements for Iowa, Kansas, Michigan,
Missouri, Oklahoma, and Wisconsin.
Table III-2--Projected SO2 and NOX Electric Generating Unit Emission Reductions in Covered States With the Transport Rule Compared to Base Case Without
Transport Rule or CAIR **
[Million tons]
--------------------------------------------------------------------------------------------------------------------------------------------------------
2012 Base case 2012 Transport 2012 Emission 2014 Base case 2014 Transport 2014 Emission
emissions rule emissions reductions emissions rule emissions reductions
--------------------------------------------------------------------------------------------------------------------------------------------------------
SO2..................................................... 7.0 3.0 4.0 6.2 2.4 3.9
Annual NOX.............................................. 1.4 1.3 0.1 1.4 1.2 0.2
[[Page 48215]]
Ozone-Season NOX........................................ 0.7 0.6 0.1 0.7 0.6 0.1
--------------------------------------------------------------------------------------------------------------------------------------------------------
* Note that numbers may not sum exactly due to rounding.
** As explained in section V.B, EPA's base case projections for the Transport Rule assume that CAIR is not in place.
Notes: The SO2 and annual NOX emissions in
this table reflect EGUs in the 23 states covered by this rule for
purposes of the 24-hour and/or annual PM2.5 NAAQS
(Alabama, Georgia, Illinois, Indiana, Iowa, Kansas, Kentucky,
Maryland, Michigan, Minnesota, Missouri, Nebraska, New Jersey, New
York, North Carolina, Ohio, Pennsylvania, South Carolina, Tennessee,
Texas, Virginia, West Virginia, and Wisconsin). The ozone-season
NOX emissions reflect EGUs in the 20 states covered by
this rule for purposes of the ozone NAAQS (Alabama, Arkansas,
Florida, Georgia, Illinois, Indiana, Kentucky, Louisiana, Maryland,
Mississippi, New Jersey, New York, North Carolina, Ohio,
Pennsylvania, South Carolina, Tennessee, Texas, Virginia, and West
Virginia) and the six states that would be covered for the ozone
NAAQS if EPA finalizes its supplemental proposal (Iowa, Kansas,
Michigan, Missouri, Oklahoma, and Wisconsin).
Table III-3--Projected SO2 and NOX Electric Generating Unit Emission Reductions in Covered States With the
Transport Rule Compared to 2005 Actual Emissions
[Million tons]
----------------------------------------------------------------------------------------------------------------
2012 Emission 2014 Emission
2005 Actual 2012 Transport reductions 2014 Transport reductions
emissions rule emissions from 2005 rule emissions from 2005
----------------------------------------------------------------------------------------------------------------
SO2............................. 8.8 3.0 5.8 2.4 6.4
Annual NOX...................... 2.6 1.3 1.3 1.2 1.4
Ozone-Season NOX................ 0.9 0.6 0.3 0.6 0.3
----------------------------------------------------------------------------------------------------------------
Notes: The SO2 and annual NOX emissions in
this table reflect EGUs in the 23 states covered by this rule for
purposes of the 24-hour and/or annual PM2.5 NAAQS
(Alabama, Georgia, Illinois, Indiana, Iowa, Kansas, Kentucky,
Maryland, Michigan, Minnesota, Missouri, Nebraska, New Jersey, New
York, North Carolina, Ohio, Pennsylvania, South Carolina, Tennessee,
Texas, Virginia, West Virginia, and Wisconsin). The ozone-season
NOX emissions reflect EGUs in the 20 states covered by
this rule for purposes of the ozone NAAQS (Alabama, Arkansas,
Florida, Georgia, Illinois, Indiana, Kentucky, Louisiana, Maryland,
Mississippi, New Jersey, New York, North Carolina, Ohio,
Pennsylvania, South Carolina, Tennessee, Texas, Virginia, and West
Virginia) and the six states that would be covered for the ozone
NAAQS if EPA finalizes its supplemental proposal (Iowa, Kansas,
Michigan, Missouri, Oklahoma, and Wisconsin).
In addition to the emission reductions shown above, EPA projects
other substantial benefits of the Transport Rule, as described in
section VIII in this preamble. EPA used air quality modeling to
quantify the improvements in PM2.5 and ozone concentrations
that are expected to result from the Transport Rule emission reductions
in 2014. The Agency used the results of this modeling to calculate the
average and peak reduction in annual PM2.5, 24-hour
PM2.5, and 8-hour ozone concentrations for monitoring sites
in the Transport Rule covered states (including the six states for
which EPA issued a supplemental proposal for ozone-season
NOX requirements) in 2014.
For annual PM2.5, the average reduction across all
monitoring sites in covered states in 2014 is 1.41 microgram per meter
cubed ([micro]g/m\3\) and the greatest reduction at a single site is
3.60 [micro]g/m\3\. For 24-hour PM2.5, the average reduction
across all monitoring sites in covered states in 2014 is 4.3 [micro]g/
m\3\ and the greatest reduction at a single site is 11.6 [micro]g/m\3\.
And finally, for 8-hour ozone, the average reduction across all
monitoring sites in covered states in 2014 is 0.3 parts per billion
(ppb) and the greatest is 3.9 ppb. See section VIII for further
information on air quality improvements.
EPA estimated the Transport Rule's costs and benefits, including
effects on sensitive and vulnerable and environmental justice
communities. Table III-4, below, summarizes some of these results.
Further discussion of the results is provided in preamble section VIII,
below, and in the Regulatory Impact Analysis (RIA). Estimates here are
subject to uncertainties discussed further in the RIA.
Table III-4.--Summary of Annual Benefits, Costs, and Net Benefits of the Final Transport Rule in 2014
[Billions of 2007$] \a\
----------------------------------------------------------------------------------------------------------------
Transport rule remedy (billions of 2007 $)
Description -------------------------------------------------------------------------
3% discount rate 7% discount rate
----------------------------------------------------------------------------------------------------------------
Social costs.......................... $0.81.............................. $0.81.
Total monetized benefits \b\.......... $120 to $280....................... $110 to $250.
Net benefits (benefits-costs)......... $120 to $280....................... $110 to $250.
----------------------------------------------------------------------------------------------------------------
\a\ All estimates are for 2014, and are rounded to two significant figures.
[[Page 48216]]
\b\ The total monetized benefits reflect the human health benefits associated with reducing exposure to PM2.5
and ozone and the welfare benefits associated with improved visibility in Class I areas. The reduction in
premature mortalities account for over 90 percent of total monetized PM2.5 and ozone benefits.
As a result of updated analyses and in response to public comments,
the final Transport Rule differs from the proposal in a number of ways.
The differences between proposal and final rule are discussed
throughout this preamble. Some key changes between proposal and final
rule are that EPA:
Updated emission inventories (resulting in generally lower
base case emissions). See section V.C.
Updated modeling and analysis tools (including improved
alignment between air quality estimates and air quality modeling
results). See sections V and VI.
Updated conclusions regarding which states significantly
contribute to nonattainment or interfere with maintenance of the NAAQS
in other states. See Table III-1 and sections V.D and VI.
Recalculated state budgets and variability limits, i.e.,
state assurance levels, based on updated modeling. See section VI.
Simplified variability limits for one-year application
only. See section VI.E.
Revised allocation methodology for existing and new units
and revised new unit set-asides for new units in Transport Rule states
and new units potentially locating in Indian country. See section
VII.D.
Changed start of assurance provisions to 2012 and
increased assurance provision penalties. See section VII.E.
Removed opt-in provisions. See section VII.B
Added provisions for full and abbreviated Transport Rule
SIP revisions. See section X.
EPA conducted substantial stakeholder outreach in developing the
Transport Rule, starting with a series of ``listening sessions'' in the
spring of 2009 with states, nongovernmental organizations, and
industry. EPA docketed stakeholder-related materials in the Transport
Rule docket (Docket ID No. EPA-HQ-OAR-2009-0491). The Agency conducted
general teleconferences on the rule with tribal environmental
professionals, conducted consultation with tribal governments, and
hosted a webinar for communities and tribal governments. EPA continued
to provide updates to regulatory partners and stakeholders through
several conference calls with states as well as at conferences where
EPA officials often made presentations. The Agency conducted additional
stakeholder outreach during the public comment period. EPA responded to
extensive public comments received during the public comment periods on
the proposed rule and associated NODAs.
This Transport Rule is one of a series of regulatory actions to
reduce the adverse health and environmental impacts of the power
sector. EPA is developing these rules to address judicial review of
previous rulemakings and to issue rules required by environmental laws.
Finalizing these rules will effectuate health and environmental
protection mandated by Congress while substantially reducing
uncertainty over the future regulatory obligations of power plants,
which will assist the power sector in planning for compliance more cost
effectively. The Agency is providing full opportunity for notice and
comment for each rule.
As discussed above, rules to address transport under revised NAAQS,
including the reconsidered 2008 ozone NAAQS, may result in additional
emission reduction requirements for the power sector. In addition,
existing Clean Air Act rules establishing best available retrofit
technology (BART) requirements and other requirements for addressing
visibility and regional haze may also result in future state
requirements for certain power plant emission reductions where needed.
On May 3, 2011 (76 FR 24976), EPA proposed national emission
standards for hazardous air pollutants from coal- and oil-fired
electric utility steam generating units under CAA section 112(d), also
called Mercury and Air Toxics Standards (MATS), and proposed revised
new source performance standards for fossil fuel-fired EGUs under
section 111(b). As discussed in the EPA-led public listening sessions
during February and March 2011, EPA is preparing to propose innovative,
cost-effective and flexible greenhouse gas (GHG) emissions performance
standards under section 111 for steam electric generating units, the
largest U.S. source of greenhouse gas emissions. On April 20, 2011 (76
FR 22174), EPA proposed requirements under section 316(b) of the Clean
Water Act for existing power generating facilities, manufacturing and
industrial facilities that withdraw more than two million gallons per
day of water from waters of the U.S. and use at least twenty-five
percent of that water exclusively for cooling purposes. On June 21,
2010 (75 FR 35128), the Agency proposed to regulate coal combustion
residuals (CCRs) under the Resource Conservation and Recovery Act to
address the risks from the disposal of CCRs generated from the
combustion of coal at electric utilities and independent power
producers.
EPA will coordinate utility-related air pollution rules with each
other and with other actions affecting the power sector including these
rules from EPA's Office of Water and its Office of Resource
Conservation and Recovery to the extent consistent with legal authority
in order to provide timely information needed to support regulated
sources in making informed decisions. Use of a small number of air
pollution control technologies, widely deployed, can assist with
compliance for multiple rules. EPA also notes that the flexibility
inherent in the allowance-trading mechanism included in the Transport
Rule affords utilities themselves a degree of latitude to determine how
best to integrate compliance with the emission reduction requirements
of this rule and those of the other rules. EPA will pursue energy
efficiency improvements in the use of electricity throughout the
economy, along with other federal agencies, states and other groups,
which will contribute to additional environmental and public health
improvements while lowering the costs of realizing those improvements.
IV. Legal Authority, Environmental Basis, and Correction of CAIR SIP
Approvals
A. EPA's Authority for Transport Rule
The statutory authority for this action is provided by the CAA, as
amended, 42 U.S.C. 7401 et seq. Section 110(a)(2)(D) of the CAA, often
referred to as the ``good neighbor'' provision of the Act, and requires
states to prohibit certain emissions because of their impact on air
quality in downwind states. Specifically, it requires all states,
within 3 years of promulgation of a new or revised NAAQS, to submit
SIPs that prohibit certain emissions of air pollutants because of the
impact they would have on air quality in other states. 42 U.S.C.
7410(a)(2)(D). This action addresses the requirement in section
110(a)(2)(D)(i)(I) regarding the prohibition of emissions within a
state that will significantly contribute to nonattainment or interfere
with maintenance of the NAAQS in any other
[[Page 48217]]
state. EPA has previously issued two rules interpreting and clarifying
the requirements of section 110(a)(2)(D)(i)(I). The NOX SIP
Call, promulgated in 1998, was largely upheld by the U.S. Court of
Appeals for the DC Circuit in Michigan, 213 F.3d 663. CAIR, promulgated
in 2005, was remanded by the DC Circuit in North Carolina, 531 F.3d
896, modified on reh'g, 550 F.3d. 1176. These decisions provide
additional guidance regarding the requirements of section
110(a)(2)(D)(i)(I) and are discussed later in this notice.
Section 301(a)(1) of the CAA also gives the Administrator of EPA
general authority to prescribe such regulations as are necessary to
carry out her functions under the Act. 42 U.S.C. 7601(a)(1). Pursuant
to this section, EPA has authority to clarify the applicability of CAA
requirements. In this action, among other things, EPA is clarifying the
applicability of section 110(a)(2)(D)(i)(I) by identifying
SO2 and NOX emissions that must be prohibited
pursuant to this section with respect to the PM2.5 NAAQS
promulgated in 1997 and 2006 and the 8-hour ozone NAAQS promulgated in
1997.
Section 110(c)(1) requires the Administrator to promulgate a FIP at
any time within 2 years after the Administrator finds that a state has
failed to make a required SIP submission, finds a SIP submission to be
incomplete or disapproves a SIP submission unless the state corrects
the deficiency, and the Administrator approves the SIP revision, before
the Administrator promulgates a FIP. 42 U.S.C. 7410(c)(1).
Tribes are not required to submit state implementation plans.
However, as explained in EPA's regulations outlining Tribal Clean Air
Act authority, EPA is authorized to promulgate FIPs for Indian country
as necessary or appropriate to protect air quality if a tribe does not
submit and get EPA approval of an implementation plan. See 40 CFR
49.11(a); see also 42 U.S.C. section 7601(d)(4).
Section 110(k)(6) of the CAA gives the Administrator authority,
without any further submission from a state, to revise certain prior
actions, including actions to approve SIPs, upon determining that those
actions were in error.
B. Rulemaking History
The Transport Rule FIPs will limit the interstate transport of
emissions of NOX and SO2 within 27 states in the
eastern, midwestern, and southern United States that affect the ability
of downwind states to attain and maintain compliance with the 1997 and
2006 PM2.5 NAAQS and the 1997 ozone NAAQS.\10\ Prior to this
Transport Rule, CAIR was EPA's most recent regulatory action in a
longstanding series of regulatory initiatives to address interstate
transport of air pollution. The proposed Transport Rule preamble
provides more information on EPA actions prior to CAIR (75 FR 45221-
45225).
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\10\ As discussed in section III of this preamble, EPA is
proposing to apply ozone-season NOX requirements to
additional states. If EPA finalizes that action as proposed, the
total number of states covered by the Transport Rule FIPs would be
28.
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CAIR, promulgated May 12, 2005 (70 FR 25162), required 29 states to
adopt and submit revisions to their SIPs to eliminate SO2
and NOX emissions that contribute significantly to downwind
nonattainment of the PM2.5 and ozone NAAQS promulgated in
1997. The states covered by CAIR were similar but not identical to the
states covered by the Transport Rule. The CAIR FIPs, promulgated April
26, 2006 (71 FR 25328), regulated electric generating units in the
covered states and achieved CAIR's emission reduction requirements
unless or until states had approved SIPs to achieve the required
reductions.
In July 2008, the DC Circuit Court found CAIR and the CAIR FIPs
unlawful and vacated CAIR. North Carolina, 531 F.3d at 929-30. However,
the Court subsequently remanded CAIR to EPA without vacatur in order to
``at least temporarily preserve the environmental values covered by
CAIR.'' North Carolina, 550 F.3d at 1178. CAIR requirements have
remained in place and CAIR's emission trading programs have operated
while EPA developed replacement rules in response to the remand.
By promulgating the Transport Rule FIPs, EPA is responding to the
Court's remand of CAIR and the CAIR FIPs and replacing those rules. The
approaches EPA used in the Transport Rule to measure and address each
state's significant contribution to downwind nonattainment and
interference with maintenance are guided by and consistent with the
Court's opinion in North Carolina and address the flaws in CAIR
identified by the Court therein.
By notice of proposed rulemaking (Federal Implementation Plans To
Reduce Interstate Transport of Fine Particulate Matter and Ozone, 75 FR
45210; August 2, 2010), EPA proposed the Transport Rule to identify and
limit NOX and SO2 emissions within 32 states in
the eastern, midwestern, and southern United States that affect the
ability of downwind states to attain and maintain compliance with the
1997 and 2006 PM2.5 NAAQS and the 1997 ozone NAAQS. EPA
proposed to achieve the emission reductions under FIPs, which states
may choose to replace by submitting SIPs for EPA approval. EPA proposed
to limit emissions by regulating electric generating units in the 32
states with interstate emission trading programs and assurance
provisions to ensure the required reductions occur in each covered
state. EPA also requested comment on two alternative FIP remedies.
EPA supplemented the Transport Rule record with additional
information relevant to the rulemaking in three NODAs for which EPA
requested comments:
Notice of Data Availability Supporting Federal
Implementation Plans to Reduce Interstate Transport of Fine Particulate
Matter and Ozone (75 FR 53613; September 1, 2010). This NODA provided
an updated database of unit-level characteristics of EGUs included in
EPA modeling, an updated version of the power sector modeling platform
EPA used to support the final rule, and other input assumptions and
data EPA provided for public review and comment.
Notice of Data Availability Supporting Federal
Implementation Plans To Reduce Interstate Transport of Fine Particulate
Matter and Ozone: Revisions to Emission Inventories (75 FR 66055;
October 27, 2010). This NODA provided additional information relevant
to the rulemaking, including updated emission inventory data for 2005,
2012 and 2014 for several stationary and mobile source inventory
components.
Notice of Data Availability for Federal Implementation
Plans To Reduce Interstate Transport of Fine Particulate Matter and
Ozone: Request for Comment on Alternative Allocations, Calculation of
Assurance Provision Allowance Surrender Requirements, New-Unit
Allocations in Indian Country, and Allocations by States (76 FR 1109;
January 7, 2011). This NODA provided additional information relevant to
the rulemaking, including emissions allowance allocations for existing
units calculated using two alternative methodologies, data supporting
those calculations, information about an alternative approach to
calculation of assurance provision allowance surrender requirements,
allocations for new units locating in Indian country in Transport Rule
states in the future, and provisions for states to submit SIPs
providing for state allocation of allowances in the Transport Rule
trading programs.
[[Page 48218]]
C. Air Quality Problems and NAAQS Addressed
1. Air Quality Problems and NAAQS Addressed
a. Fine Particles
Fine particles are associated with a number of serious health
effects including premature mortality, aggravation of respiratory and
cardiovascular disease (as indicated by increased hospital admissions,
emergency room visits, health-related absences from school or work, and
restricted activity days), lung disease, decreased lung function,
asthma attacks, and certain cardiovascular problems. In addition to
effects on public health, fine particles are linked to a number of
public welfare effects, including (1) Reduced visibility (haze) in
scenic areas, (2) effects caused by particles settling on ground or
water, such as: making lakes and streams acidic, changing the nutrient
balance in coastal waters and large river basins, depleting the
nutrients in soil, damaging sensitive forests and farm crops, and
affecting the diversity of ecosystems, and (3) staining and damaging of
stone and other materials, including culturally important objects such
as statues and monuments.
In 1997, EPA revised the NAAQS for PM to add new annual and 24-hour
standards for fine particles, using PM2.5 as the indicator
(62 FR 38652). These revisions established an annual standard of 15
[mu]g/m\3\ and a 24-hour standard of 65 [mu]g/m\3\. During 2006, EPA
revised the air quality standards for PM2.5. The 2006
standards decreased the level of the 24-hour fine particle standard
from 65 [mu]g/m\3\ to 35 [mu]g/m\3\, and retained the annual fine
particle standard at 15 [mu]g/m\3\.
b. Ozone
Short-term (1- to 3-hour) and prolonged (6- to 8-hour) exposures to
ambient ozone have been linked to a number of adverse health effects.
At sufficient concentrations, short-term exposure to ozone can irritate
the respiratory system, causing coughing, throat irritation, and chest
pain. Ozone can reduce lung function and make it more difficult to
breathe deeply. Breathing may become more rapid and shallow than
normal, thereby limiting a person's normal activity. Ozone also can
aggravate asthma, leading to more asthma attacks that may require a
doctor's attention and the use of additional medication. Increased
hospital admissions and emergency room visits for respiratory problems
have been associated with ambient ozone exposures. Longer-term ozone
exposure can inflame and damage the lining of the lungs, which may lead
to permanent changes in lung tissue and irreversible reductions in lung
function. A lower quality of life may result if the inflammation occurs
repeatedly over a long time period (such as months, years, or a
lifetime). There is also epidemiological evidence indicating a
correlation between short-term ozone exposure and premature mortality.
In addition to causing adverse health effects, ozone affects
vegetation and ecosystems, leading to reductions in agricultural crop
and commercial forest yields; reduced growth and survivability of tree
seedlings; and increased plant susceptibility to disease, pests, and
other environmental stresses (e.g., harsh weather). In long-lived
species, these effects may become evident only after several years or
even decades and have the potential for long-term adverse impacts on
forest ecosystems. Ozone damage to the foliage of trees and other
plants can also decrease the aesthetic value of ornamental species used
in residential landscaping, as well as the natural beauty of our
national parks and recreation areas. In 1997, at the same time we
revised the PM2.5 standards, EPA issued its final action to
revise the NAAQS for ozone (62 FR 38856) to establish new 8-hour
standards. In this action published on July 18, 1997, we promulgated
identical revised primary and secondary ozone standards that specified
an 8-hour ozone standard of 0.08 parts per million (ppm). Specifically,
the standards require that the 3-year average of the fourth highest 24-
hour maximum 8-hour average ozone concentration may not exceed 0.08
ppm. In general, the 8-hour standards are more protective of public
health and the environment and more stringent than the pre-existing 1-
hour ozone standards.
On March 12, 2008, EPA published a revision to the 8-hour ozone
standard, lowering the level from 0.08 ppm to 0.075 ppm. On September
16, 2009, EPA announced it would reconsider these 2008 ozone standards.
The purpose of the reconsideration is to ensure that the ozone
standards are clearly grounded in science, protect public health with
an adequate margin of safety, and are sufficient to protect the
environment. EPA proposed revisions to the standards on January 19,
2010 (75 FR 2938) and anticipates issuing final standards soon.
c. Which NAAQS does this rule address?
This action addresses the requirements of CAA section
110(a)(2)(D)(i)(I) as they relate to:
(1) The 1997 annual PM2.5 standard,
(2) The 2006 24-hour PM2.5 standard, and
(3) The 1997 ozone standard.
The original CAIR and CAIR FIP rules, which pre-dated the 2006
PM2.5 standards, addressed the 1997 ozone and 1997
PM2.5 standards only.
In this action, EPA fully addresses, for the states covered by this
rule, the requirements of CAA section 110(a)(2)(D)(i)(I) for the annual
PM2.5 standard of 15 [mu]g/m\3\ and the 24-hour standard of
35 [mu]g/m\3\. For the 1997 8-hour ozone standard of 0.08 ppm, EPA
fully addresses the CAA section 110(a)(2)(D)(i)(I) requirements for
some states covered by this rule, but for the remaining states EPA is
conducting further analysis to determine whether further requirements
are needed, as discussed in section III of this preamble.
This action does not address the CAA section 110(a)(2)(D)(i)(I)
requirements for the revised ozone standards promulgated in 2008. These
standards are currently under reconsideration. We are, however,
actively conducting the technical analyses and other work needed to
address interstate transport for the reconsidered ozone standard as
soon as possible. We intend to issue as soon as possible a proposal to
address the transport requirements with respect to the reconsidered
standard.
This action addresses these CAA transport requirements through
reductions in annual emissions of SO2 and NOX,
and through reductions in ozone-season NOX. The rationale
for these reductions is discussed in detail later in the preamble.
d. Public Comments
EPA received comments on two issues related to the NAAQS regulated
under the proposed FIPs.
A number of commenters believed that EPA's approach to ozone was
inadequate, and that EPA should not have based the proposed
requirements on the 1997 ozone NAAQS. These commenters cited EPA's 2008
revision to the standard which lowered the standard to 75 ppb, and
noted that EPA's January 2010 proposal for reconsidered ozone NAAQS
would, if finalized, further lower the primary NAAQS from 75 ppb to a
value between 60 and 70 ppb. Accordingly, many of the commenters
believed that EPA should have considered the 75 ppb level to be the
maximum possible value moving forward, and that EPA should have used a
value no greater than 75 ppb in its analysis.
EPA agrees with commenters that EPA and states should address
interstate transport with respect to the tighter
[[Page 48219]]
ozone NAAQS as quickly as possible. EPA, as commenters noted, intends
to propose a second rule to address interstate transport of ozone that
will be appropriately configured for the revised level of the ozone
NAAQS after reconsideration of the 2008 standard is finalized. EPA is
mindful of the need for SIPs to provide for continuing ozone progress
to meet the 75 ppb level of the 2008 NAAQS, or possibly lower levels
based on the reconsideration. EPA believes that the ozone-season
NOX requirements of this rule will provide important initial
assistance to states in this regard.
Some commenters questioned whether EPA had given states the
opportunity to provide SIPs addressing transport under the 2006
PM2.5 NAAQS, and thus questioned the appropriateness of the
issuance of FIPs addressing those NAAQS. Those comments, and EPA's
response, are discussed in detail in section IV.C.2.
2. FIP Authority for Each State and NAAQS Covered
The CAA requires and authorizes EPA to promulgate each of the
Federal Implementation Plans in this final rule. Section 110(c)(1) of
the CAA requires the Administrator to promulgate a FIP at any time
within 2 years after the Administrator takes one of three distinct
actions: (1) She finds that a state has failed to make a required SIP
submission; (2) she finds a SIP submission to be incomplete; or (3) she
disapproves a SIP submission. Once the Administrator has taken one of
these actions with respect to a specific state's 110(a)(2)(D)(i)(I)
obligation for a specific NAAQS, she has a legal obligation to
promulgate a FIP to correct the SIP deficiency within 2 years. EPA is
relieved of the obligation to promulgate a FIP only if two events occur
before the FIP is promulgated: (1) The state submits a SIP correcting
the deficiency; and (2) the Administrator approves the SIP revision. 42
U.S.C. 7410(c)(1).\11\
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\11\ The CAA provides that EPA is not relieved of its obligation
to promulgate FIPs unless the state submits a SIP that corrects the
deficiency and EPA approves the SIP. Nonetheless, in the preamble to
the proposed rule, EPA indicated that for states not covered by CAIR
which had 110(a)(2)(D)(i)(I) SIPs pending at the time of proposal,
EPA would finalize the FIP only if EPA determined the submission was
incomplete or disapproved the SIP submission. The only two states
covered by this rule but not covered by CAIR are Kansas and
Nebraska. Both Kansas and Nebraska are covered by this rule based
only on their significant contribution to nonattainment or
interference with maintenance of the 2006 PM2.5 NAAQS.
EPA has not received a 110(a)(2)(D)(i)(I) submission from Nebraska
with respect to the requirements of the 2006 PM2.5 NAAQS.
EPA disapproved a SIP submission from Kansas with respect to the
requirements of 110(a)(2)(D)(i)(I) for the 2006 PM2.5
NAAQS.
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For each FIP in this rule,\12\ EPA either has found that the state
has failed to make a required 110(a)(2)(D)(i)(I) SIP submission, or has
disapproved a SIP submission.\13\ In addition, EPA has determined, in
each case, that there has been no approval by the Administrator of a
SIP submission correcting the deficiency prior to promulgation of the
FIP. EPA's obligation to promulgate a FIP arose when the finding of
failure to submit or disapproval was made, and in no case has it been
relieved of that obligation.
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\12\ In this action, EPA is issuing 59 FIPs. EPA is issuing 20
FIPs to remedy SIP deficiencies relating to the 110(a)(2)(D)(i)(I)
requirements for the 1997 ozone NAAQS. EPA is also issuing 18 FIPs
to remedy SIP deficiencies relating to the 1997 PM2.5
NAAQS. Finally, EPA is issuing 21 FIPs to remedy SIP deficiencies
relating to the 2006 PM2.5 NAAQS.
\13\ The specific findings made and actions taken by EPA are
described in greater detail in the TSD entitled ``Status of CAA
110(a)(2)(D)(i)(I) SIPs.''
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Some commenters argued that EPA was relieved of its obligation to
promulgate FIPs when it approved the CAIR SIPs for certain states. As
an initial matter, EPA notes that this argument applies only to EPA's
authority to promulgate FIPs with respect to the 1997 PM2.5
and/or 1997 ozone NAAQS for a subset of states covered by the CAIR. It
does not apply to EPA's authority to promulgate FIPs for the 2006
PM2.5 NAAQS which was not addressed in CAIR. It also does
not apply to EPA's authority to promulgate FIPs for the 1997 ozone and
1997 PM2.5 NAAQS for states that remain subject to the CAIR
FIPs, including the states that received EPA approval of abbreviated
CAIR SIPs which allowed the states to allocate allowances while
remaining subject to the CAIR FIPs.\14\
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\14\ States may also have received approval to expand the
applicability of the CAIR NOX ozone season program to
include all units subject to the NOX Budget Program,
allow opt-ins, or provide for distribution of a Compliance
Supplement Pool under the CAIR NOX (annual) program.
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Further, the CAIR SIP approvals do not eliminate EPA's obligation
and authority to promulgate a FIP to address the requirements of
110(a)(2)(D)(i)(I) because the Court in North Carolina v. EPA, 531 F.3d
896 (D.C. Cir. 2008) found that compliance with CAIR does not satisfy
the requirement that each state prohibit all emissions within the state
that significantly contribute to nonattainment or interfere with
maintenance in another state. The Court's finding that CAIR was
unlawful because it did not make measureable progress towards the
statutory mandate of section 110(a)(2)(D)(i)(I) meant that the CAIR
SIPs were not adequate to satisfy that mandate. The CAIR SIPs thus do
not correct the SIP deficiencies identified in the 2005 findings of
failure to submit. The SIPs remained in force for the limited purpose
allowed by the Court--that is, to achieve interim reductions until EPA
promulgated a rule to replace CAIR. Given the flaws the court
identified with CAIR, EPA's approval of a CAIR SIP does not relieve it
of the obligation to promulgate FIPs created under section 110(c)(1) of
the CAA.
Further, to avoid any confusion, EPA has decided to correct, in
this notice, the full CAIR SIP approvals for states covered by this
rule and the CAA 110(a)(2)(D)(i) SIP approvals for states covered by
CAIR to rescind any statements suggesting that the SIP submissions
satisfied or relieved states of the obligation to submit SIPs to
satisfy the requirements of section 110(a)(2)(D)(i)(I) or that EPA was
relieved of its obligation and authority to promulgate FIPs under
110(a)(2)(D)(I)(i).
Some commenters further argued that states should be given
additional time, following promulgation of the Transport Rule, to
submit a SIP to meet the requirements of section 110(a)(2)(D)(i)(I) and
that CAIR should remain in place in the meantime. Some commenters
specifically suggested that EPA restart the ``FIP clock'' \15\ to give
states this additional time. EPA does not interpret the CAA as giving
it authority to extend the deadline for SIP submissions or restart the
FIP clock. And nothing in the Act requires EPA to give the states
another opportunity, following promulgation of the Transport Rule, to
promulgate a SIP before EPA promulgates a FIP. The plain language of
section 110(a)(1) of the Act requires the submission of SIPs that meet
the requirements of 110(a)(2)(D)(i)(I) within 3 years after the
promulgation of or revision of a primary NAAQS. See 42 U.S.C.
7410(a)(1). Section 110(a)(2)(D)(i)(I) SIPs for the 1997 ozone and
PM2.5 NAAQS were due in 2000 and 110(a)(2)(D)(i)(I) SIPs for
the 2006 PM2.5 NAAQS were due in 2009. While the statute
gives EPA authority to prescribe a shorter period of time for states to
make these SIP submissions, it does not give EPA authority to extend
the 3-year deadline established by the Act. See 42 U.S.C. 7410(a)(1).
The plain language of section 110(c)(1) of the Act, in turn, provides
that EPA shall promulgate a FIP at any time within 2 years after the
Administrator makes a finding of failure to make a required SIP
[[Page 48220]]
submission of disapproves, in whole or in part, a SIP submission. See
42 U.S.C. 7410(c)(1). EPA does not have authority to set aside the
specific deadlines established in the statute, and neither provision
allows for the deadlines to be extended or to run from promulgation by
EPA of a rule to quantify the state's specific obligations pursuant to
section 110(a)(2)(D)(i)(I). The Act does not require EPA to promulgate
a rule or issue guidance regarding the specific requirements of section
110(a)(2)(D)(i)(I) in advance of the SIP submittal deadline, much less
require EPA to promulgate such a rule a specific amount of time before
the SIP submittal deadline. For these reasons, EPA has neither
authority to alter the SIP submittal deadline nor authority to alter
the statute provision regarding when EPA's obligation to promulgate a
FIP is triggered.
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\15\ ``FIP clock'' is a term used to describe EPA's
responsibility found in CAA Section 110(c)(1) to promulgate a FIP
within 2 years after either: Finding that a state has not submitted
a required SIP revision or that a submitted SIP revision is
incomplete; or disapproving a SIP revision.
---------------------------------------------------------------------------
Finally, EPA does not believe it would be appropriate, in light of
the Court's decision in North Carolina, to establish a lengthy
transition period to the rule that will replace CAIR. The Court
decision remanding CAIR without vacatur stressed the court's conclusion
that CAIR was deeply flawed and emphasized EPA's obligation to remedy
those flaws expeditiously. North Carolina, 550 F.3d 1176. Although the
Court did not set a specific deadline for corrective action, the Court
took care to note that the effect of its opinion would not be delayed
``indefinitely'' and that petitioners could bring a mandamus petition
if EPA were to fail to modify CAIR in a manner consistent with its
prior opinion. Id. Given the Court's emphasis on remedying CAIR's flaws
expeditiously, EPA does not believe it would be appropriate to
establish a lengthy transition period to the rule which is to replace
CAIR.
3. Additional Information Regarding CAA Section 110(a)(2)(D)(i)(I) SIPs
for States in the Transport Rule Modeling Domain
This final rule quantifies out-of-state contributions for the 38
states that are fully contained within the 12 kilometers (km) eastern
U.S. modeling domain. EPA is making no specific finding for states that
are not fully contained within the eastern 12 km modeling domain. EPA
did not conduct a contribution analysis or make any specific finding
for New Mexico, Colorado, Wyoming, and Montana since they are only
partially contained within the 12 km modeling domain. With regard to
the 1997 PM2.5 NAAQS and 2006 PM2.5 NAAQS, EPA
believes that states that are included in this 38 state modeling domain
will meet their section 110(a)(2)(D)(i)(I) obligations to address the
``significant contribution'' and ``interference with maintenance''
requirements by complying with the requirements in this rule. With
regard to the 1997 ozone NAAQS, EPA believes that states that are
included in this 38 state modeling domain will meet their section
110(a)(2)(D)(i)(I) obligations to address the ``significant
contribution'' and ``interference with maintenance'' requirements by
complying with the requirements in this rule, except for the 10 states
found to significantly contribute to nonattainment or interference of
maintenance in either Houston or Baton Rouge (i.e., Alabama, Arkansas,
Georgia, Illinois, Indiana, Kentucky, Louisiana, Mississippi,
Tennessee, and Texas). States that are in the 38 state modeling domain,
and that are not found to be contributing significantly to
nonattainment or interfering with maintenance for any NAAQS evaluated
in the modeling for the final rule, could rely on this analysis as
technical support that their existing or future interstate transport
SIP submittals are adequate to address the transport requirements of
110(a)(2)(D)(i)(I). For example, this rule finds that South Carolina
significantly contributes to nonattainment and interferes with
maintenance of the 1997 ozone NAAQS and the 1997 PM2.5 NAAQS
in downwind states. The technical support for the rule does not show
that South Carolina significantly contributes to nonattainment or
interferes with maintenance of the 2006 PM2.5 NAAQS in
downwind states. EPA believes that South Carolina can make a negative
declaration concluding that the state does not significantly contribute
to nonattainment or interfere with maintenance in other states with
regard to the 2006 PM2.5 NAAQS.
D. Correction of CAIR SIP Approvals
In this action, EPA is also correcting its prior approvals of CAIR
related SIP submissions and CAA 110(a)(2)(D)(i) SIP submissions from
Alabama, Arkansas, Connecticut, Florida, Georgia, Illinois, Indiana,
Iowa, Kentucky, Louisiana, Maryland, Massachusetts, Minnesota,
Mississippi, Missouri, New York, North Carolina, Ohio, Pennsylvania,
South Carolina, Virginia and West Virginia to rescind any statements
that the SIP submissions either satisfy or relieve the state of the
obligation to submit a SIP to satisfy the requirements of section
110(a)(2)(D)(i)(I) with respect to the 1997 ozone and/or 1997
PM2.5 NAAQS or any statements that EPA's approval of the SIP
submissions either relieve EPA of the obligation to promulgate a FIP or
remove EPA's authority to promulgate a FIP. This action is based on
EPA's determination that those SIP approvals were in error to the
extent they provided explicitly or implicitly that compliance with CAIR
satisfies the requirements of 110(a)(2)(D)(i)(I) with respect to the
1997 ozone and 1997 PM2.5 NAAQS. The July 2008 decision of
the DC Circuit held, among other things, that the CAIR rule did not
``achieve[] something measureable toward the goal of prohibiting
sources `within the State' from contributing to nonattainment or
interfering with maintenance in `any other State.''' North Carolina,
531 F.3d 908; see also, e.g., id. at 916 (EPA not exercising its
authority to make measureable progress towards the goals of section
110(a)(2)(D)(i)(I) because the emission budgets were insufficiently
related to the statutory mandate). EPA's actions to approve CAIR SIP
submittals as satisfying the requirements of section
110(a)(2)(D)(i)(I), based on the flawed determination in CAIR that
compliance with CAIR satisfied those statutory requirements, were thus
in error as were the separate actions taken to approve section
110(a)(2)(D)(i)(I) submissions that relied wholly or in part on CAIR.
The approval for Alabama titled ``Approval and Promulgation of
Implementation Plans; Alabama; Clean Air Interstate Rule'' which is
hereby corrected was originally published in the Federal Register on
October 1, 2007 (72 FR 55659).
The approval for Arkansas titled ``Approval and Promulgation of
Implementation Plans; Arkansas; Clean Air Interstate Rule Nitrogen
Oxides Ozone Season Trading Program'' which is hereby corrected was
originally published in the Federal Register on September 26, 2007 (72
FR 54556).
The approval for Connecticut titled ``Approval and Promulgation of
Air Quality Implementation Plans; Connecticut; State Implementation
Plan Revision to Implement the Clean Air Interstate Rule'' which is
hereby corrected was originally published in the Federal Register on
January 24, 2008 (73 FR 4105) and the approval for Connecticut titled
``Approval and Promulgation of Air Quality Implementation Plans;
Connecticut; Interstate Transport of Pollution'' which is hereby
corrected was originally published in the Federal Register on May 7,
2008 (73 FR 25516).
The approval for Florida titled ``Approval and Promulgation of
Implementation Plans; Florida; Clean Air Interstate Rule'' which is
hereby corrected was originally published in the Federal Register on
October 12, 2007 (72 FR 58016).
[[Page 48221]]
The approval for Georgia titled ``Approval and Promulgation of
Implementation Plans; Georgia; Clean Air Interstate Rule'' which is
hereby corrected was originally published in the Federal Register on
October 9, 2007 (72 FR 57202).
The approval for Illinois titled ``Approval of Implementation Plans
of Illinois: Clean Air Interstate Rule'' which is hereby corrected was
originally published in the Federal Register on October 16, 2007 (72 FR
58528).
The approval for Indiana titled ``Limited Approval of
Implementation Plans of Indiana: Clean Air Interstate Rule'' which is
hereby corrected was originally published in the Federal Register on
October 22, 2007 (72 FR 59480) and the approval for Indiana titled
``Approval and Promulgation of Air Quality Implementation Plans;
Indiana; Clean Air Interstate Rule'' which is hereby corrected was
originally published in the Federal Register on November 29, 2010 (75
FR 72956).
The approval for Iowa titled ``Approval and Promulgation of
Implementation Plans; Iowa; Clean Air Interstate Rule'' which is hereby
corrected was originally published in the Federal Register on August 6,
2007 (72 FR 43539) and the approval for Iowa titled ``Approval and
Promulgation of Implementation Plans; Iowa; Interstate Transport of
Pollution'' which is hereby corrected was originally published in the
Federal Register on March 8, 2007 (72 FR 10380).
The approval for Kentucky titled ``Approval of Implementation Plans
of Kentucky: Clean Air Interstate Rule'' which is hereby corrected was
originally published in the Federal Register on October 4, 2007 (72 FR
56623).
The approval for Louisiana titled ``Approval and Promulgation of
Implementation Plans; Louisiana; Clean Air Interstate Rule Sulfur
Dioxide Trading Program'' which is hereby corrected was originally
published in the Federal Register on July 20, 2007 (72 FR 39741) and
the approval for Louisiana titled ``Approval and Promulgation of
Implementation Plans; Louisiana; Clean Air Interstate Rule Nitrogen
Oxides Trading Program'' which is hereby corrected was originally
published in the Federal Register on September 28, 2007 (72 FR 55064).
The approval for Maryland titled ``Approval and Promulgation of Air
Quality Implementation Plans; Maryland; Clean Air Interstate Rule''
which is hereby corrected was originally published in the Federal
Register on October 30, 2009 (74 FR 56117).
The approval for Massachusetts titled ``Approval and Promulgation
of Air Quality Implementation Plans; Massachusetts; State
Implementation Plan Revision to Implement the Clean Air Interstate
Rule'' which is hereby corrected was originally published in the
Federal Register on December 3, 2007 (72 FR 67854).
The approval for Minnesota titled ``Approval and Promulgation of
Air Quality Implementation Plans; Minnesota; Interstate Transport of
Pollution'' which is hereby corrected was originally published in the
Federal Register on June 2, 2008 (73 FR 31366).
The approval for Mississippi titled ``Approval and Promulgation of
Implementation Plans; Mississippi: Clean Air Interstate Rule'' which is
hereby corrected was originally published in the Federal Register on
October 3, 2007 (72 FR 56268).
The approval for Missouri titled ``Approval and Promulgation of
Implementation Plans; Missouri; Clean Air Interstate Rule'' which is
hereby corrected was originally published in the Federal Register on
December 14, 2007 (72 FR 71073) and the approval of Missouri titled
``Approval and Promulgation of Implementation Plans; Missouri;
Interstate Transport of Pollution'' which is hereby corrected was
originally published in the Federal Register on May 8, 2007 (75 FR
25975).
The approval for New York titled ``Approval and Promulgation of
Implementation Plans; New York: Clean Air Interstate Rule'' which is
hereby corrected was originally published in the Federal Register on
January 24, 2008 (73 FR 4109).
The approval for North Carolina titled ``Approval of Implementation
Plans; North Carolina: Clean Air Interstate Rule'' which is hereby
corrected was originally published in the Federal Register on October
5, 2007 (72 FR 56914) and the approval for North Carolina titled
``Approval and Promulgation of Air Quality Implementation Plans; North
Carolina; Clean Air Interstate Rule'' which is hereby corrected was
originally published in the Federal Register on November 30, 2009 (74
FR 62496).
The approval for Ohio titled ``Approval and Promulgation of Air
Quality Implementation Plans; Ohio; Clean Air Interstate Rule'' which
is hereby corrected was originally published in the Federal Register on
February 1, 2008 (73 FR 6034) and the approval for Ohio titled
``Approval and Promulgation of Air Quality Implementation Plans; Ohio;
Clean Air Interstate Rule'' which is hereby corrected was originally
published in the Federal Register on September 25, 2009 (74 FR 48857).
The approval for Pennsylvania titled ``Approval and Promulgation of
Air Quality Implementation Plans; Pennsylvania; Clean Air Interstate
Rule; NOX SIP Call Rule; Amendments to NOX
Control Rules'' which is hereby corrected was originally published in
the Federal Register on December 10, 2009 (74 FR 65446).
The approval for South Carolina titled ``Approval of Implementation
Plans of South Carolina: Clean Air Interstate Rule'' which is hereby
corrected was originally published in the Federal Register on October
9, 2007 (72 FR 57209) and the approval for South Carolina titled
``Approval and Promulgation of Air Quality Implementation Plans; South
Carolina; Clean Air Interstate Rule'' which is hereby corrected was
originally published in the Federal Register on October 16, 2009 (74 FR
53167).
The approval for Virginia titled ``Approval and Promulgation of Air
Quality Implementation Plans; Virginia; Clean Air Interstate Rule
Budget Trading Programs'' which is hereby corrected was originally
published in the Federal Register on December 28, 2007 (72 FR 73602).
The approval for West Virginia titled ``Approval and Promulgation
of Air Quality Implementation Plans; West Virginia; Clean Air
Interstate Rule'' which is hereby corrected was originally published in
the Federal Register on December 18, 2007 (72 FR 71576) and the
approval for West Virginia titled ``Approval and Promulgation of Air
Quality Implementation Plans; West Virginia; Clean Air Interstate
Rule'' which is hereby corrected was originally published in the
Federal Register on August 4, 2009 (74 FR 38536).
EPA is taking this final action without prior opportunity for
notice and comment because EPA finds, for good cause, that notice and
public procedure thereon are unnecessary and not in the public
interest. Section 553(b)(B) of the Administrative Procedure Act
provides that the notice and comment requirements in section 553 do not
apply when the agency for good cause finds that notice and public
procedure there on are impracticable, unnecessary, or contrary to the
public interest. 5 U.S.C. 553(b)(B). Section 307(d)(1) of the CAA in
turn provides that the requirements of section 307(d) do not apply in
the case of a rule or circumstance referred to in section 553(b)(A) or
section 553(b)(B) of the Administrative Procedure Act in Title 5. 42
U.S.C. 7607(1).
EPA finds that notice and public procedure are unnecessary because
EPA has no discretion given the specific
[[Page 48222]]
circumstances presented in this case. EPA is bound by the decisions of
the courts and must act in accordance with those decisions. EPA must
accept the Court's conclusion that compliance with CAIR does not
satisfy the requirements of CAA section 110(a)(2)(D)(i)(I) and lacks
discretion to reach a different conclusion. This correction is a
ministerial matter consistent with the decisions of the courts. For
these reasons, it is unnecessary to provide an opportunity for notice
and comment.
V. Analysis of Downwind Air Quality and Upwind State Emissions
A. Pollutants Regulated
To address interstate transport of air pollution, EPA must choose
which pollutants to regulate relevant to significant contribution to
nonattainment or interference with maintenance of the NAAQS of concern
downwind. This section of the preamble discusses the pollutants
regulated under the final Transport Rule.
1. Background
Based on scientific and technical information, as well as EPA's air
quality modeling, EPA concluded for CAIR that the most effective
approach to reducing the contribution of interstate transport to
PM2.5 was to control SO2 and NOX
emissions. For CAIR, EPA did not limit emissions of other components of
PM2.5, noting that ``current information relating to sources
and controls for other components identified in transported
PM2.5 (carbonaceous particles, ammonium, and crustal
materials) does not, at this time, provide an adequate basis for
regulating the regional transport of emissions responsible for these
PM2.5 components'' (69 FR 4582).
With respect to ozone transport, EPA has previously concluded that
it is proper to control ozone-season NOX emissions. For CAIR
and the NOX SIP Call programs, EPA based this conclusion on
the assessment of ozone transport conducted by the Ozone Transport
Assessment Group (OTAG) in the mid-1990s. The OTAG Regional and Urban
Scale Modeling and Air Quality Analysis Work Groups concluded that
regional NOX emission reductions are effective in producing
ozone benefits that grow with increasing regional NOX
abatement.
The relative importance of NOX and VOC in ozone
formation and control varies with local and time-specific factors,
including the relative amounts of VOC and NOX present. In
rural areas and many urban areas with high concentrations of VOC from
biogenic sources, ozone formation and control is governed by
NOX. In some urban core situations, NOX
concentrations can be high enough relative to VOC to suppress ozone
formation locally, but still contribute to increased ozone downwind
from the city. In such situations, VOC reductions are most effective at
reducing ozone within the urban environment and immediately downwind.
The formation of ozone increases with temperature and sunlight, which
is one reason ozone levels are higher during the summer. Increased
temperature also increases emissions of volatile man-made and biogenic
organics and can indirectly increase NOX as well (e.g.,
increased electricity generation for air conditioning). Summertime
conditions also bring increased episodes of large scale stagnation of
air masses, which promote the build-up of direct emissions and
pollutants formed through atmospheric reactions over large regions.
Authoritative assessments of ozone control approaches have concluded
that, for reducing regional scale ozone transport, a NOX
control strategy is most effective, whereas VOC reductions are
generally most effective locally, in more dense urbanized areas.
Studies conducted since the 1970s established that ozone occurs on
a regional scale (i.e., thousands of kilometers) over much of the
eastern U.S., with elevated concentrations occurring in rural as well
as metropolitan areas. While substantial progress has been made in
reducing ozone in many urban areas, regional-scale ozone transport is
still an important component of high ozone concentrations during the
extended summer ozone season. A series of more recent progress reports
discussing the effect of the NOX SIP Call reductions can be
found on EPA's Web site at: http://www.epa.gov/airmarkets/progress/progress-reports.html.
More recent assessments of ozone (including those conducted for the
Regulatory Impact Analysis for the ozone standards in 2008) continue to
show the importance of NOX transport as a factor in ozone
formation. For addressing interstate ozone transport in CAIR, EPA
required NOX emission reductions but did not include
requirements for VOCs. EPA believes that VOCs from some upwind states
do indeed have an impact in some nearby downwind states, particularly
over short transport distances. EPA expects that states, typically in
local nonattainment planning, would benefit from examining the extent
to which VOC emissions affect ozone pollution levels within and near
urban nonattainment areas, and states may identify areas where multi-
state VOC strategies might assist in attainment planning for meeting
the 8-hour standard. However, EPA continues to believe that the most
effective regional pollution control strategy for mitigation of
interstate transport of ozone remains NOX emission
reductions.
2. Which pollutants did EPA propose to control for purposes of
PM2.5 and ozone transport?
For the proposed rule, EPA concluded that its findings in CAIR
regarding the nature of pollutant contributions are still appropriate.
EPA proposed to require SO2 and annual NOX
emission reductions to control PM2.5 transport and to
require ozone-season NOX emission reductions to control
ozone transport. In the proposal, EPA discussed and requested comment
on the inclusion of southern states in the annual NOX
program for PM2.5 control.
3. Comments and Responses
EPA received no adverse comments on its proposal to regulate
SO2 for addressing PM2.5 transport, the proposal
not to regulate direct PM2.5 or organic PM2.5
precursors, and the proposal to focus ozone-season efforts on
NOX and not to regulate VOCs.
One commenter questioned EPA's regulation of NOX for
purposes of addressing PM2.5 transport in all states
(including northern states with cooler climates and higher nitrate
deposition). Several commenters, representing southern state air
quality agencies and regulated sources in southern states, disagreed
with EPA's proposed regulation of annual NOX emissions for
all regulated states. These commenters, while not disagreeing with the
need for regulation of SO2, observed that in EPA's modeling
analysis, contributions from certain southern states' NOX
emissions to PM2.5 in downwind states were relatively small.
Accordingly, these commenters argued that either (1) EPA should
remove NOX as a precursor analyzed for PM2.5
contribution from those states, or (2) the required remedy for emission
reductions in those states should not require reductions in annual
NOX.
For the final rule, EPA retains the approach for regulated
pollutants in the proposal, which regulates annual NOX and
SO2 for states affecting downwind state PM2.5
nonattainment and maintenance sites, and ozone-season NOX
for states impacting downwind state ozone nonattainment and
maintenance. EPA considered commenters' requests to remove some states
from the annual NOX program. However, EPA believes that it
is
[[Page 48223]]
appropriate to establish a cap on these states' annual NOX
emissions, in part to ensure the continued annual operation of existing
control equipment that would prevent substantial increases in
NOX emissions. EPA believes that without these reductions,
increased ``nitrate replacement'' could occur, a known atmospheric
phenomenon whereby some of the sulfate reductions due to SO2
emission reductions are eroded by increases in nitrate concentrations
due solely to those SO2 reductions.\16\ This is an
especially pertinent concern for southern states which have significant
impacts on northern receptors in colder climates where nitrate
concentrations are generally higher. For example, Alabama and Tennessee
are both linked to Washtenaw County, MI for 24-hour PM2.5;
North Carolina is linked to Lancaster County, PA for 24-hour
PM2.5; and Texas is linked to Madison County, IL for both
annual and 24-hour PM2.5. All of these downwind areas have
appreciable nitrate deposition contributing to nonattainment and
maintenance concerns for the PM2.5 NAAQS. If the states
linked to those receptors were to make SO2 reductions only,
their beneficial impact on downwind air quality would be partially
eroded by nitrate replacement. EPA therefore believes that it is
reasonable to seek both SO2 and NOX reductions
from states included in the Transport Rule program that are found to
significantly contribute to nonattainment or interfere with maintenance
of the PM2.5 NAAQS in downwind states.
---------------------------------------------------------------------------
\16\ SO2 reductions successfully decrease atmospheric
formation of ammonium sulfate, but in doing so they ``free up'' the
ammonia component that would otherwise have reacted with
SO2 and is now free to react with NOX instead,
causing a ``rebound effect'' partially eroding the improvement in
PM2.5 concentrations. This effect can be mitigated with
tandem NOX reductions.
---------------------------------------------------------------------------
In addition, EPA notes that there would be important disbenefits to
effectively removing CAIR's existing annual NOX requirements
in those states. If EPA were to allow annual NOX emissions
to increase for those states, there would be potentially harmful
effects on visibility, nitrogen deposition, and other aspects of human
and environmental health.
B. Baseline for Pollution Transport Analysis
Implementing the mandate of CAA section 110(a)(2)(D)(i)(I) requires
EPA to determine which states significantly contribute to nonattainment
and interfere with maintenance of the NAAQS in other states, as well as
to quantify the emissions in each state that must be eliminated. This
process begins with an analysis of baseline emissions. Baseline
emissions are the emissions that would occur in each state if EPA did
not promulgate the Transport Rule. To conduct such analysis, EPA
generally takes into account emission limitations that are currently,
and will continue to be, in place. From that baseline, EPA analyzes
whether additional reductions are necessary beyond those already
mandated by existing emission limitation requirements. For example, the
base case used in CAIR reflected the reductions already required by the
NOX SIP Call, which remained in effect even after the CAIR
emission reduction requirements took effect.
The unique legal situation addressed by the Transport Rule
necessarily affects the quantification of baseline emissions.
Specifically, because the Transport Rule will replace CAIR, EPA cannot
consider reductions associated with CAIR in the ``base case'' (i.e.,
analytical baseline emissions scenario). If EPA were to consider all
reductions associated with CAIR in the ``base case,'' the baseline
emissions would not adequately reflect the true 2012 baseline in each
state (i.e., the emissions that would occur in each state in 2012 if
the Transport Rule did not require any reductions in that state).
Similarly, if EPA were to treat the capital investments that have
already been made to meet the requirements of CAIR as new costs rather
than treating them as ``sunk'' capital costs, EPA's analysis would not
accurately reflect the cost of emission reductions required by the
Transport Rule. As explained below, EPA's analysis both properly
considered all capital investments made in response to CAIR and
properly recognized that, after CAIR is terminated, the emission
limitations imposed by CAIR will cease to exist.
In 2005 EPA promulgated CAIR, which required large electric
generating units in 29 states to make phase I emission reductions in
NOX emissions starting in 2009, phase I emission reductions
in SO2 starting in 2010 and phase II reductions in emissions
of both pollutants starting in 2015. On July 11, 2008, the DC Court of
Appeals held that CAIR had ``more than several fatal flaws,'' North
Carolina, 531 F.3d at 901, and remanded and vacated the rule, id. at
930. The Court subsequently granted EPA's petition for rehearing in
part and remanded CAIR without vacatur ``for EPA to conduct further
proceedings consistent with'' the Court's July 11, 2008 opinion. North
Carolina, 550 F.3d 1176. The Court explained that it was ``allowing
CAIR to remain in effect until it is replaced by a rule consistent with
[the July 11, 2008] opinion'' because this ``would at least temporarily
preserve the environmental values covered by CAIR.'' Id. at 1178.
Moreover, the Court stated that it did not ``intend to grant an
indefinite stay of the effectiveness of'' the July 11, 2008 order
vacating CAIR. Id. In summary, the Court determined that CAIR was
fatally flawed and could remain in effect only as a stopgap measure
until EPA could act to replace it.
Thus, unlike most other regulatory requirements (such as the Acid
Rain Program under CAA Title IV, the NOX Budget Trading
Program under the NOX SIP Call, New Source Performance
Standards, and state laws and consent orders requiring emission
reductions), the emission limitations contained in CAIR are only
temporary. Moreover, the duration of these limitations is directly tied
to the Transport Rule. The Transport Rule replaces CAIR. Thus, CAIR
itself will be terminated for the SO2, annual
NOX, and ozone-season NOX control periods
starting in 2012 when the emission limitations established in the final
Transport Rule for those control periods take effect (January 1, 2012
for the annual control periods and May 1, 2012 for the ozone-season
control period). For this reason, emission reductions made to comply
with CAIR cannot be treated as if they were emission reductions
achieved to comply with statutory provisions, rules, consent decrees,
and other enforceable requirements that establish permanent emission
limitations. EPA takes reductions made to comply with permanent
limitations into consideration when quantifying each state's baseline
emissions for the purpose of analyzing whether its emissions
significantly contribute to nonattainment or interfere with maintenance
in another state. However, the unique legal status of CAIR and its
replacement with the Transport Rule distinguish the emission reductions
required by CAIR from those of other regulatory requirements. Since the
limitations and emission reduction requirements in CAIR are temporary
and will be terminated by the Transport Rule, they must be excluded
from the Transport Rule's base case analysis.
Some comments on the Transport Rule proposal claim that EPA's
treatment of CAIR is inconsistent with the treatment, in prior
rulemakings, of the Acid Rain Program and the NOX SIP Call.
Such comments ignore the unique legal status of CAIR, and EPA therefore
rejects these claims.
A simple example illustrates this point. Assume state Z's emissions
before
[[Page 48224]]
CAIR were 2,000 tons and that state Z was required by CAIR to reduce
its emissions to 1,000 tons. If EPA were to determine that state Z's
baseline emissions were 1,000 tons and then conclude, based on that
assumption, that no additional reductions in state Z are necessary
because state Z does not significantly contribute to downwind
nonattainment unless its emissions exceed 1,500 tons, then state Z
would not be covered by the Transport Rule. However, the Transport Rule
will terminate all CAIR requirements in all CAIR states regardless of
whether they are covered by the Transport Rule. Thus, after
promulgation of the Transport Rule, state Z would again be allowed, and
would be projected in this example, to emit 2,000 tons. In other words,
state Z would be allowed to significantly contribute to nonattainment
and/or interfere with maintenance in other states--a result that would
be inconsistent with the statutory mandate of CAA section
110(a)(2)(D)(i)(I). On the other hand, if EPA assumes state Z's
baseline emissions are 2,000 tons as projected without CAIR in place,
EPA can properly determine whether, if state Z were allowed to emit
that amount (i.e., the amount state Z would be projected to emit if
excluded from the Transport Rule), the state would significantly
contribute to nonattainment or interfere with maintenance in any other
state. In other words, EPA can determine the stringency of emission
limitations needed (if any) to replace those that were established by
CAIR in order to ensure that state Z prohibits all emissions that
significantly contribute to nonattainment or interfere with maintenance
in other states.
In fact, commenters' suggestion that the Transport Rule base case
should include CAIR would cause the anomalous result of excluding
sources in a state from the Transport Rule because of their CAIR-
required emission reductions while simultaneously eliminating those
CAIR emission reduction requirements. If EPA's base case analysis were
to assume erroneously that reductions from CAIR would continue
indefinitely, a state currently covered by CAIR, but not covered by the
Transport Rule, would have no CAIR requirements once the Transport Rule
programs began and so could increase emissions beyond the CAIR
limitations. Downwind areas that are in attainment (and are not
experiencing interference with maintenance of such attainment) solely
because of emission reductions required by CAIR could again face
nonattainment or interference with maintenance problems because the
current protection from upwind pollution from such an upwind state
would not be replaced. In short, the analysis of whether a state should
be included in a rule eliminating and replacing CAIR cannot logically
assume that CAIR remains in place. For these reasons, EPA believes it
is reasonable to use a base case that does not assume that the CAIR
reduction requirements will continue to be achieved and so does not
include CAIR-specific emission reductions.
As a result, EPA's 2012 base case shows emissions higher than
current levels in some states. In the absence of the CAIR
SO2 and NOX programs that EPA has been directed
to eliminate and replace, utility emissions in CAIR states will be
limited only by non-CAIR constraints including the Acid Rain Program,
the NOX SIP Call, New Source Performance Standards, any
state laws and consent order requiring emission reductions, and any
other permanent and enforceable binding reduction commitments. This
will lead to increased emissions in some states in the 2012 base case
relative to current emissions. For example, efforts to comply with the
Acid Rain Program at the least cost may occur, in some cases, without
the operation of existing scrubbers through use of readily available,
inexpensive Title IV allowances.
It is important to note that, to the extent that emission
reductions currently required by CAIR are also reflected in emission
reduction requirements under the Acid Rain Program, the NOX
SIP Call, New Source Performance Standards, any state laws and consent
orders requiring emission reductions, and any other enforceable binding
reduction commitments, such reductions are accounted for in EPA's 2012
base case. Some commenter claimed that in excluding CAIR-specific
emission reductions from the base case, EPA ignores non-CAIR legal
requirements (e.g., in Title V permits) that may prevent sources from
increasing emissions above CAIR levels. Such allegations are incorrect.
As discussed elsewhere in this preamble, EPA accounted for any Title V
permits, consent decrees, state rules, and other enforceable
limitations on sources' emissions; if these non-CAIR limitations
effectively restrain a state's emissions to not exceed the state's CAIR
limitations, EPA's base case modeling would reflect this outcome.
Commenters also assert that utilities are unlikely to dismantle or
discontinue running the installed controls to the point of returning to
pre-CAIR emission levels. EPA agrees that installed controls are not
likely to be physically dismantled, and as discussed elsewhere in this
preamble, EPA's analysis properly treats the capital investments made
in emission controls attributed to CAIR as ``sunk'' capital costs
(i.e., capital costs already obligated in the past) that are not
included as costs of meeting Transport Rule requirements.
Our cost analysis for significant contribution reflects on-the-
ground realities. Investments in pollution control equipment were made
in response to CAIR requirements. Those expenditures are ``sunk''
capital costs, meaning that those investments were committed in the
past, prior to the Transport Rule. Adding the capital costs of that
equipment into the costs of Transport Rule emission reduction options
would be incorrect; those capital investments are represented in place
in the base case.
However, given ongoing costs associated with operating these
controls, EPA believes sources would have an economic incentive to
discontinue operating installed controls, or to operate those controls
less effectively, except to the extent non-CAIR legal requirements
mandate emission reductions or to the extent that sources would find it
economic to operate the controls for non-CAIR market-based emission
control programs. EPA properly treats the costs of operating controls
installed to meet CAIR requirements as costs of meeting Transport Rule
requirements.\17\ EPA's base case accounts for non-CAIR requirements
and does not make the unreasonable assumption that installed controls
would be operated to achieve emission reductions that are not necessary
to meet non-CAIR requirements. For all of these reasons, EPA rejects
commenters' claims that the base case is ``unrepresentative'' or lacks
``a rational relationship to the real world.''
---------------------------------------------------------------------------
\17\ For more details on how EPA models economic operation of
existing pollution control equipment in the Transport Rule base
case, please see Section 6 (``Dispatchable Controls'') in ``Updates
to EPA Base Case v3.02 EISA Using the Integrated Planning Model''
Technical Support Document (TSD) for the Transport Rule Docket ID
No. EPA-HQ-OAR-2009-0491, U.S. EPA, July 2010 (available at http://www.epa.gov/airmarkets/progsregs/epa-ipm/IPM Update
Documentation.pdf).
---------------------------------------------------------------------------
C. Air Quality Modeling To Identify Downwind Nonattainment and
Maintenance Receptors
1. Emission Inventories
To inform air quality modeling for the development of the final
Transport Rule, EPA developed emission
[[Page 48225]]
inventories for a 2005 base year and for 2012 and 2014 projections. The
inventories for all years include emission estimates for EGUs, non-EGU
point sources, stationary nonpoint sources, onroad mobile sources,
nonroad mobile sources, and biogenic (non-human) sources. EPA's air
quality modeling relies on this comprehensive set of emission
inventories because emissions from multiple source categories are
needed to model ambient air quality and to facilitate comparison of
model outputs with ambient measurements. In addition, EPA considers all
relevant emissions (regardless of source category) when determining
whether a state is found to be significantly contributing to or
interfering with maintenance of a particular NAAQS in another state.
The emission inventories were processed through the Sparse Matrix
Operator Kernel Emissions (SMOKE) Modeling System version 2.6 to
produce the gridded, hourly, speciated, model-ready emissions for input
to the CAMx air quality model. Additional information on the
development of the emission inventories and related data sets for
emissions modeling are provided in the Emission Inventory Final
Transport Rule TSD.
On October 27, 2010, EPA issued a NODA on ``Revisions to Emission
Inventories.'' The NODA's primary purpose was to notify the public
about changes to emission inventories made since the proposal modeling.
The affected emission sectors were non-EGU stationary point sources,
nonpoint sources, and Category 3 commercial marine vessel sources. The
NODA also presented a newly released model for developing onroad mobile
source emissions for use in air quality modeling for the final
Transport Rule.
The major comments received in response to the emission inventories
and modeling included in the proposed Transport Rule and the October 27
NODA are summarized in the following subsections. EPA agreed with the
comments summarized below and adopted technical corrections or updates
to the emission inventories and modeling accordingly. For EPA to be
able to take appropriate action, comments on the emission inventories
needed to be specific enough to allow for credible alternative data
sources to be located. EPA adopted corrections from comments on in-
place control programs or devices where the controls were enforceable
and quantifiable.
a. Foundation Emission Inventory Data Sets
EPA developed emission data representing the year 2005 to support
air quality modeling of a base year from which future air quality could
be forecasted. EPA used the 2005 National Emission Inventory (NEI),
version 2 from October 6, 2008, as the chief basis for the U.S.
inventories supporting the 2005 air quality modeling. This inventory
includes 2005-specific data for point and mobile sources, while most
nonpoint data were carried forward from version 3 of the 2002 NEI. The
future base case scenarios modeled for 2012 and 2014 represent
predicted emission reductions primarily from already promulgated
federal measures.
EPA used a 2006 Canadian inventory and a 1999 Mexican inventory for
the portions of Canada and Mexico within the air quality modeling
domains for all modeled scenarios. Emissions from Canada and Mexico for
all source sectors (including EGUs) in these countries were held
constant for all base- and future-year cases. EPA made this assumption
because it does not currently have sufficient data to support
projections of future-year emissions from Canada and Mexico.
b. Development of Emission Inventories for EGUs
The annual NOX and SO2 emissions for EGUs in
the 2005 NEI v2 are based primarily on data from continuous emissions
monitoring systems (CEMS), with other EGU pollutants estimated using
emission factors and annual heat input data reported to EPA. Although
only NOX and SO2 are considered for control in
this rule, emissions for all criteria air pollutants are necessary to
model air quality. For EGUs without CEMS, EPA used data submitted to
the NEI by the states. For more information on the details of how the
2005 EGU emissions were developed, see the Emissions Inventory Final
Rule TSD.
Commenters stated that some point sources that were classified as
non-EGUs in the proposal modeling were actually EGUs, resulting in
double counting of emissions in future-year modeling. EPA reviewed its
assignment of EGUs and non-EGUs and reclassified EGU sources found to
be in the non-EGU inventory for the updated 2005 EGU inventory to
prevent double counting of future-year emissions.
The future base case scenarios for EGUs reflect projected changes
to fuel usage and economics, as described in the Emission Inventory
Final Rule TSD. Future year base case EGU emissions that predict
SO2, NOX, and PM2.5 were obtained from
version 4.10--FTransport of the Integrated Planning Model (IPM) outputs
(http://www.epa.gov/airmarkt/progsregs/epa-ipm/index.html). The IPM is
a multi-regional, dynamic, deterministic linear programming model of
the U.S. electric power sector; version 4.10--FTransport reflects state
rules and consent decrees through December 1, 2010, and incorporates
public comments on existing controls submitted to EPA through both the
Transport Rule-related notice and comment process as well as the
proposed Mercury and Air Toxics Standards Information Collection
Request (ICR). The operation of existing SO2 or
NOX advanced controls (e.g., scrubber, SCR) on units that
were not required to operate those controls for compliance with Title
IV, New Source Review (NSR), state settlements, or state-specific rules
was projected by IPM on the basis of providing least cost operation of
the power generation system subject to existing regulatory requirements
except CAIR (see baseline discussion in section V.B).
Additionally, IPM v.4.10--FTransport incorporates comments received
during the rulemaking process. Fuel-related updates include comment-
driven unit-specific limitations on 2012 coal rank selection, limiting
unrestricted switching from bituminous to subbituminous coal by
imposing boiler modification costs for those units shifting from
bituminous to subbituminous coal without historical precedent, and a
correction of waste coal prices. Pollution control-related updates
include keying the performance assumptions for FGD and SCR more closely
to historic performance data, and the inclusion of dry sorbent
injection (DSI), a SO2 removal technology. Other notable
updates include revised assumptions on the heat rate and consequent
dispatching of cogenerating units and incorporation of additional
planned retirements. Further details on these updates are available in
the IPM Documentation, available in the docket and at: http://www.epa.gov/airmarkets/progsregs/epa-ipm/index.html.
c. Development of Emission Inventories for Non-EGU Point Sources
Details on the development of emission inventories are available in
the Emission Inventory Final Rule TSD. In both the proposal and final
modeling, controls on industrial boilers installed under the
NOX SIP call were assumed to have been implemented by 2005
and captured in the 2005 NEI v2. The non-EGU point source emissions
were updated from the 2005 NEI and the
[[Page 48226]]
emissions used for the proposal modeling through the incorporation of
comments on the proposal emissions values, previously unknown facility
closures, and through other data improvements as identified by EPA
analyses.
EPA does not factor in economic growth to develop non-EGU point
source emission projections because analysis of historical emission
trends and economic data did not support using economic growth to
project non-EGU emissions. More details on the rationale for not
applying economic growth to non-EGU industrial sources can be found in
Appendix D of the Regulatory Impact Assessment (RIA) for the PM NAAQS
rule (http://www.epa.gov/ttn/ecas/regdata/RIAs/Appendix%20D_
Inventory.pdf). Although projections based on economic growth were not
included, EPA did include reductions resulting from plant and unit
closures, local and federal consent decrees, and several Maximum
Achievable Control Technology (MACT) standards.
For non-EGU point sources, local control programs that may be
necessary for areas to attain the annual PM2.5 NAAQS and the
ozone NAAQS are only included in the future base case projections when
specific information about existing enforceable local controls was
provided.
Since aircraft at airports were treated as point emissions sources
in the 2005 NEI v2, we applied projection factors based on activity
growth projected by the Federal Aviation Administration Terminal Area
Forecast (TAF) system, published in December 2008.
A number of comments were received on the stationary non-EGU point
source inventories. Below is a summary of the major comments that
impacted the stationary non-EGU point source inventories for the final
modeling:
Comment: Commenters stated that EPA did not properly represent some
point source emissions in base-year and future-year inventories due to
facility and unit closures, consent decrees, emission caps, control
programs, and alternative emission estimates.
Response: EPA reviewed the sources referenced in the individual
comments regarding the base-year and future-year inventories. In cases
where credible alternative data were available, EPA revised the
emission inventories to incorporate additional facility and unit
closures, consent decrees, emission caps, control programs, enforceable
local controls, and alternative emission estimates.
Comment: Commenters stated that EPA should include controls from
the National Emission Standards for Hazardous Air Pollutants for
Reciprocating Internal Combustion Engines (RICE NESHAP) in our
modeling.
Response: EPA included reductions expected to be achieved by the
RICE NESHAP across the United States in our final modeling of
stationary non-EGU and nonpoint sources.
Comment: Commenters stated that EPA was not properly representing
existing or planned controls for cement plants.
Response: EPA updated control and projection information for cement
plants based on the latest available data and cement sector-specific
modeling results.
Comment: EPA specifically requested comments on whether to
incorporate emission reduction estimates from the NESHAP for Major
Sources: Industrial, Commercial, and Institutional Boilers and Process
Heaters (75 FR 32006). Commenters stated that emission reduction
estimates should not be included until the rule became final.
Response: EPA did not incorporate emission reduction estimates from
the NESHAP for Major Sources: Industrial, Commercial, and Institutional
Boilers and Process Heaters (75 FR 32006) into the proposal or final
modeling because the rule was not final at the time the modeling was
performed. Note that reductions from this rule would not have impacted
the 2012 base case due to its implementation schedule, and only the
2014 emissions would have been affected.
d. Development of Emission Inventories for Onroad Mobile Sources
The onroad emissions in the proposal modeling were primarily based
on the National Mobile Inventory Model (NMIM) monthly, county, and
process level emissions along with gasoline exhaust emissions from a
fall 2008 draft version of the Motor Vehicle Emission Simulator
(MOVES). A major comment on the proposal modeling for onroad mobile
sources was the following:
Comment: Commenters stated that EPA should use a publicly released
version of MOVES for its final modeling.
Response: EPA updated the final modeling to use data from the
publicly released version of the MOVES 2010 model because the model
became available in time for inclusion of its results in the final
modeling. It was not used for the proposal modeling because it was not
available at the time the modeling was performed.
In the final Transport Rule modeling, EPA used MOVES 2010 state-
month level emissions for all criteria pollutants and all modes
(evaporative, exhaust, brake wear and tire wear) and allocated those
emissions to counties according to state-county NMIM emissions ratios.
For California (the emissions for which are included to support the
coarse modeling domain), the onroad mobile emissions data were derived
from data provided by the state. These data were augmented with MOVES
2010 outputs for NH3 because data for that pollutant had not
been provided. Additional information on the approach to onroad mobile
source emissions is available in the Emission Inventory Final Rule TSD.
In the future-year base modeling for mobile sources, all national
measures available at the time of modeling were included. The future
scenarios for mobile sources reflect projected changes to fuel usage,
as described in the Emission Inventory Final Rule TSD. Emissions for
these years reflect onroad mobile control programs including the Light-
Duty Vehicle Tier 2 Rule, the Onroad Heavy-Duty Rule, the Light-Duty
Vehicle Greenhouse Gas Rule, the Renewable Fuel Standards Rule, and the
Mobile Source Air Toxics (MSAT) final rule.
e. Development of Commercial Marine Category 3 Vessel Emission
Inventories
For the 2005 modeling, the commercial marine category 3 (C3) vessel
emissions, a portion of nonroad mobile emissions, were augmented with
gridded 2005 emissions from the previous modeling efforts for the rule
called ``Control of Emissions from New Marine Compression-Ignition
Engines at or Above 30 Liters per Cylinder.'' Emissions out to 200
nautical miles from the coastline were allocated to states in the
proposal modeling. A major comment on the proposal modeling was the
following:
Comment: Commenters stated that emissions from commercial marine
sources (a component of the nonroad emissions in the summaries that
were provided for the NPR) were too high.
Response: EPA reviewed the approach used for commercial marine
C3 emissions in the proposal. In the final modeling, instead
of using the boundary of 200 nautical miles from the coast as was used
in the proposal, EPA adopted the Mineral Management Service state-
federal water boundaries that assign state waters 3-10 nautical miles
from the coast. This approach is consistent with the approach used in
the 2005 and 2008 National Emission Inventories. In addition, the
category 3 commercial marine emissions were adjusted to reflect a
coordination between the Emissions Control Area proposal to the
International Maritime Organization
[[Page 48227]]
(EPA-420-F-10-041, August 2010) control strategy; reductions of
NOX, VOC, and CO emissions for new C3 engines
starting in 2011; and fuel sulfur limits that go into effect as early
as 2010.
f. Development of Emission Inventories for Other Nonroad Mobile Sources
The nonroad mobile source emissions for sources other than
C3 marine were primarily based on NMIM monthly, county, and
process level emissions from the 2005 NEI v2. These emissions were
unchanged from proposal modeling, except for PM emissions in California
that were updated to correct for missing emissions in a few counties
and source categories.
Nonroad mobile emissions were created for future years with NMIM
using an approach consistent with that used for 2005. The nonroad
emissions for 2012 and 2014 were calculated using NMIM future-year
equipment population estimates and control programs. Nonroad mobile
emission reductions for 2012 and 2014 include reductions to
locomotives, various nonroad engines including diesel engines and
various marine engine types, fuel sulfur content, and evaporative
emissions standards. A more comprehensive list of control programs
included for mobile sources is available in the Emission Inventory
Final Rule TSD.
The 2012 and 2014 nonroad mobile emissions for locomotives and
category 1 and 2 (C1 and C2) commercial marine vessels were based on
emissions published in EPA's Locomotive Marine Rule, Regulatory Impact
Assessment, Chapter 3.
g. Development of Nonpoint Emission Inventories
For the proposal Transport Rule modeling, EPA augmented the 2002
NEI nonpoint emission inventory with a non-California Western Regional
Air Partnership (WRAP) oil and gas exploration inventory, which
includes emissions in several states within the eastern U.S. 12 km
modeling domain and additional states within the national 36 km
modeling domain. For the final Transport Rule modeling, EPA updated the
nonpoint emission estimates for oil and gas sources. EPA continued to
use the same WRAP inventory from the proposal, emissions in Texas and
Oklahoma were updated but for the final modeling with data from the
Texas Commission on Environmental Quality (TCEQ) and the Oklahoma
Department of Environmental Quality (DEQ), respectively.
The average-year county-based inventories for wildfire and
prescribed burning emissions were unchanged between the proposal and
final modeling.
For stationary nonpoint sources, local control programs that may be
necessary for areas to attain the annual PM2.5 NAAQS and the
ozone NAAQS are not included in the future base case projections unless
specific information about existing enforceable controls was available
(e.g., ozone SIP controls from Ozone Transport Commission rules that
impact source categories such as Consumer Products, Solvent Cleaning,
Adhesives and Sealants). EPA specifically requested comment on local
control data as part of the proposal and the October 27 NODA, and
incorporated any usable data that was provided into the final
inventories.
For stationary nonpoint sources, refueling emissions were projected
using the refueling results from the NMIM runs performed for the onroad
mobile sector.
Portable fuel container emissions were projected to future years
using estimates from previous OTAQ rulemaking inventories. Emissions of
ammonia and dust from animal operations were projected based on animal
population data from the Department of Agriculture and EPA. Residential
wood combustion was projected by replacement of obsolete wood stoves
with new wood stoves and a 1 percent annual increase in fireplaces.
Landfill emissions were projected using MACT controls. All other
nonpoint sources were held constant between 2005 and the future years.
Some specific adjustments to the inventories were made in the final
modeling to address comments that were received as described below.
Area source MACT programs and controls from the RICE NESHAP were
included in the final modeling to address submitted comments, as were
fuel sulfur controls that were enforceable and that take effect by
2014.
The major comments that impacted the nonpoint sectors are as
follows:
Comment: Commenters stated that the SO2 emissions from
industrial fuel combustion in Nebraska EPA are too high.
Response: EPA reviewed the NEI 2002-based data that had been used
for the proposal modeling and determined that emissions from the 2005
inventory compiled for the Central Regional Air Planning Association
(CENRAP) were more up to date for this source category and based on
more localized data sources. The 2005 CENRAP emissions for industrial
fuel combustion were used in the final modeling.
Comment: Commenters stated that EPA should include sulfur rule
controls that take effect prior to the future years that were modeled.
Response: EPA included quantifiable sulfur rule controls in 2014
modeling for those states that had implemented the rules (New Jersey
and Maine).
Comment: A commenter stated that emissions for Delaware were
overestimated for several nonpoint categories in base-year and future-
year inventories and provided alternative estimates for these
categories.
Response: EPA reviewed the alternative estimates provided and found
them to be credible and based on more detailed local scale information
than were available in the national inventories. EPA incorporated the
alternative emission estimates for Delaware into the final modeling.
Comment: A commenter stated that residual oil is not used as an
industrial fuel in South Carolina.
Response: EPA analyzed the emissions from residual oil industrial
fuel combustion in South Carolina and all other states, and analyzed
preliminary regional planning office inventories and the 2008 NEI
submittals. The South Carolina residual oil industrial fuel emissions
were determined to be anomalously large in comparison to the near zero
emissions in other submittals and were therefore removed from the
nonpoint inventory.
2. Air Quality Basis for Identifying Receptors
a. Introduction
In this section, we describe the final approach to identify
downwind nonattainment and maintenance receptors. We briefly summarize
the modeling platform, the proposed approach to identify receptors,
comments received, and the results of the final analysis.
In the Transport Rule, EPA has explicitly given independent meaning
to the ``interfere with maintenance'' prong of section
110(a)(2)(D)(i)(I) by evaluating contributions to identified
maintenance receptors as well as contributions to identified
nonattainment receptors. EPA identified maintenance receptors as those
receptors that would have difficulty maintaining the relevant NAAQS in
a scenario that takes into account historic variability in air quality
at that receptor. Specifically, EPA projects future air quality design
values based on measured data during the period 2003 to 2007. In
determining the downwind receptors of concern, EPA
[[Page 48228]]
does not solely rely on the projection of an average design value based
on measured data from the relevant period (in this case 2003 to 2007)
to make a determination of ``attainment'' or ``nonattainment.''
Instead, EPA also evaluates the maximum future design value at that
receptor based on measured data over the relevant period. Receptors for
which this latter analysis projects design values higher than the NAAQS
are identified as maintenance receptors.
EPA believes it is appropriate and reasonable to use this approach
to identify receptors that may have maintenance problems in the future.
This approach uses measured data in order to establish potential air
quality outcomes at each receptor that take into account the variable
meteorological conditions present across the entire period of measured
data (2003 to 2007). EPA interprets the maximum future design value to
be a potential future air quality outcome consistent with the
meteorology that yielded maximum measured concentrations in the ambient
data set analyzed for that receptor. In other words, the average design
value gives a reasonable projection of future air quality at the
receptor under ``average'' conditions. However, EPA also recognizes
that previously experienced meteorological conditions (e.g., dominant
wind direction, temperatures, air mass patterns) promoting ozone or
fine particle formation that led to maximum concentrations in the
measured data may reoccur in the future. The maximum design value gives
a reasonable projection of future air quality at the receptor under a
scenario in which such conditions do, in fact, reoccur. It also
identifies upwind emissions that under those circumstances could
interfere with the downwind area's ability to maintain the NAAQS.
Per the court's opinion in North Carolina, it is necessary for the
Agency to evaluate ``interference with maintenance'' separately from
``significant contribution to nonattainment'' in order to give
independent meaning to that phrase in the statute. The approach
described above does so and provides a reasonable basis for identifying
upwind emissions that interfere with maintenance of the NAAQS at
downwind receptors.
Because the methodology is based on actual variations in design
values measured at the receptors, EPA believes that the application of
this design value methodology for identifying maintenance receptors
reasonably anticipates possible future air quality outcomes based on
meteorological conditions independent of emission reduction
requirements occurring between 2005 (the base year for air quality
analysis) and 2012 (the future year for air quality analysis of the
base case without CAIR or the Transport Rule in place). EPA uses air
quality modeling to properly account for changes in air quality from
2005 to 2012 due to emission control requirements and trends in
emission source fleet turnover (such as increasingly cleaner motor
vehicle fleets). The air quality modeling process allows EPA to
effectively adjust measured data to project design values in 2012 based
on the forecast changes in emissions. For a given receptor, the
forecast change in emissions from 2005 to 2012 is a constant factor
applied across all of the design values from the period 2003 to 2007.
Thus, a comparison of the projected (future-year) design values
themselves is equivalent to comparing the base period design values
from the data set to consider how pollution concentrations are affected
by non-modeled factors such as environmental and meteorological
variability independent of the forecast emission reductions that stem
from successful imposition of emission limitations and controls on
various sources between the base and future modeling years. EPA
believes it is reasonable to anticipate that these year-to-year
meteorological fluctuations may reoccur at any time in the future and
are relevant to determining receptors that are at risk of having a
problem in the future with maintenance of the NAAQS. Therefore, EPA
assesses the relationship of the maximum projected design value for
2012 at each receptor to the relevant NAAQS, and where such a value
exceeds the NAAQS, EPA determines that receptor to be a ``maintenance''
receptor for purposes of defining interference with maintenance under
the Transport Rule.
To provide an illustrative example, consider a hypothetical
receptor ``Y'' whose measured data for 2003-2007 yields three design
values for annual fine particles: 17 for 2003-05; 14 for 2004-06; and
12 [micro]g/m\3\ for 2005-07. Thus, the maximum measured design value
for this period is 17 and the average design value is 14.3. To
determine whether the receptor is a nonattainment or maintenance
receptor, EPA projects a corresponding future-year (2012) design value
for each measured design value. These projections are based on the
results of air quality modeling, which demonstrates predicted changes
in pollution concentrations for each receptor from 2005 to 2012. For
this example, assume that the projected future-year design values that
correspond with the measured design values, are 16 (corresponds with
the 2003-05 design value of 17), 13 (corresponds with the 2004-06
design value of 14), and 11 [micro]g/m\3\ (corresponds with the 2005-07
design value of 12). The average future-year design value is 13.3
(corresponds with the average measured design value from 2003-2007 of
14.3). The projected future design values are all lower than the
measured design values because air quality is projected to improve
between 2005 and 2012. In this example, the analysis establishes that
the average projected future design value is 13.3 and the maximum
projected future design value is 16.
The average future (2012) projected design value of 13.3 based on
the average design value for the period 2003-07 does not exceed the
1997 annual PM2.5 NAAQS. For this reason, EPA would conclude
that receptor Y will most likely have attainment air quality in the
future year. Therefore, it would not be identified as a nonattainment
receptor.
However, the future projected design value of 16 based on the
maximum design value for the period 2003-07 does exceed the NAAQS. For
this reason, EPA would conclude that the receptor may have difficulty
maintaining attainment with the NAAQS under future potential
meteorological conditions. EPA therefore would identify the receptor as
a maintenance receptor and evaluate whether upwind state emissions
interfere with maintenance of the NAAQS at that receptor.
EPA's methodology accounts for the range of meteorological
conditions reflected by design values from the measured 2003-2007 data
at receptor Y and also accounts for the projected changes in emissions
from 2005 to 2012 at receptor Y. The range of meteorological conditions
is accounted for by using data from three different 3-year periods as
described above. The projected changes in emissions are accounted for
by applying to the measured design values the forecasted change in
PM2.5 concentrations, as determined through air quality
modeling of the 2005 and 2012 emissions. In this example, the maximum
measured design value for receptor Y is 17. This design value
represents measured data from 2003 to 2005. EPA applies to this design
value the modeled 2005-to-2012 change in concentrations at receptor Y
to obtain a 2012 maximum design value for that
[[Page 48229]]
receptor, which is 16. In this way, this maximum 2012 design value
takes into consideration the air quality impacts of all known and
legally applicable emission limitations taking effect after the 2003 to
2005 base period. Therefore, each of the projected future-year design
values provide a fair representation of future air quality at receptor
Y under different conditions while accounting for the emissions
projected to remain in 2012. EPA thus believes that if one of these
future-year design values for a particular receptor exceeds the NAAQS,
it is reasonable to conclude that the area may have difficulty
maintaining that NAAQS. For this reason, EPA identifies such receptors
as maintenance receptors. In this example, EPA would find that while
receptor Y's average future-year design value would not exceed the
NAAQS, its maximum future-year design value (16) would exceed the
NAAQS, and it would thus be designated as a ``maintenance'' receptor
for purposes of the Transport Rule analyses.
In the proposed rule we used air quality modeling to (1) Identify
locations where we expected there to be nonattainment and/or
maintenance problems for annual average PM2.5, 24-hour
PM2.5, and/or 8-hour ozone in 2012, (2) quantify the impacts
(i.e., air quality contributions) of SO2 and NOX
emissions from upwind states on downwind annual average and 24-hour
PM2.5 concentrations at monitoring sites projected to be
nonattainment or have maintenance problems in 2012 for the 1997 annual
and 2006 24-hour PM2.5 NAAQS, respectively, and (3) quantify
the impacts of NOX emissions from upwind states on downwind
8-hour ozone concentrations at monitoring sites projected to be
nonattainment or have maintenance problems in 2012 for the 1997 ozone
NAAQS.
To support the proposal, air quality modeling was performed for
four emission scenarios: a 2005 base year, a 2012 ``no CAIR'' base
case, a 2014 ``no CAIR'' base case, and a 2014 control case that
reflects the emission reductions expected from the FIPs. The modeling
for 2005 was used as the base year for projecting air quality for each
of the 3 future-year scenarios. The 2012 base case modeling was used to
identify future nonattainment and maintenance locations and to quantify
the contributions of emissions in upwind states to annual average and
24-hour PM2.5 and 8-hour ozone. The 2012 ozone and
PM2.5 concentrations were derived by projecting 2003 through
2007 based ambient ozone and/or PM2.5 data to the future
using the relative (percent) change in modeled concentrations between
2005 and 2012. The 2014 base case and 2014 control case modeling were
used to quantify the benefits of this proposal.
In the proposed rule, EPA used the Comprehensive Air Quality Model
with Extensions (CAMx) version 5.20 \18\ to simulate ozone and
PM2.5 concentrations for the 2005 base year and the 2012 and
2014 future year scenarios. The CAMx model applications were designed
to cover states in the central and eastern U.S. using a horizontal
resolution of 12 x 12 km.\19\
---------------------------------------------------------------------------
\18\ Comprehensive Air Quality Model with Extensions Version 5
User's Guide. Environ International Corporation. Novato, CA. March
2009.
\19\ The 12 km domain was nested within a coarse grid, 36 x 36
km modeling domain which covers the lower 48 states and adjacent
portions of Canada and Mexico. Predictions from this Continental
U.S. (CONUS) domain were used to provide initial and boundary
concentrations for simulations in the 12 km domain.
---------------------------------------------------------------------------
CAMx contains ``source apportionment'' tools that are designed to
quantify the contribution of emissions from various sources and areas
to ozone and PM2.5 component species in other downwind
locations. The source apportionment tools were used to quantify the
downwind contributions of ozone and PM2.5 from upwind
states.
In the proposed rule, EPA used a 2005-based air quality modeling
platform which included 2005 base year emissions and 2005 meteorology
for modeling ozone and PM2.5 with CAMx.
We received comments related to several aspects of the air quality
modeling platform.
Comment: There was wide support from commenters for the use of CAMx
as an appropriate, state-of-the science air quality tool for use in the
Transport Rule. There were no comments that suggested that EPA should
use an alternative model for quantifying interstate transport. Many
commenters requested that EPA update the emission inventories used for
the Transport Rule and then remodel the 2005 base year and future year
emissions using the updated emissions and the most recent version of
CAMx to reassess interstate transport for the final rule.
Response: For the final rule we have updated our modeling using the
latest public release of CAMx (version 5.30) and associated
preprocessors. We have also made numerous improvements to the emission
inventories for the 2005 base year as well as the 2012 and 2014 future
year base cases in response to public comments. The emissions changes
are described in section V.C.1. The projection of future year
nonattainment and maintenance sites and the quantification of ozone and
PM2.5 transport for the final rule are based on modeling
with CAMx v5.30 using the updated emission inventories. The final rule
air quality projections of 2012 nonattainment and maintenance are
described below. The final rule interstate contributions are presented
in section V.D.
Comment: The performance evaluation of the 2005 base year model
predictions for the proposed rule was too cursory and did not provide
sufficient detail on model performance. Commenters requested additional
analyses and spatial resolution describing how well base year model
predictions compare to the corresponding measured values.
Response: For the final rule we have expanded the scope of the
model evaluation for 2005 to include a broader suite of statistics to
characterize performance for individual subregions of the eastern U.S.
modeling domain. The results of the performance evaluation for the
final rule 2005 base year air quality modeling are described in the Air
Quality Modeling Final Rule TSD.
Comment: The 2005 based modeling platform should be updated to a
more recent year. There were several different aspects of this comment.
Some commenters stated that EPA should be using a more recent emission
inventory as a base year, due to identified changes and updates to the
inventories. Other commenters stated that EPA should use a more recent
base year, due to a trend of improvement in air quality over the past
few years. The commenters claim that the 2005-based EPA modeling does
not account for large emission reductions and air quality improvements
that have occurred over the last several years.
Response: There are several reasons why the use of a 2005 modeling
base case is both reasonable and, in fact, necessary for the Transport
Rule. As explained in section V.B, above, because the Transport Rule
will replace CAIR, EPA cannot consider reductions associated with CAIR
in the analytical baseline emissions scenario. Thus, the base year for
the air quality projections should be a year that represents emissions
before CAIR was in place (i.e. 2005). We are projecting emissions to a
future 2012 ``no CAIR'' case and therefore want to best represent the
air quality change between 2005 and 2012, without CAIR. To do this, we
projected emissions that existed before CAIR was in effect and modeled
the air quality change that occurs between 2005 and 2012 without CAIR.
[[Page 48230]]
A key consideration in our projection methodology is the use of
ambient data to anchor the design value projections to the future. The
modeling is used in a relative sense by multiplying the modeled percent
change in ozone or PM2.5 species concentrations by the base
year ambient data. The ozone and PM2.5 modeling guidance
recommends projecting design values based on 5 years \20\ of monitoring
data that is centered on the base model year. Using 2005 as a base
emissions and meteorological year entailed the use of 2003-2007 ambient
air quality data (5 years of data centered about 2005). This was a
reasonable choice because the majority of the ambient data from this
period was not impacted by CAIR emission reductions.
---------------------------------------------------------------------------
\20\ The modeling guidance recommends using a five year weighted
average design value. This is calculated by averaging the three
consecutive design value periods of 2003-2005, 2004-2006, and 2005-
2007.
---------------------------------------------------------------------------
After 2005, early emission reductions of SO2 and
NOX in response to CAIR began to impact the measured air
quality concentrations. Since the modeling projection methodology uses
both modeled and observed data, 2005 is the latest base year that we
deemed appropriate (before CAIR emission reductions took place) for use
in projecting the measured air quality to a 2012 future year. The early
years of the 5 year period (2003, 2004, and 2005) were not impacted by
CAIR.\21\ The last 2 years in the period (2006 and 2007) were slightly
impacted by CAIR emission reductions. But the 5 year average is
weighted towards the middle year of the period (2005), so the impact of
the years after CAIR promulgation should be minimal.
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\21\ The CAIR final rule was published on May 12, 2005.
---------------------------------------------------------------------------
The 2005 base year was also chosen because it was an appropriate
meteorological year. In the eastern U.S. there was relatively high
ozone during the summer of 2005 and relatively high PM2.5
periods during the year. The modeled attainment tests for both ozone
and 24-hour PM2.5 depend on having a sufficient number of
``high'' modeled days to project to the future. Modeling a year that is
not meteorologically conducive to ozone and/or PM2.5
formation is discouraged by the modeling guidance because a
meteorological year that is not conducive to ozone or PM2.5
formation may be less responsive to changes in emissions in the future.
Therefore, projecting the relative change in ozone or PM2.5
for a non-conducive base year may underestimate the future change in
ozone and/or PM2.5 concentrations.
Additionally, all enforceable emission reductions that occurred
between 2005 and 2012 (other than those required under CAIR) are
captured by the modeling system. Any enforceable non-EGU emission
reductions due to existing rules or the installation of emissions
controls after 2005 were included in the 2012 base case inventory. As
explained above in section V.B, to capture changes in EGU emissions
between 2005 and 2012, EPA did not assume operation of all controls
installed during that time period, as many of those controls were built
in response to CAIR. EPA used IPM to project 2012 EGU emissions
incorporating all non-CAIR enforceable emission constraints; operation
of existing pollution controls was taken into account only where non-
CAIR constraints made it economic or legally necessary to operate them.
We also accounted for permanent source shutdowns that occurred after
2005. Where possible, we incorporated reported emission changes based
on comments to the proposed rule and a subsequent emission inventory
NODA.
Comment: Several commenters stated that we used a ``modeled +
monitored'' test in CAIR to identify future year nonattainment
receptors, but we only used a modeled test in the Transport Rule
proposal. They suggest that we should either go back to the ``modeled +
monitored'' test or explain why we should not use monitoring data in
the identification of nonattainment and maintenance receptors. They say
that we should not base nonattainment and maintenance receptors solely
on modeled violations. They also say that we if we had looked at the
most recent ambient data we would see that most of the modeled
nonattainment and maintenance receptors are already attaining the ozone
and/or PM2.5 NAAQS.
Response: In the identification of future year nonattainment
receptors for CAIR, EPA used what was called the ``modeled + monitored
test''. The most recent ambient data (2001-2003 design values at the
time) were examined to further verify that nonattainment was still
being measured at potential future year nonattainment receptors. In the
proposed Transport Rule, EPA identified future year nonattainment and
maintenance receptors based on modeled projections of ambient data from
the 2003-2007 time period. The future year receptors were not compared
to most recent ambient data to verify that nonattainment still existed.
For the final Transport Rule, there are several reasons that EPA
did not examine the most recent ambient data to verify that receptors
were still measuring nonattainment. The main reason for dropping the
``monitored'' part of the modeled + monitored test is the fact that the
most recent monitoring data (2007-2009 design values) include large
emission reductions from CAIR. As explained in section V.B, above,
because the Transport Rule will replace CAIR, we must model a future
year base case which does not assume that CAIR is in place (a ``no-
CAIR'' case). It is simply not appropriate to examine the current
monitoring data, which represent air quality with CAIR emission
reductions in place, and compare the values to 2012 projected air
quality that is based on a no-CAIR modeling case. As discussed above,
we modeled a 2005 base case with pre-CAIR emissions and a 2012 future
``no CAIR'' case. The change in modeled air quality is due to the non-
CAIR enforceable emission changes between 2005 and 2012 and therefore
explicitly does not take CAIR into account. As a consequence, the 2012
projected design values represent a unique case (necessary for
analyzing future air quality without either CAIR or its replacement
Transport Rule in effect) that cannot be represented by current ambient
data.
It is also important to note that all of the projected 2012 design
values are based on projections of measured ambient data. They are a
combination of measured data and modeled response factors. Therefore,
it is inaccurate to imply that future year nonattainment and
maintenance receptors are solely based on modeled projections. The
future year concentrations are firmly rooted in base year measured
ambient data that have been projected to the future using modeled data.
There are additional reasons for not verifying the nonattainment
and maintenance receptors against the most recent ambient data. In CAIR
we did not explicitly identify maintenance receptors. In the Transport
Rule proposal we identified maintenance receptors based on 2012
projections of maximum design values from the 2003-2007 period. Even
though receptors may be measuring attainment based on recent data, they
may still be at risk for falling back into nonattainment. Therefore,
even if commenters argue that recent data show that monitoring sites
should not be nonattainment receptors (with which we disagree), the
same argument cannot be made regarding maintenance receptors. Clearly,
receptors with recent ``clean'' ambient data may still experience
higher PM2.5 and/or ozone concentrations in the future
(based on
[[Page 48231]]
meteorological and emission variability) and therefore may be
appropriate maintenance receptors.
Comment: Several commenters claim that the maintenance receptor
methodology overstates actual future design values. They also recommend
an alternative methodology which takes into account the downward trend
in observed PM2.5 concentrations over the last 5+ years. The
methodology would remove the trend in the data where air quality is
improving over the period by applying a linear fit to the data,
calculating the residuals and then adding the residuals back to the
average of the data. Given a site with a downward trend, this has the
effect of decreasing the calculated maximum values from the early years
in the period and increasing the values from the end years in the
period.
Response: EPA continues to believe that our approach to identify
maintenance receptors is reasonable and appropriate. For the final
rule, we continue to identify maintenance receptors by projecting the
maximum design value from the 2003-2007 period to the future. The
methodology assumes that the combination of emissions and meteorology
that occurred in the base period (which led to relatively high ambient
design values) could happen again in the future (albeit at lower
emissions levels). There is no information presented by the commenters
which explains why the magnitude of base year design value variability
could not occur in the same way in the future. The commenters cite the
downward trend in ambient data as the reason why the EPA methodology is
not reasonable. However, in most cases, the recent downward trend in
ambient data is due to a combination of ongoing emission reductions
(which includes CAIR), variability in meteorology, and depressed
emissions due to the recession. In fact, the most recent ambient design
value period (2007-2009) is heavily influenced by extremely low ozone
and PM2.5 concentrations measured in 2009. The 2009 data are
marked by relatively low emissions due to cool summer weather and
ongoing effects of the recession. The preliminary \22\ 2010 ambient
data in the eastern U.S. show that ozone and PM2.5 values
were considerably higher in 2010 compared to 2009. In the states that
are included in the final Transport Rule region, there were 158 ozone
monitor days that exceeded 84 ppb in 2009 compared to 412 monitor
exceedance days in 2010. For PM2.5, there were 251 monitor
days that exceeded 35 [mu]g/m \3\ in 2009 compared to 417 monitor
exceedance days in 2010. Even though the SO2 and
NOX emissions were generally lower in 2010, the observed
ozone and PM2.5 concentrations were higher. This shows the
important influence of meteorology on ambient concentrations. Clearly,
the year to year variability due to meteorology can be large. We
acknowledge the downward trend in ambient data over the last few years.
But this does not mean that conditions that led to high ozone and/or
PM2.5 in the 2003-2007 period could not occur again in the
future. The 2010 ambient data show that meteorology can cause
concentrations to go back up, even though there is a downward trend in
emissions.
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\22\ The 2010 data is preliminary. Exceptional event data has
not been flagged and removed from the reported data.
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We also believe that the alternate maintenance methodology
presented by the commenter is inappropriate. The EPA modeling for 2012
(and 2014) appropriately accounts for emission reductions that occur
after 2005 except for those that should not be considered, as explained
in section V.B., because they were required only by CAIR. Therefore,
the starting point design values used to project to the future should
not be lowered to account for emission reduction trends that occur
after 2005. Doing so would give ``double credit'' to the more recent
emission reductions and provides an inappropriate downward adjustment
to the early design value periods of the 2003-2007 period.
Comment: One commenter claims that EPA did not follow our own
modeling guidance by not doing local scale modeling in urban areas with
high PM2.5 concentration gradients. They suggested that the
methodology to calculate future year design values should have included
dispersion modeling to calculate the change in concentration over time
of primary PM2.5 emissions.
Response: EPA modeling guidance for PM2.5 attainment
demonstrations recommends photochemical grid modeling to examine future
year changes in PM2.5 concentrations. There are several
optional aspects of the modeling which are recommended in specific
cases. This includes a recommendation for a ``local area analysis''
using a dispersion model. An area with relatively large local primary
PM2.5 concentration gradients may want to do additional
modeling to examine the impacts of local controls on its future year
PM2.5 concentrations. This is particularly important when
local controls of primary PM2.5 are included as part of the
attainment demonstration.
As noted above, a ``local area analysis'' is recommended as part of
the local attainment demonstration process in specific situations. It
is impractical for EPA to perform this type of analysis for each local
area in the regional Transport Rule. National rulemakings are not
attainment demonstrations. We are not able to perform fine scale
analyses for each area. For the final rule modeling, we have attempted
to address all emissions and modeling related comments. We have updated
the modeling platform to use the latest version of CAMx and are
continuing to model ozone and PM2.5 at 12km grid resolution,
which for PM2.5 is a more refined grid resolution compared
to the CAIR modeling.
Additionally, there is no evidence presented by the commenter that
would indicate that the future year PM2.5 concentrations
from the Transport Rule are biased high. In fact, depending on the
circumstances, local fine scale grid or dispersion modeling may result
in lower or higher future year design values. In a fine scale analysis,
the dominant local primary PM2.5 emissions become a larger
percentage of the PM2.5 concentrations. Therefore, if the
local emissions are forecast to decrease, fine scale modeling may lead
to lower future design values. However, if the local emissions are
forecast to increase or stay the same between the base and future
years, local modeling will likely show higher future year design values
compared to a regional analysis. This points to the fact that perceived
biases in modeling results may not always be correct.
In sum, fine scale modeling of local areas may lead to either
higher or lower future year design values. There is no indication that
EPA's regional modeling is biased in either direction. EPA's Transport
Rule modeling generally followed EPA's modeling guidance and is
appropriate for the purpose of this rulemaking.
Comment: One commenter completed and submitted a detailed CAMx
based modeling analysis with a 2008 base year and future years of 2014
and 2018. The analysis shows that the majority of the proposed rule
2012 nonattainment and maintenance sites are already attaining based on
either 2006-2008 or 2007-2009 ambient data. Based on this, the
commenter claims that air quality has improved more rapidly than
predicted by EPA's proposed rule modeling. Also, based on the
commenter's 2014 modeling of CAIR emissions (including utility consent
decrees and state programs), the commenter concludes that no additional
controls are needed
[[Page 48232]]
beyond CAIR to bring most or all sites into attainment by 2014.
Response: As an initial matter, we note that the basic question
addressed by the commenter, ``whether additional controls beyond CAIR
are necessary,'' is not on point. As explained previously, the D.C.
Circuit remanded CAIR to EPA and it remains in place only temporarily.
The question EPA must answer in this rulemaking, therefore, is not what
controls in addition to CAIR are necessary but what, if any,
restrictions on emissions must be put in place to replace CAIR in order
to satisfy the requirements of section 110(a)(2)(D)(i)(I) of the CAA.
For this reason, and as explained in greater detail in section V.B of
this preamble, any analysis of whether beyond CAIR controls are
necessary is irrelevant to this rulemaking. Nonetheless, we have
carefully reviewed different aspects of the commenter's analysis. We
previously addressed comments related to the use of more recent ambient
data to examine future year nonattainment and maintenance receptors. As
noted above, the 2006-2008 and 2007-2009 ambient data is heavily
influenced by several factors. Among them are the emissions reductions
from CAIR, the relatively low recent observed ozone and
PM2.5 concentrations at least partially due to non-conducive
meteorology (particularly in 2009), and the atypical suppression of
emissions due to the sharp recession. For all of these reasons, we
believe it is not possible to directly compare the most recent design
values to the predicted future year 2012 and 2014 design values from
the Transport Rule. In particular, it is inappropriate to compare
current design values to EPA's no-CAIR 2012 future year modeling
results. As noted in the comment summary, the commenter's modeling
analysis assumed that CAIR was in place in both 2008 and the future
years. This is a fundamentally different assumption than the modeling
EPA used to define the Transport Rule nonattainment and maintenance
receptors in 2012 and is inappropriate for purposes of the Transport
Rule for reasons described above and in section V.B.
Additionally, EPA's maintenance methodology chooses the highest of
three base year design value periods projected to the future. The
commenter only used a single design value period in their analysis and
therefore did not fully examine maintenance issues. In fact, the 2014
nonattainment modeling receptors in the final Transport Rule and the
commenter's modeling analysis are similar. As documented in section
VI.D, in the 2014 final rule remedy case, there is only one remaining
nonattainment area for ozone and one remaining nonattainment area for
24-hour PM2.5. This is similar to the modeling results
presented in the comments.\23\ However, EPA modeling identifies
additional maintenance receptors in 2012 that continue to have
maintenance issues in 2014.
---------------------------------------------------------------------------
\23\ The purpose of this comparison is to note that the modeling
analyses are actually more similar than the commenter implies.
However, the Transport Rule differs from the commenter's modeling
due to the assumption that CAIR was in place. CAIR and the Transport
Rule differ in state coverage and emission budgets. They are
therefore not directly comparable.
---------------------------------------------------------------------------
EPA also examined our ozone and PM2.5 projection
procedures to see if there might be additional reasons for the
relatively lower current ambient design values (and modeled design
values in the commenter's analysis) compared to the 2014 remedy modeled
values. Upon further analysis of EPA's 24-hour attainment test
methodology, we noted certain discrepancies between the methodology and
the calculation of the ambient 24-hour design values. In the proposed
rule 24-hour attainment test, for each PM2.5 monitor, we
projected the measured 98th percentile concentrations from the 2003-
2007 period to the future. A basic assumption in this methodology is
that the distribution of high measured days in the base period will be
the same in the future. For example, if the observed 98th percentile
day is the 3rd high day for a particular year, we assume that the 1st,
2nd, and 3rd high days (and subsequent high days) in the future remain
in the same basic distribution. Further examination of the proposed
rule modeling found that this is not always the case. In situations
where there are large summer PM2.5 concentration reductions,
some of the high days may switch from the summer in the base period to
the winter in the future period.
In order to better account for the complicated future response in
24-hour design values, we have updated the 24-hour attainment
demonstration methodology to more closely reflect the way 24-hour
design values are calculated. In the revised methodology, we do not
assume that the temporal distribution of high days in the base and
future periods will remain the same. We project a larger set of ambient
days from the base period to the future and then re-rank the entire set
of days to find the new future 98th percentile value (for each year).
More specifically, we project the highest 8 days per quarter (32 days
per year) to the future and then re-rank the 32 days to derive the
future year 98th percentile concentrations. In the case of the
Transport Rule model results, this has the effect of lowering the
future year 24-hour design values compared to the old methodology. The
2012 base case design values for all nonattainment and maintenance
receptors were either unchanged or lower with the revised methodology.
3. How did EPA project future nonattainment and maintenance for annual
PM2.5, 24-hour PM2.5, and 8-hour ozone?
Final Rule: In general, the methodology to project ozone and
PM2.5 concentrations to the future year(s) remains the same
for the final rule. The proposal modeling followed the modeling
guidance procedures for projecting ambient design values to future
years. For the final rule, we continue to follow the basic procedures
outlined in the guidance. The 8-hour ozone and annual PM2.5
methodology are unchanged from the proposal. However, the 24-hour
PM2.5 methodology has been updated in the final rule to be
more consistent with the calculation of 24-hour PM2.5 design
values. There were also additional minor updates to the ambient
data.\24\ The methodology to identify maintenance receptors is also
unchanged from the proposal. We continue to use the maximum design
value (projected from the 5 year base period) to calculate future year
maintenance receptors.
---------------------------------------------------------------------------
\24\ The base year design values were updated based on the
latest official data. See http://www.epa.gov/airtrends/values.html.
---------------------------------------------------------------------------
As noted in the proposal, EPA considers that the maintenance
concept has two components: Year-to-year variability in emissions and
air quality, and continued maintenance of the air quality standard over
time. The way that EPA defined maintenance based on year-to-year
variability (as discussed in detail here) directly affects the
requirements of this final rule. EPA also considered whether further
reductions were necessary to ensure continued lack of interference with
maintenance of the NAAQS over time (e.g., after 2014). EPA concluded
that in light of projected emission trends, and also considering the
emission reductions from this proposed rule, no further reductions are
required solely for this purpose at PM2.5 and ozone
receptors for which we are partially or fully determining significant
contribution for the current NAAQS. (See discussion of emission trends
in Chapter 7 of TSD entitled ``Emission Inventories,'' included in the
docket for the Transport Rule proposal.)
[[Page 48233]]
a. Which ambient ozone and PM2.5 data did EPA use for the
purpose of projecting future year concentrations?
The final rule modeling continues to use a 2005 base case inventory
and 2005 meteorology. Therefore, we continue to use ambient data from
the 2003-2007 period. For each monitoring site, all valid design values
(up to 3) from this period were averaged together. Since 2005 is
included in all three design value periods, this has the effect of
creating a 5-year weighted average, where the middle year is weighted 3
times, the 2nd and 4th years are weighted twice, and the 1st and 5th
years are weighted once. We refer to this as the 5-year weighted
average value. The 5-year weighted average values were then projected
to the future years that were analyzed for this final rule. The 2003-
2005, 2004-2006, and 2005-2007 design values are accessible at http://www.epa.gov/airtrends/values.html. The design values have been updated
based on the latest official values. The official values have
exceptional events removed from the calculations if they are flagged by
states and concurred with by EPA Regional offices.
The procedures for projecting annual average PM2.5 and
8-hour ozone conform to the methodology in the current attainment
demonstration modeling guidance.\25\
---------------------------------------------------------------------------
\25\ U.S. EPA, 2007: Guidance on the Use of Models and Other
Analyses for Demonstrating Attainment of Air Quality Goals for
Ozone, PM2.5, and Regional Haze; Office of Air Quality
Planning and Standards, Research Triangle Park, NC.
---------------------------------------------------------------------------
b. Projection of Future Annual and 24-Hour PM2.5
Nonattainment and Maintenance
(1) Methodology for Projecting Future Annual PM2.5
Nonattainment and Maintenance
For the final rule, annual PM2.5 modeling was performed
for the 2005 base year emissions and for the 2012 base case as part of
the approach for projecting which locations are expected to be in
nonattainment and/or have difficulty maintaining the PM2.5
standards in 2012. We refer to these areas as nonattainment sites and
maintenance sites respectively.
Concentrations of PM2.5 in 2012 were estimated by
applying the modeled 2005-to-2012 relative change in PM2.5
species to each of the 3-year ambient monitoring data periods (i.e.,
2003-2005, 2004-2006, and 2005-2007) to obtain up to 3 future-year
PM2.5 design values for each monitoring site. We used the
highest of these projections at each monitoring site to determine which
sites are expected to have maintenance problems in 2012. We used the 5
year weighted average of those projections to determine which
monitoring sites are expected to be nonattainment in this future year.
For the analysis of both nonattainment and maintenance, monitoring
sites were included in the analysis if they had at least one complete
design value in the 2003-2007 period.\26\ There were 721 monitoring
sites in the 12 km modeling domain which had at least one complete
design value period for the annual PM2.5 NAAQS, and 722
sites which met this criterion for the 24-hour NAAQS.\27\
---------------------------------------------------------------------------
\26\ If there is only one complete design value, then the
nonattainment and maintenance design values are the same.
\27\ Design values were only used if they were deemed to be
officially complete based on CFR 40 Part 50 Appendix N. The
completeness criteria for the annual and 24-hour PM2.5
NAAQS are different. Therefore, there are fewer complete sites for
the annual NAAQS.
---------------------------------------------------------------------------
EPA followed the procedures recommended in the modeling guidance
for projecting PM2.5 by projecting individual
PM2.5 component species and then summing these to calculate
the concentration of total PM2.5. EPA's Modeled Attainment
Test Software (MATS) was used to calculate the future year design
values. The software (including documentation) is available at: http://www.epa.gov/scram001/modelingapps_mats.htm. Additional details on the
annual PM2.5 nonattainment and maintenance projections
methodology can be found in the Air Quality Modeling Final Rule TSD.
The 2012 annual PM2.5 design values were calculated for
each of the 721 sites. The calculated annual PM2.5 design
values are truncated after the second decimal place.\28\ This is
consistent with the ambient monitoring data truncation and rounding
procedures for the annual PM2.5 NAAQS. Any value that is
greater than or equal to 15.05 [micro]g/m\3\ is rounded to 15.1
[micro]g/m\3\ and is considered to be violating the NAAQS. Thus, sites
with projected 5-year weighted average (``average'') annual
PM2.5 design values of 15.05 [micro]g/m\3\ or greater are
predicted to be nonattainment sites. Sites with projected maximum
design values of 15.05 [micro]g/m\3\ or greater are predicted to be
maintenance sites. Note that nonattainment sites are also maintenance
sites because the maximum design value is always greater than or equal
to the 5-year weighted average. For ease of reference we use the term
``nonattainment sites'' to refer to those sites that are projected to
exceed the NAAQS based on both the average and maximum design values.
Those sites that are projected to be attainment based on the average
design value, but exceed the NAAQS based on the maximum design value,
are referred to as maintenance sites. The monitoring sites that we
project to be nonattainment and/or maintenance for the annual
PM2.5 NAAQS in the 2012 base case are the nonattainment/
maintenance receptors used for assessing the contribution of emissions
in upwind states to downwind nonattainment and maintenance of the
annual PM2.5 NAAQS.
---------------------------------------------------------------------------
\28\ For example, a calculated annual average concentration of
14.94753 * * * becomes 14.94 when digits beyond two places to the
right of the decimal are truncated.
---------------------------------------------------------------------------
Table V.C-1 contains the 2003-2007 base case period average and
maximum annual PM2.5 design values and the corresponding
2012 base case average and maximum design values for sites projected to
be nonattainment of the annual PM2.5 NAAQS in 2012. Table
V.C-2 contains this same information for projected 2012 maintenance
sites.
Table V.C-1--Average and Maximum 2003-2007 and 2012 Base Case Annual PM2.5 Design Values ([micro]g/m\3\) at Projected Nonattainment Sites
--------------------------------------------------------------------------------------------------------------------------------------------------------
Final rule Final rule
Monitor ID State County Average design Maximum design average design maximum design
value 2003-2007 value 2003-2007 value 2012 value 2012
--------------------------------------------------------------------------------------------------------------------------------------------------------
010730023.................... Alabama................. Jefferson.............. 18.57 18.94 16.15 16.46
010732003.................... Alabama................. Jefferson.............. 17.15 17.69 15.16 15.64
131210039.................... Georgia................. Fulton................. 17.43 17.47 15.07 15.10
171191007.................... Illinois................ Madison................ 16.72 17.01 15.46 15.73
261630033.................... Michigan................ Wayne.................. 17.50 18.16 15.73 16.32
[[Page 48234]]
390350038.................... Ohio.................... Cuyahoga............... 17.37 18.10 15.99 16.66
390350045.................... Ohio.................... Cuyahoga............... 16.47 16.98 15.14 15.61
390350060.................... Ohio.................... Cuyahoga............... 17.11 17.66 15.67 16.18
390610014.................... Ohio.................... Hamilton............... 17.29 17.53 15.76 15.98
390610042.................... Ohio.................... Hamilton............... 16.85 17.25 15.40 15.77
390618001.................... Ohio.................... Hamilton............... 17.54 17.90 16.01 16.33
420030064.................... Pennsylvania............ Allegheny.............. 20.31 20.75 17.94 18.33
--------------------------------------------------------------------------------------------------------------------------------------------------------
Table V.C-2--Average and Maximum 2003-2007 and 2012 Base Case Annual PM2.5 Design Values ([mu]g/m\3\) at Projected Maintenance-Only Sites
--------------------------------------------------------------------------------------------------------------------------------------------------------
Final rule Final rule
Monitor ID State County Average design Maximum design average design maximum design
value 2003-2007 value 2003-2007 value 2012 value 2012
--------------------------------------------------------------------------------------------------------------------------------------------------------
180970081.................... Indiana................. Marion................. 16.05 16.36 14.86 15.16
180970083.................... Indiana................. Marion................. 15.90 16.27 14.71 15.06
390350065.................... Ohio.................... Cuyahoga............... 15.97 16.44 14.67 15.10
390617001.................... Ohio.................... Hamilton............... 16.17 16.56 14.74 15.10
--------------------------------------------------------------------------------------------------------------------------------------------------------
(2) Methodology for Projecting Future 24-Hour PM2.5
Nonattainment and Maintenance
The procedures for calculating the future year 24-hour
PM2.5 design values have been updated for the final
rule.\29\ The revised procedures are in response to comments which
noted relatively high future year 24-hour PM2.5 design
values in EPA's modeling of the proposed Transport Rule. The updates
are intended to make the projection methodology more consistent with
the procedures for calculating ambient design values.
---------------------------------------------------------------------------
\29\ There were no updates to the ozone and annual
PM2.5 attainment test methodology.
---------------------------------------------------------------------------
As noted above, for the proposed Transport Rule EPA projected for
each PM2.5 monitor the measured 98th percentile
concentrations from the 2003-2007 period to the future. As an
additional check, we also projected the next highest concentrations
from the three calendar quarters in each year when the 98th percentile
did not occur in the 2003-2007 base period, to ensure that the future
year 98th percentile did not switch seasons in the future year compared
to the base year. A basic assumption in this methodology is that the
distribution of high measured days in the base period will be the same
in the future.
In other words, EPA assumed at proposal that the 98th-percentile
day could only be displaced ``from below'' in the instance that a
different day's future concentration exceeded the original 98th-
percentile day's future concentration. In that case, the original 98th-
percentile day may become the 97th- or 96th-percentile day in the
future year; EPA accounted for this possibility at proposal. EPA did
not, however, consider that the 98th-percentile day could also be
displaced ``from above'' in the instance that higher-concentration days
in the base period were projected to have future concentrations lower
than the original 98th-percentile day's future concentration. In that
case, the original 98th-percentile day may become the 99th- or 100th-
percentile day. Because EPA continued to use that day's future
concentration to determine the monitor's future design value at
proposal, this sometimes resulted in overstatement of future-year
design values for 24-hour PM2.5 monitoring sites whose
seasonal distribution of highest-concentration 24-hour PM2.5
days changed between the 2003-2007 period and the future year modeling.
Examination of the proposed rule remedy modeling (2014 remedy case)
showed that many of the highest PM2.5 days switched from the
summer in the base period to the winter in the future period. This is
especially true in areas of the upper Midwest which experience both
high summer and winter PM2.5 episodes.
In the revised methodology, we do not assume that the seasonal
distribution of high days in the base period years and future years
will remain the same. We project a larger set of ambient days from the
base period to the future and then re-rank the entire set of days to
find the new future 98th percentile value (for each year). More
specifically, we project the highest 8 days per quarter (32 days per
year) to the future and then re-rank the 32 days to derive the future
year 98th percentile concentrations. In the case of the Transport Rule
model results, this has the effect of lowering the future year 24-hour
design values compared to the old methodology.
The modeling guidance recommendations for state attainment
demonstrations have been updated to reflect the changes outlined above.
Further details on the 24-hour PM2.5 design value
calculations can be found in the Air Quality Modeling Final Rule TSD.
The above procedures for determining future year 24-hour
PM2.5 concentrations were applied for each site. The 24-hour
PM2.5 design values are truncated after the first decimal
place. This approach is consistent with the ambient data truncation and
rounding procedures for the 24-hour PM2.5 NAAQS. Any value
that is greater than or equal to 35.5 [micro]g/m\3\ is rounded to 36
[mu]g/m\3\ and is violating the NAAQS. Sites with future year 5-year
weighted average design values of 35.5 [mu]g/m\3\ or greater, based on
the projection of 5-year weighted average concentrations, are predicted
to be nonattainment. Sites with future year maximum design values of
35.5 [micro]g/m\3\ or greater are predicted to be maintenance sites.
Note that nonattainment sites for the 24-hour NAAQS are also
maintenance sites because the maximum design value is always greater
than or equal to the 5-year weighted average. The monitoring
[[Page 48235]]
sites that we project to be nonattainment and/or maintenance for the
24-hour PM2.5 NAAQS in the 2012 base case are the
nonattainment/maintenance receptors used for assessing the contribution
of emissions in upwind states to downwind nonattainment and maintenance
of 24-hour PM2.5 NAAQS as part of this final rule.
Table V.C-3 contains the 2003-2007 base period average and maximum
24-hour PM2.5 design values and the 2012 base case average
and maximum design values for sites projected to be 2012 nonattainment
of the 24-hour PM2.5 NAAQS in 2012. Table V.C-4 contains
this same information for projected 2012 24-hour maintenance sites.
Table V.C-3--Average and Maximum 2003-2007 and 2012 Base Case 24-Hour PM2.5 Design Values ([mu]g/m3) at Projected Nonattainment Sites
--------------------------------------------------------------------------------------------------------------------------------------------------------
Final rule Final rule
Monitor ID State County Average design Maximum design average design maximum design
value 2003-2007 value 2003-2007 value 2012 value 2012
--------------------------------------------------------------------------------------------------------------------------------------------------------
010730023.................... Alabama................. Jefferson.............. 44.0 44.2 36.9 37.3
170311016.................... Illinois................ Cook................... 43.0 46.3 37.5 40.4
171191007.................... Illinois................ Madison................ 39.1 40.1 36.5 36.8
180970043.................... Indiana................. Marion................. 38.4 39.9 35.7 37.1
180970066.................... Indiana................. Marion................. 38.3 39.6 35.7 36.9
180970081.................... Indiana................. Marion................. 38.2 39.2 35.8 36.9
261470005.................... Michigan................ St Clair............... 39.6 40.6 36.2 37.1
261630015.................... Michigan................ Wayne.................. 40.1 40.6 35.5 36.0
261630016.................... Michigan................ Wayne.................. 42.9 45.4 38.9 41.2
261630019.................... Michigan................ Wayne.................. 40.9 41.4 37.3 37.8
261630033.................... Michigan................ Wayne.................. 43.8 44.2 39.4 39.8
390350038.................... Ohio.................... Cuyahoga............... 44.2 47.0 39.4 41.8
390350060.................... Ohio.................... Cuyahoga............... 42.1 45.7 37.7 40.8
420030064.................... Pennsylvania............ Allegheny.............. 64.2 68.2 56.7 59.9
420030093.................... Pennsylvania............ Allegheny.............. 45.6 51.5 39.1 44.3
420030116.................... Pennsylvania............ Allegheny.............. 42.5 42.5 35.5 35.5
420070014.................... Pennsylvania............ Beaver................. 43.4 44.6 36.2 37.4
420710007.................... Pennsylvania............ Lancaster.............. 40.8 44.0 35.9 38.3
540090011.................... West Virginia........... Brooke................. 43.9 44.9 37.5 38.3
550790043.................... Wisconsin............... Milwaukee.............. 39.9 40.8 36.2 37.1
--------------------------------------------------------------------------------------------------------------------------------------------------------
Table V.C-4--Average and Maximum 2003-2007 and 2012 Base Case 24-Hour PM2.5 Design Values ([micro]g/m\3\) at Projected Maintenance-Only Sites
--------------------------------------------------------------------------------------------------------------------------------------------------------
Final rule Final rule
Monitor ID State County Average design Maximum design average design maximum design
value 2003-2007 value 2003-2007 value 2012 value 2012
--------------------------------------------------------------------------------------------------------------------------------------------------------
010732003.................... Alabama................. Jefferson.............. 40.3 40.8 35.3 35.9
170310052.................... Illinois................ Cook................... 40.2 41.4 34.9 36.0
170312001.................... Illinois................ Cook................... 37.7 40.6 33.6 36.1
170313301.................... Illinois................ Cook................... 40.2 43.3 34.9 37.6
170316005.................... Illinois................ Cook................... 39.1 41.8 34.1 36.4
171190023.................... Illinois................ Madison................ 37.3 38.1 35.1 35.8
180890022.................... Indiana................. Lake................... 38.9 44.0 34.9 39.5
180890026.................... Indiana................. Lake................... 38.4 41.3 34.0 37.0
261610008.................... Michigan................ Washtenaw.............. 39.4 40.8 35.0 36.3
390170003.................... Ohio.................... Butler................. 39.2 41.1 34.4 36.5
390350045.................... Ohio.................... Cuyahoga............... 38.5 41.5 34.7 38.1
390350065.................... Ohio.................... Cuyahoga............... 38.6 41.0 34.9 37.6
390618001.................... Ohio.................... Hamilton............... 40.6 40.9 35.2 35.8
390811001.................... Ohio.................... Jefferson.............. 41.9 45.5 34.5 37.8
391130032.................... Ohio.................... Montgomery............. 37.8 40.0 33.6 35.6
420031008.................... Pennsylvania............ Allegheny.............. 41.3 42.8 35.0 36.3
420031301.................... Pennsylvania............ Allegheny.............. 40.3 42.4 33.9 35.6
420033007.................... Pennsylvania............ Allegheny.............. 37.5 43.1 32.3 37.3
421330008.................... Pennsylvania............ York................... 38.2 40.7 33.3 36.0
550790010.................... Wisconsin............... Milwaukee.............. 38.6 40.0 35.4 36.7
550790026.................... Wisconsin............... Milwaukee.............. 37.3 41.3 33.6 37.2
--------------------------------------------------------------------------------------------------------------------------------------------------------
(3) Methodology for Projecting Future 8-Hour Ozone Nonattainment and
Maintenance
The final rule methodology to calculate 8-hour ozone nonattainment
and maintenance receptors is identical to the proposed rule. The May-
to-September 24-hour maximum 8-hour average concentrations from the
2005 base case and the 2012 base case were used to project ambient
design values to 2012. The following is a brief summary of the future
year 8-hour average ozone calculations. Additional details are provided
in the Air Quality Modeling Final Rule TSD.
We are using the base period 2003-2007 ambient ozone design value
data for projecting future year design values. Relative response
factors (RRF) for each monitoring site were calculated as the
[[Page 48236]]
percent change in ozone on days with modeled ozone greater than 85
ppb.\30\
---------------------------------------------------------------------------
\30\ As specified in the attainment demonstration modeling
guidance, if there are less than 10 modeled days > 85 ppb, then the
threshold is lowered in 1 ppb increments (to as low as 70 ppb) until
there are 10 days. If there are less than 5 days > 70 ppb, then an
RRF calculation is not completed for that site.
---------------------------------------------------------------------------
The maximum future design value is calculated by projecting design
values for each of the three base periods (2003-2005, 2004-2006, and
2005-2007) separately. The highest of the three future values is the
maximum design value. This maximum value is used to identify the 8-hour
ozone maintenance receptors.
The future year design values are truncated to integers in units of
ppb. This approach is consistent with the ambient data truncation and
rounding procedures for the 8-hour ozone NAAQS. Future year design
values that are greater than or equal to 85 ppb are considered to be
violating the NAAQS. Sites with future year 5-year weighted average
design values of 85 ppb or greater are predicted to be nonattainment.
Sites with future year maximum design values of 85 ppb or greater are
predicted to be future year maintenance sites. Note that, as described
previously for the annual and 24-hour PM2.5 NAAQS,
nonattainment sites for the ozone NAAQS are also maintenance sites
because the maximum design value is always greater than or equal to the
5-year weighted average. The monitoring sites that we project to be
nonattainment and/or maintenance for the 8-hour ozone NAAQS in the 2012
base case are the nonattainment/maintenance receptors used for
assessing the contribution of emissions in upwind states to downwind
nonattainment and maintenance of ozone NAAQS.
Table V.C-5 contains the 2003-2007 base period average and maximum
8-hour ozone design values and the 2012 base case average and maximum
design values for sites projected to be 2012 nonattainment of the 8-
hour ozone NAAQS in 2012. Table V.C-6 contains this same information
for projected 2012 8-hour ozone maintenance sites.
Table V.C-5--Average and Maximum 2003-2007 and 2012 Base Case 8-Hour Ozone Design Values (ppb) at Projected Nonattainment Sites
--------------------------------------------------------------------------------------------------------------------------------------------------------
Final rule Final rule
Monitor ID State County Average design Maximum design average design maximum design
value 2003-2007 value 2003-2007 value 2012 value 2012
--------------------------------------------------------------------------------------------------------------------------------------------------------
220330003.................... Louisiana............... East Baton Rouge....... 92.0 96 85.6 89.3
480391004.................... Texas................... Brazoria............... 94.7 97 86.7 88.8
482010051.................... Texas................... Harris................. 93.0 98 86.1 90.8
482010055.................... Texas................... Harris................. 100.7 103 93.3 95.4
482010062.................... Texas................... Harris................. 95.7 99 88.8 91.8
482010066.................... Texas................... Harris................. 92.3 96 87.1 90.6
482011039.................... Texas................... Harris................. 96.3 100 88.8 92.2
--------------------------------------------------------------------------------------------------------------------------------------------------------
Table V.C-6--Average and Maximum 2003-2007 and 2012 Base Case 8-Hour Ozone Design Values (ppb) at Projected Maintenance-Only Sites
--------------------------------------------------------------------------------------------------------------------------------------------------------
Average design Maximum design Average design Maximum design
Monitor ID State County value 2003-2007 value 2003-2007 value 2012 value 2012
--------------------------------------------------------------------------------------------------------------------------------------------------------
090011123.................... Connecticut............. Fairfield.............. 92.3 94 83.9 85.5
090093002.................... Connecticut............. New Haven.............. 90.3 93 82.7 85.1
240251001.................... Maryland................ Harford................ 92.7 94 84.4 85.6
260050003.................... Michigan................ Allegan................ 90.0 93 82.4 85.1
482010024.................... Texas................... Harris................. 88.0 92 83.4 87.2
482010029.................... Texas................... Harris................. 91.7 93 84.2 85.4
482011015.................... Texas................... Harris................. 89.0 96 82.4 88.9
482011035.................... Texas................... Harris................. 86.3 95 79.9 88.0
482011050.................... Texas................... Harris................. 89.3 92 82.8 85.4
--------------------------------------------------------------------------------------------------------------------------------------------------------
D. Pollution Transport From Upwind States
1. Choice of Air Quality Thresholds
a. Thresholds
In this action, EPA uses air quality thresholds to identify
linkages between upwind states and downwind nonattainment and
maintenance receptors. States whose contributions to a specific
receptor meet or exceed the thresholds identified are considered linked
to that receptor; those states' emissions (and available emission
reductions) are analyzed further in the second step of EPA's
significant contribution analysis. States whose contributions are below
the thresholds are not included in the Transport Rule for that NAAQS.
In other words, we are finding that states whose contributions are
below these thresholds do not significantly contribute to nonattainment
or interfere with maintenance of the relevant NAAQS.
We use separate air quality thresholds for annual PM2.5,
24-hour PM2.5, and 8-hour ozone. Each air quality threshold
is calculated as 1 percent of the NAAQS. Specifically, we use an air
quality threshold of 0.15 [mu]g/m\3\ for annual PM2.5, 0.35
[mu]g/m\3\ for 24-hour PM2.5, and 0.8 ppb for 8-hour ozone.
These are the same air quality thresholds we proposed.
EPA received a number of comments on the thresholds we proposed,
and those comments and EPA's responses are discussed below.
b. General Comments on the Overall Stringency and Use of 1 Percent of
the NAAQS
EPA received numerous comments supporting and opposing the proposed
thresholds. A number of commenters cited support for EPA's approach.
Some
[[Page 48237]]
commenters believed that use of a 1 percent threshold was too
stringent, and recommended that EPA should use a threshold greater than
1 percent. Others believed that 1 percent was not stringent enough, and
they recommended using a lower value such as 0.5 percent. EPA believes
that for both PM2.5 and for ozone, it is appropriate to use
a threshold of 1 percent of the NAAQS for identifying states whose
contributions do not significantly contribute to nonattainment or
interfere with maintenance of the relevant NAAQS; therefore, EPA has
retained the 1 percent threshold for the reasons described below.
As we found at the time of CAIR, EPA's analysis of base case
PM2.5 transport shows that, in general, PM2.5
nonattainment problems result from the combined impact of relatively
small contributions from many upwind states, along with contributions
from in-state sources and, in some cases, substantially larger
contributions from a subset of particular upwind states. (See section
II of the January 2004 CAIR proposal, 69 FR 4575-87).
In the 1998 NOX SIP Call (63 FR 57456, October 27, 1998)
and in CAIR, EPA also found important contributions from multiple
upwind states. As a result of the upwind ``collective contributions,''
EPA determined that it is appropriate to use a low air quality
threshold when analyzing upwind states' contributions to downwind
states' attainment and maintenance problems for ozone as well as
PM2.5.
Low threshold values are also warranted, as EPA discussed in the
notices for CAIR, due to adverse health impacts associated with ambient
PM2.5 and ozone even at low concentrations (See relevant
portions of the CAIR proposal notice (63 FR 4583-84) and the CAIR final
rule notice (70 FR 25189-25192)).
To aid in responding to comments, EPA has compiled the contribution
modeling results to analyze the impact of different possible
thresholds. This analysis demonstrates the reasonableness of using the
1 percent threshold to account for the combined impact of relatively
small contributions from many upwind states (see Air Quality Modeling
Final Rule TSD). In this analysis, EPA identifies for annual
PM2.5 (sulfate and nitrate), 24-hour PM2.5
(sulfate and nitrate), and 8-hour ozone receptors: (1) Total upwind
state contributions, and (2) the amount of the total upwind state
contribution that is captured at thresholds of 1 percent, 5 percent and
0.5 percent of the NAAQS. EPA continues to find that the total
``collective contribution'' from upwind sources represents a large
portion of PM2.5 and ozone at downwind locations and that
the total amount of transport is composed of the individual
contribution from numerous upwind states.
The analysis shows that the 1 percent threshold captures a high
percentage of the total pollution transport affecting downwind states
for both PM2.5 and ozone. In response to commenters who
advocated a higher threshold, EPA observes that higher thresholds would
exclude increasingly large percentages of total transport, which we do
not believe would be appropriate. For example, a 5 percent threshold
would exclude the majority--and for annual PM, more than 80 percent--of
interstate pollution transport affecting the downwind state receptors
analyzed (based on the average percentage of total interstate transport
across all receptors captured at the 5 percent threshold).
In response to commenters who advocated a lower threshold, EPA
observes that the analysis shows that a lower threshold such as 0.5
percent would result in relatively modest increases in the overall
percentages of PM2.5 and ozone pollution transport captured
relative to the amounts captured at the 1 percent level. A 0.5 percent
threshold could lead to emission reduction responsibilities in
additional states that individually have a very small impact on those
receptors--an indicator that emission controls in those states are
likely to have a smaller air quality impact at the downwind receptor.
We are not convinced that selecting a threshold below 1 percent is
necessary or desirable. A strong indication that the amount of
pollution transport being excluded from consideration is not excessive
is that the controls required under this rule are projected to
eliminate nonattainment and maintenance problems with air quality
standards at most downwind state receptors.
Considering the combined downwind impact of multiple upwind states,
the health effects of low levels of PM2.5 and ozone
pollution, and EPA's previous use of a 1 percent threshold for
PM2.5 in CAIR, EPA's judgment is that the 1 percent
threshold is a reasonable choice.
Some commenters noted that the PM2.5 thresholds used for
this rule are less than the ``significant impact levels'' (SILs) used
for permitting programs. As EPA stated at the time of CAIR, since the
thresholds referred to by the commenters serve different purposes than
the CAIR threshold for significant contribution, it does not follow
that they should be made equivalent (70 FR 25191; May 12, 2005).
c. Comments on the Rounding Conventions for PM2.5
In the final Transport Rule, EPA is using two-digit values for the
PM2.5 thresholds. Some commenters suggested that EPA should
use the same rounding convention for annual PM2.5 used in
CAIR; that is, the threshold should be 0.2 [mu]g/m\3\ rather than 0.15
[mu]g/m\3\. The reasons for EPA's decision are below.
The rationale for the single digit value for the final CAIR rule
was that a single digit is consistent with the EPA monitoring data
reporting requirements in Part 50, Appendix N, section 4.3. These
reporting requirements specify that design values for the annual
PM2.5 standard shall be rounded to the tenths place
(decimals 0.05 and greater are rounded up to the next 0.1, and any
decimal lower than 0.05 is rounded down to the nearest 0.1).
Because the design value is to be reported only to the nearest 0.1
[mu]g/m\3\, EPA deemed it preferable for the final CAIR to select the
threshold value at the nearest 0.1 [mu]g/m\3\ as well, and hence one
percent of the 15 [mu]g/m\3\, rounded to the nearest 0.1 [mu]g/m\3\
became 0.2 [mu]g/m\3\.
The reporting requirements in section Part 50, Appendix N, section
4.3 for the 24-hour PM2.5 standard state that design values
for this standard shall be rounded to the nearest 1 [mu]g/m\3\
(decimals 0.5 and greater are rounded up to the nearest whole number,
and any decimal lower than 0.5 is rounded down to the nearest whole
number).
If the approach used in CAIR were to be used to establish an air
quality threshold for the 24-hour PM2.5 NAAQS (which CAIR
did not address), the resulting threshold would be zero. One percent of
the 24-hour standard is 0.35 [mu]g/m\3\, and rounding to the nearest
whole number would yield an air quality threshold of zero. Thus if we
were to apply the same rationale used to develop the annual
PM2.5 threshold for the final CAIR, there would be no air
quality threshold for 24-hour PM2.5, which EPA believes to
be counter-intuitive and unworkable as an approach for assessing
interstate contributions.
Therefore, for this rule, EPA proposed and is now finalizing an
approach that decouples the precision of the air quality thresholds
from the monitoring reporting requirements, and uses 2-digit values
representing one percent of the PM2.5 NAAQS; that is, 0.15
[mu]g/m\3\ for the annual standard, and 0.35 [mu]g/m\3\ for the 24-hour
standard. EPA believes there are a number of considerations favoring
this approach. First, it provides for a consistent approach for the
annual and 24-hour standards. Second, the
[[Page 48238]]
approach is readily applicable to any current and future NAAQS and
would automatically adjust the stringency of the transport threshold to
maintain a constant relationship with the stringency of the relevant
NAAQS as they are revised. The CAIR approach would not allow for this
continuity: For example, if EPA were to retain the CAIR approach for
the annual standard, any future lowering of the PM2.5 NAAQS
to below 15 [mu]g/m\3\ would reduce the air quality threshold to the
same outcome: 0.1 [mu]g/m\3\. This would occur because any value less
than 0.15 [mu]g/m\3\ would round to 0.1 [mu]g/m\3\ (assuming EPA would
not round down to zero for the reasons described above), which means
that the air quality threshold would have a different relative
stringency to each possible future NAAQS value. For the above reasons,
EPA believes the use of two-digit thresholds for both annual
PM2.5 and 24-hour PM2.5 in the final rule is both
reasonable and appropriate. The departure from the approach used for
annual PM2.5 in CAIR is appropriate given the additional
considerations that were not in existence at the time of the final
CAIR, and the importance of using a consistent approach to developing
air quality thresholds for all NAAQS addressed by this rule as well as
future NAAQS considered in future transport-related actions.
Some of these commenters suggested using the CAIR rounding
conventions coupled with use of a 1-digit threshold of 0.4 [mu]g/m\3\
for 24-hour PM2.5. EPA considered the approach suggested by
commenters, but determined that the proposed approach is more
appropriate. First, adhering to the rounding conventions used for CAIR
for annual PM2.5 is not workable for the 24-hour standard
because the rounding convention would yield a threshold of zero.
Rounding alternatively to 0.4 [mu]g/m\3\ would require EPA to find a
basis for rounding the threshold to the nearest 0.1 [mu]g/m\3\ instead
of using a strict application of 1 percent; we do not see any basis for
such rounding at this time.
d. Comments Related to the Multi-Factor Test EPA Used for Ozone in CAIR
Some commenters suggested that, for ozone, EPA should use the
multiple-metric test we used for CAIR, and not a simple threshold based
on 1 percent of the NAAQS. With respect to ozone, EPA proposed in the
Transport Rule to take a more straightforward approach to air quality
thresholds than the multi-factor approaches used for the NOX
SIP Call and the CAIR. As proposed, EPA is using a contribution metric
that is calculated based on the multi-day average contribution. This
metric is compared to one percent of the 1997 8-hour ozone standard of
0.08 ppm. Under this approach, one percent of the NAAQS is a value of
0.8 ppb. Contributions of 0.8 ppb and higher are above the threshold;
ozone contributions less than 0.8 ppb are below the threshold. In past
rulemakings (e.g., CAIR) EPA used multiple ozone metrics, including the
average contribution and maximum single day contribution to downwind
nonattainment. EPA believes the average contribution (calculated over
multiple high ozone days) is a robust metric compared to the maximum
contribution on a single day. EPA believes that this approach is
preferable because it uses a robust metric, it is consistent with the
approach for PM2.5, and it provides for a consistent
approach that takes into account, and is applicable to, any future
ozone standards below 0.08 ppm.
One of these commenters suggested that the 0.8 ppb threshold value
was substantially more stringent than the 2 ppb screening test which
was a part of the approach used for CAIR. The 1 percent threshold (0.8
ppb) is not substantially more stringent than the previous 2 ppb test
because of differences in the metrics used to evaluate contributions
against these two levels. The 2 ppb test was evaluated using the
highest single day absolute model-predicted downwind contribution from
an upwind state. The 1 percent threshold is evaluated based on the
average relative downwind impact calculated over multiple days.
Therefore, it is appropriate to set a lower concentration threshold for
use with the average contribution metric calculated for the Transport
Rule. More details on the calculation of the contribution metric can be
found in the Air Quality Modeling Final Rule TSD. As noted above, EPA
believes that the approach used for the proposed rule provides for a
simplified, yet robust approach compared to CAIR. Accordingly, for the
final rule we have retained the approach used for the proposal.
One commenter suggested that EPA retain the CAIR multiple-factor
approach for ozone, and to apply that same approach to 24-hour
PM2.5. As noted above, EPA is not retaining this approach
for ozone, and for similar reasons we believe a multi-factor approach
is not needed for 24-hour PM2.5. The approach based on 1
percent of the NAAQS is consistent with the form of the 24-hour
standard. In addition, this approach is based on contributions on days
with high 24-hour PM2.5 predictions and therefore is
relevant for characterizing transport during short-term high
PM2.5 episodic conditions.
e. Comments on the Relationship to Measurement Precision
Other commenters suggested that, as did commenters on the
thresholds used in CAIR, EPA should take into consideration the
measurement precision of existing PM2.5 monitors in setting
the thresholds for the Transport Rule. EPA disagrees that monitoring
precision is relevant to determining the amount of modeled
PM2.5 or ozone that should be considered to be a
``contribution'' from upwind states since states are not required to,
nor would it be possible for them to, measure their individual state
impacts on downwind receptors. The approach for eliminating significant
contribution is based on the implementation of enforceable emissions
budgets and not on a measurement of ambient air quality. Thus, EPA
believes it is a reasonable exercise of its discretion to de-couple
monitoring precision from the choice of contribution states.
f. Comments Related to the CAIR Court Decision
Commenters recommended that EPA should have retained the criteria
used for CAIR because those values were upheld by the Court. As noted
above, EPA could not have used the approach for annual PM2.5
that was used in CAIR to develop a 24-hour PM2.5 threshold,
as that approach would have yielded a threshold value of zero 24-hour
PM2.5.
Further, nothing in the North Carolina opinion suggests that the
thresholds and methods used in CAIR were the only possible approaches
EPA could have used, that they were preferable to other approaches, or
that other alternatives would not be acceptable. Instead, the Court
upheld the 0.2 [micro]g/m\3\ threshold used for PM2.5 on the
grounds that it was not ``wholly unsupported by the record'' (North
Carolina, 531 F.3d at 915). EPA has determined for reasons explained in
the record that the thresholds used in this final rule are both
reasonable and appropriate for use in this final rule.
2. Approach for Identifying Contributing Upwind States
This section documents the procedures used by EPA to quantify the
contribution of emissions in specific upwind states to air quality
concentrations in projected 2012 downwind nonattainment and maintenance
locations for annual PM2.5, 24-hour PM2.5, and 8-
hour ozone. In the
[[Page 48239]]
proposed rule EPA used CAMx photochemical source apportionment modeling
to quantify the impact of emissions in specific upwind states on
projected downwind nonattainment and maintenance receptors for both
PM2.5 and 8-hour ozone. In this modeling we tracked the
ozone and PM2.5 formed from 2012 base case emissions from
anthropogenic sources in each upwind state in the 12 km modeling
domain. The CAMx Particulate Source Apportionment Technique (PSAT) was
used to calculate downwind contributions to nonattainment and
maintenance of PM2.5. In the PSAT simulation NOX
emissions are tracked to particulate nitrate concentrations,
SO2 emissions are tracked to particulate sulfate
concentrations, and primary particulates (organic carbon, elemental
carbon, and other PM2.5) are tracked as primary
particulates. As described earlier in section V.A, the nitrate and
sulfate contributions were combined and used to evaluate interstate
contributions of PM2.5.
The CAMx Ozone Source Apportionment Technique (OSAT) was used to
calculate downwind 8-hour ozone contributions to nonattainment and
maintenance. OSAT tracks the formation of ozone from NOX and
VOC emissions.
Comment: Three commenters stated that the CAMx source apportionment
techniques used for the proposed rule reflect state-of-the science
technologies and are appropriate for evaluating interstate transport.
One commenter asked that EPA do more to demonstrate that the PSAT and
OSAT techniques give reliable answers, although no suggestions were
provided on how this might be done. Another commenter said that the
results of the contribution analyses were consistent with the results
of their scientific research.
Response: EPA is not changing its conclusion that the CAMx source
apportionment techniques are appropriate for quantifying interstate
transport. The strength of the source apportionment technique is that
all modeled ozone and/or PM2.5 mass at a given location in
the modeling domain is tracked back to specific sources of emissions
and boundary conditions to fully characterize culpable sources. No
commenters provided technically valid analyses indicating that EPA's
use of CAMx source apportionment techniques are inappropriate for the
purposes of the Transport Rule.
Comment: We received comments that certain states included in the
proposed rule should be excluded from the final rule because EPA had
overstated the 2012 emissions in these states. Commenter requested that
we redo the contribution modeling using 2012 base case emission
inventories that are revised based on proposed rule comments. Several
commenters also asked that EPA update the contribution modeling
analyses using the latest version of CAMx.
Response: In response to these comments, we have rerun our source
apportionment modeling for PM2.5 and ozone for the 2012 base
case using the updated emission inventories described above in section
V.C.1 and the latest version of CAMx, version 5.30.
The states EPA analyzed for interstate contributions for ozone and
for PM2.5 for the final rule are: Alabama, Arkansas,
Connecticut, Delaware, Florida, Georgia, Illinois, Indiana, Iowa,
Kansas, Kentucky, Louisiana, Maine, Maryland,\31\ Massachusetts,
Michigan, Minnesota, Mississippi, Missouri, Nebraska, New Hampshire,
New Jersey, New York, North Carolina, North Dakota, Ohio, Oklahoma,
Pennsylvania, Rhode Island, South Carolina, South Dakota, Tennessee,
Texas, Vermont, Virginia, West Virginia, and Wisconsin.\32\ These are
the same states that EPA analyzed for the proposed rule.
---------------------------------------------------------------------------
\31\ As in the proposal, EPA has combined the contributions from
Maryland and the District of Columbia as a single entity in our
contribution analysis for the final rule. EPA believes that this is
a fair representation of emissions for transport analysis because of
the small size of the District of Columbia and its close proximity
to Maryland. However, the District of Columbia is not included in
the Transport Rule due to the significant contribution analysis
findings in section VI.D.
\32\ There were also several other states that are only
partially contained within the 12 km modeling domain (i.e.,
Colorado, Montana, New Mexico, and Wyoming). However, EPA did not
individually track the emissions or assess the contribution from
emissions in these states.
---------------------------------------------------------------------------
For the proposed rule, we used a relative approach for calculating
the contributions to downwind nonattainment and maintenance receptors
from the outputs of the source apportionment modeling. As part of this
approach, the source apportionment predictions are combined with
measurement-based concentrations to calculate the contributions from
each state to nonattainment and/or maintenance receptors. This is
similar to the approach used to calculate future year design values, as
described in section V.C.2.
Comment: One commenter said that using the source apportionment
modeling predictions in a relative sense strengthens the determination
of contributions and addresses an important source of uncertainty.
There were no comments that suggested an alternative approach.
Response: For the final Transport Rule we are applying the relative
approach developed for the proposed rule to calculate contributions
from each state to downwind nonattainment and maintenance receptors.
As noted above, for the final rule we modeled the updated 2012 base
case emissions using CAMX v5.30 to determine the
contributions from emissions in upwind states to nonattainment and
maintenance sites in downwind states. Contributions to nonattainment
and maintenance receptors are evaluated independently for each state to
determine if the contributions are at or above the threshold criteria.
For each upwind state, the maximum contribution to nonattainment is
calculated based on the single largest contribution to a future year
(2012) downwind nonattainment receptor. The maximum contribution to
maintenance is calculated based on the single largest contribution to a
future year (2012) downwind maintenance receptor. Since the
contributions are calculated independently for each receptor, the
upwind contribution to maintenance can sometimes be larger than the
contribution to nonattainment, and vice versa. This also means that
maximum contributions to nonattainment can be below the threshold while
maximum contributions to maintenance may be at or above the threshold,
or vice versa.
V.D.2.a. Estimated Interstate Contributions to Annual PM2.5
and 24-Hour PM2.5
In this section, we present the interstate contributions from
emissions in upwind states to downwind nonattainment and maintenance
sites for the annual PM2.5 NAAQS and the 24-hour
PM2.5 NAAQS based on modeling updated for the final rule. As
described previously in section V.D.1, states which contribute 0.15
[mu]g/m\3\ or more to annual PM2.5 nonattainment or
maintenance in another state are identified as states with
contributions large enough to warrant further analysis. For 24-hour
PM2.5, states which contribute 0.35 [mu]g/m \3\ or more to
24-hour PM2.5 nonattainment or maintenance in another state
are identified as states with contributions to downwind nonattainment
and maintenance sites large enough to warrant further analysis.
For annual PM2.5, we calculated each state's
contribution to each of the 12 monitoring sites that are projected to
be nonattainment and each of the 4 sites that are projected to have
maintenance problems for the annual PM2.5 NAAQS in the 2012
base case. A detailed
[[Page 48240]]
description of the calculations can be found in the Air Quality
Modeling Final Rule TSD. The largest contribution from each state to
annual PM2.5 nonattainment in downwind sites is provided in
Table V.D-1. The Largest Contribution from Each State to Annual
PM2.5 maintenance in downwind sites is also provided in
Table V.D-1. The contributions from each state to all projected 2012
nonattainment and maintenance sites for the annual PM2.5
NAAQS are provided in the Air Quality Modeling Final Rule TSD.
Table V.D-1--Largest Contribution to Downwind Annual PM2.5 ([mu]g/m\3\)
Nonattainment and Maintenance for Each of 37 States
------------------------------------------------------------------------
Largest downwind Largest downwind
contribution to contribution to
Upwind state nonattainment for maintenance for
annual PM2.5 annual PM2.5
([mu]g/m\3\) ([mu]g/m\3\)
------------------------------------------------------------------------
Alabama......................... 0.51 0.19
Arkansas........................ 0.10 0.04
Connecticut..................... 0.00 0.00
Delaware........................ 0.00 0.00
Florida......................... 0.08 0.01
Georgia......................... 0.46 0.13
Illinois........................ 0.50 0.65
Indiana......................... 1.34 1.27
Iowa............................ 0.26 0.14
Kansas.......................... 0.09 0.04
Kentucky........................ 0.94 0.81
Louisiana....................... 0.09 0.03
Maine........................... 0.00 0.00
Maryland........................ 0.15 0.06
Massachusetts................... 0.00 0.00
Michigan........................ 0.64 0.64
Minnesota....................... 0.14 0.09
Mississippi..................... 0.05 0.01
Missouri........................ 1.22 0.27
Nebraska........................ 0.06 0.03
New Hampshire................... 0.00 0.00
New Jersey...................... 0.02 0.01
New York........................ 0.21 0.21
North Carolina.................. 0.20 0.06
North Dakota.................... 0.06 0.04
Ohio............................ 1.34 0.94
Oklahoma........................ 0.08 0.03
Pennsylvania.................... 0.54 0.54
Rhode Island.................... 0.00 0.00
South Carolina.................. 0.24 0.04
South Dakota.................... 0.03 0.01
Tennessee....................... 0.32 0.32
Texas........................... 0.18 0.07
Vermont......................... 0.00 0.00
Virginia........................ 0.12 0.06
West Virginia................... 0.95 0.40
Wisconsin....................... 0.22 0.19
------------------------------------------------------------------------
Based on the state-by-state contribution analysis, there are 18
states \33\ which contribute 0.15 [mu]g/m\3\ or more to downwind annual
PM2.5 nonattainment. These states are: Alabama, Georgia,
Illinois, Indiana, Iowa, Kentucky, Maryland, Michigan, Missouri, New
York, North Carolina, Ohio, Pennsylvania, South Carolina, Tennessee,
Texas, West Virginia, and Wisconsin. In Table V.D-2, we provide a list
of the downwind nonattainment sites to which each upwind state
contributes 0.15 [mu]g/m\3\ or more (i.e., the upwind state to downwind
nonattainment ``linkages'').
---------------------------------------------------------------------------
\33\ As in the proposal, EPA has combined the contributions from
Maryland and the District of Columbia as a single entity in our
contribution analysis for the final rule. EPA believes that this is
a fair representation of emissions for transport analysis because of
the small size of the District of Columbia and its close proximity
to Maryland. However, the District of Columbia is not included in
the Transport Rule due to the significant contribution analysis
findings in section VI.D.
---------------------------------------------------------------------------
There are 12 states which contribute 0.15 [mu]g/m\3\ or more to
downwind annual PM2.5 maintenance. These states are:
Alabama, Illinois, Indiana, Kentucky, Michigan, Missouri, New York,
Ohio, Pennsylvania, Tennessee, West Virginia, and Wisconsin. In Table
V.D-3, we provide a list of the downwind maintenance sites to which
each upwind state contributes 0.15 [mu]g/m\3\ or more (i.e., the upwind
state to downwind maintenance ``linkages'').
[[Page 48241]]
Table V.D-2--Upwind State to Downwind Nonattainment Site ``Linkages'' for Annual PM2.5
----------------------------------------------------------------------------------------------------------------
----------------------------------------------------------------------------------------------------------------
Upwind state Downwind receptor sites
----------------------------------------------------------------------------------------------------------------
Alabama..................... Fulton, GA Hamilton, OH Hamilton, OH Hamilton, OH
(131210039). (390610014). (390610042). (390618001).
Georgia..................... Jefferson, AL Jefferson, AL
(10730023). (10732003).
Illinois.................... Jefferson, AL Fulton, GA Wayne, MI Cuyahoga, OH
(10732003). (131210039). (261630033). (390350038).
Cuyahoga, OH Cuyahoga, OH Hamilton, OH Hamilton, OH
(390350045). (390350060). (390610014). (390610042).
Hamilton, OH Allegheny, PA
(390618001). (420030064).
Indiana..................... Jefferson, AL Jefferson, AL Fulton, GA Madison, IL
(10730023). (10732003). (131210039). (171191007).
Wayne, MI Cuyahoga, OH Cuyahoga, OH Cuyahoga, OH
(261630033). (390350038). (390350045). (390350060).
Hamilton, OH Hamilton, OH Hamilton, OH Allegheny, PA
(390610014). (390610042). (390618001). (420030064).
Iowa........................ Madison, IL
(171191007).
Kentucky.................... Jefferson, AL Jefferson, AL Fulton, GA Madison, IL
(10730023). (10732003). (131210039). (171191007).
Wayne, MI Cuyahoga, OH Cuyahoga, OH Cuyahoga, OH
(261630033). (390350038). (390350045). (390350060).
Hamilton, OH Hamilton, OH Hamilton, OH Allegheny, PA
(390610014). (390610042). (390618001). (420030064).
Maryland.................... Allegheny, PA
(420030064).
Michigan.................... Madison, IL Cuyahoga, OH Cuyahoga, OH Cuyahoga, OH
(171191007). (390350038). (390350045). (390350060).
Hamilton, OH Hamilton, OH Hamilton, OH Allegheny, PA
(390610014). (390610042). (390618001). (420030064).
Missouri.................... Madison, IL Cuyahoga, OH Cuyahoga, OH Cuyahoga, OH
(171191007). (390350038). (390350045). (390350060).
Hamilton, OH Hamilton, OH Hamilton, OH
(390610014). (390610042). (390618001).
New York.................... Cuyahoga, OH Cuyahoga, OH Cuyahoga, OH Allegheny, PA
(390350038). (390350045). (390350060). (420030064).
North Carolina.............. Fulton, GA
(131210039).
Ohio........................ Jefferson, AL Jefferson, AL Fulton, GA Madison, IL
(10730023). (10732003). (131210039). (171191007).
Wayne, MI Allegheny, PA
(261630033). (420030064).
Pennsylvania................ Fulton, GA Wayne, MI Cuyahoga, OH Cuyahoga, OH
(131210039). (261630033). (390350038). (390350045).
Cuyahoga, OH Hamilton, OH Hamilton, OH Hamilton, OH
(390350060). (390610014). (390610042). (390618001).
South Carolina.............. Fulton, GA
(131210039).
Tennessee................... Jefferson, AL Jefferson, AL Fulton, GA Madison, IL
(10730023). (10732003). (131210039). (171191007).
Hamilton, OH Hamilton, OH Hamilton, OH
(390610014). (390610042). (390618001).
Texas....................... Madison, IL
(171191007).
West Virginia............... Fulton, GA Wayne, MI Cuyahoga, OH Cuyahoga, OH
(131210039). (261630033). (390350038). (390350045).
Cuyahoga, OH Hamilton, OH Hamilton, OH Hamilton, OH
(390350060). (390610014). (390610042). (390618001).
Allegheny, PA
(420030064).
Wisconsin................... Madison, IL Wayne, MI Cuyahoga, OH Cuyahoga, OH
(171191007). (261630033). (390350038). (390350045)
Cuyahoga, OH Hamilton, OH Hamilton, OH
(390350060). (390610014). (390618001).
----------------------------------------------------------------------------------------------------------------
Table V.D-3--Upwind State to Downwind Maintenance Site ``Linkages'' for Annual PM2.5
----------------------------------------------------------------------------------------------------------------
----------------------------------------------------------------------------------------------------------------
Upwind state Downwind receptor sites
----------------------------------------------------------------------------------------------------------------
Alabama..................... Marion, IN Marion, IN Hamilton, OH
(180970081). (180970083). (390617001).
Illinois.................... Marion, IN Marion, IN Cuyahoga, OH Hamilton, OH
(180970081). (180970083). (390350065). (390617001).
Indiana..................... Cuyahoga, OH Hamilton, OH
(390350065). (390617001).
Kentucky.................... Marion, IN Marion, IN Cuyahoga, OH Hamilton, OH
(180970081). (180970083). (390350065). (390617001).
Michigan.................... Marion, IN Marion, IN Cuyahoga, OH Hamilton, OH
(180970081). (180970083). (390350065). (390617001).
Missouri.................... Marion, IN Marion, IN Cuyahoga, OH Hamilton, OH
(180970081). (180970083). (390350065). (390617001).
New York.................... Cuyahoga, OH
(390350065).
Ohio........................ Marion, IN Marion, IN
(180970081). (180970083).
Pennsylvania................ Marion, IN Marion, IN Cuyahoga, OH Hamilton, OH
(180970081). (180970083). (390350065). (390617001).
Tennessee................... Marion, IN Marion, IN Hamilton, OH
(180970081). (180970083). (390617001).
West Virginia............... Marion, IN Marion, IN Cuyahoga, OH Hamilton, OH
(180970081). (180970083). (390350065). (390617001).
Wisconsin................... Marion, IN Marion, IN Cuyahoga, OH Hamilton, OH
(180970081). (180970083). (390350065). (390617001).
----------------------------------------------------------------------------------------------------------------
For 24-hour PM2.5, we calculated each state's
contribution to each of the 20 monitoring sites that are projected to
be nonattainment and each of the 21 sites that are projected to have
maintenance problems for the 24-hour PM2.5 NAAQS in the 2012
base case. A detailed description of the calculations can be found in
the Air Quality Modeling Final Rule TSD. The largest contribution from
each state to 24-hour PM2.5 nonattainment in downwind sites
is provided in Table V.D-4. The largest contribution from each state to
24-hour PM2.5 maintenance in downwind sites is also provided
in Table V.D-4. The contributions from each state to all projected 2012
nonattainment and maintenance sites for the 24-hour PM2.5
NAAQS are provided in the Air Quality Modeling Final Rule TSD.
Table V.D-4--Largest Contribution to Downwind 24-Hour PM2.5 ([micro]g/
m\3\) Nonattainment and Maintenance for Each of 37 States
------------------------------------------------------------------------
Largest downwind Largest downwind
contribution to contribution to
Upwind state nonattainment for maintenance for 24-
24-hour PM2.5 hour PM2.5 ([mu]g/
([mu]g/m\3\) m\3\)
------------------------------------------------------------------------
Alabama......................... 0.51 0.42
[[Page 48242]]
Arkansas........................ 0.24 0.23
Connecticut..................... 0.10 0.18
Delaware........................ 0.22 0.20
Florida......................... 0.07 0.03
Georgia......................... 1.10 0.92
Illinois........................ 3.72 5.70
Indiana......................... 3.56 5.15
Iowa............................ 0.82 1.55
Kansas.......................... 0.37 0.81
Kentucky........................ 4.38 3.58
Louisiana....................... 0.11 0.13
Maine........................... 0.06 0.10
Maryland........................ 2.83 2.11
Massachusetts................... 0.19 0.30
Michigan........................ 1.86 2.03
Minnesota....................... 0.61 1.01
Mississippi..................... 0.06 0.07
Missouri........................ 3.73 3.71
Nebraska........................ 0.24 0.52
New Hampshire................... 0.05 0.10
New Jersey...................... 0.68 0.75
New York........................ 0.83 1.34
North Carolina.................. 0.40 0.38
North Dakota.................... 0.21 0.33
Ohio............................ 5.85 4.74
Oklahoma........................ 0.17 0.20
Pennsylvania.................... 2.85 2.29
Rhode Island.................... 0.02 0.03
South Carolina.................. 0.29 0.25
South Dakota.................... 0.10 0.17
Tennessee....................... 1.38 1.30
Texas........................... 0.37 0.33
Vermont......................... 0.03 0.05
Virginia........................ 1.21 1.01
West Virginia................... 4.02 3.33
Wisconsin....................... 0.69 0.97
------------------------------------------------------------------------
Based on the state-by-state contribution analysis, there are 21
states \34\ which contribute 0.35 [mu]g/m\3\ or more to downwind 24-
hour PM2.5 nonattainment. These states are: Alabama,
Georgia, Illinois, Indiana, Iowa, Kansas, Kentucky, Maryland, Michigan,
Minnesota, Missouri, New Jersey, New York, North Carolina, Ohio,
Pennsylvania, Tennessee, Texas, Virginia, West Virginia, and Wisconsin.
In Table V.D-5, we provide a list of the downwind nonattainment
counties to which each upwind state contributes 0.35 [mu]g/m\3\ or more
(i.e., the upwind state to downwind nonattainment ``linkages'').
---------------------------------------------------------------------------
\34\ As in the proposal, EPA has combined the contributions from
Maryland and the District of Columbia as a single entity in our
contribution analysis for the final rule. EPA believes that this is
a fair representation of emissions for transport analysis because of
the small size of the District of Columbia and its close proximity
to Maryland. However, the District of Columbia is not included in
the Transport Rule due to the significant contribution analysis
findings in section VI.D.
---------------------------------------------------------------------------
There are 21 states which contribute 0.35 [mu]g/m\3\ or more to
downwind 24-hour PM2.5 maintenance. These states are:
Alabama, Georgia, Illinois, Indiana, Iowa, Kansas, Kentucky, Maryland,
Michigan, Minnesota, Missouri, Nebraska, New Jersey, New York, North
Carolina, Ohio, Pennsylvania, Tennessee, Virginia, West Virginia, and
Wisconsin. In Table V.D-6, we provide a list of the downwind
maintenance sites to which each upwind state contributes 0.35 [mu]g/
m\3\ or more (i.e., the upwind state to downwind maintenance
``linkages'').
Table V.D-5--Upwind State to Downwind Nonattainment Site ``Linkages'' for 24-Hour PM2.5
----------------------------------------------------------------------------------------------------------------
----------------------------------------------------------------------------------------------------------------
Upwind state Downwind receptor sites
----------------------------------------------------------------------------------------------------------------
Alabama..................... Marion, IN Marion, IN Marion, IN
(180970043). (180970066). (180970081).
Georgia..................... Jefferson, AL
(10730023).
Illinois.................... Marion, IN Marion, IN Marion, IN St Clair, MI
(180970043). (180970066). (180970081). (261470005).
Wayne, MI Wayne, MI Wayne, MI Wayne, MI
(261630015). (261630016). (261630019). (261630033).
Cuyahoga, OH Cuyahoga, OH Allegheny, PA Allegheny, PA
(390350038). (390350060). (420030064). (420030093).
Allegheny, PA Beaver, PA Brooke, WV Milwaukee, WI
(420030116). (420070014). (540090011). (550790043).
[[Page 48243]]
Indiana..................... Jefferson, AL Cook, IL Madison, IL St Clair, MI
(10730023). (170311016). (171191007). (261470005).
Wayne, MI Wayne, MI Wayne, MI Wayne, MI
(261630015). (261630016). (261630019). (261630033).
Cuyahoga, OH Cuyahoga, OH Allegheny, PA Allegheny, PA
(390350038). (390350060). (420030064). (420030093).
Allegheny, PA Beaver, PA Brooke, WV Milwaukee, WI
(420030116). (420070014). (540090011). (550790043).
Iowa........................ Cook, IL Madison, IL Milwaukee, WI
(170311016). (171191007). (550790043).
Kansas...................... Madison, IL
(171191007).
Kentucky.................... Jefferson, AL Cook, IL Madison, IL Marion, IN
(10730023). (170311016). (171191007). (180970043).
Marion, IN Marion, IN St Clair, MI Wayne, MI
(180970066). (180970081). (261470005). (261630015).
Wayne, MI Wayne, MI Wayne, MI Cuyahoga, OH
(261630016). (261630019). (261630033). (390350038).
Cuyahoga, OH Allegheny, PA Allegheny, PA Allegheny, PA
(390350060). (420030064). (420030093). (420030116).
Beaver, PA Brooke, WV Milwaukee, WI
(420070014). (540090011). (550790043).
Maryland.................... Cuyahoga, OH Lancaster, PA
(390350038). (420710007).
Michigan.................... Cook, IL Madison, IL Cuyahoga, OH Cuyahoga, OH
(170311016). (171191007). (390350038). (390350060).
Allegheny, PA Allegheny, PA Beaver, PA Brooke, WV
(420030064). (420030093). (420070014). (540090011).
Milwaukee, WI
(550790043).
Minnesota................... Milwaukee, WI
(550790043).
Missouri.................... Cook, IL Madison, IL Marion, IN Marion, IN
(170311016). (171191007). (180970043). (180970066).
Marion, IN St Clair, MI Wayne, MI Allegheny, PA
(180970081). (261470005). (261630015). (420030064).
Allegheny, PA Beaver, PA Milwaukee, WI
(420030116). (420070014). (550790043).
New Jersey.................. Lancaster, PA
(420710007).
New York.................... St Clair, MI Wayne, MI Wayne, MI Wayne, MI
(261470005). (261630016). (261630019). (261630033).
Cuyahoga, OH Lancaster, PA
(390350060). (420710007).
North Carolina.............. Lancaster, PA
(420710007).
Ohio........................ Jefferson, AL Cook, IL Madison, IL Marion, IN
(10730023). (170311016). (171191007). (180970043).
Marion, IN Marion, IN St Clair, MI Wayne, MI
(180970066). (180970081). (261470005). (261630015)
Wayne, MI Wayne, MI Wayne, MI Allegheny, PA
(261630016). (261630019). (261630033). (420030064).
Allegheny, PA Allegheny, PA Beaver, PA Lancaster, PA
(420030093). (420030116). (420070014). (420710007).
Brooke, WV Milwaukee, WI
(540090011). (550790043).
Pennsylvania................ Jefferson, AL Cook, IL Madison, IL Marion, IN
(10730023). (170311016). (171191007). (180970043).
Marion, IN Marion, IN St Clair, MI Wayne, MI
(180970066). (180970081). (261470005). (261630015).
Wayne, MI Wayne, MI Wayne, MI Cuyahoga, OH
(261630016). (261630019). (261630033). (390350038).
Cuyahoga, OH Brooke, WV Milwaukee, WI
(390350060). (540090011). (550790043)..
Tennessee................... Jefferson, AL Madison, IL Marion, IN Marion, IN
(10730023). (171191007). (180970043). (180970066).
Marion, IN St Clair, MI Wayne, MI Wayne, MI
(180970081). (261470005). (261630015). (261630033).
Cuyahoga, OH Allegheny, PA
(390350038). (420030116).
Texas....................... Madison, IL
(171191007).
Virginia.................... Lancaster, PA
(420710007).
West Virginia............... Jefferson, AL Cook, IL Madison, IL Marion, IN
(10730023). (170311016). (171191007). (180970043).
Marion, IN Marion, IN St Clair, MI Wayne, MI
(180970066). (180970081). (261470005). (261630015).
Wayne, MI Wayne, MI Wayne, MI Cuyahoga, OH
(261630016). (261630019). (261630033). (390350038).
Cuyahoga, OH Allegheny, PA Allegheny, PA Allegheny, PA
(390350060). (420030064). (420030093). (420030116).
Beaver, PA Lancaster, PA Milwaukee, WI
(420070014). (420710007). (550790043).
Wisconsin................... Cook, IL Wayne, MI Wayne, MI
(170311016). (261630019). (261630033).
----------------------------------------------------------------------------------------------------------------
Table V.D-6--Upwind State to Downwind Maintenance Site ``Linkages'' for 24-Hour PM2.5
----------------------------------------------------------------------------------------------------------------
----------------------------------------------------------------------------------------------------------------
Upwind state Downwind receptor sites
----------------------------------------------------------------------------------------------------------------
Alabama..................... Washtenaw, MI Butler, OH Montgomery, OH
(261610008). (390170003). (391130032).
Georgia..................... Jefferson, AL
(10732003).
Illinois.................... Lake, IN Lake, IN Washtenaw, MI Butler, OH
(180890022). (180890026). (261610008). (390170003).
Cuyahoga, OH Cuyahoga, OH Hamilton, OH Jefferson, OH
(390350045). (390350065). (390618001). (390811001).
Montgomery, OH Allegheny, PA Allegheny, PA Allegheny, PA
(391130032). (420031008). (420031301). (420033007).
York, PA Milwaukee, WI Milwaukee, WI
(421330008). (550790010). (550790026).
Indiana..................... Jefferson, AL Cook, IL Cook, IL Cook, IL
(10732003). (170310052). (170312001). (170313301).
Cook, IL Madison, IL Washtenaw, MI Butler, OH
(170316005). (171190023). (261610008). (390170003).
Cuyahoga, OH Cuyahoga, OH Hamilton, OH Jefferson, OH
(390350045). (390350065). (390618001). (390811001).
Montgomery, OH Allegheny, PA Allegheny, PA Allegheny, PA
(391130032). (420031008). (420031301). (420033007).
York, PA Milwaukee, WI Milwaukee, WI
(421330008). (550790010). (550790026).
Iowa........................ Cook, IL Cook, IL Cook, IL Cook, IL
(170310052). (170312001). (170313301). (170316005).
Madison, IL Lake, IN Lake, IN Milwaukee, WI
(171190023). (180890022). (180890026). (550790010).
Milwaukee, WI
(550790026).
Kansas...................... Cook, IL Cook, IL Milwaukee, WI Milwaukee, WI
(170310052). (170316005). (550790010). (550790026).
Kentucky.................... Jefferson, AL Cook, IL Cook, IL Cook, IL
(10732003). (170310052). (170312001). (170313301).
Cook, IL Madison, IL Lake, IN Lake, IN
(170316005). (171190023). (180890022). (180890026).
Washtenaw, MI Butler, OH Cuyahoga, OH Cuyahoga, OH
(261610008). (390170003). (390350045). (390350065).
Hamilton, OH Jefferson, OH Montgomery, OH Allegheny, PA
(390618001). (390811001). (391130032). (420031008).
Allegheny, PA Allegheny, PA York, PA Milwaukee, WI
(420031301). (420033007). (421330008). (550790010).
Milwaukee, WI
(550790026).
[[Page 48244]]
Maryland.................... York, PA
(421330008).
Michigan.................... Cook, IL Cook, IL Cook, IL Cook, IL
(170310052). (170312001). (170313301). (170316005).
Madison, IL Lake, IN Lake, IN Butler, OH
(171190023). (180890022). (180890026). (390170003).
Cuyahoga, OH Cuyahoga, OH Hamilton, OH Jefferson, OH
(390350045). (390350065). (390618001). (390811001).
Montgomery, OH Allegheny, PA Allegheny, PA Allegheny, PA
(391130032). (420031008). (420031301). (420033007).
York, PA Milwaukee, WI Milwaukee, WI
(421330008). (550790010). (550790026).
Minnesota................... Milwaukee, WI Milwaukee, WI
(550790010). (550790026).
Missouri.................... Cook, IL Cook, IL Cook, IL Cook, IL
(170310052). (170312001). (170313301). (170316005).
Madison, IL Lake, IN Lake, IN Washtenaw, MI
(171190023). (180890022). (180890026). (261610008).
Butler, OH Hamilton, OH Montgomery, OH Allegheny, PA
(390170003). (390618001). (391130032). (420031008).
Milwaukee, WI Milwaukee, WI
(550790010). (550790026).
Nebraska.................... Milwaukee, WI Milwaukee, WI
(550790010). (550790026).
New Jersey.................. York, PA
(421330008).
New York.................... Washtenaw, MI Cuyahoga, OH Cuyahoga, OH York, PA
(261610008). (390350045). (390350065). (421330008).
North Carolina.............. York, PA
(421330008).
Ohio........................ Jefferson, AL Cook, IL Cook, IL Cook, IL
(10732003). (170310052). (170312001). (170313301).
Cook, IL Madison, IL Lake, IN Lake, IN
(170316005). (171190023). (180890022). (180890026).
Washtenaw, MI Allegheny, PA Allegheny, PA Allegheny, PA
(261610008). (420031008). (420031301). (420033007).
York, PA Milwaukee, WI Milwaukee, WI
(421330008). (550790010). (550790026).
Pennsylvania................ Jefferson, AL Cook, IL Cook, IL Cook, IL
(10732003). (170310052). (170312001). (170313301).
Madison, IL Lake, IN Lake, IN Washtenaw, MI
(171190023). (180890022). (180890026). (261610008).
Butler, OH Cuyahoga, OH Cuyahoga, OH Hamilton, OH
(390170003). (390350045). (390350065). (390618001).
Jefferson, OH Montgomery, OH Milwaukee, WI Milwaukee, WI
(390811001). (391130032). (550790010). (550790026).
Tennessee................... Jefferson, AL Madison, IL Washtenaw, MI Butler, OH
(10732003). (171190023). (261610008). (390170003).
Cuyahoga, OH Hamilton, OH Montgomery, OH
(390350065). (390618001). (391130032).
Virginia.................... York, PA
(421330008).
West Virginia............... Jefferson, AL Cook, IL Cook, IL Cook, IL
(10732003). (170310052). (170312001). (170313301).
Madison, IL Lake, IN Lake, IN Washtenaw, MI
(171190023). (180890022). (180890026). (261610008).
Butler, OH Cuyahoga, OH Cuyahoga, OH Hamilton, OH
(390170003). (390350045). (390350065). (390618001).
Jefferson, OH Montgomery, OH Allegheny, PA Allegheny, PA
(390811001). (391130032). (420031008). (420031301).
Allegheny, PA York, PA Milwaukee, WI
(420033007). (421330008). (550790010).
Wisconsin................... Cook, IL Cook, IL Cook, IL Cook, IL
(170310052). (170312001). (170313301). (170316005).
Lake, IN Lake, IN
(180890022). (180890026).
----------------------------------------------------------------------------------------------------------------
b. Estimated Interstate Contributions to 8-Hour Ozone
In this section, we present the interstate contributions from
emissions in upwind states to downwind nonattainment and maintenance
sites for the ozone NAAQS. As described previously in section V.D.1,
states which contribute 0.8 ppb or more to 8-hour ozone nonattainment
or maintenance in another state are identified as states with
contributions to downwind attainment and maintenance sites large enough
to warrant further analysis.
We calculated each state's contribution to ozone at each of the 4
monitoring sites that are projected to be nonattainment and each of 6
\35\ sites that are projected to have maintenance problems for the 8-
hour ozone NAAQS in the 2012 base case. A detailed description of the
calculations can be found in the Air Quality Modeling Final Rule TSD.
The largest contribution from each state to 8-hour ozone nonattainment
in downwind sites is provided in Table V.D-7. The largest contribution
from each state to 8-hour ozone maintenance in downwind sites is also
provided in Table V.D.2-7. The contributions from each state to all
projected 2012 nonattainment and maintenance sites for the 8-hour ozone
NAAQS are provided in the Air Quality Modeling Final Rule TSD.
---------------------------------------------------------------------------
\35\ There are 6 additional sites with projected 2012
nonattainment or maintenance (Harris Co., Texas sites 482010024,
482010062, 482010066, 482011015, 482011035, and 482011039) for which
there are less than 5 days with 8-hour ozone predictions of at least
70 ppb. Thus, we did not calculate contributions for these 6 sites.
Table V.D-7--Largest Contribution to Downwind 8-Hour Ozone Nonattainment
and Maintenance for Each of 37 States
------------------------------------------------------------------------
Largest downwind Largest downwind
contribution to contribution to
Upwind state nonattainment for maintenance for
ozone (ppb) ozone (ppb)
------------------------------------------------------------------------
Alabama......................... 4.0 2.8
Arkansas........................ 2.1 2.0
[[Page 48245]]
Connecticut..................... 0.0 0.2
Delaware........................ 0.0 0.6
Florida......................... 0.5 3.6
Georgia......................... 1.6 2.8
Illinois........................ 1.9 26.8
Indiana......................... 1.3 9.4
Iowa............................ 0.6 0.9
Kansas.......................... 0.5 1.0
Kentucky........................ 1.6 1.6
Louisiana....................... 8.0 11.1
Maine........................... 0.0 0.0
Maryland........................ 0.0 2.7
Massachusetts................... 0.0 0.6
Michigan........................ 0.0 0.9
Minnesota....................... 0.3 0.2
Mississippi..................... 4.0 3.3
Missouri........................ 1.1 4.8
Nebraska........................ 0.2 0.2
New Hampshire................... 0.0 0.1
New Jersey...................... 0.0 11.5
New York........................ 0.0 18.8
North Carolina.................. 0.5 1.3
North Dakota.................... 0.2 0.1
Ohio............................ 0.1 3.2
Oklahoma........................ 0.3 2.8
Pennsylvania.................... 0.1 8.2
Rhode Island.................... 0.0 0.0
South Carolina.................. 0.4 0.9
South Dakota.................... 0.1 0.1
Tennessee....................... 2.2 1.1
Texas........................... 3.9 1.9
Vermont......................... 0.0 0.0
Virginia........................ 0.2 8.2
West Virginia................... 0.0 2.8
Wisconsin....................... 0.2 2.2
------------------------------------------------------------------------
Based on the state-by-state contribution analysis, there are 11
states that contribute 0.8 ppb or more to downwind 8-hour ozone
nonattainment. These states are: Alabama, Arkansas, Georgia, Illinois,
Indiana, Kentucky, Louisiana, Mississippi, Missouri, Tennessee, and
Texas.\36\ In Table V.D-8, we provide a list of the downwind
nonattainment counties to which each upwind state contributes 0.8 ppb
or more (i.e., the upwind state to downwind nonattainment
``linkages'').
---------------------------------------------------------------------------
\36\ As discussed in section III, EPA is issuing a supplemental
notice of proposed rulemaking to provide an opportunity for public
comment on our conclusion that emissions from Iowa, Kansas,
Michigan, Missouri, Oklahoma, and Wisconsin significantly contribute
to nonattainment or interfere with maintenance of the 1997 ozone
NAAQS in other states.
---------------------------------------------------------------------------
There are 26 states \37\ which contribute 0.8 ppb or more to
downwind 8-hour ozone maintenance. These states are: Alabama, Arkansas,
Florida, Georgia, Illinois, Indiana, Iowa, Kansas, Kentucky, Louisiana,
Maryland, Michigan, Mississippi, Missouri, New Jersey, New York, North
Carolina, Ohio, Oklahoma, Pennsylvania, South Carolina, Tennessee,
Texas, Virginia, West Virginia, and Wisconsin.\38\ In Table V.D.2-9, we
provide a list of the downwind nonattainment counties to which each
upwind state contributes 0.8 ppb or more (i.e., the upwind state to
downwind nonattainment ``linkages'').
---------------------------------------------------------------------------
\37\ As in the proposal, EPA has combined the contributions from
Maryland and the District of Columbia as a single entity in our
contribution analysis for the final rule. EPA believes that this is
a fair representation of emissions for transport analysis because of
the small size of the District of Columbia and its close proximity
to Maryland. However, the District of Columbia is not included in
the Transport Rule due to the significant contribution analysis
findings in section VI.D.
\38\ As discussed in section III, EPA is issuing a supplemental
notice of proposed rulemaking to provide an opportunity for public
comment on our conclusion that emissions from Iowa, Kansas,
Michigan, Missouri, Oklahoma, and Wisconsin significantly contribute
to nonattainment or interfere with maintenance of the 1997 ozone
NAAQS in other states.
[[Page 48246]]
Table V.D-8--Upwind State to Downwind Nonattainment ``Linkages'' for 8-Hour Ozone
----------------------------------------------------------------------------------------------------------------
----------------------------------------------------------------------------------------------------------------
Upwind state Downwind receptor sites
----------------------------------------------------------------------------------------------------------------
Alabama..................... East Baton Rouge, Brazoria, TX Harris, TX Harris, TX
LA (220330003). (480391004). (482010051). (482010055).
Arkansas.................... East Baton Rouge, Brazoria, TX
LA (220330003). (480391004).
Georgia..................... East Baton Rouge, Brazoria, TX Harris, TX Harris, TX
LA (220330003). (480391004). (482010051). (482010055).
Illinois.................... Brazoria, TX Harris, TX Harris, TX
(480391004). (482010051). (482010055).
Indiana..................... Brazoria, TX Harris, TX Harris, TX
(480391004). (482010051). (482010055).
Kentucky.................... Brazoria, TX Harris, TX Harris, TX
(480391004). (482010051). (482010055).
Louisiana................... Brazoria, TX Harris, TX Harris, TX
(480391004). (482010051). (482010055).
Mississippi................. East Baton Rouge, Brazoria, TX Harris, TX Harris, TX
LA (220330003). (480391004). (482010051). (482010055).
Missouri.................... Brazoria, TX Harris, TX Harris, TX
(480391004). (482010051). (482010055).
Tennessee................... East Baton Rouge, Brazoria, TX Harris, TX Harris, TX
LA (220330003). (480391004). (482010051). (482010055).
Texas....................... East Baton Rouge,
LA (220330003).
----------------------------------------------------------------------------------------------------------------
Table V.D-9--Upwind State to Downwind Maintenance ``Linkages'' for 8-Hour Ozone
----------------------------------------------------------------------------------------------------------------
----------------------------------------------------------------------------------------------------------------
Upwind state Downwind receptor sites
----------------------------------------------------------------------------------------------------------------
Alabama..................... Harris, TX Harris, TX
(482010029). (482011050).
Arkansas.................... Allegan, MI
(260050003).
Florida..................... Harris, TX Harris, TX
(482010029). (482011050).
Georgia..................... Harris, TX Harris, TX
(482010029). (482011050).
Illinois.................... Fairfield, CT Allegan, MI Harris, TX
(90011123). (260050003). (482011050).
Indiana..................... Fairfield, CT New Haven, CT Harford, MD Allegan, MI
(90011123). (90093002). (240251001). (260050003).
Iowa........................ Allegan, MI
(260050003).
Kansas...................... Allegan, MI
(260050003).
Kentucky.................... Fairfield, CT New Haven, CT Harford, MD Harris, TX
(90011123). (90093002). (240251001). (482011050).
Louisiana................... Harris, TX Harris, TX
(482010029). (482011050).
Maryland.................... Fairfield, CT New Haven, CT
(90011123). (90093002).
Michigan.................... Harford, MD
(240251001).
Mississippi................. Harris, TX Harris, TX
(482010029). (482011050).
Missouri.................... Allegan, MI
(260050003).
New Jersey.................. Fairfield, CT New Haven, CT
(90011123). (90093002).
New York.................... Fairfield, CT New Haven, CT Harford, MD
(90011123). (90093002). (240251001).
North Carolina.............. New Haven, CT Harford, MD
(90093002). (240251001).
Ohio........................ Fairfield, CT New Haven, CT Harford, MD
(90011123). (90093002). (240251001).
Oklahoma.................... Allegan, MI
(260050003).
Pennsylvania................ Fairfield, CT New Haven, CT Harford, MD
(90011123). (90093002). (240251001).
South Carolina.............. Harris, TX
(482010029).
Tennessee................... Fairfield, CT Harford, MD Harris, TX
(90011123). (240251001). (482011050).
Texas....................... Allegan, MI
(260050003).
Virginia.................... Fairfield, CT New Haven, CT Harford, MD
(90011123). (90093002). (240251001).
West Virginia............... Fairfield, CT New Haven, CT Harford, MD
(90011123). (90093002). (240251001).
Wisconsin................... Allegan, MI
(260050003).
----------------------------------------------------------------------------------------------------------------
VI. Quantification of State Emission Reductions Required
A. Cost and Air Quality Structure for Defining Reductions
1. Summary
Section V, above, describes EPA's approach to identifying upwind
states with air quality contributions that meet or exceed the air
quality thresholds discussed therein for each of the NAAQS addressed in
this rule. A state is covered by the Transport Rule if its
contributions meet or exceed one of those air quality thresholds and
the Agency identifies, using the cost- and air quality-based approach
described below, emissions within the state that constitute the state's
significant contribution to nonattainment and interference with
maintenance with respect to the 1997 ozone, 1997 PM2.5 or
2006 PM2.5 NAAQS.
In this section, EPA explains its final cost- and air quality-based
approach to quantify the amount of emissions that represent significant
contribution to nonattainment and interference with maintenance for
each state. EPA then applies that approach for the three different
NAAQS being addressed in this rule: The 1997 ozone NAAQS, the 1997
annual PM2.5 NAAQS and the 2006 24-hour PM2.5
NAAQS. EPA believes that the methodology finalized could also be used
to address transport concerns under other NAAQS, including future
revisions to the ozone and PM2.5 NAAQS.
EPA applies the methodology described herein to fully quantify the
emissions that constitute each covered state's significant contribution
to nonattainment and interference with maintenance with respect to the
1997 annual PM2.5 and the 2006 24-hour PM2.5
NAAQS. The FIPs with respect to the annual and 24-hour PM2.5
NAAQS that are finalized in this action ensure that all such emissions
are prohibited. Each such FIP thus fully satisfies the requirements of
110(a)(2)(D)(i)(I) with
[[Page 48247]]
respect to the annual and/or 24-hour PM2.5 NAAQS for the
covered state.
EPA also applies the methodology to quantify significant
contribution to nonattainment and interference with maintenance with
respect to the 1997 ozone NAAQS. However, we have not been able to
fully quantify such emissions for all covered states. In this action,
EPA fully quantifies the significant contribution to nonattainment and
interference with maintenance for 15 states. We finalize FIPs with
respect to the 1997 ozone standards for 10 of these 15 states (Florida,
Maryland, New Jersey, New York, North Carolina, Ohio, Pennsylvania,
South Carolina, Virginia, and West Virginia). We are also publishing a
supplemental notice of rulemaking to take comment on whether FIPs
should be finalized for the remaining 5 states (Iowa, Kansas, Michigan,
Oklahoma, and Wisconsin). The FIPs for these 10 states (and the FIPs
for the remaining 5 states, if finalized) fully satisfy the
requirements of 110(a)(2)(D)(i)(I) with respect to the 1997 ozone NAAQS
for the covered state.
In addition, we apply the methodology described herein to quantify,
for 11 additional states, ozone-season NOX emission
reductions that are necessary but may not be sufficient to eliminate
all significant contribution to nonattainment and interference with
maintenance in other states. We finalize FIPs with respect to the 1997
ozone standards for 10 of these 11 states (Alabama, Arkansas, Georgia,
Illinois, Indiana, Kentucky, Louisiana, Mississippi, Tennessee, and
Texas). We are also publishing a supplemental notice of rulemaking to
take comment on whether FIPs should be finalized for the remaining
state (Missouri). The FIPs for these 10 states (and the FIP for the
remaining state, if finalized) make measurable progress toward
satisfying the requirements of 110(a)(2)(D)(i)(I) with respect to the
1997 ozone NAAQS in each covered state. To the extent that significant
contribution to nonattainment and interference with maintenance is not
entirely eliminated for the 1997 ozone NAAQS through today's action,
EPA will address these instances in a future rulemaking. This is
further explained in section VI.D.
With respect to the 1997 annual PM2.5 NAAQS, this rule
finds that 18 states have SO2 and NOX emission
reduction responsibilities. EPA also finds that 21 states have
SO2 and NOX emission reduction responsibilities
with respect to the 2006 24-hour PM2.5 NAAQS. There are a
total of 23 states that have SO2 and NOX emission
reduction responsibilities for one or both of the above
PM2.5 NAAQS. We apply the methodology to quantify emission
reductions that these states must achieve to eliminate the state's
significant contribution to nonattainment and interference with
maintenance. The states are listed in Table III-1 in section III of
this preamble.
This rule will prohibit all significant contribution to
nonattainment and interference with maintenance with respect to the
annual and 24-hour PM2.5. In addition, it will resolve air
quality issues at most nonattainment and maintenance receptors
identified by EPA. EPA projects that unresolved nonattainment and
maintenance issues will remain in only a few downwind states after
promulgation and implementation of the Transport Rule. For the annual
PM2.5 standard, EPA projects that this rule will help assure
that all areas in the east fully resolve their nonattainment and
maintenance concerns. This rule will also help a number of areas
achieve the standard earlier than they may have otherwise. For the 2006
24-hour PM2.5 NAAQS, one area is projected to remain in
nonattainment (Liberty-Clairton) and three areas are projected to have
remaining maintenance concerns after imposition of the Transport Rule
(Chicago,\39\ Detroit, and Lancaster County).\40\
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\39\ This area is not currently designated as nonattainment for
the 24-hour PM2.5 standard. EPA is portraying the
receptors and counties in this area as a single 24-hour maintenance
area based on the annual PM2.5 nonattainment designation
of Chicago-Gary-Lake County, IL-IN.
\40\ In the Transport Rule proposal, EPA noted that the Liberty-
Clairton receptor in Allegheny county was significantly impacted by
local emissions from a sizeable coke production facility and other
nearby sources (75 FR 45281).
---------------------------------------------------------------------------
The methodology provides similar assistance for ozone, assuring
upwind reductions that will assist downwind states in controlling ozone
pollution. It reduces ozone concentration levels in 2012 and helps
assure that all but two downwind areas fully resolve their
nonattainment and maintenance problems with the 1997 ozone NAAQS by
2014. While Houston is projected to still face nonattainment and Baton
Rouge is projected to still face maintenance concerns with the 1997
ozone NAAQS, the Transport Rule improves air quality in these two areas
and provides both health benefits and assistance for these local areas
in meeting the NAAQS requirements. For reasons explained below, EPA
will conduct further analysis in a subsequent transport-related
rulemaking to determine whether further upwind state reductions are
warranted to assist attainment and maintenance of the ozone NAAQS in
Houston and Baton Rouge areas.
When EPA proposed this air-quality and cost-based multi-factor
approach to identify emissions that constitute significant contribution
to nonattainment and interference with maintenance from upwind states
with respect to the 1997 ozone, annual PM2.5, and 2006 24-
hour PM2.5 NAAQS, the Agency indicated that the approach was
designed to be applicable to both current and potential future ozone
and PM2.5 NAAQS (75 FR 45214). EPA believes that the final
Transport Rule demonstrates the value of this approach for addressing
the role of interstate transport of air pollution in communities'
ability to comply with current and future NAAQS. EPA believes that the
Transport Rule's approach of using air-quality thresholds to determine
upwind-to-downwind-state linkages and using the cost- and air quality-
based multi-factor approach to quantify significant contribution to
nonattainment and interference with maintenance (i.e., to determine the
specific amount of emissions that each upwind state must reduce) could
serve as a precedent for quantifying upwind state emission reduction
responsibilities with respect to potential future NAAQS.
One commenter suggested that the rule could set a flawed precedent
for future transport analyses and remedies, as it does not fully
eliminate the prohibited emissions in every upwind state. EPA disagrees
with this characterization of the Transport Rule. EPA notes that the
partial determination of significant contribution to nonattainment and
interference with maintenance for certain upwind states in the
Transport Rule with respect to the ozone NAAQS is not a function of the
multi-factor approach itself, but is instead a function of its limited
application in this rulemaking to identify emission reductions from a
single source category (EGUs). In fact, the Transport Rule's approach
itself allowed EPA to determine for which upwind states we have
identified all emissions that constitute significant contribution to
nonattainment and interference with maintenance, and for which upwind
states we have identified emissions that are necessary but may not be
sufficient to eliminate the prohibited emissions. As EPA explained at
proposal, developing the additional information needed to consider
NOX emissions from non-EGU source categories in order to
fully quantify upwind state responsibility with respect to the 1997
ozone NAAQS would
[[Page 48248]]
substantially delay promulgation of the Transport Rule. EPA explained
that we do not believe that effort should delay the emission reductions
and large health benefits this final rule will deliver (75 FR 45213).
EPA further explained that we believe it is likely that the Agency can
provide the greatest assistance to states in addressing transported
pollution by issuing a separate (subsequent) rule to address additional
reductions that may be necessary to fully eliminate upwind state
responsibility with respect to the 1997 ozone NAAQS (75 FR 45288).
Thus, EPA decided to promulgate the Transport Rule as quickly as
possible. EPA anticipates that application of this air-quality and
cost-based multi-factor approach to a broader set of source categories
in a subsequent rulemaking will identify any remaining prohibited
emissions in the upwind states for which the Transport Rule may not
fully eliminate those emissions with respect to the 1997 ozone NAAQS.
2. Background
After using air quality analysis to identify upwind states that are
``linked'' to downwind air quality monitoring sites with nonattainment
and maintenance problems through contribution of at least one percent
of the relevant NAAQS, EPA quantifies the portion of each state's
contribution that constitutes its ``significant contribution'' or
``interference with maintenance.''
This section describes the methodology developed by EPA for this
analysis and then explains how that methodology is applied to measure
significant contribution to nonattainment and interference with
maintenance with respect to the NAAQS of concern. For this portion of
the analysis, EPA expands upon the methodology used in the
NOX SIP Call and CAIR but modifies it in important respects.
In the NOX SIP Call and CAIR, EPA's methodology defined
significant contribution as those emissions that could be removed with
the use of ``highly cost effective'' controls. In the Transport Rule,
rather than relying solely on an analysis of what constitutes ``highly
cost effective'' controls, EPA relies on an analysis that accounts for
both cost and air quality improvement to identify the portion of a
state's contribution that constitutes its significant contribution to
nonattainment and interference with maintenance. Furthermore, in
response to the Court's opinion in North Carolina, EPA has developed an
approach which gives independent meaning to the ``interfere with
maintenance'' prong of section 110(a)(2)(D)(i)(I).
The methodology takes into account both the D.C. Circuit Court's
determination that EPA may consider cost when measuring significant
contribution, Michigan, 213 F.3d at 679, and its rejection of the
manner in which cost was used in the CAIR analysis, North Carolina, 531
F.3d at 917. It also recognizes that the Court accepted--but did not
require--EPA's use of a single, uniform cost threshold to measure
significant contribution. Michigan, 213 F.3d at 679.
As EPA discussed at length in the Transport Rule proposal, using
both air quality and cost factors allows EPA to consider the full range
of circumstances and state-specific factors that affect the
relationship between upwind emissions and downwind nonattainment and
maintenance problems (75 FR 45271). For example, considering cost takes
into account the extent to which existing plants are already controlled
as well as the potential for, and relative difficulty of, additional
emission reductions. Therefore, EPA believes that it is appropriate to
consider both cost and air quality metrics when quantifying each
state's significant contribution.
This methodology is consistent with the statutory mandate in
section 110(a)(2)(D)(i)(I) which requires upwind states to prohibit
emissions that significantly contribute to nonattainment or
interference with maintenance in another state. As discussed in more
detail in the proposal, interpreting significant contribution to
nonattainment and interference with maintenance inherently involves a
decision on how much emissions control responsibility should be
assigned to upwind states, and how much responsibility should be left
to downwind states. EPA's methodology is intended to ``assign a
substantial but reasonable amount of responsibility to upwind states. *
* *to control their emissions'' (75 FR 45272). EPA believes that upwind
states contributing to downwind state air quality degradation should
bear substantial responsibility to control their emissions because of
the plain language of the good neighbor provision, the health risks and
control cost impacts that upwind emissions cause in the downwind state,
and the cumulative impact in the downwind state of emissions from
multiple upwind states, and the importance of achieving attainment in
downwind states as expeditiously as practicable but no later than
specific deadlines as required by the Act. EPA's approach does not
shift the responsibility for achieving or maintaining the NAAQS to the
upwind state. See 75 FR 45272.
The methodology defines each state's significant contribution to
nonattainment and interference with maintenance as the emission
reductions available at a particular cost threshold in a specific
upwind state which effectively address nonattainment and maintenance of
the relevant NAAQS in the linked downwind states of concern. Unlike the
NOX SIP Call and CAIR, where EPA's significant contribution
analysis had a regional focus, the methodology used in the Transport
Rule focuses on state-specific factors. The methodology uses a multi-
step process to analyze costs and air quality impacts, identify
appropriate cost thresholds, quantify reductions available from EGUs in
each state at those thresholds, and consider the impact of variability
in EGU operations. There are four steps to this methodology: (1)
Identification of each state's emission reductions available at
ascending costs per ton as appropriate; (2) assessment of those upwind
emission reductions' downwind air quality impacts; (3) identification
of upwind ``cost thresholds'' delivering effective emission reductions
and downwind air quality improvement; and (4) enshrinement of the
upwind emission reductions available at those cost thresholds in state
budgets.
In step one, EPA identifies what emission reductions are available
at various cost thresholds, quantifying emission reductions that would
occur within each state at ascending costs per ton of emission
reductions. In other words, EPA determined for specific cost per ton
thresholds, the emission reductions that would be achieved in a state
if all EGUs greater than 25 MW in that state used all emission controls
and emission reduction measures available at that cost threshold. For
purposes of this discussion, we refer to these as ``cost curves.''
For this final rule, EPA used updated IPM modeling to conduct a
similar cost curve analysis as conducted in the Transport Rule proposal
(75 FR 45275). In the proposal, the cost curves only reflected
escalating cost for one pollutant while the other pollutant cost was
held constant at base case levels (i.e., $0/ton). However, EPA improved
the costing analysis for the final rule by identifying upwind emission
reductions available as costs were imposed on both SO2 and
NOX simultaneously for states linked to downwind states on
the basis of the PM2.5 NAAQS. In other words, the cost
curves in the proposal depicted state level emissions when only one
pollutant was priced (i.e., NOX at $500/
[[Page 48249]]
ton). Separate cost curves were done for each pollutant. For the final
rule, EPA conducted some preliminary cost curve analysis for
identifying NOX thresholds in this manner. However, for the
final cost curve analysis, EPA relied on cost curves that reflected
state emissions when pollutants were priced simultaneously (e.g.,
NOX at $500/ton and SO2 at $1,600/ton). For
reasons described in section VI.B, EPA was able to conduct this type of
analysis because the preliminary cost curves specific to annual and
ozone-season NOX suggested little flexibility in adjusting
the $500/ton cost thresholds imposed for each. Therefore, EPA was able
to hold the cost threshold constant at $500/ton for these pollutants in
its examination of SO2 at various cost thresholds. EPA
believes this approach to cost analysis is a better simulation of the
Transport Rule's likely impact on covered sources. Under the final
Transport Rule, covered sources in states regulated for
PM2.5 must address compliance requirements for
SO2 and NOX emissions simultaneously, and this
refined approach to cost curve analysis and subsequent air quality
analysis better reflects this reality. Section VI.B of this preamble
describes the costing analysis in further detail. Also, for more detail
on the development of the cost curves, see ``Significant Contribution
and State Emission Budgets Final Rule TSD'' in the docket for this
rule.
Although the cost curves presented in this rule only include EGU
reductions, EPA also assessed the cost of SO2 and
NOX emission reductions available for source categories
other than EGUs in the proposed rulemaking. This preliminary assessment
in the rule proposal suggested that there likely would be very large
emission reductions available from EGUs before costs reach the point
for which non-EGU sources have available reductions (75 FR 45272). EPA
revisited these non-EGU reduction cost levels in this final rulemaking
and verified that there are little or no reductions available from non-
EGUs at costs lower than the thresholds that EPA has chosen ($500/ton
for NOX, $2,300/ton for SO2).
Further details on EPA's application of cost curves are provided
below, in section VI.B.
In step two, EPA uses an air quality assessment tool to estimate
the impact that the combined reductions available from upwind
contributing states and the downwind receptor state at different cost-
per-ton levels would have on air quality at downwind monitoring sites
projected to have nonattainment and/or maintenance problems.\41\ While
less rigorous than the air quality models used for attainment
demonstrations, EPA believes this air quality assessment tool (which
has been refined since proposal) is acceptable for assessing the impact
of numerous options for upwind emission reductions in the process of
defining an upwind state's significant contribution to nonattainment
and interference with maintenance. It allows the Agency to anticipate
specific air quality impacts of many more potential emission reduction
scenarios pertinent to the relevant NAAQS than time- and resource-
intensive comprehensive air quality modeling would permit.
---------------------------------------------------------------------------
\41\ As is discussed in the RIA, EPA also used the CAMx model to
perform air quality analysis of its proposed remedy to address
significant contribution. Results from this modeling will not
exactly correspond to results from the air quality assessment tool
both because the inputs to the air quality modeling are different
and the sophisticated model more fully accounts for the complex air
chemistry interactions. The full air quality modeling looks at the
remedy, including reductions in upwind states that do not contribute
as well as the impacts of the variability provisions discussed later
in this section. It also provides a metric against which to evaluate
the air quality assessment tool.
---------------------------------------------------------------------------
Further details on EPA's application of step two in this
methodology are provided below, in section VI.C.
In step three, EPA examines cost and air quality information to
identify ``significant cost thresholds.'' EPA considered a significant
cost threshold to be a point along the cost curves where a noticeable
change occurred in downwind air quality, such as a point where large
upwind emission reductions become available because a certain type of
emissions control strategy becomes cost-effective.\42\
---------------------------------------------------------------------------
\42\ The cost thresholds identified in this rule are specific to
the section 110(a)(2)(D)(i)(I) requirements for the states and NAAQS
considered in this proposal. They do not represent an agency
position on the appropriateness of such cost thresholds for any
other application under the Act.
---------------------------------------------------------------------------
This methodology allows EPA, where appropriate, to define multiple
cost thresholds that vary for a particular pollutant for different
upwind states. As explained in the Transport Rule proposal, EPA does
not believe it is required to utilize multiple cost thresholds to
regulate upwind emissions for purposes of the mandate in CAA section
110(a)(2)(D), but EPA's multi-factor methodology developed for the
Transport Rule to define significant contribution to nonattainment and
interference with maintenance allows the Agency to consider whether a
single cost threshold or multiple cost thresholds are appropriate for
meeting the requirements of CAA section 110(a)(2)(D) relevant to a
particular NAAQS (75 FR 45274).
In step four, EPA uses the information regarding emission
reductions available in each ``linked'' upwind state at the appropriate
cost threshold to form a state ``budget,'' representing the remaining
emissions from covered sources for the state in an average year once
significant contribution to nonattainment and interference with
maintenance have been eliminated; each budget also allows for the
identification of an associated variability limit. These budgets and
variability limits are used to develop enforceable requirements under
the final remedy. The final rule's methodology for identifying state
budgets is derived directly from the cost curves and multi-factor
analysis EPA uses to determine each state's significant contribution to
nonattainment and interference with maintenance. State emission budgets
are discussed in section VI.D and the variability limits are discussed
in section VI.E.
B. Cost of Available Emission Reductions (Step 1)
This subsection provides more detail on the cost curves that EPA
developed to assess the costs of reducing SO2 and
NOX emissions to address transport related to ozone and
PM2.5 concentrations (described previously as Step 1). It
summarizes the information from the curves and then provides EPA's
interpretation of that information. EPA used IPM to develop the EGU
cost curves described in this rulemaking. More information can be found
regarding EPA's use of IPM for the final Transport Rule in the
``Significant Contribution and State Emission Budgets Final Rule TSD''.
The amount of emission reductions that the cost curves suggest are
available at various costs are specific to the 2012 and 2014 time
periods. These cost estimates factor in the time interval between rule
finalization and compliance periods, existing controls already in
place, and controls that could potentially come on line by the start of
the compliance period. EPA notes that cost curves are a fluid concept
and would vary given different compliance dates.
1. Development of Annual NOX and Ozone-Season NOX
Cost Curves
EPA conducted preliminary cost curve analysis for annual
NOX and ozone-season NOX in a similar manner to
that used in the proposed rulemaking. That is, the impact of various
cost thresholds on emissions was examined individually. For example,
state level emissions were examined at cost levels for annual
NOX of $500, $1,000, and
[[Page 48250]]
$2,500/ton while SO2 was held at base case levels. EPA used
this approach to examine NOX and ozone-season NOX
emission reductions available from EGUs by 2012 and 2014 at various
cost levels, reaching to $2,500/ton for annual NOX and up to
$5,000/ton for ozone-season NOX (in 2007-year dollars).
Section VI.D explains why EPA analyzed the $500/ton threshold for
annual and ozone-season NOX. EPA selected two higher cost
thresholds to analyze for annual and ozone-season NOX that
provided a reasonable spectrum of emission reduction opportunities from
EGUs at higher cost thresholds. Specifically, EPA analyzed these two
higher cost thresholds because the first ($1,000/ton) was informative
in regards to the additional EGU NOX emissions reductions
available without installation of advanced controls, and the second
($2,500/ton for annual NOX, $5,000/ton for ozone-season
NOX) was informative in regards to additional EGU reductions
available at cost thresholds where advanced NOX control
retrofits are economic for some units. The cost thresholds were only
applied to states with air quality contributions that meet or exceed
the air quality thresholds as identified in section V.D. For both
annual and ozone-season NOX, EPA did not consider cost
thresholds below $500/ton for reasons explained in section VI.D.
EPA observed in the proposal that low-cost NOX
reductions are available at upwind sources with existing pollution
control equipment that may not otherwise be operated in the future
without the Transport Rule. EPA believes it is appropriate to prohibit
any ``linked'' upwind state from potentially increasing its emissions
through a failure to operate these existing pollution controls, which
could worsen downwind air quality problems. Thus, EPA reflected
operation of these controls in all modeling of different cost
thresholds (i.e., the modeling assumes year-round operation of post-
combustion NOX controls in covered PM2.5 states
and ozone-season operation of post-combustion NOX controls
in covered ozone states).
Table VI.B-1 shows the annual NOX emissions from EGUs at
various levels of control cost per ton for 2014. Table VI.B-2 presents
the cost curves for ozone-season NOX emissions from EGUs. As
discussed in section VI.D, EPA determined that $500/ton for annual and
ozone NOX was the appropriate cost threshold for this rule
(although EPA plans to determine in the future whether a higher cost/
ton threshold may be warranted for states contributing to nonattainment
or maintenance problems with the 1997 ozone air quality standard
projected to remain in two downwind areas).
Table VI.B-1--2014 Annual NOX Emissions From Fossil-Fuel Fired EGUs Greater Than 25 MW for Each Transport Rule
State at Various Costs per Ton
[(2007$) per ton (thousand tons)]
----------------------------------------------------------------------------------------------------------------
Base case level $500 $1,000 $2,500
----------------------------------------------------------------------------------------------------------------
Alabama................................. 75 72 72 70
Georgia................................. 48 41 41 39
Illinois................................ 55 51 50 49
Indiana................................. 117 108 107 100
Iowa.................................... 45 40 39 37
Kansas.................................. 32 25 25 23
Kentucky................................ 83 83 81 78
Maryland................................ 17 17 17 17
Michigan................................ 64 61 61 60
Minnesota............................... 38 30 30 30
Missouri................................ 55 54 54 51
Nebraska................................ 43 27 26 21
New Jersey.............................. 8 8 8 8
New York................................ 19 19 18 18
North Carolina.......................... 46 46 46 44
Ohio.................................... 99 95 94 92
Pennsylvania............................ 132 124 124 116
South Carolina.......................... 38 38 37 36
Tennessee............................... 29 29 29 29
Texas................................... 141 138 138 136
Virginia................................ 36 35 35 28
West Virginia........................... 64 64 64 61
Wisconsin............................... 37 32 32 31
-----------------------------------------------------------------------
Total............................... 1,321 1,236 1,229 1,174
----------------------------------------------------------------------------------------------------------------
Table VI.B-2--2012 Ozone-Season NOX Emissions From Fossil-Fuel Fired EGUs Greater Than 25 MW for Each Transport
Rule State at Various Costs
[(2007$) per ton (thousand tons)]
----------------------------------------------------------------------------------------------------------------
Base case level $500 $1,000 $5,000
----------------------------------------------------------------------------------------------------------------
Alabama................................. 34 34 34 31
Arkansas................................ 15 15 15 14
Florida................................. 42 27 27 24
Georgia................................. 29 28 28 25
Illinois................................ 21 21 21 21
Indiana................................. 47 46 46 43
Kentucky................................ 38 37 36 34
[[Page 48251]]
Louisiana............................... 13 13 13 13
Maryland................................ 7 7 7 7
Mississippi............................. 10 10 10 9
New Jersey.............................. 3 3 3 3
New York................................ 8 8 8 8
North Carolina.......................... 23 23 23 21
Ohio.................................... 42 42 42 38
Pennsylvania............................ 53 53 52 49
South Carolina.......................... 15 15 15 14
Tennessee............................... 16 16 15 15
Texas................................... 65 63 63 60
Virginia................................ 15 15 15 13
West Virginia........................... 26 26 26 24
-----------------------------------------------------------------------
Total............................... 523 504 501 467
----------------------------------------------------------------------------------------------------------------
EPA notes that the cost curves presented here differ somewhat from
the cost curves presented in the proposal. The NOX emissions
modeled at a $500/ton cost threshold for the final rule are lower than
they were at proposal. In addition, the emission reductions they
represent from the updated base case are not as pronounced as was found
in modeling for the proposed rule. It is worth emphasizing that the
lower emission reductions observed at $500/ton in this final rulemaking
are due to a lower starting point in updated base case EGU
NOX emission levels (and thus do not reflect higher
NOX emissions remaining after the reductions made at the
$500/ton threshold). While the base case 2012 nationwide annual EGU
NOX emissions were approximately 3 million tons in the
proposal, they were only 2.1 million tons in the final rule. This
approximately 33 percent reduction in base case EGU NOX
emissions in the final rule modeling relative to the proposal is due to
a combination of modeling updates, including lower natural gas prices,
reduced electricity demand, newly-modeled consent decrees and state
rules, and updated NOX rates to reflect 2009 emissions data.
All of these factors resulted in substantially lower base case
Transport Rule NOX emissions in the final rule modeling.
2. Development of SO2 Cost Curves
As explained in detail below in section VI.D, EPA determined that a
single threshold of $500/ton for ozone-season NOX control in
the states covered for the 1997 ozone NAAQS and a single threshold of
$500/ton for annual NOX control in the states covered for
the PM2.5 NAAQS were appropriate cost thresholds for
identifying upwind control under the Transport Rule. With these
parameters determined, EPA was able to assess the availability of
SO2 emission reductions from EGUs at various SO2
cost per ton thresholds with the corresponding NOX reduction
requirements simultaneously represented in the analysis.
This approach of simultaneously modeling cost levels for covered
pollutants is different from the approach taken in the proposal. In the
proposal, cost curves were developed and examined independently for
each pollutant. For example, with the SO2 cost curves in the
proposal, the NOX cost level was held constant at base case
levels as the SO2 cost threshold was varied from base case
levels to $2,400/ton. Commenters noted that this did not accurately
reflect a reality where source owners/operators view price signals for
all covered pollutants simultaneously and make operation decisions
accordingly. For the final rule, EPA included cost thresholds of $500/
ton for annual NOX in PM2.5 states and $500/ton
for ozone-season NOX in ozone-season states while examining
different SO2 cost thresholds. This allows EPA to develop
final cost curves for air quality analysis and budget determination
that reflect EGU operation when faced with the appropriate cost
thresholds on all covered pollutants. EPA believes this approach of
modeling final cost curves is superior to the methodology used in the
proposal because it reflects market signals for each pollutant
simultaneously, as would be experienced by states and sources regulated
under the Transport Rule.
In this manner, EPA examined several SO2 cost thresholds
of $500, $1,600, $2,300, $2,800, $3,300 and $10,000 per ton. EPA
selected these cost thresholds for the final rule's analysis as a
representative sampling of points along the SO2 cost curve
thoroughly explored at proposal. Modeling of these cost thresholds
provided a spectrum of emission reduction opportunities yielding
meaningful differences to consider in total costs and air quality
improvements at each threshold. The proposal's more detailed analysis
using smaller increments between cost thresholds outlined the general
form of the sector's SO2 emission reduction cost curve and
therefore allowed EPA to use larger increments between cost thresholds
for the final rule's analysis. Each of the cost thresholds examined for
the final rule represents a point where there is a significant change
in available controls, emission reductions, or costs and economic
impacts. EPA believes analysis of these thresholds illustrate a
meaningful progression of costs and air quality impacts that enabled
the Agency to determine a proper threshold along this cost curve to
identify significant contribution to nonattainment and interference
with maintenance for this rulemaking.
The cost thresholds above $500/ton were applied starting in 2014.
In all modeling, the 2012 cost per ton threshold was held constant at
$500/ton as EPA believes that this cost threshold captures all emission
reductions feasible by 2012 (see section VI.B.3 below for more
discussion). At the higher cost levels (e.g., $2,800/ton and above),
the curve does not include all available reductions as they do not
include non-EGU reductions. As described above for NOX, EPA
also observed at proposal that substantial low-cost SO2
reductions are available from the operation of existing scrubbers that
may not otherwise operate in the future without the
[[Page 48252]]
Transport Rule in place. Therefore, all of the final SO2
cost curves assume operation of existing scrubbers in PM2.5
states under the Transport Rule. In 2014, approximately 3 million tons
of SO2 reductions can be achieved at the $500/ton cost
threshold through operation of existing controls and some fuel
switching.
This final cost curve also appropriately reflects the Group 1/Group
2 distinction for states covered for PM2.5. As discussed in
more detail in section VI.D, EPA identified Group 2 states as those
that were linked to states where all nonattainment and maintenance
issues had been resolved at $500/ton levels. There is no longer any
significant contribution to nonattainment or interference with
maintenance by these seven Group 2 states at levels above $500/ton.
Therefore, in the final curves, these Group 2 states' cost thresholds
were held constant at $500/ton as the higher cost thresholds were
applied to the remaining Group 1 states starting in 2014. For example,
the modeled emissions at the $2,300 per ton cost threshold shown in
Table VI.B-3 below reflect each state's emissions when Group 1 states
are subjected to a $2,300 per ton SO2 constraint and Group 2
states are subjected to a $500/ton SO2 constraint.
Additional reductions can be achieved at the higher cost
thresholds. The cost curves demonstrate that sources begin to build
significant additional flue gas desulfurization (FGD) retrofits at an
SO2 cost threshold of $1,600 per ton and additional dry
sorbent injection (DSI) retrofits at an SO2 cost threshold
of $2,300 per ton.
With these final cost curves in hand, EPA was able to identify the
combined reductions available from upwind contributing states and the
downwind state, at different cost-per-ton levels. Additionally, EPA was
able to examine the economic impacts of imposing such cost constraints
on power sector generation. However, this only constitutes a portion of
EPA's multi-factor assessment used to determine the amount of emissions
that represent significant contribution to nonattainment and
interference with maintenance. As noted in the Transport Rule proposal,
EPA's multi-factor assessment considered air quality and cost
considerations when identifying cost thresholds (75 FR 45271). The air
quality portion of the assessment is described in section VI.C of the
final Transport Rule preamble.
3. Amount of Reductions That Could Be Achieved by 2012 and 2014
EPA applied escalating SO2 cost per ton thresholds for
Group 1 states to create the cost curves for 2014 and beyond. For 2012
SO2, the cost per ton was held constant at $500/ton as the
cost thresholds in 2014 and beyond were varied. The advanced pollution
controls incentivized by these higher cost-per-ton levels can
reasonably be installed by 2014. EPA also considered whether any of
these emission reductions could be achieved prior to 2014. For the
reasons that follow, EPA concluded that significant reductions could be
achieved by 2012 and that it is important to require all such
reductions by 2012 to ensure that they are achieved as expeditiously as
practicable. SO2 and NOX reductions come from
operating existing controls, installing combustion controls, fuel
switching, and increased dispatch of lower-emitting generation which
can be achieved by 2012. In general, compliance mechanisms that do not
involve post-combustion control installation are feasible before 2014.
For this reason, EPA believes it is appropriate to require these
emissions to be removed in 2012, consistent with the Act's requirement
that downwind states attain the NAAQS as expeditiously as practicable.
Therefore, all of the cost curves presented below include all
feasible 2012 reductions up to a threshold of $500/ton for
SO2 and $500/ton for annual NOX in states linked
to receptors for PM2.5, as well as $500/ton for ozone-season
NOX in states linked to receptors for ozone. These cost per
ton levels do not precipitate advanced post-combustion control
installation in 2012 (as EPA acknowledges that such installations are
not feasible by 2012), but they do promote the compliance options
outlined above. The higher cost thresholds for SO2 Group 1
states were only applied starting in 2014. Therefore, the 2012 state
level emissions in the ``$2,300 per ton threshold'' reflect a cost
threshold of only $500/ton for all pollutants (the $2,300 per ton value
starts in 2014 for Group 1 states' SO2).
The table below illustrates the change in state level
SO2 emissions as the higher cost per ton thresholds are
applied to Group 1 states.
Table VI.B-3--2014 SO2 Emissions From Fossil-Fuel-Fired EGUs Greater Than 25 MW for Each Transport Rule State at
Various Costs per Ton
[Thousand tons] \a\
----------------------------------------------------------------------------------------------------------------
State Base
SO2 case $500 $1,600 $2,300 $2,800 $3,300 $10,000
group level
----------------------------------------------------------------------------------------------------------------
Alabama......................... 2 417 201 226 213 214 236 190
Georgia......................... 2 170 94 94 95 95 95 98
Illinois........................ 1 138 134 130 124 117 102 36
Indiana......................... 1 711 245 179 161 153 121 69
Iowa............................ 1 127 112 78 75 67 45 13
Kansas.......................... 2 70 55 57 61 61 61 45
Kentucky........................ 1 488 161 126 106 103 89 46
Maryland........................ 1 43 32 28 28 26 24 18
Michigan........................ 1 266 206 189 144 105 94 24
Minnesota....................... 2 66 43 45 46 46 46 44
Missouri........................ 1 382 212 173 166 109 84 21
Nebraska........................ 2 72 68 70 70 70 70 66
New Jersey...................... 1 39 7 7 7 7 6 5
New York........................ 1 40 21 20 12 11 10 8
North Carolina.................. 1 120 104 61 58 49 40 30
Ohio............................ 1 832 294 175 137 123 115 65
Pennsylvania.................... 1 507 294 164 112 107 102 75
South Carolina.................. 2 210 93 100 103 104 104 105
Tennessee....................... 1 284 82 63 59 59 59 24
[[Page 48253]]
Texas........................... 2 453 281 282 284 281 281 243
Virginia........................ 1 65 59 51 35 33 32 16
West Virginia................... 1 497 157 122 76 74 72 55
Wisconsin....................... 1 125 51 47 40 38 34 14
-------------------------------------------------------------------------------
Total....................... ........ 6,122 3,007 2,487 2,212 2,053 1,919 1,311
-------------------------------------------------------------------------------
Group 1 total............... ........ 4,665 2,172 1,612 1,340 1,180 1,025 520
-------------------------------------------------------------------------------
Group 2 total............... ........ 1,457 835 875 872 872 894 791
----------------------------------------------------------------------------------------------------------------
\a\ Note: As described in the preamble language for this section, the escalating cost per ton figures in each
column header only apply to Group 1 states in 2014 and each year thereafter. Cost per ton for Group 2 states
is held constant at $500/ton for all the costing runs. In some cases, the escalating cost levels in Group 1
states affect emission levels in Group 2 states as some generation shifts between states in response to newly
imposed costs.
C. Estimates of Air Quality Impacts (Step 2)
After developing cost curves to show the state-by-state cost-
effective emission reductions available, EPA estimates the air quality
impacts of these reductions using the air quality assessment tool
coupled with full-scale air quality modeling where possible. EPA uses
the air quality assessment tool to evaluate the impact on air quality
for downwind nonattainment and maintenance receptors from upwind
reductions in ``linked'' states. This section describes the development
of the air quality assessment tool and summarizes the results of this
evaluation.
1. Development of the Air Quality Assessment Tool and Air Quality
Modeling Strategy
In response to comments on the methodology used for the proposed
rule, EPA made significant improvements to the air quality assessment
tool (AQAT) for the final Transport Rule. Furthermore, EPA relied on
CAMx to model the air quality response to NOX reductions and
limited AQAT's role (relative to the Transport Rule proposal) to
estimating the relative response of sulfate concentrations from
SO2 reductions. EPA did not use AQAT to address
NOX reductions in the final rule analyses. These and other
changes to our approach, as described below and in the ``Significant
Contribution and State Emission Budgets Final Rule TSD'', address
commenter's concerns about the scientific rigor of the design and
application of AQAT and commenter's recommendations to rely upon air
quality modeling as part of this analysis.
For the final Transport Rule, EPA created an AQAT calibration
scenario consisting of full-scale air quality modeling using CAMx of a
2014 control scenario reflecting SO2 and NOX
emission reductions of similar stringency and from the same geography
as the Transport Rule proposal. Modeling of this AQAT calibration
scenario reflected all updates made to the air quality modeling
platform, as described in the ``Air Quality Modeling Final Rule TSD''
found in the docket for this rulemaking. CAMx modeling of each
receptor's response in this control scenario accounts for complex
chemical interactions and covariation of these pollutants. Among the
important atmospheric chemical interactions accounted for in CAMx is
``nitrate replacement.'' \43\ Nitrate replacement occurs when
SO2 emission reductions lead to decreases in ammonium
sulfate, which in turn, can result in an increase in ammonium nitrate
concentrations. As described below, EPA used the CAMx modeling results
for this AQAT calibration scenario together with the modeling for the
2012 base case to characterize the response of ozone, nitrate, and
sulfate at each nonattainment and maintenance receptor to the mix of
upwind NOX and SO2 emission reductions at each
cost threshold.
---------------------------------------------------------------------------
\43\ Observable indicators of the sensitivity of
PM2.5 nitrate to emission reductions--Part II:
Sensitivity to errors in total ammonia and total nitrate of the
CMAQ-predicted non-linear effect of SO2 emission
reductions. R.L. Dennis, P.K. Bhave, and R.W. Pinder. 2008.
Atmospheric Environment (42):1287-1300.doi:10.1016/
j.atmosenv.2007.10.036.
---------------------------------------------------------------------------
As described in section VI.D, EPA determined that the $500/ton
threshold for upwind annual and ozone-season NOX control is
appropriate for the final Transport Rule (although EPA plans to
determine in the future whether a higher cost/ton threshold may be
warranted for states contributing to nonattainment or maintenance
problems with the 1997 ozone air quality standard projected to remain
at receptors in two downwind areas \44\). Because this threshold
corresponds to the NOX control strategy modeled in the AQAT
calibration scenario described above, EPA is able to rely on this CAMx
air quality modeling to assess the response of ozone and nitrate
concentrations due to NOX reductions and does not estimate
ozone or nitrate impacts for this final rulemaking using AQAT. Further
information on the air quality modeling of this AQAT calibration
scenario can be found in the Air Quality Modeling Final Rule TSD and
the Significant Contribution and State Emission Budgets Final Rule TSD
in the docket for this rulemaking.
---------------------------------------------------------------------------
\44\ Houston and Baton Rouge nonattainment areas.
---------------------------------------------------------------------------
In order to estimate 2014 annual and 24-hour PM2.5
concentrations, AQAT uses the 2012 annual and seasonal contributions
which quantify the contribution of SO2 emissions in specific
upwind states to sulfate concentrations at specific downwind receptors.
These contributions are described in section V.D.2 and the Air Quality
Modeling Final Rule TSD.
EPA utilizes CAMx modeling of the AQAT calibration scenario,
described above, to ``calibrate'' the contribution factors by
developing and applying linear sulfate response factors for each
downwind receptor. These factors calibrate each receptor's sulfate
response to varying levels of upwind SO2 emissions. These
calibration factors are based on the sulfate response modeled by CAMx
due to emission changes occurring between the 2012 base case and the
2014 AQAT
[[Page 48254]]
calibration scenario. Calibration factors were constructed for the
annual and 24-hour PM2.5 AQAT.
To further allow adequate assessment of the seasonal impacts of
various levels of upwind SO2 reductions on each receptor's
24-hour PM2.5 concentration using AQAT, EPA developed
response factors for sulfate on a quarterly basis to capture important
air quality differences between summer and winter emissions and
concentrations. This process allowed EPA to estimate the air quality
values for each season at each cost threshold, and then estimate the
air quality design values.
Finally, EPA's air quality assessment accounts for the impact that
this differential response in sulfate by quarter can have on the
ordering of 24-hour concentrations when calculating the 98th percentile
for the 24-hour standard. AQAT estimates quarterly-specific relative
response factors that estimate quarterly-specific proportional change
in ammonium sulfate resulting from the SO2 emission
reduction from the 2012 base case scenario to the 2014 cost threshold
scenario being assessed. These quarterly relative response factors are
then applied to each of the maximum 24-hour PM2.5
concentrations for eight days per quarter per year at each receptor
from the 2012 base case. This methodology improvement allows EPA to
redetermine the 98th percentile day for each year and recalculate
average and maximum design values for the 24-hour PM2.5
standard.
These improvements for the final rule increase EPA's confidence
that the air quality estimates provided by AQAT, now customized for
this application, more accurately estimate the results of full-scale
air quality modeling of the various levels of upwind SO2
reductions considered. EPA evaluated the estimates from AQAT using an
independent data set, the 2014 base case estimates from CAMx, finding
that the results are unbiased with minimal differences. See
``Significant Contribution and State Emission Budgets Final Rule TSD''
for more details.
As such, EPA believes the revised AQAT provides an appropriate
basis for assessing the air quality portion of the multi-factor
methodology to define significant contribution to nonattainment and
interference with maintenance.\45\
---------------------------------------------------------------------------
\45\ EPA used CAMx to conduct full air quality modeling of the
final Transport Rule remedy embodying the emission reductions that
EPA first selected on the basis of the multi-factor analysis using
AQAT to project air quality impacts from varying levels of emission
reductions analyzed. The CAMx results confirmed the relative
magnitude and direction of AQAT's estimates of the outcomes for the
2012 base case nonattainment and maintenance receptors analyzed, and
the AQAT estimates closely tracked CAMx-modeled concentrations at
those receptors under the Transport Rule remedy. The paired AQAT-
estimated and CAMx-modeled concentrations were found to be highly
correlated with an R\2\ value of 0.997. As a result, EPA is
confident that AQAT's estimates of impacts on sulfate concentrations
at the varying levels of SO2 emission reductions analyzed
provide a technically valid and sound basis for the Agency's
selection of the final rule's emission reductions necessary to
eliminate (or make meaningful progress toward eliminating)
significant contribution and interference with maintenance for the
PM2.5 NAAQS considered in this rulemaking. Further
details on the comparison of CAMx and AQAT results can be found in
the Significant Contribution and State Emission Budgets Final Rule
TSD.
---------------------------------------------------------------------------
2. Utilization of AQAT To Evaluate Control Scenarios
For the final Transport Rule, EPA performed air quality analysis
for each downwind annual and 24-hour PM2.5 receptor with a
nonattainment and/or maintenance problem in the 2012 base case. For
each receptor, EPA quantified the sulfate reduction and resulting air
quality improvement when a group of states consisting of the upwind
states that are ``linked'' to the downwind receptor (as explained in
section V.D) and the downwind state where the receptor is located, all
made the SO2 emission reductions that EPA identified as
available at each cost threshold. EPA assumes reductions at each cost
threshold from the linked upwind states as well as the downwind
receptor state to assess the shared responsibility of these upwind
states to address air quality at the identified receptors. Analysis of
each receptor did not assume any emission reductions beyond those
included in the 2014 base case from upwind states that are not
``linked'' to that specific downwind receptor (even if the state was
``linked'' to a different receptor and/or otherwise would have made
emission reductions beginning in 2012 due to the Transport Rule).
EPA disagrees with comments suggesting that emission reductions,
and resulting decreases in contribution, from upwind states that are
not ``linked'' to a particular downwind receptor should be accounted
for in the 2014 AQAT analysis of that receptor. EPA decided to assume
reductions only from linked states when analyzing each receptor because
EPA is performing a state-specific analysis to support a determination
of the amount of each upwind state's responsibility for air quality
problems at the downwind receptors that it significantly affects. If
the AQAT analysis were to assume emissions reductions in other non-
linked states, the AQAT analysis would then contradict the first step
of our two-step approach to defining significant contribution to
nonattainment and interference with maintenance. Under EPA's two-step
approach, only a state that (1) contributes a threshold amount or more
to a particular downwind state receptor's air quality problem, and (2)
has emission reductions available at the selected cost threshold can be
deemed to have responsibility to reduce its emissions to improve air
quality at that downwind receptor. EPA believes that the commenters'
suggested approach would not qualify as a state-specific approach for
determining upwind state responsibility for downwind air quality
problems.
Because EPA is relying on the CAMx estimate of nitrate
concentrations from the AQAT calibration scenario, the response in
nitrate to NOX reductions at a cost threshold of $500/ton is
present in each SO2 cost threshold scenario analyzed.
EPA determines the cumulative air quality improvement that can be
expected at a particular downwind receptor by multiplying each upwind
state's percent SO2 emission reduction by its calibrated
receptor specific sulfate response factor and summing the sulfate,
nitrate, and other PM2.5 components (also taken from the
2014 CAMx AQAT calibration scenario).
3. Air Quality Assessment Results
The results of EPA's air quality assessment of the cost threshold
scenarios focus on air quality metrics including, but not limited to,
average air quality improvement at receptors with 2012 base case
nonattainment and maintenance exceedances and an evaluation of
estimated receptor design values against annual and 24-hour
PM2.5 standards. See ``Significant Contribution and State
Emission Budgets Final Rule TSD'' for more details.
In EPA's air quality analysis of each downwind receptor, all air
quality improvements are measured relative to the ``AQAT base case.''
This base case reflects AQAT's estimated PM2.5
concentrations under base case 2014 SO2 emissions. The AQAT
base case itself is not used for any decision points and only serves as
an appropriate starting point for comparison of air quality
improvements at SO2 cost thresholds. EPA ensures internal
analytic consistency by comparing all air quality improvements at
analyzed SO2 cost thresholds to the AQAT base case.
Regarding average air quality improvement at exceeding 2012 base
case receptors, EPA identified 41 receptors with nonattainment or
maintenance problems in the 2012 base
[[Page 48255]]
case. EPA assessed the cumulative reduction in 24-hour PM2.5
maximum design value at each increasing SO2 cost threshold
from the maximum design value from the AQAT base case, and averaged the
reduction across the 41 receptors. The results of this assessment
indicate diminishing incremental returns to 24-hour PM2.5
maximum design value reduction as SO2 cost threshold levels
increase. EPA finds reductions in maximum design value of 4.28 [mu]g/
m\3\ at $500; 4.98 [mu]g/m\3\ at $1,600; 5.33 [mu]g/m\3\ at $2,300;
5.46 [mu]g/m\3\ at $2,800; 5.60 [mu]g/m\3\ at $3,300; and 6.08 [mu]g/
m\3\ at $10,000. These results are provided in table VI.C-1.
Table VI.C-1--Average 2014 Air Quality Improvement at Receptors With
2012 Base Case Nonattainment and Maintenance Problems
------------------------------------------------------------------------
Average air
quality
improvement at
Group 1 state SO2 cost per ton threshold exceeding
receptors in
2012 base case
([mu]g/m\3\)
------------------------------------------------------------------------
$500.................................................. 4.28
$1,600................................................ 4.98
$2,300................................................ 5.33
$2,800................................................ 5.46
$3,300................................................ 5.60
$10,000............................................... 6.08
------------------------------------------------------------------------
Additionally, EPA evaluated the AQAT estimated 2014 average and
maximum design values for these receptors at each cost threshold
against the annual and 24-hour PM2.5 standards. EPA
determined the estimated number of receptors with nonattainment or
maintenance problems at $500/ton cost threshold of NOX and
each of the cost threshold scenarios assessed for SO2. These
results are provided in table VI.C-2 in terms of the number of
receptors and the number of nonattainment areas containing these
receptors.
Table VI.C-2--Receptors With Nonattainment and/or Maintenance Exceedances of the Annual or 24-Hour PM2.5 NAAQS in 2014
--------------------------------------------------------------------------------------------------------------------------------------------------------
Annual Annual 24-hour 24-hour Annual and 24-hour
nonattainment nonattainment or nonattainment nonattainment or nonattainment and
SO2 cost threshold --------------------- maintenance --------------------- maintenance maintenance
--------------------- -----------------------------------------
Receptors Areas Receptors Areas Receptors Areas Receptors Areas Receptors Areas
--------------------------------------------------------------------------------------------------------------------------------------------------------
$500........................................... 1 1 1 1 2 2 9 6 9 6
$1,600......................................... 1 1 1 1 2 2 8 5 8 5
$2,300......................................... 0 0 1 1 1 1 6 4 6 4
$2,800......................................... 0 0 1 1 1 1 5 4 5 4
$3,300......................................... 0 0 1 1 1 1 5 4 5 4
$10,000........................................ 0 0 1 1 1 1 3 3 3 3
--------------------------------------------------------------------------------------------------------------------------------------------------------
In the proposal, EPA evaluated whether the imposition of the rule's
upwind emission reduction requirements could cause changes in operation
of electric generating units in states not regulated under the
proposal. EPA recognized that such changes could lead to increased
emissions in those states, potentially affecting whether they would
meet or exceed the 1 percent contribution thresholds used to identify
linkages between upwind and downwind states. Such shifting of emissions
between states may occur because of the interconnected nature of the
country's energy system (including both the electricity grid as well as
coal and natural gas supplies).
Using updated emissions and air quality information developed for
the final rule, EPA's IPM modeling found that of the states not covered
in the final rule for PM2.5, Arkansas, Colorado, Louisiana,
Montana, and Wyoming are all projected to have SO2 emission
increases above 5,000 tons in 2014 with the rule in effect. EPA
analysis shows the SO2 emission increases result from
expected shifts to higher sulfur coal in these states. Using AQAT, a
state-level assessment of these emission increases relative to the
state specific contributions to downwind receptors (where available)
indicates that projected increases in the SO2 emissions
would not increase any of these states' contributions to an amount that
would meet or exceed the 0.15 [mu]g/m\3\ or 0.35 [mu]g/m\3\ thresholds
for annual and 24-hour PM2.5, respectively. For this reason,
EPA has determined that it is not necessary to include these additional
states in the Transport Rule as a result of the effects of the rule
itself on SO2 emissions in uncovered states. See
``Significant Contribution and State Emission Budgets Final Rule TSD''
in the docket for this rulemaking for more details.
D. Multi-Factor Analysis and Determination of State Emission Budgets
EPA used the cost, emission, and air quality information described
in the previous sections to perform its multi-factor analysis. By
looking at different ``cost thresholds''--places where there was a
noticeable change on the cost curve because emission reductions occur--
and examining the corresponding impact on air quality, EPA identified
the amount of emissions that represent significant contribution to
nonattainment and interference with maintenance within each state.
After quantifying this amount of emissions, EPA established state
``budgets'' which represent the remaining emissions for the state in an
average year (step 4).
For states covered by the rule for PM2.5, EPA calculated
annual NOX and annual SO2 budgets. For states
covered by the rule for ozone, EPA calculated ozone-season
NOX budgets. This section explains the multi-factor
assessment and how EPA used this assessment to determine state-specific
budgets.
1. Multi-Factor Analysis (Step 3)
a. Overview
As described in section VI.B, EPA examined how different cost
thresholds impacted emissions in states with air quality contributions
that meet or exceed specific air quality thresholds, as discussed in
section V.D of this preamble. Section VI.C summarizes the estimated air
quality impacts in 2014 of these emission levels at downwind receptors,
including estimates of their nonattainment and maintenance status (see
``Significant Contribution and State Emission Budgets Final Rule TSD''
for more details). From these two steps, EPA evaluated the interaction
between upwind emissions at different cost levels and air quality at
downwind receptors to identify ``significant cost thresholds.'' These
cost thresholds are
[[Page 48256]]
based on air quality considerations (such as the cost at which the air
quality assessment analysis projects large numbers of downwind site
maintenance and nonattainment problems would be resolved) or cost
criteria (such as a cost where large emissions reductions occur because
a particular technology is widely implemented at that cost). EPA
examined each cost threshold and then used a multi-factor assessment to
determine which serve as cost thresholds that eliminate significant
contribution to nonattainment and interference with maintenance for
upwind states. Air quality considerations in the assessment include,
for example, how much air quality improvement in downwind states
results from upwind state emission reductions at different levels;
whether, considering upwind emission reductions and assumed local (in-
state) reductions, the downwind air quality problems would be resolved;
and the components of the remaining downwind air quality problem (e.g.,
whether it is a predominantly local or in-state problem, or whether it
still contains a large upwind component). Cost considerations include,
for example, how the cost per ton of emission reduction compares with
the cost per ton of existing federal and state rules for the same
pollutant; whether the cost per ton is consistent with the cost per ton
of technologies already widely deployed (similar to the highly-cost-
effective criteria used in both the NOX SIP Call and CAIR);
and what cost increase is required to achieve additional meaningful air
quality improvement.
The specific cost per ton thresholds selected as a basis for
identifying significant contribution to nonattainment and interference
with maintenance in this rulemaking apply only to the determinations
made in this rule and do not establish any precedent for future EPA
actions under section 110(a)(2)(D)(i)(I) or any other section of the
CAA. EPA's selection of specific cost thresholds in the context of this
rulemaking relies on current analyses of the cost of available emission
reductions, the pattern of interstate linkages for pollution transport,
and the downwind air quality impacts specifically related to the 1997
ozone NAAQS, the 1997 annual PM2.5 NAAQS, and the 2006 24-
hour PM2.5 NAAQS. In addition and as explained below, the
selection of the threshold for ozone-season NOX was
influenced by the limited scope of this rule. Any or all of these
variables used to identify specific cost thresholds are subject to
change. Thus, EPA may use different cost thresholds in future actions,
even if those actions relate to the same NAAQS addressed in this rule.
b. Cost Thresholds Examined and Selected for Ozone-Season
NOX
In the proposal, EPA examined various cost thresholds for ozone
season NOX and identified a cost threshold with rapidly
diminishing returns at $500/ton. EPA observed that moving beyond the
$500 cost threshold up to a $2,500 cost threshold would result in only
minimal additional ozone season NOX emission reductions and
would likely bypass less expensive non-EGU emission reduction
opportunities (75 FR 45281). EPA noted that for greater costs the
curves did not include all available reductions as they do not include
non-EGU reductions (75 FR 44286). In the proposal, EPA noted the timely
promulgation and implementation of this rule is responsive to the
Court's remand of CAIR, will accelerate critical air quality
improvement, and more effectively address the mandate of CAA section
110(a)(2)(D) to address significant contribution to nonattainment and
interference with maintenance as expeditiously as practicable. EPA did
not want to risk delaying air quality benefits available from EGU
emission reductions, particularly those emission reductions which
eliminate significant contribution to nonattainment and interference
with maintenance for many receptors, while the Agency conducts
additional analysis to support subsequent transport-related rulemakings
including coverage of non-EGU sources (75 FR 45285).
EPA received comments suggesting that it consider cost thresholds
higher than $500/ton as reductions beyond the proposed $500/ton cost
threshold were needed to fully resolve nonattainment and maintenance
issues in downwind states analyzed at proposal. Some of these comments
suggested EPA should include non-EGUs as they consider the higher cost
thresholds, others suggested EPA continue to exclude non-EGU sources in
this rulemaking.
In response to those comments that suggested EPA explore higher
cost thresholds because nonattainment and maintenance was not fully
resolved, EPA first notes that CAA section 110 (a)(2)(D)(i)(I) only
requires the elimination of emissions that significantly contribute to
nonattainment or interfere with maintenance of the NAAQS in other
states. Section 110(a)(2)(D)(i)(I) focuses exclusively on the transport
component of nonattainment and maintenance problems. Section
110(a)(2)(D)(i)(I) does not shift to upwind states the responsibility
for ensuring that all areas in other states attain the NAAQS. As such,
the mandate of section 110(a)(2)(D)(i)(I) is not to ensure that
reductions in upwind states are sufficient to bring all downwind areas
in to attainment, it is simply to ensure that all significant
contribution to nonattainment and interference with maintenance is
eliminated. Thus, the presence of residual nonattainment or maintenance
areas does not, by itself, signify a failure to satisfy the
requirements of 110(a)(2)(D)((i)(I).
Furthermore, as noted in section VI.A, EPA is finalizing coverage
only for the EGU emission source-sector category in this rulemaking.
EPA has not included non-EGU sources in this final rulemaking. EPA
remains convinced that timely promulgation and implementation of this
rule is responsive to the Court's remand of CAIR.
To the extent that significant contribution is not eliminated for
the 1997 ozone NAAQS standard at the $500/ton cost threshold, EPA is
not addressing in this rulemaking whether a cost threshold greater than
$500/ton is justified for some upwind states and downwind receptors.
EPA believes it can best serve these states where concerns persist
regarding projected nonattainment or maintenance of the 1997 ozone
NAAQS by quickly finalizing this rule and seeking further non-EGU
reductions in subsequent rulemakings. Table VI.B-2 illustrates the
small amount of EGU reductions available as cost threshold increases
above $500/ton. The ozone-season NOX reductions available in
the Transport Rule states between the $500/ton and $1,000/ton cost
thresholds amount to less than 3,000 tons. EPA believes that
potentially substantial non-EGU ozone-season NOX reductions
become available approaching the $1,000/ton cost threshold. EPA
emphasized this in the proposal, noting that the cost curves for ozone
season NOX did not reflect all available reductions as they
do not include non-EGU reductions (75 FR 45286). For these reasons, EPA
did not consider cost thresholds greater than $500/ton.
EPA did not consider cost thresholds below $500/ton for ozone-
season NOX. $500/ton is a reasonable threshold representing
a significant amount of lowest-cost NOX emission reductions
from EGUs, largely accruing from the installation of combustion
controls, such as low-NOX burners, and constitutes a
reasonable cost level for operation of existing NOX controls
such as SCRs. EPA believes it would be
[[Page 48257]]
inappropriate for a state linked to downwind nonattainment or
maintenance areas to stop operating existing pollution control
equipment (which would increase their emissions and contribution). This
is increasingly likely to occur at cost thresholds lower than $500/ton.
Therefore, EPA did not find cost thresholds lower than $500/ton for
ozone-season NOX to be reasonable for development of the
Transport Rule cost curves.
As discussed in section III of this preamble, EPA intends to
finalize reconsideration of the March 2008 ozone NAAQS in the summer of
2011 and to expeditiously propose a transport-related action to address
any necessary upwind state control responsibilities with respect to
that reconsidered NAAQS.
c. Cost Thresholds Examined and Selected for Annual NOX
Following the assessment of the cost curves in section IV.B and the
air quality modeling of the AQAT calibration scenario using CAMx, EPA
identified a single cost threshold at $500/ton for annual
NOX. Beyond requiring the year-round operation of existing
post-combustion NOX controls and other reductions modeled at
$500/ton threshold, EPA observed a limitation in available low-cost
annual NOX reductions from EGUs. Approximately 7,000 tons of
annual NOX reductions were available from EGUs between the
$500/ton and the $1,000/ton cost thresholds (See Table VI.B.-1).
Furthermore, above the $500/ton threshold, similar to ozone-season
NOX cost curves, the annual NOX cost curves do
not include all available reductions as they do not include non-EGU
reductions. EPA analysis suggests that while NOX emission
reductions lead to reductions in PM2.5, SO2
reductions are generally more cost-effective than NOX
reductions at reducing PM2.5 (75 FR 45281). In part, for
these reasons, EPA's multi-factor assessment suggested that the $500/
ton cost threshold for annual NOX in concert with the cost
thresholds identified for SO2 were the appropriate cost
thresholds for eliminating significant contribution to nonattainment
and interference with maintenance. EPA finds in the final Transport
Rule that the $500/ton cost threshold for annual NOX, in
concert with the SO2 cost threshold selected below,
successfully eliminates significant contribution to nonattainment and
interference with maintenance for the 1997 annual PM2.5
NAAQS and the 2006 24-hour PM2.5 NAAQS in the states covered
by this Rule for PM2.5.
The reasons for not considering cost thresholds lower than $500/ton
for annual NOX are the same as those identified for not
doing so for ozone-season NOX. In addition to its
PM2.5 reduction benefits, annual NOX control at
the $500/ton threshold can help to reduce nitrate replacement in the
atmosphere. As explained earlier, nitrate replacement happens when
SO2 emissions reductions successfully reduce ammonium
sulfate (a component of PM2.5) but provoke a
PM2.5 rebound effect by freeing up additional ammonia to
form ammonium nitrate (another component of PM2.5).
d. Cost Thresholds Examined and Selected for SO2
EPA first assessed the downwind air quality impacts of emission
reductions modeled at the $500/ton threshold in all states found to be
linked to downwind sites for PM2.5 transport, as well as in
the states hosting those downwind sites. The air quality assessment
tool projected that those reductions do not fully resolve nonattainment
and maintenance problems with the PM2.5 standards for
certain areas to which the following states are linked: Illinois,
Indiana, Iowa, Kentucky, Maryland, Michigan, Missouri, New Jersey, New
York, North Carolina, Ohio, Pennsylvania, Tennessee, Virginia, West
Virginia, and Wisconsin. EPA proceeded to analyze available 2014
emission reductions at higher cost thresholds from these states,
collectively referred to as Group 1 states for SO2 control.
For Group 2 states, the air quality assessment tool projected that
the SO2 reductions at this first cost threshold assessed
would resolve the nonattainment and maintenance problems for all of the
areas to which the following states are linked: Alabama, Georgia,
Kansas, Minnesota, Nebraska, South Carolina, and Texas. EPA thus finds
that these states' significant contribution is eliminated at the $500
per ton level in 2014; they are collectively referred to as Group 2
states for SO2 control. Because their significant
contribution is eliminated at this stringency of control, EPA did not
analyze higher cost thresholds for Group 2 states.
The states in Group 1 and Group 2 are rationally grouped
considering air quality and cost. EPA determined that it would not be
appropriate to assign the same cost threshold to Group 2 and Group 1
states because a significantly lower cost threshold was sufficient to
resolve air quality problems at all downwind receptors linked to the
Group 2 states. Although states are linked to different sets of
downwind receptors, EPA analysis indicated that the cost threshold
needed to resolve downwind air quality problems varied only to a
limited extent among states within Group 1 and among states within
Group 2. It did, however, vary greatly between the Group 1 and Group 2
states. The ruling of the DC Circuit in Michigan v. EPA, 213 F.3d 663,
679-80 (D.C. Cir. 2000), accepting EPA's prior use of a transport
remedy with uniform controls, supports EPA's decision to use a uniform
cost threshold for a group of states.
As discussed in section VI.B, the cost threshold for Group 1 states
was examined at escalating levels in 2014 (it remained at $500/ton for
Group 2 states). EPA examined emissions at SO2 cost
thresholds of $500, $1,600, $2,300, $2,800, $3,300, and $10,000/ton for
Group 1 states in 2014. The higher SO2 marginal costs were
only imposed in Transport Rule states starting in 2014, by which time
the advanced pollution control retrofits induced at those higher cost
thresholds could be installed. (See section VI.D.2 for EPA's assessment
and decisions regarding SO2 budget formation in Group 1
states in 2014.)
EPA observed some degree of additional air quality benefit at
downwind receptors across all of the cost thresholds examined for
SO2, but significant air quality outcomes were achieved at
the $2,300/ton cost threshold. The $2,300/ton threshold is projected to
resolve the last remaining nonattainment area for the annual
PM2.5 standard (Liberty-Clairton),\46\ and it also is
projected to resolve the nonattainment and maintenance problems with
the 24-hour PM2.5 standard at 1 monitor in the Detroit area
and resolve the maintenance problems in the Cleveland area. There were
significant air quality improvements at this level in connection with
widespread deployment of pollution control technology, while the cost
impacts remained reasonable.
---------------------------------------------------------------------------
\46\ AQAT results indicated that one receptor in the Liberty-
Clairton area continued to have maintenance problems with the annual
PM2.5 standard. However, final air quality modeling
results (described in section VIII.B) indicated that this
maintenance problem was resolved for this receptor under the final
Transport Rule.
---------------------------------------------------------------------------
Moving beyond $2,300/ton to the $2,800/ton and $3,300/ton
thresholds, EPA projected notably smaller air quality improvements
compared to those projected when moving from the $1,600/ton threshold
to the $2,300/ton threshold. EPA also projected no ultimate change in
the 24-hour PM2.5
[[Page 48258]]
attainment status of the remaining nonattainment area (Liberty-
Clairton) or three remaining maintenance areas (Chicago,\47\ Detroit,
and Lancaster).\48\ At the same time, the total program cost continued
to increase by about the same interval at each of these thresholds as
it had between the $1,600/ton and $2,300/ton thresholds. EPA thus
observed a relatively lower cost-effectiveness of downwind
PM2.5 control via upwind SO2 reductions beyond
$2,300/ton for the receptors linked to Group 1 states. Table VI.D-1 and
Figure VI.D-1 demonstrate this relationship between cost of EGU
SO2 control and downwind PM2.5 concentration
impacts, showing a sustained diminishing of cost effectiveness beyond
the $2,300/ton threshold. The $2,300/ton threshold in this analysis is
situated at the ``knee-in-the-curve'' area of cost-effectiveness for
addressing downwind PM2.5 concentrations with SO2
reductions, beyond which point the air quality gains per dollar spent
on additional reductions are much smaller. This relationship is
demonstrative of the economic potency of SO2 reductions at
each cost threshold to address the PM2.5 concentrations at
linked receptors in this analysis.
---------------------------------------------------------------------------
\47\ This area is not currently designated as nonattainment for
the 24-hour PM2.5 standard. EPA is portraying the
receptors and counties in this area as a single 24-hour maintenance
area based on the annual PM2.5 nonattainment designation
of Chicago-Gary-Lake County, IL-IN.
\48\ AQAT results indicated that two receptors in the Detroit
area continued to have maintenance problems with the 24-hour
PM2.5 standard. However, final air quality modeling
results (described in section VIII.B) indicated that only one
receptor continued to have maintenance problems in this area for
this standard under the final Transport Rule.
Table VI.D-1--Cost-Effectiveness of Group 1 State SO2 Reductions a for Downwind PM2.5 Control
----------------------------------------------------------------------------------------------------------------
Air quality cost-
Additional system cost Average PM2.5 air effectiveness (average
SO2 cost threshold expended (2007$, quality improvement [micro]g/m\3\ reduced
billions) ([micro]g/m\3\) \b\ per billion $
expended)
----------------------------------------------------------------------------------------------------------------
$500................................. 0.22 3.27 14.74
$1,600............................... 0.82 3.86 4.70
$2,300............................... 1.35 4.22 3.11
$2,800............................... 1.94 4.37 2.25
$3,300............................... 2.36 4.50 1.91
$10,000.............................. 3.61 4.99 1.38
----------------------------------------------------------------------------------------------------------------
\a\ Downwind PM2.5 improvement based on SO2 reductions from states ``linked'' to specific receptors. See section
VI.C.
\b\ Measured as the reduction in maximum design value for the 24-hour PM2.5 NAAQS from AQAT base case to each
SO2 threshold for receptors with remaining nonattainment and maintenance exceedances at the $500/ton
threshold, averaged across these receptors.
[GRAPHIC] [TIFF OMITTED] TR08AU11.000
Furthermore, even at the $10,000/ton cost threshold, AQAT still
projects Liberty-Clairton to face maintenance concerns with the annual
PM2.5 standard and is projected to remain in nonattainment
of the 24-hour PM2.5 standard, while the Chicago \49\ and
Lancaster areas are still projected to have residual maintenance
problems
[[Page 48259]]
with the 24-hour PM2.5 standard. EPA projected that even
total elimination of EGU SO2 emissions (no matter the cost)
would not be able to resolve either nonattainment of the 24-hour
PM2.5 standard in the Liberty-Clairton area or the residual
maintenance concerns with that standard in Lancaster County. EPA thus
finds that other PM2.5 strategies, including local
reductions of other PM2.5 precursors, are important to
consider for remaining nonattainment and maintenance areas to seek
further improvements in PM2.5 concentrations.
---------------------------------------------------------------------------
\49\ This area is not currently designated as nonattainment for
the 24-hour PM2.5 standard. EPA is portraying the
receptors and counties in this area as a single 24-hour maintenance
area based on the annual PM2.5 nonattainment designation
of Chicago-Gary-Lake County, IL-IN.
---------------------------------------------------------------------------
Considering both air quality and cost, EPA's multi-factor analysis
indicated $2,300 per ton as an appropriate cost threshold for
SO2 in the Group 1 states. EPA believes the analyzed cost
thresholds lower than $2,300/ton were not appropriate for
SO2 control in the Group 1 states under the Transport Rule
for the following reasons:
Downwind air quality impacts up to the $2,300 threshold
are significant. Moving up to $2,300/ton successfully resolves all
downwind nonattainment of the annual and 24-hour PM2.5
standards except for the Liberty-Clairton receptor in Allegheny county
with respect to 24-hour PM2.5, which EPA has noted is
heavily influenced by a local source of organic carbon (75 FR 45281).
Upwind emission reductions available up to $2,300/ton are
highly cost-effective compared with similar regulations.
The emission reductions up to this threshold are
achievable with widespread deployment of controls that can be installed
at power plants by 2014.
As stated at proposal, EPA finds it reasonable to require
a substantial level of control of upwind state emissions that
significantly contribute to nonattainment or maintenance problems in
another state. The $2,300/ton cost threshold is comparable to EPA's
survey of local non-EGU SO2 reduction opportunities in the
PM2.5 NAAQS RIA, which range in cost from just above $2,300/
ton to over $16,000/ton (2007 $). EPA thus finds it reasonable to seek
EGU SO2 reductions up to $2,300/ton (rather than at a lower
cost threshold) in the states linked to receptors with ongoing
attainment and maintenance concerns with the PM2.5 NAAQS.
EPA believes the analyzed cost thresholds above $2,300/ton were not
appropriate for SO2 control in the Group 1 states under the
Transport Rule for the following reasons:
As noted above, AQAT suggests reductions up to $2,300/ton
were able to resolve all projected downwind nonattainment of the annual
and 24-hour PM2.5 NAAQS, with the sole exception of
projected nonattainment of the 24-hour PM2.5 standard at a
receptor in Liberty-Clairton. It is well-established that, in addition
to being impacted by regional sources, the Liberty-Clairton area is
significantly affected by local emissions from a sizable coke
production facility and other nearby sources, leading to high
concentrations of organic carbon in this area.\50\ EPA finds that the
remaining PM2.5 nonattainment problem is predominantly local
and therefore does not believe that it would be appropriate to
establish a higher cost threshold solely on the basis of this projected
ongoing nonattainment of the 24-hour PM2.5 standard at the
Liberty-Clairton receptor.
---------------------------------------------------------------------------
\50\ http://www.epa.gov/pmdesignations/2006standards/final/TSD/tsd_4.0_4.3_4.3.3_r03_PA_2.pdf.
---------------------------------------------------------------------------
Approximately 70 percent of base case SO2
emissions from Group 1 states were eliminated at the $2,300/ton cost
threshold, leaving a decreasing amount of emission reductions available
at each increased cost threshold beyond $2,300/ton.
Additional EGU SO2 reductions available from
EGUs beyond the $2,300/ton threshold level realize significantly less
improvement in downwind PM2.5 concentrations per dollar
spent to impact receptors linked to Group 1 states. In other words, the
cost-effectiveness of controlling EGU emissions in Group 1 states to
improve downwind PM2.5 concentrations at the linked
receptors is notably diminished beyond the $2,300/ton threshold in this
analysis. See Figure VI.D-1.
EGUs are by far the largest source category for
SO2 emissions. This analysis shows that reductions of EGU
SO2 emissions up to the $2,300/ton cost threshold were
significantly more cost-effective for improving downwind
PM2.5 concentrations than further such reductions (beyond
the $2,300/ton cost threshold) would be to address the remaining
PM2.5 maintenance concerns. EPA's analysis also shows that
these maintenance concerns cannot be fully resolved even with complete
elimination of all remaining EGU SO2 emissions, no matter
the cost. EPA finds that other PM2.5 precursor emission
reductions, particularly those from local sources will be critical for
states in these remaining areas to consider for controlling
PM2.5 concentrations with respect to maintenance of the 2006
24-hour PM2.5 NAAQS.
In summary, the appropriate cost thresholds for each state were
identified through the multi-factor assessment. This assessment
included both cost and air quality considerations. As explained above,
the ozone-season NOX threshold was determined to be $500/ton
for all states required to reduce ozone-season NOX, with
residual nonattainment and maintenance concerns to be addressed in a
future rulemaking addressing a broader set of source categories for
additional cost-effective reductions. For PM2.5, the
appropriate cost threshold for each state was determined to be either
the level at which nonattainment and maintenance issues were completely
resolved in downwind states to which the state is linked, the level
where remaining nonattainment and maintenance issues are primarily
local, or where we found greatly diminished improvements in air quality
occurring if EPA moved further up the cost curve. This assessment
yielded a cost threshold of $2,300/ton on SO2 for Group 1
states starting in 2014 ($500/ton in 2012), a cost threshold of $500/
ton on SO2 for Group 2 states, and a cost threshold of $500/
ton on annual NOX for all states required to reduce
emissions for purposes of the annual or 24-hour PM2.5 NAAQS
in this rule.
As explained above, none of these specific cost thresholds
establish any precedent for the cost per ton stringency of reductions
EPA may require in future transport-related rulemakings; these specific
cost thresholds are based on current analyses of air quality and cost
of emission reductions with respect to the NAAQS considered in this
rulemaking and thus would not be relevant to future rulemakings (which
would consider updated information) or rulemakings with respect to
different NAAQS. In particular, EPA acknowledges that additional action
EPA will require in a subsequent rulemaking to address significant
contribution to nonattainment and interference with maintenance of the
2008 ozone NAAQS (once reconsideration is finalized) is very likely to
require a higher cost per ton stringency of ozone-season NOX
control applied to a broader set of source categories from upwind
states than found to be appropriate for this rulemaking.
2. State Emission Budgets (Step 4)
a. Budget Methodology
EPA used the multi-factor assessment to identify, for each state,
the cost threshold that should be used to quantify that state's
significant contribution. As described above, in the context of this
rulemaking EPA identified a cost threshold of $500/ton for ozone-season
NOX control for all states required to reduce ozone-season
[[Page 48260]]
NOX emissions for purposes of the 1997 ozone NAAQS in this
rule. EPA also identified a cost threshold of $500/ton for annual
NOX control for all states required to reduce annual
NOX emissions for purposes of the annual or 24-hour
PM2.5 NAAQS in this rule. Finally, EPA identified a cost
threshold of $500/ton of SO2 starting in 2012 for all states
required to reduce SO2 emissions for purposes of the annual
or 24-hour PM2.5 NAAQS in this rule, and $2,300/ton for the
Group 1 states starting in 2014.
EPA used these cost thresholds from the multi-factor analysis to
quantify each state's emissions that significantly contribute to
nonattainment or interfere with maintenance downwind. For example, for
a Group 1 state, EPA modeling of the cost threshold conveys emission
reductions available in each covered state from operation of existing
pollution controls as well as all emission reductions available at cost
thresholds of $500/ton for annual NOX in 2012 and 2014,
$500/ton for SO2 in 2012, and $2,300/ton for SO2
in 2014. The total SO2 and NOX projected at these
cost levels in that state in those years represents that state's
emissions once significant contribution to nonattainment or
interference with maintenance downwind for the relevant
PM2.5 NAAQS has been eliminated.
Table VI.D-2--Example of Emission Reductions and Budget Formation in Pennsylvania for Annual SO2 and NOXa
--------------------------------------------------------------------------------------------------------------------------------------------------------
Remaining
Final cost Base case emissions at Emissions
threshold emissions (1,000 cost thresholds eliminated
tons) (1,000 tons) (1,000 tons)
--------------------------------------------------------------------------------------------------------------------------------------------------------
A B............................... C D E F
--------------------------------------------------------------------------------------------------------------------------------------------------------
2012.......................................... SO2............................. $500 493 279 215
NOX............................. 500 129 120 9
2014.......................................... SO2............................. 2,300 507 112 395
NOX............................. 500 132 119 13
--------------------------------------------------------------------------------------------------------------------------------------------------------
\a\ Note: In this table, emissions are shown for fossil-fuel-fired EGUs > 25 MW (i.e., those units likely covered by the Transport Rule). Table VI.D.2
illustrates how budgets are derived from the elimination of significant contribution for the state of Pennsylvania. Column C illustrates the cost
thresholds applied in the costing run that was ultimately identified as the final cost threshold in the multi-factor analysis. Column D shows the base
case emissions for the identified pollutant in the identified time period. Column E shows the emission levels that result when the cost thresholds
identified in column C are applied. Because this is the cost threshold identified through the multi-factor analysis and the point where all
significant contribution to nonattainment and interference with maintenance has been addressed for the PM2.5 NAAQS--state budgets are based on these
emission levels. The final column illustrates the emission reductions for the state in an average year (before accounting for variability).
EPA's modeling of a state's SO2 and annual
NOX emission levels (from fossil-fired EGUs > 25 MW) at the
relevant cost thresholds in each state reflect that state's emissions
from covered sources after the removal of significant contribution to
nonattainment and interference with maintenance of the PM2.5
NAAQS considered in this rulemaking. As these state emission levels
reflect the removal of significant contribution and interference with
maintenance, they are reasonable levels on which to determine state
budgets. Consequently, EPA based state budget levels on the state level
emissions that remained at the cost threshold. Each state's budget
corresponds to its emission level following the elimination of
significant contribution to nonattainment and interference with
maintenance in an average year (before taking year-to-year variability
into account, as discussed in section VI.E below). Therefore, the
implementation and realization of these budgeted emission levels leads
to the elimination of significant contribution to nonattainment and
interference with maintenance and EPA meets the statutory mandate of
section 110(a)(2)(D)(i)(I) with respect to the 1997 annual
PM2.5 NAAQS and the 2006 24-hour PM2.5 NAAQS.
EPA's establishment of state budgets for ozone-season
NOX control follow the same methodology as described above
for SO2 and annual NOX. Implementation of these
ozone-season NOX budgets reflects the elimination of
significant contribution to nonattainment and interference with
maintenance of the 1997 ozone NAAQS for 15 states, whereas 11 other
states' ozone-season NOX budgets reflect meaningful progress
toward (but may not reflect full completion of) this elimination under
the mandate of section 110(a)(2)(D)(i)(I). See section III for lists of
states.
This approach to basing budgets on projected state level emissions
used in the multi-factor analysis is identical to the approach used in
the proposal for determining 2014 SO2 budgets for Group 1
states. EPA is extending this approach more broadly in the final
Transport Rule to create state budgets for ozone-season NOX,
annual NOX, and SO2 in all relevant states in
both 2012 and 2014. In the proposal EPA used a more complex approach
based on a comparison of historic and projected unit-level emissions
(further adjusted for operation of existing controls) in each state to
create 2012 state budgets for ozone-season NOX, annual
NOX, and Group 2 SO2. At the time of proposal,
EPA believed that historic 2009 emissions data were in some cases more
representative of expected emissions in 2012 than pure modeling
projections made at the time (75 FR 45290).
However, following the proposal EPA has made significant updates to
the IPM model for projecting EGU emissions, including specifically the
adoption of 2009 historic data into its modeling parameters directly.
EPA also received substantial public input following the proposal on
the model's assumptions and representation of individual units, which
allowed EPA to improve its 2012 and 2014 emission projections for
states under the cost thresholds considered. These modeling updates
diminish the concerns EPA expressed at proposal that 2009 historic data
may have offered for some states a better proxy for 2012 emissions than
model projections, particularly now that EPA is incorporating 2009 data
directly in its updated modeling projections. Given these updates to
the model in response to public comment, EPA believes it is more
appropriate for the final rule to use a consistent approach based on
projected state level emissions for all state budgets, as was done for
Group 1 SO2 budgets in 2014 at proposal. EPA received
significant comment supporting the use of the model to
[[Page 48261]]
project state-level emissions for creating budgets in this manner. EPA
also received comments that criticized the proposal's methodology for
2012 budgets for lack of transparency, unnecessary complexity, and
inconsistency with the state-level emission projections used in the air
quality modeling. EPA's decision for the final Transport Rule to
consistently apply across all pollutants the budget methodology
originally used for Group 1 SO2 budgets in 2014 addresses
those concerns.
This budget methodology for the final rule uses projected state-
level emissions in 2012 and 2014 to set emission budgets for those
years on relevant pollutants for that state to control under the
Transport Rule. EPA's modeling projects that some states have 2014
emissions that are lower than their 2012 projected emissions even as
the same cost threshold (e.g., $500/ton) is applied in both years. This
occurs in the annual NOX, ozone-season NOX, and
Group 2 SO2 program. As such, EPA's application of this
budgeting methodology results in a tightening of budgets in states
whose projected emissions of that budgeted pollutant decline from 2012
to 2014 as the cost threshold is held constant.
There are two primary variables that explain the decrease in
emissions for some states between 2012 and 2014 as the cost threshold
remains constant over both time periods. First, even though the cost
threshold is constant between 2012 and 2014 for the programs noted
above, the cost threshold for SO2 Group 1 increases in 2014.
This higher cost threshold for Group 1 SO2 results in
obvious reductions in SO2 emissions in the Group 1 states,
but also may lower the cost of certain related NOX
reductions in those states as well such that they become newly
available within the $500/ton threshold. For example, if a state
increases natural gas generation in response to the higher
SO2 cost threshold, such action also yields additional
annual and ozone-season NOX emission reductions that are
cost-effective at the $500/ton NOX threshold. Where the cost
curve modeling shows such additional cost-effective NOX
reductions in tandem with SO2 control, EPA is therefore
reducing those states' 2014 annual NOX and ozone-season
NOX budgets accordingly, so that those budgets accurately
reflect remaining emissions from covered sources in those states after
the elimination of all emissions that can be reduced up to the relevant
cost thresholds (e.g., $500/ton).
Second, some of these additional reductions are driven by non-
Transport Rule variables. These are reductions that occur due to state
rules, consent decrees, and other planned changes in generation
patterns that occur after 2012, but during or prior to 2014. For
example, EPA modeling reflects emission reduction requirements under
provisions of a Georgia state rule that go into effect after 2012 but
before 2014. These requirements involve the installation and operation
of specific advanced pollution controls. These source-specific
requirements under a legal authority unrelated to the Transport Rule
result in sharp reductions in Georgia's baseline emission projections
between 2012 and 2014. Even though the cost threshold for
NOX and for SO2 in Georgia is $500/ton in both
2012 and 2014, EPA believes it is important to establish separate
NOX and SO2 budgets that accurately reflect the
emissions remaining in Georgia (and other states experiencing similar
reductions) after the elimination of emissions that can be reduced up
to the Transport Rule remedy's cost thresholds (e.g., $500/ton) (see
Table VI.D.3). It illustrates a notable decrease between the 2012 and
2014 state budgets for NOX and SO2 in Georgia
that is largely driven by state rule requirements. If EPA did not
adjust 2014 budgets to account for other emission reductions that would
occur even in the baseline, other sources within the state would be
allowed to increase their emissions under the unadjusted Transport Rule
budgets to offset the emission reductions planned under other
requirements such as state rules. Therefore, to prevent the Transport
Rule from allowing such offsetting of emission reductions already
expected to occur between 2012 and 2014, EPA is establishing separate
budgets for 2012 and 2014 in the final Transport Rule to capture
emission reductions in each state that would occur for non-Transport
Rule-related reasons (i.e., in the base case) during that time.
EPA's modeling also projects that other states would slightly
increase emissions from 2012 to 2014 even at the same cost threshold,
such as $500/ton. There are two primary variables that explain the
increase in emissions for these states between 2012 and 2014. These
increases are generally small in magnitude. For annual and ozone season
NOX, they occur as a byproduct of small changes in dispatch
related to changes in non-Transport Rule factors (e.g., higher demand
in 2014). For SO2, they primarily occur in Group 2 states
and, in addition to the reasons given above, are influenced by some
generation shifting from Group 1 to Group 2 states as the Group 1
states begin to face a higher cost threshold in 2014. EPA believes that
allowing for such emission growth in covered states beyond 2012 would
be inconsistent with the Transport Rule's identification and
elimination of significant contribution to nonattainment and
interference with maintenance beginning in 2012. Therefore, for any
covered state whose emissions of a relevant pollutant are projected to
increase from 2012 to 2014 under the relevant cost thresholds selected
in the multi-factor analysis described above, EPA is finalizing that
state's 2014 emission budget to maintain the same level of the 2012
emission budget, thereby disallowing such an emission increase that is
inconsistent with the 110(a)(2)(D)(i)(I) mandate. Tables VI.D-3 and
VI.D-4 below list state emission budgets.\51\
---------------------------------------------------------------------------
\51\ These budgets include minor technical corrections to
SO2 budgets in three states (KY, MI, and NY) that were
made after the impact analyses for the final rule were conducted.
EPA conducted sensitivity analysis confirming that these differences
do not meaningfully alter any of the Agency's findings or
conclusions based on the projected cost, benefit, and air quality
impacts presented for the final Transport Rule. The results of this
sensitivity analysis are presented in Appendix F in the final
Transport Rule RIA.
Table VI.D-3--SO2 and Annual NOX State Emission Budgets for Electric Generating Units Before Accounting for Variability *
[Tons]
--------------------------------------------------------------------------------------------------------------------------------------------------------
SO2 NOX
Group -----------------------------------------------------------------------
2012-2013 2014 and beyond 2012-2013 2014 and beyond
--------------------------------------------------------------------------------------------------------------------------------------------------------
Alabama....................................................... 2 216,033 213,258 72,691 71,962
Georgia....................................................... 2 158,527 95,231 62,010 40,540
[[Page 48262]]
Illinois...................................................... 1 234,889 124,123 47,872 47,872
Indiana....................................................... 1 285,424 161,111 109,726 108,424
Iowa.......................................................... 1 107,085 75,184 38,335 37,498
Kansas........................................................ 2 41,528 41,528 30,714 25,560
Kentucky...................................................... 1 232,662 106,284 85,086 77,238
Maryland...................................................... 1 30,120 28,203 16,633 16,574
Michigan...................................................... 1 229,303 143,995 60,193 57,812
Minnesota..................................................... 2 41,981 41,981 29,572 29,572
Missouri...................................................... 1 207,466 165,941 52,374 48,717
Nebraska...................................................... 2 65,052 65,052 26,440 26,440
New Jersey.................................................... 1 5,574 5,574 7,266 7,266
New York...................................................... 1 27,325 18,585 17,543 17,543
North Carolina................................................ 1 136,881 57,620 50,587 41,553
Ohio.......................................................... 1 310,230 137,077 92,703 87,493
Pennsylvania.................................................. 1 278,651 112,021 119,986 119,194
South Carolina................................................ 2 88,620 88,620 32,498 32,498
Tennessee..................................................... 1 148,150 58,833 35,703 19,337
Texas......................................................... 2 243,954 243,954 133,595 133,595
Virginia...................................................... 1 70,820 35,057 33,242 33,242
West Virginia................................................. 1 146,174 75,668 59,472 54,582
Wisconsin..................................................... 1 79,480 40,126 31,628 30,398
-----------------------------------------------------------------------
Grand Total............................................... ................ 3,385,929 2,135,026 1,245,869 1,164,910
-----------------------------------------------------------------------
Group 1 Total............................................. ................ 2,530,234 1,345,402 NA NA
-----------------------------------------------------------------------
Group 2 Total............................................. ................ 855,695 789,624 NA NA
--------------------------------------------------------------------------------------------------------------------------------------------------------
Note: These state emission budgets apply to emissions from electric generating units covered by the Transport Rule Program. Group 1/Group 2 designations
are only relevant for SO2 emissions budgets.
* The impact of variability on budgets is discussed in section VI.E.
The District of Columbia is not covered by the final Transport
Rule. As discussed in section V.D of this preamble and as done for the
Transport Rule proposal, EPA combined contributions projected in the
air quality modeling from Maryland and the District of Columbia to
determine whether those jurisdictions collectively contribute to any
downwind nonattainment or maintenance receptor in amounts equal to or
greater than the 1 percent thresholds. This modeling confirmed that the
combined contributions exceed the air quality threshold at downwind
receptors for the ozone, annual PM2.5, and 24-hour
PM2.5 NAAQS considered. Both Maryland and the District of
Columbia are therefore linked to these receptors.\52\ However, the
District of Columbia is not included in the Transport Rule because, in
the second step of EPA's significant contribution analysis, we
concluded that there are no emission reductions available from EGUs in
the District of Columbia at the cost thresholds deemed sufficient to
eliminate significant contribution to nonattainment and interference
with maintenance of the NAAQS considered at the linked receptors. At
the time of this rulemaking, EPA finds only one facility with units
meeting the Transport Rule applicability requirements in the District
of Columbia. EPA's projections do not show any generation from this
facility to be economic under any scenario analyzed (including the base
case), and the facility's owners have also announced plans to retire
its units in early 2012.\53\ Therefore, this unit is projected to have
zero emissions in 2012. As such, the total SO2 and
NOX emissions in the District of Columbia for EGUs that meet
the Transport Rule applicability requirements is also projected to be
zero. It follows therefore, that EPA did not identify any emission
reductions available at any of the cost thresholds considered in the
final rule's multi-factor analysis to identify significant contribution
to nonattainment and interference with maintenance. For this reason,
EPA concludes that no additional limits or reductions are necessary, at
this time, in the District of Columbia to satisfy the requirements of
section 110(a)(2)(D)(i)(I) with respect to the 1997 ozone, the 1997
PM2.5 and the 2006 PM2.5 NAAQS. EPA is therefore
neither establishing budgets nor finalizing any FIPs for the District
of Columbia in this rule.
---------------------------------------------------------------------------
\52\ It is important to note that Maryland's modeled
contributions in isolation were greater than the 1 percent threshold
for all three of the NAAQS considered at all of the same receptors
for which Maryland and DC were ``linked,'' and therefore EPA would
have considered Maryland ``linked'' to the same set of downwind
receptors even if the Agency had treated Maryland's contributions
and the District of Columbia's contributions separately.
\53\ The future retirement status of this D.C. facility was also
supported by its inclusion on PJM's future deactivation list. PJM
further suggested that reliability issues related to their
retirement are expected to be resolved by next year in time for its
planned retirement date. (See PJM pending deactivation request in TR
Docket.)
Table VI.D-4--Ozone Season NOX State Emission Budgets for Electric
Generating Units Before Accounting for Variability *
[Tons]
------------------------------------------------------------------------
2014 and
2012-2013 beyond
------------------------------------------------------------------------
Alabama......................................... 31,746 31,499
Arkansas........................................ 15,037 15,037
Florida......................................... 27,825 27,825
Georgia......................................... 27,944 18,279
Illinois........................................ 21,208 21,208
[[Page 48263]]
Indiana......................................... 46,876 46,175
Kentucky........................................ 36,167 32,674
Louisiana....................................... 13,432 13,432
Maryland........................................ 7,179 7,179
Mississippi..................................... 10,160 10,160
New Jersey...................................... 3,382 3,382
New York........................................ 8,331 8,331
North Carolina.................................. 22,168 18,455
Ohio............................................ 40,063 37,792
Pennsylvania.................................... 52,201 51,912
South Carolina.................................. 13,909 13,909
Tennessee....................................... 14,908 8,016
Texas........................................... 63,043 63,043
Virginia........................................ 14,452 14,452
West Virginia................................... 25,283 23,291
-----------------------
Total....................................... 495,314 466,051
------------------------------------------------------------------------
Note: These state emission budgets apply to emissions from electric
generating units covered by the Transport Rule Program. Group 1/Group
2 designations are only relevant for SO2 emissions budgets.
* The impact of variability on budgets is discussed in section VI.E.
EPA notes that the NOX budgets for five states linked to
downwind ozone receptors in the final Transport Rule are equal to their
projected 2012 base case emissions. The five states are Arkansas,
Indiana, Louisiana, Maryland, and Mississippi. These states are among
those found to meet or exceed the 1 percent contribution threshold for
the 1997 ozone NAAQS at downwind receptors and are thus ``linked'' to
downwind receptors. EPA therefore evaluates, in the second step of its
significant contribution analysis, what emission limits are necessary
to ensure that all emissions that constitute the state's significant
contribution to nonattainment and interference with maintenance are
prohibited. As explained above, EPA decided to require from all such
states all reductions available at the $500/ton cost threshold. The
five states identified above do not appear to show EGU ozone-season
NOX reductions at the $500/ton cost threshold relative to
the 2012 base case projections (which do not take into account
reductions to be made in other states as a result of this rule).
Therefore, EPA conducted further analysis to evaluate whether such
reductions were available in these states and whether emission limits
are necessary to prohibit these states from significantly contributing
to downwind nonattainment or interfering with maintenance of the 1997
ozone NAAQS in other states. (See the docket to this rulemaking for the
IPM run titled TR--uncontrolled--ozone--states--Final.'')
Specifically, EPA projected those states' ozone-season
NOX emissions if all other linked states (but not these five
states) were to make all available reductions at the $500/ton
threshold. That analysis revealed that if emission limits were not
established for these five states, ozone-season NOX
emissions in each of the states would increase (beyond the 2012 base
case emission projections), due to interstate shifts in electricity
generation that cause ``emissions leakage'' in uncovered states. These
increases would result in each state's emissions being above the level
associated with the prohibition of all emissions that can be eliminated
at the $500/ton threshold. EPA thus determined that it is necessary to
establish emission limits for these states at the $500/ton level. These
limits, although equal to the state's 2012 projected base case
emissions, are necessary to prohibit all emissions that can be
controlled at the $500/ton cost threshold. In other words, the
significant contribution to nonattainment and interference with
maintenance addressed by the ozone FIPs for these states is the
difference between these states' projected emissions if they were not
covered under the Transport Rule (but other states were), and their
emissions after all emissions that can be eliminated at $500/ton are
prohibited.
In addition, EPA notes that four of these five states (Arkansas,
Indiana, Louisiana, and Mississippi) are linked to receptors in either
the Houston or Baton Rouge areas, which are projected to continue
facing nonattainment or maintenance concerns with the 1997 ozone NAAQS,
respectively. To allow these states to increase emissions above base
case projections would erode the measurable progress toward eliminating
significant contribution to nonattainment and interference with
maintenance secured by achieving ozone-season NOX reductions
in the other states linked to these receptors. Furthermore, as
discussed in section III, EPA may require additional reductions in
these states to fully address significant contribution to nonattainment
and interference with maintenance with respect to the 1997 ozone NAAQS
in a future rulemaking to be proposed after finalizing reconsideration
of the 2008 ozone NAAQS.
b. Relationship of Group 1 and Group 2 States for SO2
Control
In the Proposal, EPA chose not to allow sources in Group 1 states
to use Group 2 SO2 allowances for compliance, and likewise
not to allow sources in Group 2 states to use Group 1 SO2
allowances for compliance at any time. The preamble clearly states,
``With regard to interstate trading, the two SO2 stringency
tiers would lead to two exclusive SO2 trading groups. That
is, states in SO2 Group 1 could not trade with states in
SO2 Group 2'' (75 FR 45216). No such distinction or
limitation exists for NOX allowance trading.
EPA received significant public comment both in support and
opposition to the two distinct SO2 trading programs. Those
in opposition noted that the variability limits imposed at the state
level made the compliance restrictions between the two groups
unnecessary. Commenters also noted that it may unfairly penalize
sources that are part of the same airshed, but are on opposite sides of
a state boundary. Those in favor of the separate SO2
compliance programs noted that it would reduce the probability of a
state exceeding its variability limit. Allowing the use of Group 1 or
Group 2 allowances for compliance between the two SO2
programs would potentially encourage Group 1 states to purchase
allowances instead of making reductions necessary to eliminate
significant contribution. Group 1 states are states that need continued
reductions (beyond the $500/ton threshold) to eliminate their
significant contribution to nonattainment and interference with
maintenance. Group 2 states have already eliminated their significant
contribution to nonattainment and interference with maintenance at the
$500/threshold. So to allow Group 1 or Group 2 allowances to be used
interchangeably for compliance between the two SO2 groups
would be to allow the shifting of reductions from areas where they are
needed to eliminate significant contribution to nonattainment and
interference with maintenance to areas where they are not needed to
eliminate the prohibited emissions. EPA also agrees that allowing for
trading between the two groups in the remedy finalized in this action
would increase risk of a state exceeding its variability limit. For
these reasons, EPA is finalizing this rulemaking with the same
prohibition on SO2 trading between Group 1 and Group 2
states that was defined in the proposal. Further, EPA clarifies that
while trading of allowances (i.e.,
[[Page 48264]]
buying, selling, and banking) is allowed without restriction, it is
specifically the surrender of SO2 allowances for compliance
that is limited. As mentioned earlier, a source in a Group 1 state can
only use SO2 allowances allocated to Group 1 states for
compliance with the SO2 trading program. Likewise, a source
in a Group 2 state can only use SO2 allowances allocated to
Group 2 states for compliance with the SO2 trading program.
c. Ozone-Season Budgets
EPA established the ozone-season NOX budgets in a
similar manner to the annual NOX and SO2 budgets
by using the state level emissions from the cost threshold that
reflected the removal of significant contribution to nonattainment and
interference with maintenance. Ozone-season budgets were based on the
state level emissions from fossil-fuel-fired units greater than 25 MW
observed at this cost threshold. As described in section VI.B, all cost
thresholds examined reflected the final Transport Rule geography and
the marginal costs were applied accordingly. Therefore, for an ozone-
only state like Florida, the state level emissions would only reflect
an ozone-season cost threshold of $500/ton in the final cost curves for
2012 and 2014. For a state subject to both annual and ozone-season
programs, the marginal cost curves would reflect a $500/ton
NOX cost year round, a $500/ton SO2 cost in 2012
and the $2,300/ton SO2 cost starting in 2014 if a Group 1
state.
(1) Length of Ozone Season
(a) Proposed Rule. For purposes of determining ozone-season budgets
in the proposed rule, EPA defined the ozone season based on a 5 month
period (May 1 through September 30). This 5 month ozone season was
consistent with the approach taken by the OTAG, the NOX SIP
Call, and CAIR. EPA requested comment on whether EPA should base final
rule budgets on a longer season, such as March through October.
(b) Public Comments. Several commenters supported continuing with
the May through September time period. One commenter supported
continuing with this time period, but argued that EPA should consider
lengthening the ozone season for future efforts. One commenter
questioned the concept of ozone season budgets and recommended EPA
focus on sources with greater emissions on high ozone days.
(c) Final rule. For the final rule, EPA has retained the approach
in the proposed rule, as commenters broadly supported the proposal's
ozone-season duration and ozone-season NOX limitations.
Notably, many Transport Rule states covered for PM2.5
reductions will have sources with annual NOX controls that
are likely to keep operating year round to address PM2.5 and
ozone. EPA believes that experience from ozone-season NOX
trading has consistently shown that the emission measures taken to
comply with ozone-season budgets provide emission reductions throughout
the ozone-season, including the highest ozone days. (See NOX
Budget Trading Program and CAIR Program progress reports in the docket
to this rulemaking or at http://www.epa.gov/airmarkets/progress/nbp08.html and http://www.epa.gov/airmarkets/progress/CAIR_09/CAIR09.html.) However, EPA believes that there is merit in future
Agency actions addressing ozone transport in considering strategies to
target high ozone days more specifically.
d. Summary of Cost Thresholds and Final Budgets for PM2.5
and Ozone
Summary of methodology. In summary, EPA determined that
SO2 emissions that could be reduced for $2,300/ton in 2014
should be considered a state's significant contribution to
nonattainment and interference with maintenance, unless EPA determined
that a lesser reduction would fully resolve the nonattainment and/or
maintenance problem for all the downwind receptors to which a
particular state might be linked. For these Group 2 states EPA is
determining that a lesser reduction of SO2, based on the
amount of SO2 reductions that can be reasonably achieved by
2012 is appropriate. This level is defined by the reductions observed
in the $500/ton cost threshold. EPA also determined that all states
linked to downwind PM2.5 nonattainment and maintenance
problems should be required to achieve those emission reductions that
can be reasonably achieved by 2012. Finally, EPA determined that all
states linked to downwind PM2.5 nonattainment and
maintenance problems should, by 2012, remove all NOX
emissions that can be reduced for $500/ton and run all existing
controls in 2012.
For ozone-season NOX, EPA determined that all states
linked to downwind ozone and nonattainment and maintenance problems
should be required to achieve those ozone-season emission reductions
associated with a cost threshold of $500 per ton. Additionally, EPA
examined final 2012 and 2014 budgets based on state level emissions at
$500 cost threshold.
The budget formation methodology finalized in this action responds
to concerns about state budgets expressed by commenters on the
Transport Rule proposal. EPA requested comment on the four step
approach used to determine significant contribution and determine
budgets in the proposal. Some commenters noted that the state level
emissions from the cost thresholds used to determine significant
contribution to nonattainment and interference with maintenance did not
match the state level emissions allowed by the final budgets. The
concern was that the state level emissions that reflected the
elimination of significant contribution in the AQAT analysis, in
particular for NOX, were less than the emissions allowed by
the final budgets. The result would be an implementation that did not
quite fully eliminate the significant contribution to nonattainment and
interference with maintenance defined in the rule. The proposed budgets
not matching the levels reflected in the proposed costing runs were an
artifact of the budget formation process that relied on a combination
of historic and projected data. While EPA noted this process resulted
in state budgets that ``reflected'' EGU emissions at $500/ton, it was
not always consistent with the EGU emissions at $500/ton in the costing
runs as the commenters noted. By using the cost curves to determine
both significant contribution to nonattainment and interference with
maintenance--and state budgets--in the final rule, EPA addresses the
commenter's concerns about any inconsistency between the two in the
proposal.
Some commenters expressed concern that the Transport Rule would
result in state budgets that were in some cases higher than those
established in CAIR. Commenters suggested that this would be
inconsistent with requirements or the spirit of certain CAA provisions
aimed at preventing backsliding, i.e., sections 110(l), 172(e), and
193. However, the DC Court of Appeals rejected the state budgets in
CAIR as arbitrary and capricious and not consistent with CAA section
110(a)(2)(D)(i)(I) (North Carolina, 531 F.3d 918 and 921) and remanded
CAIR to EPA to promulgate a new rule replacing CAIR and consistent with
the Court's decision (North Carolina, 550 F.3d 1178). As discussed
elsewhere in this section, on remand EPA developed new, final state
budgets that address the Court's concerns and meet section
110(a)(2)(D)(i)(I) requirements.
Although some state budgets under the final rule are higher than
those
[[Page 48265]]
under CAIR, this does not violate either the letter or the spirit of
CAA provisions aimed at backsliding. In particular, CAA section 110(l)
provides that the Administrator may not approve a plan revision that
would ``interfere with any * * * applicable requirement'' of the CAA.
42 U.S.C. 7410(l). Because the Court reversed and remanded CAIR with
instructions to ``remedy'' the rule's ``fundamental flaws'' (including
specifically the state budgets found to be unlawful (North Carolina,
550 F.3d 1178), it is difficult to see how new state budgets replacing
unlawful budgets and meeting section 110(a)(2)(D)(i)(I) requirements
could be viewed as interfering with requirements of the CAA. Indeed,
the commenters' approach would severely limit EPA's ability to meet the
Court's mandate to develop a new rule consistent with section
110(a)(2)(D)(i)(I). See North Carolina, 531 F.3d 921 (explaining that
EPA may not require ``some states to exceed the mark'' of eliminating
their significant contribution). Further, the other CAA sections cited
by the commenters (section 172(e), addressing circumstances where the
Administrator relaxes a NAAQS, and section 193, addressing the
treatment of requirements promulgated before the November 15, 1990,
enactment date for the 1990 Amendments to the Clean Air Act) are not
applicable here.
Additionally, while the CAIR budgets may have been tighter than
Transport Rule state budgets for a couple of states, the sum of state
budgets that were subject to both CAIR and the Transport Rule is lower
under the Transport Rule for the annual programs. Moreover, the
carryover of the large Title IV allowance bank in CAIR allowed for a
great deal more emissions within any given state than is permitted
under the Transport Rule.
E. Approach to Power Sector Emission Variability
1. Introduction to Power Sector Variability
Variability is an inherent aspect of the production and delivery of
electricity. It follows that variations in state emissions are not only
a result of variations in the level of emission control, but also are
caused by the inherent variability in power generation. The state
budgets do not account for this latter source of variability at the
state level. Emission variability is built into the design of power
systems, which use a wide mix of power generation sources with varying
use and emission patterns to ensure reliability in electric power
generation. Variations in weather, demand due to changes in the level
of economic activity, the portion of electric generation that is
fossil-fuel-fired, the length and number of outages at power generation
units, and other factors, can lead to significant variations in the
load levels of different power generation sources. Variations in the
load levels of sources in any given state cause variations in the level
of emissions in that state. Thus, EPA believes it is appropriate, in
this rule, to take into account the variations that are caused by
inherent variability in power generation. More specifically, variations
in these external variables can cause significant fluctuations in state
emissions, even when action has been taken to prohibit all emissions
within a state that significantly contribute to nonattainment or
interfere with maintenance in another state. For this reason, EPA
considers variability when determining the state specific requirements
in this rule. EPA does so by developing variability limits and
assurance levels for each state, as described in this section, that are
consistent with the statutory mandate of CAA section
110(a)(2)(D)(i)(I).
Loads on a power system, and thus on power generation sources in a
given state that are on the power system, vary over every time
interval, changing not only in the short term and seasonally, but also
annually. As noted above, load patterns and levels are determined by a
multiplicity of factors, including weather, economic activity, the
portion of electric generation that is fossil-fuel-fired, and the
length and number of outages at power generation units, which vary over
time. In particular, weather obviously varies not just from season-to-
season but also from year-to-year, and even small changes in annual
weather patterns can affect how the power system and power generation
sources on the power system operate during a year. For example, load,
and the resulting use of generation sources on an interconnected grid
to meet load, depend not only on how hot a summer day is, but also on
where a heat wave occurs and how long it lasts. Similarly, a relatively
cold winter that drives up winter load may also change what generation
sources are used to address the increased demand for heat. Thus, the
pattern of generation may shift geographically as a weather pattern
moves across the country. Because weather and other factors affecting
loads, and the patterns of generation used to meet loads, vary over
time and from state to state, the resulting level of emissions also
varies over time and from state to state.
This variability in emissions is not a result of variation in
emission rates, emission controls, or emission control strategies, but
instead is a result of the inherent variability in power generation.
Patterns of generation change to ensure demand for electricity is met
and to ensure continued reliability of the power system. This results
in temporal and geographic fluctuations in emissions. In the final
Transport Rule, like the proposed rule, EPA explicitly takes account of
these changing patterns of generation and the resultant variability in
power sector emissions.
As discussed previously, EPA identified a specific amount of
emissions that must be prohibited by each state to meet the
requirements of CAA section 110(a)(2)(D)(i)(I). EPA also developed
state baseline emissions for power generation sources based on
projections of state emissions in an average year before the
elimination of prohibited emissions, and state budgets for power
generation sources based on projections of state emissions in an
average year after the elimination of such emissions. However, because
of the inherent variability in state-level baseline emissions--
resulting from the inherent variability in loads and power system and
power generation source operations--state-level emissions will
fluctuate from year-to-year even after all significant contribution to
nonattainment and interference with maintenance that EPA identified in
this final rule are eliminated. In an above average year, emissions may
exceed the state budgets which are based on an analysis of projected
emissions in an average year. EPA believes that, because baseline
emissions are variable for reasons unrelated to the degree of emission
control in a state and emissions after the elimination of all
significant contribution to nonattainment and interference with
maintenance are therefore also variable, it is appropriate to take this
variability into account in developing the remedy for meeting the
requirements of CAA section 110(a)(2)(D)(i)(I). The variability limits
and assurance levels in the final rule account for this inherent
variability, while ensuring that emissions within each state that
significantly contribute to nonattainment or interfere with maintenance
in another state are prohibited. EPA believes this approach is both
reasonable in that it reflects the operation of the power system
generation in order to maintain electric reliability and consistent
with the statutory mandate of CAA section 110(a)(2)(D)(i)(I). For these
reasons, EPA
[[Page 48266]]
is finalizing variability limits for each state budget to identify the
range of emissions that EPA believes is likely to occur in each state
following the elimination of all the state's significant contribution
to nonattainment and interference with maintenance.
As discussed above, the air quality-assured trading remedy's state-
specific budgets represent each state's emissions in an average year
after elimination of significant contribution to nonattainment and
interference with maintenance. Because actual base case emissions are
likely to vary from projected base case emissions, this remedy
incorporates provisions that account for such variability. While the
primary purpose of this remedy is to eliminate significant contribution
and interference with maintenance, EPA believes variability limits also
satisfy several other objectives. The remedy provides the flexibility
to deal with real-world variability in the operation of the power
system through air quality-assured trading and reduces costs of
compliance with emission reduction requirements, while still providing
assurance for downwind states that significant contribution to
nonattainment and interference with maintenance by upwind states will
be eliminated. EPA believes the limited fluctuation in state level
emissions that this approach permits is consistent with the statutory
mandate of section 110(a)(2)(D)(i)(I) because some geographic and
temporal shifting of emissions necessarily results from the inherent
variability in power generation and is caused by factors unrelated to
the degree of emission control, such as weather, economic activity, and
unit availability. Far from excusing any state from addressing
emissions within the state that significantly contribute to
nonattainment or interfere with maintenance in other states, these
variability limits ensure that the system can accommodate the inherent
variability in the power sector while ensuring that each state
eliminates the amount of emissions within the state, in a given year,
that must be eliminated to meet the statutory mandate of section
110(a)(2)(D)(i)(I).
Moreover, the structure of the program, which achieves the required
emission reductions through limits on the total number of allowances
allocated, assurance provisions, and penalty mechanisms, ensures that
the variability limits only allow the amount of temporal and geographic
shifting of emissions that is likely to result from the inherent
variability in power generation, and not from decisions to avoid or
delay the installation of necessary controls. Under the remedy, an
individual state can have emissions up to its budget plus the
variability limit. However, the requirement that all sources hold
allowances covering emissions, and the fact that those allowances are
allocated based on state-specific budgets without variability, ensure
that the total emissions from the states do not exceed the sum of the
state budgets. The remedy, therefore, ensures both that total emissions
do not exceed the total of the state budgets and that the required
emission reductions occur in each state.
This section describes how EPA calculated variability limits for
each state to achieve this goal.
2. Transport Rule Variability Limits
EPA performed analyses using historical data to demonstrate that
there is year-to-year variability in base case emissions (even when
emission rates for all units are held constant) and to quantify the
magnitude of this variability.
The focus of the analysis is on quantifying the magnitude of the
inherent year-to-year variability in state-level EGU emissions
independent of measures taken to control those emissions (and thus due
only to changes in electricity generation within each state). EPA used
this analysis to set variability limits as part of the remedy to ensure
that states are eliminating their significant contribution to
nonattainment and interference with maintenance to protect air quality.
As discussed in detail below, EPA is finalizing the Transport Rule
with 1-year variability limits calculated using a modified approach
from the one described in the proposal. EPA is not including the
proposal's 3-year variability limits in the final Transport Rule. EPA
received comments that the 3-year variability limits increased program
costs and diminished compliance flexibility without delivering any
additional air quality benefits. EGU owners and operators expressed
concern that 3-year variability limits would be impracticable to
implement and that the 1-year variability limits themselves would be
adequately stringent to ensure elimination of significant contribution
to nonattainment and interference with maintenance in each state.
After further consideration, EPA has concluded that 3-year
variability limits would be unnecessary, would be difficult to
anticipate, and would not have a measurable impact on air quality
benefits. EPA has determined that annual limits are sufficient to
eliminate significant contribution to nonattainment and interference
with maintenance in all upwind states while accommodating the
historically observed year-to-year fluctuation in state-level EGU
emissions even at the same rate of emissions control in a given state.
In the proposal, EPA used statistical methods to derive the 3-year
variability limit directly from the 1-year variability limit, meaning
that the two are statistically equivalent in the long run under certain
statistical assumptions. Primarily, these assumptions were that the
variation in electric demand around the budget is random from year-to-
year and that, when the annual emissions are averaged over a multi-year
time period, the average emissions per year will equal the state's
budget. The first assumption was also made in the assessment of the
historical year-to-year variation in heat input in developing the 1-
year limit (see section 2 of the ``Power Sector Variability Final Rule
TSD'' for more details). Regarding the second assumption, since the
state-by-state emission budgets are based on the availability of
emission reductions at an equal marginal cost level, EPA expects the
sources in each of the upwind states to make these cost-effective
reductions and to meet the emission budgets each year, on average.
Since the 3-year variability limit was based on average year-to-
year variability over a longer time horizon, EPA notes that a random
ordering of those years could yield 2 above-average years in a row. If,
by chance, a third above-average year were to follow, the state could
face violation of the 3-year limit, even if over a time period longer
than 3 years, that state would never have exceeded the statistically-
equivalent 1-year variability limit and its annual emissions would have
averaged to the level of its budget. Effectively, this means that
imposing a multi-year variability limit would erode the 1-year
variability limit's ability to accommodate historically observed year-
to-year variability in state-level EGU emissions (due only to
generation changes), and it would do so without providing any
additional air quality benefits or protection for downwind areas (since
the average emissions over the long time horizon equal the level of the
budget).
For more details about the relationship between the 1- and 3-year
limits, see the discussions in section 3 of the ``Power Sector
Variability'' TSD from the proposed Transport Rule, which describes the
derivation of the 3-year limit from the 1-year variability and section
3 of the ``Power Sector Variability Final Rule TSD'', which describes
the results of a numerical
[[Page 48267]]
simulation showing that the 1- and 3-year limits are statistically
indistinguishable and, thus, redundant over the course of the program
to accommodate year-to-year variability.
While EPA expects the yearly emissions in each state, on average,
to equal the level of the budgets, EPA also estimated the air quality
impacts of 5, 10, 15, and 20 percent emission variability using the air
quality assessment tool, which is presented in section 4 of the ``Power
Sector Variability Final Rule TSD.'' That analysis shows that year-to-
year fluctuations of up to 20 percent in SO2 emissions from
upwind states linked to a given downwind receptor do not undermine the
ability of the Transport Rule programs to resolve nonattainment or
maintenance concerns at that receptor. The analysis presented in the
TSD focuses on SO2 emissions and was designed to examine the
sensitivity of downwind air quality to upwind EGU emission levels. The
share of total SO2 emitted by EGUs is significantly larger
than the share of total NOX emitted by EGUs. For example, in
the states for which EPA modeled base case contributions of these
pollutants, EGUs accounted for 74 percent of total SO2, 14
percent of total annual NOX, and 15 percent of total ozone-
season NOX emissions. Therefore, when varying EGU emissions
only, downwind air quality would be most sensitive to upwind variations
in SO2, because relative variations in EGU SO2
emissions have a greater impact on total SO2 emissions than
the same relative variation in EGU NOX emissions would have
on total NOX emissions affecting downwind air quality.
Because the Transport Rule only affects upwind emissions from EGU
sources, downwind air quality would be more sensitive to variability in
upwind state SO2 emissions under this rule than variability
in upwind state NOX emissions under this rule (given that
the rule affects a smaller scope of total NOX emissions
compared to the scope affected of total SO2 emissions).
Thus, EPA chose to analyze the ``worst-case'' potential downwind air
quality impacts from year-to-year variability above upwind state
SO2 budgets, and EPA therefore believes that its findings
from this analysis are valid for ascertaining the potential downwind
air quality impacts from variation at those levels in both
SO2 and NOX under the Transport Rule programs.
Furthermore, because the state budgets are based directly on IPM
modeling of electric generation when cost-effective emission reductions
have been achieved, sources within each state should have the same
incentive to meet that budget, on average, in any given year.
Additional EPA analysis supports the claim that states would be no more
likely to exceed 1-year variability limits without the 3-year limits
than with the 3-year limits. See the ``Power Sector Variability Final
Rule TSD'' for more details on this statistical analysis. Finally,
because the state budgets (and thus the total amount of allowances
available) are fixed and every covered source must hold allowances
covering its emissions, it is not feasible for all, or even many,
states to repeatedly exceed their budgets.
The approach calculated the standard deviation in state-level heat
input from units expected to be covered by the final Transport Rule
over an 11-year time period (2000 through 2010), from which the 95th
percent confidence level was calculated. EPA divided this value by the
mean to get the percentage variation in heat input. The two-tailed 95th
percent confidence level is the equivalent of the 97.5 percent upper
(single-tailed) confidence level. This approach yielded an average
year-to-year heat input variability for each state, as a proxy for
historic year-to-year variability in state-level EGU emissions while
holding emission rates constant. The result, expressed as a percentage,
conveys the maximum degree to which EGU emissions at the state level
may be expected with 95th percent confidence to vary around a given
target (i.e., budget) from year-to-year, on average, based on the
statistical analysis of historic heat input over the 2000 through 2010
time period.
From the state-by-state variability calculations, EPA identified a
single variability level (percentage) for each of the annual and ozone-
season programs based on the historic variability measured at units in
covered states on an annual basis and an ozone-season basis,
respectively. In the proposal, EPA ``identified a single set of
variability levels * * * to apply to all states in order to make the
application of the variability limits straightforward rather than
developing state-by-state percentage variability values'' (75 FR
45293). In the final rule, EPA is taking the straightforward approach
of identifying a single set of variability levels to apply to all
states because EPA has determined that it is reasonable to afford all
states under the Transport Rule programs the extent of measured
historic variability experienced by any Transport Rule state during
2000 through 2010. In the variability analysis for the final rule, EPA
identified Tennessee as having the highest measured historic
variability of annual heat input of 18 percent, and Virginia as having
the highest measured historic variability of ozone-season heat input of
21 percent. Because the percentage of variability in Tennessee on an
annual basis and in Virginia on an ozone-season basis are reasonably
likely to occur in each of the other states in the future, EPA believes
it is appropriate to apply an 18 percent annual variability limit to
all states covered by the annual SO2 and NOX
programs and a 21 percent ozone-season variability limit to all states
covered by the ozone-season NOX program.\54\
---------------------------------------------------------------------------
\54\ The six states in the supplemental proposal for inclusion
in the Transport Rule's ozone-season NOX program have
measured historic ozone-season variability that would be adequately
covered by this final rule's ozone-season NOX variability
level (21 percent). Please see the ``Power Sector Variability Final
Rule TSD'' for more details.
---------------------------------------------------------------------------
EPA's analysis of historic heat input variability in multiple
states over the 2000 to 2010 baseline yields a range of potential year-
to-year variability values for state-level EGU emissions. As discussed
above, any one state's measured variability (in this case, from 2000 to
2010) is due to a multiplicity of factors. These factors include, but
are not limited to, variation in weather, variation in demand due to
increased or decreased level of economic activity, variation in the
portion of electric generation that is fossil-fuel-fired, and variation
in the length and number of outages at power generation units, and
these individual factors may sometimes act in concert and may other
times be offsetting.
The mix and levels of factors present in a state from year-to-year
can lead to variation of state-level emissions above and below the
level for the state under average conditions. Because the levels of the
various factors are difficult to predict on a year-to-year basis for an
individual state, the resulting variability in state-level emissions is
difficult to predict. Moreover, because the electric generation,
transmission, and distribution system in the eastern half of the U.S.
is highly integrated, year-to-year variation in these factors in one
state can cause year-to-year variability in state-level emissions both
in that state and in other states on the system. For example, increased
demand due to extreme weather or increased economic activity in one
state can be met through increased generation and emissions in a number
of states.
Because these factors can vary year-to-year in every state in ways
that are difficult to predict and can affect other states, EPA
maintains that the maximum variability measured in one state for a
discrete period (2000-2010) is
[[Page 48268]]
reasonably likely to occur in the future in any of the states in the
region. Consequently, EPA believes that it is reasonable to use the
maximum historic percentage variability figure as a proxy for the
percentage variability that any of the states is likely to experience
in the future. Although EPA is therefore using a uniform percentage
figure for variability, EPA applies that percentage figure to each
state-specific budget so that variability in tons of emissions is
determined on a state-specific basis. That state-specific number is
used in determining whether the assurance provisions and penalty are
triggered in the specific state. EPA also believes that it is
appropriate to accommodate this potential future variability at the
state level if and only if it can be accommodated without undermining
the programs' beneficial impacts on downwind air quality that eliminate
significant contribution to nonattainment or interference with
maintenance of the NAAQS assessed in this rulemaking (see the ``Power
Sector Variability Final Rule TSD'' for more information on this
analysis). The Transport Rule identifies and quantifies, on a state-by-
state basis, the emissions in each state that significantly contribute
to nonattainment or interfere with maintenance in another state. This
is done by analyzing specific air pollution linkages between each
upwind state and each downwind maintenance or nonattainment receptor.
Nonetheless, it is clear from the air quality analyses that the air
quality outcome at a given downwind receptor is a function of the
cumulative emissions from all upwind states and the receptor's home
state. Once the Transport Rule emission reduction requirements are
implemented in all states subject to the programs, EPA's analysis shows
that the impact on a downwind receptor of any single upwind state's
year-to-year fluctuation of up to 20 percent in SO2
emissions would be so limited as to not disturb that receptor's ability
to maintain or attain the NAAQS analyzed in this rulemaking. Therefore,
to the extent that such variability has been measured in historic data
in any state subject to the Transport Rule programs, it is reasonable
to provide for potential future variability in Transport Rule states
within the scope of what EPA's analysis shows to preserve downwind air
quality gains achieved by the Transport Rule programs.
The approach to establishing variability limits in the final rule
modifies the approach from the proposed rule in two ways. First, EPA is
applying only a percentage variability limit to each budget in the
final rule, whereas the proposed rule applied the greater of a
percentage or an absolute tonnage variability limit to each budget. EPA
explained in the proposal that it was necessary to impose both a
percentage and a tonnage limit due to the inclusion of ``states with
small numbers of units where expected variability would be more
pronounced in percentage terms'' (75 FR 45293). However, the states
with the smallest numbers of units included at proposal (such as
Connecticut and the District of Columbia) are not covered by any of the
final Transport Rule's programs. In the final rule's variability
analysis, Tennessee has the highest measured annual variability
percentage and Virginia has the highest measured ozone-season
variability percentage. Both of these states have a sufficient number
of units for the percentage variability findings to be representative
of variability in all of the Transport Rule states; therefore, it is
not necessary to impose a tonnage limitation in the final rule.
Second, EPA has expanded the historic baseline of the variability
analysis to consider heat input data from 2000 through 2010, as
compared to 2002 through 2008 at proposal, and EPA has also expanded
the dataset to include all units expected to be covered by the final
Transport Rule's programs. EPA received a number of comments that the
proposal's variability limits were too stringent in part because they
relied on too short a historical baseline that failed to capture the
full extent of long-run year-to-year variability. EPA agrees with these
comments and believes that the historic baseline modification described
above supports variability limits in the final rule that are a better
approximation of future potential year-to-year variability in state-
level EGU emissions around the budgets as a function of inherent
variability in baseline state-level EGU operations. EPA believes the
2000 through 2010 historic baseline supports a more accurate
approximation of year-to-year variability in state-level EGU operations
than previously measured on a 2002 through 2008 baseline.
Some commenters expressed the view that allowing variability limits
in addition to state budgets undermines the requirements of CAA section
110(a)(2)(D)(i)(I) to eliminate significant contribution to
nonattainment and interference with maintenance of the NAAQS in
downwind states. EPA disagrees with these comments. As explained above,
EPA finds that year-to-year variability is an inherent characteristic
of power sector emissions whether or not such emissions are controlled
by state budgets; the future year-to-year variability is a component of
the sector's emissions baseline before emission reductions are
required. As done for proposal, EPA has analyzed the impact of allowing
emissions from upwind states in a given year to rise above the budgets
but within the variability limits allowed in the final rule. This
analysis shows that emission fluctuations around the budgets but within
the variability limits will not undermine the downwind air quality
gains achieved by the implementation of the Transport Rule budgets, and
therefore the variability limits cannot be said to undermine the
elimination of significant contribution to nonattainment or
interference with maintenance achieved under the Transport Rule
programs. Based on historical data and projected air quality impacts,
the Agency believes that states will have sufficient flexibility and
room to operate within the final rule's variability limits while
addressing all emissions identified as significantly contributing to
nonattainment or interfering with maintenance in other states.
F. Variability Limits and State Emission Budgets: State Assurance
Levels
As explained above, EPA applied the variability levels on a state-
by-state basis to calculate specific emission budgets with variability
limits. The state budget plus the variability limit is also called the
``state assurance level.'' Table VI.F-1 shows final state budgets,
variability limits, and assurance levels by state for SO2
emissions. Table VI.F-2 shows final state budgets, variability limits,
and assurance levels by state for annual NOX emissions.
Table VI.F-3 shows final state budgets, variability limits, and
assurance levels by state for ozone-season NOX emissions.
[[Page 48269]]
Table VI.F-1--State Budgets, Variability Limits, and Assurance Levels for SO2 Emissions
--------------------------------------------------------------------------------------------------------------------------------------------------------
Emission budget (tons) Emission variability limit State emissions assurance
-------------------------------- (tons) level (tons)
---------------------------------------------------------------
2012-2013 2014 and 2014 and 2014 and
beyond 2012-2013 beyond 2012-2013 beyond
--------------------------------------------------------------------------------------------------------------------------------------------------------
Alabama................................................. 216,033 213,258 38,886 38,386 254,919 251,644
Georgia................................................. 158,527 95,231 28,535 17,142 187,062 112,373
Illinois................................................ 234,889 124,123 42,280 22,342 277,169 146,465
Indiana................................................. 285,424 161,111 51,376 29,000 336,800 190,111
Iowa.................................................... 107,085 75,184 19,275 13,533 126,360 88,717
Kansas.................................................. 41,528 41,528 7,475 7,475 49,003 49,003
Kentucky................................................ 232,662 106,284 41,879 19,131 274,541 125,415
Maryland................................................ 30,120 28,203 5,422 5,077 35,542 33,280
Michigan................................................ 229,303 143,995 41,275 25,919 270,578 169,914
Minnesota............................................... 41,981 41,981 7,557 7,557 49,538 49,538
Missouri................................................ 207,466 165,941 37,344 29,869 244,810 195,810
Nebraska................................................ 65,052 65,052 11,709 11,709 76,761 76,761
New Jersey.............................................. 5,574 5,574 1,003 1,003 6,577 6,577
New York................................................ 27,325 18,585 4,919 3,345 32,244 21,930
North Carolina.......................................... 136,881 57,620 24,639 10,372 161,520 67,992
Ohio.................................................... 310,230 137,077 55,841 24,674 366,071 161,751
Pennsylvania............................................ 278,651 112,021 50,157 20,164 328,808 132,185
South Carolina.......................................... 88,620 88,620 15,952 15,952 104,572 104,572
Tennessee............................................... 148,150 58,833 26,667 10,590 174,817 69,423
Texas................................................... 243,954 243,954 43,912 43,912 287,866 287,866
Virginia................................................ 70,820 35,057 12,748 6,310 83,568 41,367
West Virginia........................................... 146,174 75,668 26,311 13,620 172,485 89,288
Wisconsin............................................... 79,480 40,126 14,306 7,223 93,786 47,349
--------------------------------------------------------------------------------------------------------------------------------------------------------
Note: Budgets, limits, and assurance levels apply to each state's emissions from covered sources, as defined by this final rule, only.
Table VI.F-2--State Budgets, Variability Limits, and Assurance Levels for Annual NOX Emissions
--------------------------------------------------------------------------------------------------------------------------------------------------------
Emission budget (tons) Emission variability limit State emissions assurance
-------------------------------- (tons) level (tons)
---------------------------------------------------------------
2012-2013 2014 and 2014 and 2014 and
beyond 2012-2013 beyond 2012-2013 beyond
--------------------------------------------------------------------------------------------------------------------------------------------------------
Alabama................................................. 72,691 71,962 13,084 12,953 85,775 84,915
Georgia................................................. 62,010 40,540 11,162 7,297 73,172 47,837
Illinois................................................ 47,872 47,872 8,617 8,617 56,489 56,489
Indiana................................................. 109,726 108,424 19,751 19,516 129,477 127,940
Iowa.................................................... 38,335 37,498 6,900 6,750 45,235 44,248
Kansas.................................................. 30,714 25,560 5,529 4,601 36,243 30,161
Kentucky................................................ 85,086 77,238 15,315 13,903 100,401 91,141
Maryland................................................ 16,633 16,574 2,994 2,983 19,627 19,557
Michigan................................................ 60,193 57,812 10,835 10,406 71,028 68,218
Minnesota............................................... 29,572 29,572 5,323 5,323 34,895 34,895
Missouri................................................ 52,374 48,717 9,427 8,769 61,801 57,486
Nebraska................................................ 26,440 26,440 4,759 4,759 31,199 31,199
New Jersey.............................................. 7,266 7,266 1,308 1,308 8,574 8,574
New York................................................ 17,543 17,543 3,158 3,158 20,701 20,701
North Carolina.......................................... 50,587 41,553 9,106 7,480 59,693 49,033
Ohio.................................................... 92,703 87,493 16,687 15,749 109,390 103,242
Pennsylvania............................................ 119,986 119,194 21,597 21,455 141,583 140,649
South Carolina.......................................... 32,498 32,498 5,850 5,850 38,348 38,348
Tennessee............................................... 35,703 19,337 6,427 3,481 42,130 22,818
Texas................................................... 133,595 133,595 24,047 24,047 157,642 1 57,642
Virginia................................................ 33,242 33,242 5,984 5,984 39,226 39,226
West Virginia........................................... 59,472 54,582 10,705 9,825 70,177 64,407
Wisconsin............................................... 31,628 30,398 5,693 5,472 37,321 35,870
--------------------------------------------------------------------------------------------------------------------------------------------------------
Note: Budgets, limits, and assurance levels apply to each state's emissions from covered sources, as defined by this final rule, only.
[[Page 48270]]
Table VI.F-3--State Budgets, Variability Limits, and Assurance Levels for Ozone-Season NOX Emissions
--------------------------------------------------------------------------------------------------------------------------------------------------------
Emission budget (tons) Emission variability limit State emissions assurance
-------------------------------- (tons) level (tons)
---------------------------------------------------------------
2012-2013 2014 and 2014 and 2014 and
beyond 2012-2013 beyond 2012-2013 beyond
--------------------------------------------------------------------------------------------------------------------------------------------------------
Alabama................................................. 31,746 31,499 6,667 6,615 38,413 38,114
Arkansas................................................ 15,037 15,037 3,158 3,158 18,195 18,195
Florida................................................. 27,825 27,825 5,843 5,843 33,668 33,668
Georgia................................................. 27,944 18,279 5,868 3,839 33,812 22,118
Illinois................................................ 21,208 21,208 4,454 4,454 25,662 25,662
Indiana................................................. 46,876 46,175 9,844 9,697 56,720 55,872
Kentucky................................................ 36,167 32,674 7,595 6,862 43,762 39,536
Louisiana............................................... 13,432 13,432 2,821 2,821 16,253 16,253
Maryland................................................ 7,179 7,179 1,508 1,508 8,687 8,687
Mississippi............................................. 10,160 10,160 2,134 2,134 12,294 12,294
New Jersey.............................................. 3,382 3,382 710 710 4,092 4,092
New York................................................ 8,331 8,331 1,750 1,750 10,081 10,081
North Carolina.......................................... 22,168 18,455 4,655 3,876 26,823 22,331
Ohio.................................................... 40,063 37,792 8,413 7,936 48,476 45,728
Pennsylvania............................................ 52,201 51,912 10,962 10,902 63,163 62,814
South Carolina.......................................... 13,909 13,909 2,921 2,921 16,830 16,830
Tennessee............................................... 14,908 8,016 3,131 1,683 18,039 9,699
Texas................................................... 63,043 63,043 13,239 13,239 76,282 76,282
Virginia................................................ 14,452 14,452 3,035 3,035 17,487 17,487
West Virginia........................................... 25,283 23,291 5,309 4,891 30,592 28,182
--------------------------------------------------------------------------------------------------------------------------------------------------------
Note: Budgets, limits, and assurance levels apply to each state's emissions from covered sources, as defined by this final rule, only.
See section VII.E for the discussion of how variability limits and
state assurance levels are used in the implementation of assurance
provisions for the air quality-assured trading programs.
G. How the State Emission Reduction Requirements Are Consistent With
Judicial Opinions Interpreting the Clean Air Act
The methodology described in this notice quantifies states'
significant contribution to nonattainment and interference with
maintenance in a manner that is consistent with the decisions of the DC
Circuit. As discussed previously, the DC Circuit has issued two
significant decisions addressing the requirements of
110(a)(2)(D)(i)(I). The first opinion largely upheld the NOX
SIP Call, Michigan, 213 F.3d 663, and the second found significant
flaws in CAIR, North Carolina, 531 F.3d. 896. In both cases, the Court
considered aspects of the methodology used by EPA to identify emissions
that, pursuant to section 110(a)(2)(D)(i)(I), must be eliminated due to
their impact on air quality in downwind states. EPA believes that the
methodology used in this final rule is consistent with both opinions
and rectifies the flaws the North Carolina court identified with the
methodology used in CAIR. The methodology used for this rule relies on
state-specific data to analyze each individual state's significant
contribution, uses air quality considerations in addition to cost
considerations to identify each state's significant contribution, and
gives independent meaning to the ``interference with maintenance''
prong. This methodology is then applied in a reasonable manner
consistent with the relevant judicial opinions.
In North Carolina, the Court held that EPA's approach to evaluating
significant contribution was inadequate because, by evaluating only
whether emission reductions were highly cost effective ``at the
regional level assuming a trading program'', it failed to conduct the
required state-specific analysis of significant contribution. See id.
at 907. EPA, the Court concluded, ``never measured the `significant
contribution' from sources within an individual state to downwind
nonattainment areas.'' Id. The Court did not, however, disturb the air-
quality-based methodology used by EPA to identify the states with
contributions large enough to warrant further consideration.
For this rule, EPA uses a first step similar to that used in CAIR
to identify the states with relatively large contributions. However, in
contrast to CAIR, it then uses a state-specific analysis. Instead of
identifying a single emission level that could be achieved by the
application of highly cost effective controls in the region, EPA
determines, on a state-by-state basis, what reductions could
effectively be achieved by sources in each state. EPA's new approach
does not, as the CAIR methodology did, establish a regional cap on
emissions that is then divided into state budgets that set the emission
reduction requirements for each state. Instead, EPA develops, for each
covered state, emission budgets based on the reductions achievable at a
particular cost per ton in that particular state, taking into account
the need to ensure reliability of the electric generating system. The
selected cost/ton levels reflect consideration of both cost factors and
air quality factors including the estimated impact of upwind states'
emissions on each downwind receptor.
In addition, in developing this approach, EPA was guided by the
Court's holdings regarding the use of cost to identify significant
contribution. Specifically, the Court held in Michigan that EPA could
``in selecting the `significant' level of `contribution' under section
110(a)(2)(D)(i)(I), choose a level corresponding to a certain reduction
in cost.'' North Carolina, 531 F.3d at 917 (citing Michigan, 213 F.3d
at 676-77). This holding also supported the Court's conclusion in
Michigan that it was acceptable for EPA to apply a uniform cost-
criterion across states. See Michigan, 213 F.3d at 679. In the CAIR
case, the Court rejected EPA's analysis, not because it relied on cost
considerations to identify significant contribution, but because it
found that EPA had failed to draw the significant contribution line at
all. See North Carolina, 531 F.3d at 918 (``* * * here EPA did not draw
the [significant contribution] line at all. It simply verified sources
could meet the SO2 caps with controls EPA dubbed `highly
[[Page 48271]]
cost-effective.' ''). The holdings in Michigan regarding the use of
cost and a uniform cost-criterion across states were left undisturbed.
See, e.g., North Carolina, 531 F.3d at 917 (explaining that in Michigan
the Court held that ``EPA may `after [a state's] reduction of all [it]
could * * * cost-effectively eliminate[],' consider `any remaining
contribution insignificant''). In fact, the Court acknowledged that,
based on the Michigan holdings, the measurement of a state's
significant contribution need not ``directly correlate with each
state's individualized air quality impact on downwind nonattainment
relative to other upwind states.'' North Carolina, 531 F.3d at 908.
For these reasons, EPA determined that it was appropriate in this
rulemaking to consider the cost of controls to determine what portion
of a state's contribution is its ``significant contribution.'' However,
EPA also heeded the North Carolina Court's warning that ``EPA can't
just pick a cost for a region, and deem `significant' any emissions
that sources can eliminate more cheaply.'' North Carolina,, 531 F.3d at
918. Thus, in this rulemaking, EPA departs from the practice used in
the NOX SIP Call and in CAIR of evaluating, based solely on
the cost of control required in other regulatory environments, what
controls would be considered ``highly-cost-effective.'' Instead, as
part of its determination of a reasonable cost per ton for upwind state
control, EPA evaluates the air quality impact of reductions at various
cost levels and considers the reasonableness of possible cost
thresholds as part of a multi-factor analysis.
In addition, the methodology used in this rulemaking gives
independent meaning to the interfere with maintenance prong of section
110(a)(2)(D)(i)(I). In North Carolina, the Court concluded that CAIR
improperly ``gave no independent significance to the `interfere with
maintenance' prong of section 110(a)(2)(D)(i)(I) to separately identify
upwind sources interfering with downwind maintenance.'' North Carolina,
531 F.3d at 910. EPA rectified this flaw in this rulemaking by
separately identifying downwind ``nonattainment sites'' and downwind
``maintenance sites.'' EPA decided to consider upwind states'
contributions not only to sites that EPA projected would be in
nonattainment, but also to sites that, based on the historic
variability of their emissions, EPA determined may have difficulty
maintaining the relevant standards. The specific mechanism EPA used to
implement this approach is described in detail in section V.C,
previously. For annual PM2.5, this approach identified 16
maintenance sites in addition to the 32 nonattainment sites identified
in the analysis of nonattainment receptors. For 24-hour
PM2.5 this approach identified 38 maintenance sites in
addition to the 92 nonattainment sites identified in the analysis of
nonattainment receptors. For ozone it identified 16 maintenance sites
in addition to the 11 ozone nonattainment sites identified.
EPA applied this methodology using available information and data
to measure the emissions from states in the eastern United States that
significantly contribute to nonattainment or interfere with maintenance
in downwind areas with regard to the 1997 and 2006 PM2.5
NAAQS and the 1997 ozone NAAQS. Although EPA has not completely
quantified the total significant contribution of these states with
regard to all existing standards, EPA has determined, on a state-
specific basis, that the emissions prohibited in the FIPs are either
part of or constitute the state's significant contribution to
nonattainment and interference with maintenance. Thus, elimination of
these emissions will, at a minimum, make measurable progress towards
satisfying the section 110(a)(2)(D)(i)(I) prohibition on significant
contribution to nonattainment and interference with maintenance.
VII. FIP Program Structure To Achieve Reductions
A. Overview of Air Quality-Assured Trading Programs
EPA is finalizing an air quality-assured trading remedy that is
substantially similar to the preferred trading remedy presented in the
proposal. Key differences from the preferred trading remedy in the
proposal include:
Recalculated state budgets and variability limits (i.e.,
state assurance levels) based on updated modeling;
Simplified variability limits for 1-year application only;
Revised allocation methodology for existing and new units
and revised new unit set-asides for new units in Transport Rule states
and new units potentially locating in Indian country;
Changed start of assurance provisions to 2012 and
increased assurance provision penalties; and
Removed opt-in provisions.
In the final rule, as in the proposed rule, EPA is promulgating
FIPS to require SO2 and NOX reductions from power
plants in jurisdictions \55\ that contribute significantly to
nonattainment in, or interfere with maintenance by, a downwind area
with respect to the 1997 ozone NAAQS, the 1997 annual PM2.5
NAAQS, and/or the 2006 24-hour PM2.5 NAAQS. These FIPs
establish state-specific emission control requirements using state
budgets starting in 2012, with a second phase of SO2
reductions in some states in 2014. Section IV explains EPA's authority
to issue FIPs.
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\55\ Alabama, Arkansas, Florida, Georgia, Illinois, Indiana,
Iowa, Kansas, Kentucky, Louisiana, Maryland, Michigan, Minnesota,
Mississippi, Nebraska, New Jersey, New York, North Carolina, Ohio,
Pennsylvania, South Carolina, Tennessee, Texas, Virginia, West
Virginia, and Wisconsin. As discussed in section III, in a separate
notice, EPA is proposing to include Iowa, Kansas, Michigan,
Missouri, Oklahoma, and Wisconsin in the ozone-season NOX
requirements.
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The air quality-assured trading remedy in the final rule allows
interstate trading to account for variability in the electricity
sector, but also includes assurance provisions to ensure that the
necessary emission reductions occur within each covered state. The
assurance provisions restrict EGU emissions within each state to the
state's budget plus the variability limit and ensure that every state
is making reductions to eliminate the significant contribution to
nonattainment and interference with maintenance that EPA has
identified. While EPA proposed to impose these assurance provisions
starting in 2014, the final rule implements these provisions starting
in 2012 (see section VII.E of this preamble). Additionally, the final
FIPs include penalty provisions adequate to ensure that the state
budget with the variability limit will not be exceeded.
In the final rule, as in the preferred trading remedy discussed in
the proposed rule, state-specific emission budgets without the
variability limits are used to determine the number of emission
allowances allocated to sources in each state. An EGU source is
required to hold one SO2 or one NOX allowance,
respectively, for every ton of SO2 or NOX emitted
during the control period. Banking of allowances for use or trading in
future years is allowed.
The final rule establishes four interstate trading programs, each
starting in 2012: two for annual SO2, one for annual
NOX, and one for ozone-season NOX. One
SO2 trading program is for sources in states (referred to as
SO2 Group 1) that need to make larger reductions to
eliminate their significant contribution, while the second is for
sources in states (referred to as SO2 Group 2) that need to
make smaller reductions. A source in a Group 1 state can only use
SO2 allowances allocated to Group 1 states for compliance
with
[[Page 48272]]
the SO2 trading program. A source in a Group 2 state can
only use SO2 allowances allocated to Group 2 states for
compliance with the SO2 trading program. For compliance in
the annual NOX and ozone-season NOX trading
programs respectively, sources may use annual NOX and ozone-
season NOX allowances allocated for any state, even if that
state is in a different group for SO2 than the source's
state. Four sets of new emission allowances based on the new state-
specific budgets without variability are allocated to sources, one set
for each of the four trading programs. Each state has the option of
replacing these FIPs with state rules. EPA believes that this remedy
meets the concerns raised by the Court in the 2008 North Carolina
decisions which remanded CAIR to EPA.
In the proposed rule, EPA took comment on all aspects of the
preferred trading remedy and on two alternative regulatory options: (1)
intrastate trading; and (2) direct control. EPA also took comment on a
trading ratios approach.
Comments on the Preferred Trading Remedy: The great majority of
public comments supported the preferred trading remedy. Most of these
commenters voiced their support for the broadest possible trading
mechanism because it allows for the most cost-effective implementation
of any emission controls. Commenters noted that flexibility is always
needed in the early years of new programs. Further, commenters favoring
the preferred remedy agreed with EPA that, by using state-specific
control budgets and allowing for interstate trading, the preferred
remedy provided electricity generators the flexibility to undertake the
most cost-effective reductions while assuring that the resulting
reductions occur within the individual states.
Some commenters that supported the preferred remedy felt that,
while not ideal, the interstate trading remedy was preferable to the
alternative options of intrastate trading or direct control. Many
commenters that supported the preferred remedy felt that the intrastate
trading remedy and direct control remedy options offer minimal
flexibility from a compliance perspective. They stated that this lack
of flexibility would unnecessarily increase the cost of emission
reductions.
Other commenters who generally support the preferred remedy cited
concerns about the level of complexity in the assurance provisions. One
commenter surmised that the preferred option creates significant risk
where a company could unexpectedly find itself in a noncompliance
situation due to the after-the-fact variability analysis. Another said
that the rule's features needlessly reduce the system's efficiency and
increase complexity. These commenters generally preferred unlimited
trading, noting that EPA has proven success with Title IV, the
NOX SIP Call, and CAIR unlimited interstate trading programs
and that allowing unrestricted interstate trading would increase
flexibility to meet reduction goals and minimize increases in power
costs.
EPA is finalizing the preferred trading remedy for the following
reasons. EPA believes this approach is the most cost-effective and
practical way to comply with the Court decision in North Carolina to
ensure that all emissions in a given state that EPA has identified as
significantly contributing to downwind nonattainment or interfering
with maintenance are eliminated. The vast majority of public commenters
agree. In addition, this approach provides the most flexibility for
sources while meeting the Clean Air Act requirements and protecting
public health. As a result, potential innovations and resulting cost
savings are more likely to be found and implemented. Based on
historical experience (see the Transport Rule proposal, 75 FR 45315),
EPA has shown that the results offered by a flexible trading approach
(e.g., flexible compliance choices, incentives to reduce emissions
early and in the highest emitting areas, 100 percent compliance with
requirements) are substantial. A large number of commenters have
corroborated this assessment. As summarized in the proposal, EPA
believes that the preferred trading remedy will allow source owners to
choose among several compliance options to achieve required emission
reductions in the most cost-effective manner, such as installing
controls, changing fuels, reducing utilization, buying allowances, or
any combination of these actions. Interstate trading with assurance
provisions provides additional regulatory flexibility that promotes the
power sector's ability to operate as an integrated, interstate system
and to provide electric reliability.
Comments on Intrastate Trading: A few commenters favored the first
alternative, intrastate trading. One commenter who favored intrastate
trading stated that many power plants have avoided investment in
pollution controls by buying allowances from other plants, affecting
local air quality improvement. EPA notes that this Transport Rule aims
to address emissions from one state that significantly contribute to
nonattainment or interfere with maintenance of certain NAAQS in other
states. Local air quality issues are directly addressed by other
provisions in the Clean Air Act.
Several commenters raised concerns about the intrastate trading
approach. Some stated, as EPA noted in the proposal, that the
intrastate trading option would be more resource intensive, more
complex, less flexible, and potentially more susceptible to market
manipulation than the other options. In addition, some commenters felt
that this alternative would provide less flexibility to ensure electric
reliability than the preferred approach, resulting in greater private
costs to the power sector and greater social costs for consumers.
EPA is not finalizing the intrastate trading option for the
following reasons. As EPA expressed in the proposal and as commenters
have agreed, the intrastate trading option would be more resource
intensive (both for EPA and for sources), more complex, less flexible,
and potentially more susceptible to market manipulation than the
preferred trading approach that EPA is finalizing. The intrastate
trading option would be more costly and less transparent due to the
large number of trading programs that would be operated simultaneously
and the large number of annual auctions that would be held every year
to address the issues of market power within states. This option would
also result in a greater burden for participants operating EGUs in
multiple states.
Comments on Direct Control Option: Several commenters favored the
second alternative, direct control. One commenter stated that direct
control--allowing no trading--was the option best aligned with the 2008
Court decisions. EPA disagrees with this comment for the reasons given
below and because, as explained in this rule, EPA believes the air
quality-assured trading remedy finalized today is consistent with the
decisions of the DC Circuit in North Carolina.
Some commenters, who support direct control, voiced concerns that
the other emission trading approaches would disadvantage poor and
minority communities or allow increased emission impacts in
neighborhoods near power plants. EPA notes that a direct control
approach would not require controls on all plants in a state, but only
on a sufficient number to address the transport requirements under
section 110(a)(2)(d)(i)(I) that this rule addresses, and therefore
would not necessarily mandate controls on each neighborhood power
plant.
In addition, EPA has conducted an analysis of the effects of the
Transport
[[Page 48273]]
Rule on environmental justice and other vulnerable communities. We
concluded that, similar to our experience with the Acid Rain
Program,\56\ many environmental justice communities are expected to see
large health benefits, and none are expected to experience any
disbenefits, from implementing an air quality-assured trading program.
The results of this analysis are presented in section XII of this
preamble and Chapter 5 of the RIA for this rule. In addition, the CAA
provides flexibility for state and local authorities to impose stricter
limits on sources to address specific local air quality concerns. Such
limits are independent of the requirements in this rule, and compliance
with Transport Rule requirements in no way excuses a source from
complying with other CAA or state law requirements.
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\56\ See http://www.epa.gov/airmarkets/resource/docs/ejanalysis.pdf and Ringquist, Evan J. 2011. ``Trading Equity for
Efficiency in Environmental Protection? Environmental Justice
Effects from the SO2 Allowance Trading Program.'' Social
Science Quarterly 92(2):297-323
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Several commenters raised concerns with the direct control
approach. One commenter felt that issues with electricity market
reliability could occur during high electricity demand periods if
sources ceased operations due to approaching their emission rate
limitations under a direct control remedy. Another commenter was
concerned that applying emission rates under a direct control remedy to
small municipal units would cause disproportionate impacts on power
plants where pollution control is more expensive. Other commenters
cited concerns that EPA's proposed within-state company-wide averaging
provision in the direct control proposed alternative (designed to allow
some flexibility for sources) would place companies with fewer units at
a disadvantage compared to companies with more units. EPA generally
agrees with the commenters concerns and has decided not to finalize the
direct control remedy for the following reasons. EPA modeling projects
that the direct control alternative would result in fewer emission
reductions and higher costs compared to the air quality-assured trading
remedy. EPA analysis indicates that it is not necessary to implement a
direct control approach in order to protect vulnerable and sensitive
populations or environmental justice communities. Also, the direct
control approach would result in fewer compliance options because a
direct control approach would directly regulate individual sources by
setting unit-level emission rate limits. This lack of flexibility could
lead to potential increases in reliability risks in the electric power
system and fewer opportunities for potential technological innovations
that reduce emissions further and/or lower costs. For these reasons,
EPA believes that this approach is inferior to the air quality-assured
trading remedy.
Other Comments: A handful of commenters mentioned the trading
ratios approach, though none favored it as a viable alternative. One
commenter said the trading ratios approach was not consistent with CAA
section 110(a)(2)(D) requirements that reductions in emissions occur in
particular geographic locations. Other commenters agreed that it was
administratively unworkable and would be difficult to implement due to
the complexity and variety of meteorological conditions. EPA generally
concurs with the commenters. In the proposal, EPA noted that it would
not be possible under this approach, as contemplated, to include
enforceable legal requirements to ensure that a specific state's
emissions remain below a specified level or to ensure that a specific
amount of reductions occur within a particular state. EPA specifically
requested comment on whether a ratios trading program could be designed
to provide such legal assurances. Of the few comments received, none
offered such a solution. For these reasons, EPA is not finalizing this
approach.
Some commenters offered additional suggestions, such as:
unrestricted trading; using different authorities in the CAA to address
interstate transport such as section 110(k)(5) and section 126; and an
approach that would replace the assurance provisions by a system using
both emission allowances usable (as well as bankable) in any state and
assurance allowances usable (but not bankable) in only the state for
which they would be issued. While EPA appreciates the thoughtful and
constructive comments, we did not find any of these suggestions
improved our ability to address interstate transport under CAA section
110(a)(2)(D)(i)(I), in line with the Court decision, in an
administratively practical way.
Several commenters liked the idea of establishing unit-by-unit
short-term and long-term performance standards/emission rates but
suggested adding an overlaid cap and trade program. EPA believes the
air quality-assured trading remedy finalized today is consistent with
the decisions of the Court in North Carolina and will ensure the
reductions necessary to meet statutory requirements.
For the 2012-2013 period, EPA took comment on whether the assurance
provisions are needed, since the state-specific budgets would be based
on known air pollution controls and the penalty provisions would be
adequate to ensure that the budget, including a variability limit,
would not be exceeded. Further, EPA proposed to use two variability
limits: a 1-year limit, based on the year-to-year variability in
emissions relative to the proposed budgets; and a 3-year limit based on
the variability in a 3-year average relative to the proposed budget.
Based on comments on the assurance provisions (see section VII.E of
this preamble) and variability limits (see section VI.E.2 of this
preamble), EPA is finalizing the Transport Rule with state budgets plus
variability limits and assurance provisions starting in 2012 for all of
the trading programs. EPA sees an immediate need to ensure that
emissions within a state do not exceed the state budget plus the
variability limitation in order to comply with the Court's opinion.
Further, commenters stated that the 3-year variability limit increased
costs and unnecessarily complicated the trading programs. As explained
in section VI.E.2, EPA is finalizing the 1-year variability limit
starting in 2012, but not the 3-year limit.
B. Applicability
The applicability provisions in the final rule are, except as
discussed herein, essentially the same as in the proposed rules and for
each of the Transport Rule trading programs.
Under the general applicability provisions of the proposed rule,
the Transport Rule trading programs would cover fossil-fuel-fired
boilers and combustion turbines serving--on any day starting November
15, 1990 or later--an electrical generator with a nameplate capacity
exceeding 25 MWe and producing power for sale, with the exception of
certain cogeneration units and solid waste incineration units.
EPA requested comment on whether a more recent year should be used
instead. The proposed use of the November 15, 1990 date was consistent
with the use of 1990 as the beginning of the historical period for
which owners and operators would generally be required to have
information about their units for purposes of determining whether the
units were covered by the Transport Rule trading programs. Because unit
information is generally compiled and retained on a calendar year
basis, EPA believes that, for the general applicability provisions, it
is preferable to use January 1, rather than November 15. In determining
which
[[Page 48274]]
year should be used as the reference year in the general applicability
provisions, EPA considers several factors.
First, in order for owners and operators, and EPA, to be able to
determine which units are subject to the Transport Rule trading
programs, EPA believes that the reference year should not be so far in
the past that the unit information necessary to make applicability
determinations is not readily available. This particularly becomes an
issue in cases of older units that have changed ownership over time.
EPA found, in making some applicability determinations under the CAIR
trading programs, that some older units with ownership changes had
difficulty obtaining information back as far as twenty or more years.
Using January 1, 1990 as the reference date in the general
applicability provisions could effectively require some owners and
operators to retain unit information going back as far as 20 years. As
a point of contrast, under the title V permitting rules, owners and
operators are generally required to retain data for 5 years. See 40 CFR
70.6(a)(3)(B).
Second, EPA also believes that the reference year used in the
applicability provisions should be far enough in the past that the unit
information on which applicability determinations are based provides a
full picture of the nature of the unit and its operations over time,
such as the types of fuels combusted at the unit and whether the unit
has produced electricity for sale.
Third, EPA considers whether selecting a different reference year
for the applicability provisions than the one in the proposed rule
dramatically changes what units will be covered by the Transport Rule
trading programs. In this case, EPA believes, based on available
information about the units potentially subject to the Transport Rule,
that using a somewhat later year than the one in the proposed rule will
likely have little effect on what units are covered. Balancing these
factors, EPA concludes that it is reasonable to use January 1, 2005,
rather than November 15, 1990, in the general applicability provisions
in the final rule.
In the final rule, EPA is taking the same approach with regard to
defining whether a boiler or combustion turbine is considered to be
``fossil-fuel-fired'' as the one used in the proposal. Under the
proposed rule, a unit was considered to be ``fossil-fuel-fired'' if it
combusts any amount of fossil fuel at any time in 1990 or later. For
the same reasons that EPA decided to use January 1, 2005 in the general
applicability provisions, and in order to have a consistent reference
year in all applicability-related provisions, the final rule defines a
``fossil-fuel-fired'' unit as one that combusts any amount of fossil
fuel in 2005 or later.
EPA notes that the final Transport Rule allows a state to submit a
SIP revision (an abbreviated or full SIP) under which the state may--in
addition to making certain types of changes concerning allowance
allocations in the Transport Rule trading programs--expand the general
applicability provisions of the Transport Rule NOX Ozone
Season Trading Program to cover fossil-fuel-fired boilers and
combustion turbines serving--at any time starting January 1, 2005 or
later-- a generator with a nameplate capacity as low as 15 MWe
producing power for sale. The exemptions, discussed below, for
cogeneration units and solid waste incineration units still will
continue to apply.
Cogeneration unit exemption. Under the final rule (as well as the
proposed rule) certain cogeneration units or solid waste incinerators
are exempt from the FIP requirements. In particular, the final rule
includes an exemption for a unit that qualifies as a cogeneration unit
throughout the later of 2005 or the first 12 months during which the
unit first produces electricity and continues to qualify through each
calendar year ending after the later of 2005 or that 12-month period
and that meets the limitation on electricity sales to the grid. In
order to meet the definition of ``cogeneration unit'' in the final
rules, a unit (i.e., a fossil-fuel-fired boiler or combustion turbine)
must be a topping-cycle or bottoming-cycle that operates as part of a
``cogeneration system,'' which is defined as an integrated group of
equipment at a source (including a boiler, or combustion turbine, and a
steam turbine generator) designed to produce useful thermal energy for
industrial, commercial, heating, or cooling purposes and electricity
through the sequential use of energy. A topping-cycle unit is a unit
where the sequential use of energy results in production of useful
power first and then, through use of reject heat from such production,
in production of useful thermal energy. A bottoming-cycle unit is a
unit where the sequential use of energy results in production of useful
thermal energy first and then, through use of reject heat from such
production, in production of useful power. In order to qualify as a
cogeneration unit, a unit also must meet certain efficiency and
operating standards.
In the proposed rule, a unit would have to qualify as a
cogeneration unit and meet the limitation on electricity sales starting
the later of 1990 or the year when the unit begins operating. EPA
requested comment on whether a more recent year should be used. For the
reasons discussed above concerning the reference year used in the
general applicability provisions and in order to have a consistent
reference year in all applicability-related provisions, EPA concludes
that it is reasonable to use 2005, rather than 1990, in the
cogeneration unit exemption provisions in the final rule. Consequently,
the final rule provides that the requirements to qualify as a
cogeneration unit and to meet the electricity sales limitation start no
earlier than 2005.
In the final rule, EPA also clarifies that the electricity sales
limitation under the exemption is applied in the same way whether a
unit serves only one generator or serves more than one generator. In
both cases, the total amount of electricity produced annually by a unit
and sold to the grid cannot exceed the greater of one-third of the
unit's potential electric output capacity or 219,000 MWhr. This is
consistent with the approach taken in the Acid Rain Program (40 CFR
72.7(b)(4)), where the cogeneration unit exemption originated. EPA
believes that this clarification is needed to ensure that a unit
serving, for example, two generators would not have a limit on sales of
electricity to the grid that would be different (i.e., twice as high)
from the limit for a unit serving only one generator with the same
total nameplate capacity as the first unit's two generators.
EPA also took comment on whether efficiency standards should be
applied on a system-wide basis to bottoming-cycle units (where useful
thermal energy is produced before useful power is produced), as they
are for topping-cycle units (where useful thermal energy is produced
after useful power) and whether to exclude, from the requirement to
meet the operating and efficiency standards, calendar years during
which a cogeneration unit does not operate at all. Several commenters
argued EPA should apply efficiency standards to both types of units.
EPA agrees that applying efficiency standards on a system-wide basis to
both bottoming-cycle and topping-cycle units is reasonable because EPA
sees no technical reason to distinguish between the two types of units
in this instance. EPA further agrees with commenters that excluding
calendar years in which the cogeneration unit does not operate at all,
i.e., does not combust any fuel, from the requirements to meet
operating and efficiency standards is also reasonable. For such a year,
the unit would not produce any useful thermal
[[Page 48275]]
energy or useful power and therefore could not meet the minimum output
requirements in the operating and efficiency standards, but the unit
also would not have any emissions. For these reasons, the final rule
expressly provides that the operating and efficiency standards do not
have to be met for a calendar year throughout which a unit did not
operate at all.
Solid waste incineration unit exemption. The final rule also
includes an exemption for a unit that qualifies as a solid waste
incineration unit during the later of 2005 or the first 12 months
during which the unit first produces electricity, that continues to
qualify throughout each calendar year ending after the later of 2005 or
that 12-month period each year thereafter, and that meets the
limitation on fossil-fuel use. In contrast, the exemption for solid
waste incineration units in the proposed rule distinguished between
units commencing operation before January 1, 1985 and those commencing
operation on or after that date. A unit commencing operation before
January 1, 1985 would be exempt if it qualified as a solid waste
incineration unit starting the later of 1990 or the year when it began
producing electricity and its average annual fuel consumption of non-
fossil fuels exceeded 80 percent of total heat input during 1985-1987
and during any three consecutive calendar years after 1990. A unit
commencing operation on or after January 1, 1985 would be exempt if it
qualified as a solid waste incineration unit starting the later of 1990
or the year when it began producing electricity and its average annual
fuel consumption of non-fossil fuel exceeded 80 percent of total heat
input for the first 3 calendar years of operation and for any 3
consecutive calendar years thereafter.
In the proposal, EPA requested comment on whether it would be
problematic to obtain sufficiently detailed information about unit
operation potentially as far back as 1985-1987 and 1990, and whether
the fuel consumption standard for each unit should be limited to more
recent years. For the reasons discussed above concerning the reference
year used in the general applicability provisions and in order to have
a consistent reference year for all applicability-related provisions,
EPA concludes that it is reasonable to use 2005, rather than 1990, in
the solid waste incineration unit exemption in the final rule. In
particular, EPA notes that the proposed provisions for units commencing
operation before January 1, 1985 and for units commencing operation on
or after January 1, 1985 could require some owners and operators to
retain unit information going back more than 20 years before the
promulgation of this final rule. Further, EPA believes that removing
the distinction between units commencing operation during these two
periods, and referencing somewhat later years as the earliest years for
which information on fossil-fuel consumption is required, will result
in the exemption still being based on sufficient data to provide a full
picture of the nature and operation of the units involved. EPA also
believes, based on available information about the units potentially
subject to the Transport Rule, that this approach will not
significantly change which units qualify for the exemption.
Consequently, the final rule removes the distinction based on whether a
solid waste incineration unit commences operation before January 1,
1985 or on or after January 1, 1985. In order to be exempt, the unit
must qualify as a solid waste incineration unit during the later of
2005 or the first 12 months during which the unit first produces
electricity, must continue to qualify throughout each calendar year
ending after the later of 2005 or that 12-month period, and must meet
the limitation on fossil-fuel use on a 3-year average basis during the
first 3 years of operation starting no earlier than 2005 and every 3
years of operation thereafter.
Opt-in units. EPA is not finalizing the opt-in provisions that were
discussed in the Transport Rule proposal. EPA proposed opt-in
provisions to allow non-covered units to voluntarily opt in to any of
the proposed Transport Rule trading programs and receive allocations
reflecting 70 percent of the unit's emissions before opting in. These
allowances were above the state-specific budgets developed under the
Transport Rule to eliminate a state's significant contribution to
nonattainment and interference with maintenance. In theory, an opt-in
unit that makes reductions below its baseline and sells the freed-up
allowances is effectively substituting its new, lower-cost reductions
for higher-cost reductions otherwise required by a covered EGU, with
the result that the state's significant contribution is still
eliminated but at a lower total program cost.
EPA notes that theoretical benefits anticipated from allowing opt-
ins did not materialize in prior trading programs with opt-in
provisions. The Acid Rain Program has about 23 opt in units; the
NOX Budget Trading Program had five opt-in units; and no
units opted into the CAIR programs. As a group, these opt-in units
neither eased the achievement of required emission reductions in past
trading programs, nor reduced overall program costs.
In the proposal, EPA requested comment on the opt-in provisions,
specifically regarding: What are the benefits of and concerns about
including opt-in provisions; how to ensure units are not credited for
emission reductions the units would have made anyway; whether the
proposed 30 percent reduction (i.e., application of the 70 percent
multiplier to baseline emissions) or some other percentage reduction,
or no reduction, should be applied to the baseline emission rate used
in determining allocations; and whether any additional percentage
reduction (such as 45 percent) should be applied to SO2
Group 1 opt-in units in Phase II to reflect the stricter limits for
covered units.
Some commenters argued that increasing the Transport Rule budgets
for opt-ins would undermine the goal of CAA section 110(a)(2)(D)(i)(I)
to eliminate a state's significant contribution to nonattainment and
interference with maintenance. One commenter stated that it does not
favor allowing sources that are not subject to the emission reduction
requirements to be issued allowances that would increase the overall
state emission budgets, due to the uncertainty that any reductions made
by such units would be surplus, verifiable, permanent and enforceable.
This could compromise the integrity of the EGU emission reduction
requirements of the Transport Rule and jeopardize assurance that a
state's significant contribution would be eliminated, as required by
the Court in North Carolina. Other commenters claim that, while no
cheap tons are available from non-EGUs and EPA is right not to require
non-EGU reductions, EPA should nonetheless allow non-EGUs to choose
voluntarily to be covered by opting in.
As mentioned previously, the final Transport Rule does not include
any opt-in provisions either in the FIPs or in the provisions allowing
modification or replacement of the FIPs through submission of trading
program provisions in SIPs. EPA has several reasons for not adopting
provisions to allow opt-in units. First, as mentioned above,
historically, very few units have opted in. As of 2010, 28 units out of
more than 4,700 covered units (23 units out of a total of about 3,600
covered units in the Acid Rain Program and 5 units out of a total of
about 2,600 covered units in the NOX SIP Call) have opted in
to EPA trading programs over the past 15 years. In the Acid Rain
Program, 3 of the units opted in and
[[Page 48276]]
then, effective for 2005, opted out. Four of the units opted in,
immediately shut down, and continue to receive allowance allocations.
Four of the units opted in and continue to operate and receive
allowance allocations. Finally, 12 of the units opted in, after CAIR
was finalized, in order to receive allowances usable for compliance in
the CAIR SO2 trading program. Because CAIR will be replaced
by this Transport Rule, EPA anticipates that these 12 units will opt
out of the Acid Rain Program. In the NOX Budget Trading
Program, 3 plants with 5 opt-in units received allocations between 2003
and 2008.
Moreover, EPA has determined that the inclusion of opt-in units in
the Transport Rule trading programs would undermine the rule's
objective of addressing emissions in each state that significantly
contribute to nonattainment or interfere with maintenance in other
states. As explained above, EPA has established budgets plus
variability limits that states must meet to ensure that the significant
contribution to nonattainment and interference with maintenance
identified by EPA is addressed. If EPA were to allow opt-ins, and if
any opt-in unit were to receive an allocation of allowances for
emissions that would be reduced even if the units did not opt in, then
the inclusion of that opt-in unit in the program would allow the
sources covered by the Transport Rule to emit in excess of the budget
plus variability limit with no new, offsetting reduction in emissions.
For example, after a unit would opt in, process or fuel changes made
for economic reasons (rather than due to any regulatory requirements),
or installation of new emission controls or fuel-switching conducted to
meet future, non-Transport Rule regulatory requirements, could result
in emission reductions that would have occurred ``anyway'' (i.e., even
if the unit had not opted in), and the opt-in unit would be allocated
allowances for the portion of its baseline emissions that would be
removed by these ``anyway'' reductions. Allocations above the cap to
opt-in units making ``anyway'' emission reductions would convert these
reductions into extra allowances (i.e., authorizations to emit) usable
by covered EGUs to meet their requirements to hold allowances for
emissions. Because the extra EGU emissions authorized by these extra
allowances would not be offset by any new emission reductions by the
opt-in units, this could threaten a state's ability to eliminate the
significant contribution to nonattainment and interference with
maintenance identified by EPA in the final rule. Also, opt-in units,
which are allocated allowances outside the state budget for covered
units, could increase the possibility that a state's total emissions
would exceed the state budget plus variability and thus that the
assurance provisions would be triggered.
This problem of allocating allowances for emissions that would have
been reduced anyway is illustrated by the recent promulgation of the
final rule, National Emission Standards for Hazardous Air Pollutants
for Major Sources: Industrial, Commercial, and Institutional Boilers
and Process Heaters (76 FR 15608 (March 21, 2011)) (``final Boiler MACT
rule''), which requires certain industrial, commercial, and
institutional boilers to meet maximum achievable control technology
(MACT) standards for emissions of specified hazardous air pollutants,
such as hydrogen chloride (HCL) and mercury (Hg). Some of the control
technologies that can be used to meet these standards will also provide
significant reductions of SO2 emissions. For example, a
boiler may use a wet scrubber or the combination of a dry sorbent
injection system and a fabric filter (among other options) to meet the
applicable HCL standard or may use a wet scrubber or a combination of
activated carbon injection and a fabric filter (among other options) to
meet the applicable Hg standard. See 76 FR 15614 (describing testing
and compliance requirements when such controls are used to meet these
standards); and Memo from Brian Shrager to Amanda Singleton and Graham
Gibson, Revised Methodology for Estimating Cost and Emissions Impacts
for Industrial, Commercial and Institutional Boilers and Process
Heaters National Emissions Standards for Hazardous Air Pollutants--
Major Source (February 11, 2011), Document ID EPA-HQ-OAR-2009-0491-4036
(section 3.1, describing control options for HCL and Hg control). In
fact, EPA estimated that the new standards would result in emission
reductions of not only the hazardous air pollutants directly subject to
the standards, but also in other air pollutants such as SO2.
Specifically, EPA projected that compliance with the final Boiler MACT
rule standards will result in about 431,000 tons of annual
SO2 reductions from existing boilers subject to the final
Boiler MACT rule. This will comprise on average about a 46 percent
reduction in SO2 emissions for this group of boilers. Coal-
and oil-fired boilers--which are the boilers likely to have the most
uncontrolled SO2 emissions and so would be the most likely
types of units to consider opting into the Transport Rule trading
programs if opting-in were allowed--are projected to reduce about
409,000 tons of annual SO2 as a result of complying with the
final Boiler MACT rule, or about a 50 percent reduction in
SO2 emissions. See Memo from Brian Shrager to Amanda
Singleton and Graham Gibson, Appendix B-1, (where column CE represents
baseline SO2 emissions and column CH represents
SO2 reductions resulting from the final Boiler MACT rule
compliance). The amount of offsetting SO2 increases
projected to result from final Boiler MACT rule compliance, e.g., from
additional fuel being combusted to generate electricity to operate
emission controls, is minor. See 76 FR 15651 (Table 4) and 15653
(showing projected total SO2 reductions for all boilers and
process heaters of about 442,000 tons and net SO2 reductions
of about 440,000 tons).
Consequently, a boiler subject to the final Boiler MACT rule may
install a wet acid gas scrubber or a bag house in order to meet the HCL
or Hg standard applicable to boilers under the final Boiler MACT rule
and thereby achieve SO2 emission reductions. If that boiler
were to opt in to one of the Transport Rule SO2 trading
programs during the year before installing these controls to comply
with the final Boiler MACT rule, then the boiler would be allocated
allowances for the unit's current tons of SO2 emissions and
would not need to use these allowances for compliance under the
Transport Rule once the final Boiler MACT-related controls were
installed. The allowances allocated to the boiler would be additional
allowances above the Transport Rule trading budget for the state where
the boiler was located. As a result, the boiler would have freed-up
allowances above the state trading budget that represent reductions
that the boiler would have made anyway (i.e., even if the boiler had
not opted in) and that could be sold to EGUs covered by the Transport
Rule. In effect, the opting-in of the boiler would result in the
conversion of the boiler's SO2 reductions from the final
Boiler MACT rule into increased emissions above the state trading
budget from EGUs subject to the Transport Rule.
Commenters addressed this issue. For instance, one commenter
suggested that SO2 reductions made by a boiler under the
final Boiler MACT rule should be eligible for opt-in provision
allowances under the Transport Rule trading programs. Another commenter
stated that, given the uncertainty that reductions made by opt-in units
would be surplus, verifiable, permanent, and enforceable, opt-in
provisions could
[[Page 48277]]
compromise the integrity of the EGU emission reductions.
For the reasons explained above, EPA agrees with the latter
commenter. Further, EPA notes that none of the commenters supporting
adoption of the opt-in provisions suggested any revision to the
proposed opt-in provisions that would address this problem. While the
proposed opt-in provisions would limit an opt-in unit's allocation for
a control period by calculating the allocation using the lesser of the
unit's pre-opt-in SO2 emission rate or the most stringent
SO2 emission rate applicable in that control period, this
would not address SO2 rate reductions that are not directly
required by the final Boiler MACT rule but that are a secondary result
of using and operating certain emission controls installed to comply
with the HCL or Hg standards under the final Boiler MACT rule. Because
the secondary SO2 reductions will vary depending on the type
of controls installed and on the extent to which the controls are used,
and a boiler may use a combination of emission controls and other
approaches to reduce HCL or Hg emissions (such as fuel switching), EPA
believes that it is highly unlikely that opt-in provisions could
prevent allocation for ``anyway'' emission reductions resulting from
compliance with the final Boiler MACT rule. EPA therefore believes that
the final Boiler MACT rule provides a concrete example of why adoption
of opt-in provisions could undermine the rule's objective of addressing
emissions in each state that significantly contribute to nonattainment
or interfere with maintenance in other states. EPA notes that the final
Boiler MACT rule, of course, is simply one example of how allocations
for ``anyway'' reductions could occur and undermine the statutory
requirements of the Transport Rule.
C. Compliance Deadlines
1. Alignment With NAAQS Attainment Deadlines
The compliance dates in the final Transport Rule are aligned with
the attainment deadlines for the relevant NAAQS and consistent with the
charges given to EPA by the Court in North Carolina. EPA proposed to
require, and the final rule requires, compliance by 2014 with an
initial phase of reductions in 2012.\57\ Sources are required to comply
with annual SO2 and NOX requirements by January
1, 2012 and January 1, 2014 for the first and second phases,
respectively. Similarly, sources are required to comply with ozone-
season NOX requirements by May 1, 2012, and by May 1, 2014.
In selecting these dates, EPA was mindful of the NAAQS attainment
deadlines which require reductions as expeditiously as practicable and
no later than specified dates (see 42 U.S.C. 7502(a)(2)(A) (general
attainment dates); 42 U.S.C. 7511(a)(1) (attainment dates for ozone
nonattainment areas)), and also mindful of the court's instruction to
``decide what date, whether 2015 or earlier, is as expeditious as
practicable for states to eliminate their significant contributions to
downwind nonattainment.'' North Carolina, 531 F.3d at 930.
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\57\ For the annual programs, sources are required to have, by
March 1, 2013, sufficient allowances in their accounts to cover
their 2012 emissions. For the ozone-season program, they must have
allowances in their accounts by December 1, 2012 to cover 2012
ozone-season emissions. The state budgets which determine the number
of allowances allocated to units in each state become more stringent
for some states in 2014.
---------------------------------------------------------------------------
1997 PM2.5 NAAQS Attainment Deadlines. For all areas
designated as nonattainment with respect to the 1997 PM2.5
NAAQS, the deadline for attaining that standard is as expeditious as
practicable but no later than April 2010 (5 years after designation),
with a possible extension to no later than April 2015 (10 years after
designation).\58\ Many areas have already come into attainment by the
April 2010 deadline due in part to reductions achieved under CAIR. The
fact that the 2010 deadline will have passed before the Transport Rule
is finalized emphasizes the importance of obtaining reductions as
expeditiously as practicable. In addition, reductions achieved in
upwind states by the 2014 emissions year will help downwind states
demonstrate attainment by the April 2015 deadline.
---------------------------------------------------------------------------
\58\ Section 172(a)(2) of the Clean Air Act provides that the
attainment dates for areas designated nonattainment with 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. This section also allows the Administrator to
extend the attainment date to the extent she determines appropriate,
for a period no greater than 10 years from the date of designation
as nonattainment, considering the severity of nonattainment and the
availability and feasibility of pollution control measures.
Designations for the 1997 PM2.5 NAAQS became effective on
April 5, 2005. Designations for the 2006 24-hour PM2.5
NAAQS became effective on December 14, 2009.
---------------------------------------------------------------------------
2006 PM2.5 NAAQS Attainment Deadlines. For all areas
designated as nonattainment with respect to the 2006 24-hour
PM2.5 NAAQS, the attainment deadline must be as expeditious
as practicable but no later than December 2014. Areas that fail to meet
that deadline can request an extension to as late as December 2019.
Upwind emission reductions achieved by the 2014 emissions year will
help meet the December 2014 attainment deadline. In addition, the first
phase of reductions in 2012 will help many areas attain in a more
expeditious manner.
Further, a deadline of January 1, 2014 also provides adequate and
reasonable time for sources to plan for compliance with the Transport
Rule and install any necessary controls. EPA believes that this
deadline is as expeditious as practicable for the installation of the
controls, if any, needed for compliance with the 2014 state emission
budgets. (See further discussion in section V.C.2.)
1997 Ozone NAAQS Attainment Deadlines. Ozone nonattainment areas
must attain permissible levels of ozone ``as expeditiously as
practicable,'' but no later than the date assigned by EPA in the ozone
implementation rule. 40 CFR 51.903. The areas designated nonattainment
in 2004 with respect to the 1997 8-hour ozone NAAQS in the eastern
United States were assigned maximum attainment dates effectively
corresponding to the end of the 2006, 2009, and 2012 ozone seasons. The
maximum attainment deadlines for the 1997 standard run from the June
15, 2004 effective date of designation for that standard. The time
periods are based on the time periods provided for these
classifications in section 181 of the Act, 45 U.S.C. 7511(a). However,
instead of running from the 1990 date of enactment of the CAA as
specified in section 181, our regulation provides that they run from
the date of designation. An area's maximum attainment date is based on
its nonattainment classification--that is, whether it is classified as
a marginal, moderate, serious, severe, or extreme ozone nonattainment
area. Marginal areas have three years from designation to attain the
standard. Moderate, serious, severe, and extreme areas have 6, 9, 15,
and 20 years, respectively. The maximum attainment deadlines associated
with the 1997 ozone standards are June 15, 2007 for marginal areas,
June 15, 2010 for moderate areas, and June 15, 2013 for serious areas.
Because the actual deadline occurs in the middle of an ozone season,
data from that ozone season is not considered when determining whether
the area has attained by the deadline. Thus, these maximum attainment
deadline dates effectively correspond with the end of the 2006, 2009,
and 2012 ozone seasons. Reductions achieved or air quality improvements
realized after those dates will not help the areas meet their maximum
attainment deadlines.
Many areas have already attained the standard due in part to CAIR,
federal
[[Page 48278]]
mobile source standards, and other local, state, and federal measures.
Other areas, however, have been reclassified to a higher classification
either because they failed to attain by their attainment date or
because the state requested reclassification to avoid missing an
attainment date. Those that have not yet attained the standard now have
maximum attainment dates ranging from June 2011 (these are the moderate
areas that have been granted a 1-year extension due to clean data for
the 2009 ozone season) to June 2024. The areas classified as
``serious'' nonattainment areas have a June 2013 maximum attainment
deadline. Areas that missed their earlier deadlines and have been
reclassified as ``severe'' or ``extreme'' nonattainment areas now have
maximum nonattainment deadlines of June 2019 and June 2024
respectively. As explained above, an area with a June 2013 deadline
would need to attain based on ozone data from the 2010-2012 ozone
seasons, an area with a June 2019 deadline would need to attain based
on ozone data from the 2016-2018 ozone seasons, and an area with a June
2024 deadline would need to attain based on ozone data from the 2021-
2023 ozone seasons.
The Transport Rule's first phase of reductions in 2012 will help
the remaining areas with June 2013 maximum attainment deadlines attain
the 1997 8-hour ozone NAAQS by their deadline. If EPA determines that
an area failed to attain by the 2013 deadline, the area would be
reclassified to severe and would be subject to the more stringent
emission control requirements that apply to the severe classification.
The reductions will also help areas with later deadlines attain as
expeditiously as practicable and improve air quality in those areas.
2012 Interim Compliance Deadline. EPA is requiring an initial phase
of reductions starting in 2012. These reductions are necessary to
ensure that significant contribution to nonattainment and interference
with maintenance are eliminated as expeditiously as practicable and in
time to help states meet their attainment deadlines. As the court
emphasized in North Carolina, the significant contribution to
nonattainment and interference with maintenance from upwind states must
be eliminated as expeditiously as practicable to help downwind states
to achieve attainment as expeditiously as practicable as required by
the CAA. Further, reductions are needed by 2012 to help states attain
before the June 2013 maximum attainment date for ``serious'' ozone
nonattainment areas, to ensure states attain as soon after the original
April 2010 attainment deadline for the 1997 PM2.5 NAAQS, and
to help states attain before the December 2014 attainment deadline for
the 2006 PM2.5 NAAQS.
In addition, because this final rule will replace CAIR, EPA could
not assume that after this rule is finalized, EGUs would continue to
emit at the reduced emission levels achieved by CAIR. Instead, it is
the emission reduction requirements in the proposed FIPs that will
determine the level of EGU emissions in the eastern United States. For
this reason also, EPA concludes that it is appropriate to require an
initial phase of reductions by 2012 to ensure that existing and planned
SO2 and NOX controls operate as anticipated.
Addressing the Court's Concern about Timing. As directed by the
Court in North Carolina, 531 F.3d 896, and as described previously, EPA
established the compliance deadlines in the Transport Rule based on the
respective NAAQS attainment requirements and deadlines applicable to
the downwind nonattainment and maintenance sites.
The 2012 deadline for compliance with the limits on ozone-season
NOX emissions is necessary to ensure that states with June
2013 maximum attainment deadlines get the assistance needed from upwind
states to meet those deadlines. The 2012 deadline for compliance with
the limits on annual NOX and annual SO2 emissions
is necessary to ensure attainment as expeditiously as practicable in
areas which failed to attain by the 2010 attainment deadline for the
1997 PM2.5 NAAQS and had to request an extension to 2015.
Similarly, the 2014 deadline for compliance with the limits on
annual NOX and annual SO2 emissions is necessary
to ensure that downwind states get the benefit of upwind reductions
prior to the December 2014 maximum attainment deadline for the 2006
PM2.5 NAAQS. It is also necessary to ensure reductions occur
in time to assist with attainment in downwind areas that received the
maximum 5-year extension of the 5-year attainment deadline for the 1997
PM2.5 NAAQS (taking into account the need for reductions by
2014 to demonstrate attainment by April 2015).
The 2012 compliance deadline for the first-phase of annual
NOX and annual SO2 emission reductions will
assure the reductions are achieved as expeditiously as practicable. A
significant amount of the emissions identified as significantly
contributing to nonattainment or interfering with maintenance in other
states can be eliminated by 2012. EPA believes it is appropriate to do
so in light of the court's direction to EPA to ensure states eliminate
such emissions as expeditiously as practicable. North Carolina 531,
F.3d at 930. Given the time needed to design and construct scrubbers at
a large number of facilities, EPA believes the 2014 compliance date is
as expeditious as practicable for the full quantity of SO2
reductions necessary to fully address the significant contribution to
nonattainment and interference with maintenance. Requiring reductions
in transported pollution as expeditiously as practicable, as well as
within maximum deadlines, helps to promote attainment as expeditiously
as practicable. This is consistent with statutory provisions that
require states to adopt SIPs that provide for attainment as
expeditiously as practicable and within the applicable maximum
deadlines.
b. Public Comments and EPA Responses
EPA received numerous comments on the proposed compliance dates. A
number of commenters supported EPA's compliance schedule and rationale.
Other commenters supported extending the compliance deadlines to later
dates.
Many commenters questioned the technical feasibility of achieving
the required reductions by the 2012 and 2014 dates. EPA's responses to
those comments are discussed below in section VII.C.2.
Other commenters provided policy and legal arguments for allowing
states to develop SIP alternatives to the FIP, and to build time for
that SIP development and review process into the compliance schedule.
For example, some commenters asserted that the requirement in the CAA
for providing reductions ``as expeditiously as practicable'' must be
balanced with CAA provisions allowing states to develop state
implementation plans prior to EPA imposing FIPs. EPA responses to those
comments are discussed in section X.
Some commenters suggested that EPA had the ability to leave CAIR in
place for a transition period, and by doing this EPA could allow for a
longer compliance period for this rule. EPA does not believe it would
be appropriate, in light of the Court's decision in North Carolina, to
establish a lengthy transition period to the rule that will replace
CAIR. Although the Court decided on rehearing to remand CAIR without
vacatur, the Court stressed its prior decision that CAIR was deeply
flawed and EPA's obligation to remedy those flaws. North Carolina, 550
[[Page 48279]]
F.3d 1176. Although the Court did not set a definitive deadline for
corrective action, the Court took care to note that the effectiveness
of its opinion would not be delayed ``indefinitely'' and that
petitioners could bring a mandamus petition if EPA were to fail to
modify CAIR in a manner consistent with its prior opinion. Id. Given
the Court's emphasis on remedying CAIR's flaws expeditiously, EPA does
not believe it would be appropriate to establish a lengthy transition
period to the rule which is to replace CAIR.
As relates to PM2.5, EPA received a number of comments
on its proposal to include a 2012 deadline to ensure that emission
reductions needed to reduce PM2.5 be achieved ``as
expeditiously as practicable.'' Some commenters supported EPA's 2012
deadline. Other commenters believed that it was unnecessary and
unwarranted for EPA to impose emission reduction requirements in
advance of the 2014 attainment date. In light of the 2014 five-year
attainment date for the 2006 PM2.5 NAAQS (with a possible
extension to 2019), and the possible extension to April 2015 for the
1997 PM2.5 NAAQS, these commenters believed EPA's 2012
emission reduction requirements for annual PM2.5 and
NOX were not necessary. EPA disagrees with these commenters,
for a number of reasons. First, EPA notes (supported by commenters)
that there is a clear statutory obligation to attain ``as expeditiously
as practicable.'' Second, EPA notes that there are feasible reductions
available by 2012. Third, EPA believes that the substantial health and
environmental benefits achieved by the rule underscore the importance
of achieving the reductions as soon as possible.
With respect to ozone, some commenters noted that the proposed rule
required ozone reductions by 2012 for states impacting areas which
EPA's analysis shows will attain the 1997 ozone NAAQS by 2014 without
further controls. Those commenters questioned the importance of getting
reductions in such states and whether the 2012 deadline is necessary.
EPA disagrees with those comments. Except for Houston, all ozone areas
within the region addressed by this rule have attainment dates no later
than 2013. In effect, this means that emission reductions needed to
attain the 1997 ozone NAAQS must be in place by the 2012 ozone season.
EPA believes that if there are reductions available by 2012, and those
emission reductions have in fact been identified, it is appropriate and
necessary to ensure that those reductions are in place.
2. Compliance and Deployment of Pollution Control Technologies
The power industry will undertake a diverse set of actions to
comply with the Transport Rule at the start of 2012 and another set of
actions when companies in Group 1 states comply with more stringent
SO2 budgets at the start of 2014. In 2012, the industry will
largely meet the rule's NOX requirements by: Operating an
extensive existing set of combustion and post-combustion controls on
fossil fuel-fired generators; dispatching lower emitting units more
often; and installing and operating a limited amount of relatively
simple NOX pollution controls in states not previously
subject to CAIR. For the SO2 requirements, EPA anticipates
at a minimum that coal-fired generators will operate the substantial
capacity of advanced pollution controls already in place or scheduled
for 2012 use; some units will also elect to burn lower-sulfur coals;
and the fleet will increase dispatch from lower-sulfur-emitting units
as well as from natural gas-fired generators. EPA provides a more
detailed explanation below of how fuel switching to lower sulfur coals
factored in to the design of the final Transport Rule.
By 2014, EPA's budgets under the Transport Rule will sustain
previous NOX and SO2 reductions as well as
account for reductions from additional advanced NOX and
SO2 controls that are driven by other state and federal
requirements. In addition to these reductions, companies in Group 1
states are also projected to add a limited amount of advanced
SO2 controls in 2014 that will be discussed below.
EPA's expectations are supported by the IPM analysis reported in
this rule's RIA (see Chapter 7). Notably, since EPA has established a
cap and trade control system for lowering NOX and
SO2 emissions, individual owners and operators of covered
units have some flexibility in meeting the program's requirements as
needed and are free to find alternative ways to comply. The RIA clearly
shows a viable known pathway for owners and operators to comply at
reasonable costs, although it is not the only compliance pathway
possible under this flexible regulation that could deliver the emission
reductions required under the rule. Notably, by 2014 and beyond, the
power industry may also augment the projected compliance efforts with
programs aimed at improving energy efficiency.
Table VII.C.2-1--shows EPA's projection of the amount of existing
coal-fired generating capacity in gigawatts (GW) that may retrofit
various systems for compliance with this rule.
Table VII.C.2-1--Projected Potential Air Pollution Control (APC) Retrofits for Transport Rule \59\
--------------------------------------------------------------------------------------------------------------------------------------------------------
Capacity retrofitted by Wet FGD Dry FGD DSI SCR LNB/OFA improvements
--------------------------------------------------------------------------------------------------------------------------------------------------------
January 1, 2012................. ...................... ...................... ...................... ...................... 10 GW
January 1, 2014................. 5.7 GW................ 0.2 GW................ 3.0 GW................ 0 GW..................
--------------------------------------------------------------------------------------------------------------------------------------------------------
EPA received proposal comments expressing a concern about the
feasibility of deploying retrofit air pollution control (APC)
technologies in the time frames available between the final date of
this rule and the compliance dates. As discussed below, EPA believes
that it is feasible for the electric power sector and its APC supply
chain to either make most of the projected retrofits in time to meet
the 2012 and 2014 compliance deadlines, or to comply by other means.
---------------------------------------------------------------------------
\59\ GW: Gigawatts of capacity retrofitted; FGD: Flue gas
desulfurization (SO2 control); DSI: Dry sorbent injection
(SO2 control); SCR: Selective catalytic reduction
(NOX control); LNB/OFA: Low-NOX burner and/or
overfire air (NOX controls).
---------------------------------------------------------------------------
a. 2012 Power Industry Compliance
EPA's analysis of emission reductions available in 2012 assumes
year-round operation of existing post-combustion pollution controls in
states covered for PM2.5 and ozone-season operation of
NOX post-combustion controls in states covered for ozone.
EPA also modeled emission reductions available in 2012 at the $500/ton
threshold for SO2, $500/ton for annual NOX, and
$500/ton for ozone-season NOX.
For SO2, EPA believes that reductions associated with
the following methods of control are available and will be used
[[Page 48280]]
as compliance strategies to meet the 2012/2013 budgets: (1) Operation
of existing controls year-round in PM2.5 states, (2)
operation of scrubbers that are currently scheduled to come online by
2012, (3) some sources switching to lower-sulfur coal (see section
VII.C.2.c that follows), and (4) changes in dispatch and generation
shifting from higher emitting units to lower emitting units. EPA
modeling and selection of a $500/ton cost threshold includes all
existing and planned controls operating year round (items 1 and 2). It
also reflects an amount of coal switching and generation shifting that
can be achieved for $500/ton. This set of expected actions was
confirmed in the detailed modeling of EPA's final remedy in the RIA and
can be reviewed there.
The power sector is already strongly positioned to achieve the
Transport Rule state budgets presented in section VI.D through at least
three distinct strategies. First, the sector will optimize its use of
the large proportions of advanced pollution controls already present
throughout the fleet. Second, the sector will take advantage of the
substantial new pollution control technology that is already on the way
for deployment by 2012. Third, the remainder of the fleet will flexibly
adopt the most economic low-emitting fuel mix available at each unit to
deliver cost-effective emission reductions complementing the reductions
achieved from optimized use of the fleet's pollution control
technology. The state maps in Chapter 7 of this rule's Regulatory
Impact Analysis demonstrate how these emission reduction strategies for
2012 will build off of the sector's historic trend toward cleaner
generation profiles. Also, the detailed unit-level projection files
from EPA's IPM power sector modeling of the Transport Rule remedy
(found in the docket for this rulemaking) show how EGUs adopt these
strategies to not only reach the 2012 budgets, but in fact in many
states overcomply with the budgets and build up a bank of allowances
under the programs for future flexibility.
The following paragraphs illustrate the degree to which the
existing fleet is already prepared to adopt these emission reductions
in 2012 in order to attain the required emission reductions for
SO2, annual NOX, and ozone-season NOX
under the Transport Rule. More specifically, the illustrative
paragraphs demonstrate emission reduction pathways for coal capacity to
optimize or increase operation of existing control technology, timely
implement existing plans to bring additional control technology on
line, and to cost-effectively make use of lower-emitting fuel
alternatives.
Of the 240 GW of coal capacity in the Transport Rule region covered
for fine particles, approximately 110 GW--more than 45 percent--had
existing advanced pollution control for SO2 already in place
in 2010, including scrubbers (FGD), dry sorbent injection (DSI), or
circulating fluidized bed boilers. Of this controlled coal capacity,
EPA expects a significant portion will improve emission rates through
either increased use of control technology and/or additional fuel
switching. EPA notes that an additional 39 GW of advanced
SO2 controls in the region are scheduled to come online over
the 2010-2012 timeframe and will also assist in meeting 2012 emission
reduction requirements. Thus, by 2012 more than half of affected coal
capacity--152 GW--will be operating with advanced SO2
control equipment. Additionally, EPA expects approximately 40 GW of
uncontrolled coal capacity in the region to take advantage of the
existing coal supply infrastructure, possibly switching coal use or
coal blending behaviors to make cost-effective reductions in
SO2 emission rates where economic to respond to the
Transport Rule 2012 emission reduction requirements.
EPA notes that approximately 136 GW of the 240 GW--more than 56
percent--of coal capacity in the Transport Rule region covered for fine
particles had existing advanced pollution control for NOX
already in place in 2010, including selective catalytic reduction
(SCR), selective non-catalytic reduction (SNCR), or circulating
fluidized bed boilers. Of this capacity, EPA anticipates a significant
portion will improve their NOX emission rate through
increased operation of these existing controls. Additionally, EPA notes
that an additional 21 GW of SCR and 4 GW of enhanced combustion
controls (including low-NOX burners and overfire air) are
scheduled to come online in the region during the 2010-2012 timeframe,
bringing the total region's coal capacity operating with NOX
emission reduction technology to 158 GW (more than 65 percent of total
coal capacity in the Transport Rule fine particle region). EPA also
projects that approximately 13 GW of coal capacity will make some
reduction in their NOX emission rates by enhancing
performance of existing combustion controls or SNCR, or by fuel
switching.
In the Transport Rule states covered under the ozone-season
program, approximately 145 GW of the 260 GW (more than 55 percent) of
coal capacity had existing NOX control technology in place
in 2010. EPA expects a significant portion of that capacity to achieve
emission reductions during the 2012 ozone-season through improved
operation of SCR. Additionally, in the Transport Rule ozone region
there will be approximately 21 GW of additional advanced NOX
control installations and 7 GW of additional combustion control
improvements or installations coming online during the 2010 to 2012
time frame. EPA projects that 17 GW of coal capacity in the Transport
Rule ozone region will reduce NOX emission rates by
enhancing performance of existing combustion controls or SNCR or by
fuel switching.
For NOX, EPA has also concluded that it is appropriate
to require reductions through a limited amount of combustion control
improvements, and in some cases, retrofits such as low-NOX
burners (LNB) and/or overfire air (OFA). EPA recognizes that the 6-
month time frame between rule finalization and start of the first
compliance period would not allow for the installation of a major post-
combustion NOX control such as SCR. Assumed improvements and
retrofits for the January 1, 2012 deadline for annual NOX
reductions therefore only involve the much simpler LNB/OFA control
modifications or installations. Alternatively, some plant owners might
choose to achieve NOX reductions in a similar time period
through an even simpler retrofit--SNCR.\60\
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\60\ David L. Wojichowski, SNCR System--Design, Installation,
and Operating Experience http://www.netl.doe.gov/publications/proceedings/02/scr-sncr/wojichowski-1.pdf.
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Although the improvements, and in some cases, installation of
combustion controls would be an economic means of achieving emission
reductions, these specific controls are not required for compliance
purposes under the final Transport Rule remedy. Individual sources may
comply through other measures (such as purchasing additional
allowances) in the event that it takes more than 6 months for
installation of a given combustion control. The vast majority of
covered sources already have combustion controls installed; therefore,
the NOX reductions associated with these incremental control
improvements and installations are small.
[[Page 48281]]
Based on the Transport Rule's geography, EPA estimates that
approximately 10 GW of coal-fired units may improve, and in some cases,
install LNB/OFA specifically in reaction to the Transport Rule
NOX caps. EPA reflects the effects of these installations in
the 2012 annual and ozone-season NOX budgets, which would
yield reductions of approximately 28,000 tons of annual NOX
and 14,000 tons of ozone-season NOX. EPA assumes these
controls are cost effective at $500/ton and that they should be
incentivized through budgets given the 2013 attainment deadline for
ozone areas classified as ``serious.'' Once installed, LNB/OFA operates
any time the boiler is fired and thus yields NOX reductions
beyond the ozone season alone.
In the proposal's LNB technical support document,\61\ EPA observes
that LNB and/or OFA installations, burner modifications, or other
NOX reduction controls would likely have to be installed
during fall 2011 or spring 2012 outages in order to achieve significant
reductions for 2012. While this 6-month schedule is aggressive,
industry has shown that it can be met. For example, Limestone Electric
Generating Station Unit 2, an 820 MW tangentially-fired lignite unit,
was retrofitted with Foster Wheeler's Tangential Low NOX
(TLN3) system in less than six months, including engineering,
fabrication, delivery and installation.\62\ Harlee Branch Unit 4, a 535
MW cell-fired unit, was retrofitted with Riley Power's low-
NOX Dual Air Zone CCV burners on a similar schedule.\63\
These are tangentially-fired and wall-fired units, respectively,
representative of the unit types that might make LNB/OFA improvements
for compliance with this rule. Although such 6-month schedules can be
achieved on some units, under favorable circumstances, historical
projects suggest a more typical schedule would be 12 to 16 months for
the contractor's portion of the work.\64\ A plant owner's project
planning and procurement work in advance of a contract award would
typically involve several additional months. On the other hand, there
are other approaches that can also be implemented in a short time frame
to achieve significant NOX reduction. As mentioned above,
relatively simple SNCR systems can be installed quickly; and the re-
tuning or upgrading of existing combustion control systems can often
provide significant NOX reductions and can be performed
quickly.\65\
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\61\ Technical Support Document (TSD) for the Transport Rule,
Docket ID No. EPA-HQ-OAR-2009-0491, Installation Timing for Low
NOX Burners (LNB).
\62\ R. Pearce, J. Grusha, Reliant Energy Tangential Low
NOX System at Limestone Unit 2 Cuts Texas Lignite, PRB
and Pet Coke NOX, http://www.fwc.com/publications/tech_papers/files/tp_firsys_01_02.pdf.
\63\ B. Courtemanche, et al., Reducing NOX Emissions
and Commissioning Time on Southern Company Coal Fired Boilers With
Low NOX Burners and CFD Analysis, http://www.babcockpower.com/pdf/t-182.pdf.
\64\ M. O'Donnell, Babcock & Wilcox Company, (personal
communication with EPA staff, February 22, 2011).
\65\ N.C Widmer, et al., Coal Power, October 8, 2009, http://www.coalpowermag.com/ops_and_maintenance/Zonal-Combustion-Tuning-Systems-Improve-Coal-Fired-Boiler-Performance_226.html.
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As stated above, EPA believes that LNB/OFA modifications or
retrofits would be possible during the 6-month interim between rule
signature and the start of the first compliance period, particularly
for those ``early movers'' who have initiated LNB projects based on the
proposed rule. However, as shown in Table VII.C.2-2, below, even if all
LNB modifications or installations are delayed until the beginning of
the 2012 ozone season, the reductions only represent 1 percent of most
covered states' annual NOX budgets, and no more than 11
percent of any affected state's annual NOX budget. Under
such a scenario, these delayed reductions would still be well within
the 18 percent variability limit applied to each state's annual
NOX budget. In light of this limited consequence and the
supporting material above, EPA includes LNB-driven NOX
reductions in both annual and ozone-season NOX budgets for
2012.
Table VII.C.2-2--Earliest Reductions Assumed From LNB Installations in the Transport Rule States Subject to the
Annual NOX Program *
----------------------------------------------------------------------------------------------------------------
NOX reductions Percent of
from LNB budget met by
operation from Annual NOX state earliest LNB
January-April budget (tons) reductions
(tons) (percent)
----------------------------------------------------------------------------------------------------------------
Georgia................................................... 646 62,010 1
Iowa...................................................... 567 38,335 1
Kansas.................................................... 2,131 30,714 7
Minnesota................................................. 2,303 29,572 8
Nebraska.................................................. 3,008 26,440 11
-----------------------------------------------------
Region-wide Total..................................... 8,656 1,245,869 1
----------------------------------------------------------------------------------------------------------------
* Based on EPA IPM Analysis of Final Transport Rule.
b. 2014 Power Industry Compliance
EPA projects that compliance with 2014 requirements for
NOX will result largely from operation of existing and
future controls required by state and other federal requirements, as
well as the appropriate dispatch of the electric generation fleet. EPA
does not project additional NOX pollution control retrofits
aside from about 10 GWs of combustion control improvements or retrofits
projected for the 2012 compliance period. To comply with the rule's
SO2 requirements, EPA projects that the power industry will
rely on existing controls, operate newly installed advanced controls
necessary for other binding state and federal requirements, rely more
on relatively lower sulfur coals, and dispatch lower-emitting
generation units. In Group 1 states, industry is projected to increase
switching to lower sulfur coals and install a limited amount of
additional scrubbers and other advanced pollution control technology.
EPA's assessment of the industry's ability to install SO2
pollution controls in 2014 and undertake the projected coal switching
follows below.
EPA's modeling of least-cost compliance with the state budgets
under the Transport Rule projects approximately 5.9 GW of FGD systems
and lesser amounts of other technologies will be retrofitted by 2014
[[Page 48282]]
for compliance with the Transport Rule.66 67 EPA's schedule
assumptions for these larger more complex projects were developed in an
earlier study and mentioned in the proposal: 27 months for retrofitted
wet FGD and 21 months for SCR.\68\ Note that a dry FGD system, due to
its relatively simpler configuration and lesser cost, would typically
take somewhat less time to retrofit than wet FGD.
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\66\ Nearly all of the 5.9 GW of FGD retrofits are comprised by
some 12 units at 7 plants (Beckjord, Muskingum River, Homer City,
Rockport, Kammer, Danskammer, and Will County).
\67\ As noted elsewhere in this preamble, the projected impacts
of this final rule presented in the preamble do not reflect minor
technical corrections to SO2 budgets in three states (KY,
MI, and NY) and assumed preliminary variability limits that were
smaller than the variability limits finalized in this rule. EPA
conducted sensitivity analysis factoring in these corrections; the
results of this analysis include a small increase of about 700 MW of
additional wet FGD retrofit projected for 2014. This projected
additional retrofitting capacity is already required to retrofit
under a consent decree and should therefore have already conducted
advanced retrofit planning. EPA therefore believes that this
incremental projected retrofit behavior (factoring in the technical
corrections made after the main impact analyses were conducted) is
feasible by 2014 for the same reasons presented in this section
regarding the projected retrofit behavior from the main analysis of
the final rule.
\68\ EPA, Engineering and Economic Factors Affecting the
Installation of Control Technologies for Multipollutant Strategies;
EPA-600/R-02/073 October 2002.
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As discussed below, EPA believes that its schedule assumptions
remain reasonable expectations for sources that have completed most of
their preliminary project planning and can quickly make commitments to
proceed. These schedules do not include the extensive time that some
plant owners might spend in making a decision on whether or not to
retrofit. They do include the time needed to make a final confirmation
of the type of technology to be used at a particular site, to prepare
bid requests, award contracts, perform engineering, obtain construction
and operating permits (in parallel with project activities), perform
construction, tie-in to the existing plant systems, and perform
integrated systems testing.
EPA received comments on the proposed rule indicating that some
past single-unit APC retrofits had considerably longer schedules, with
a few exceeding 48 months. EPA engineering staff have extensive
experience with power plant and APC system design, construction, and
operation. Based on that experience, EPA can observe that in the
absence of a compelling deadline or major economic incentive, many
large project schedules are considerably longer than necessary. Given
further observations as explained below, EPA believes it is reasonable
to expect that almost all future APC retrofits can be completed far
more quickly than they were in recent history. EPA's perspective on
this matter derives in part from a comparison of longer APC schedules
(as provided by some commenters) to the project schedule for an entire
new coal-fired unit, including its APC systems. Springerville Unit 3,
for example, is a new 400 MW subbituminous coal-fired unit with SCR and
dry FGD that became operational in July 2006, some 33 months after the
turnkey engineering-construction contractor was given a notice to
proceed with engineering.\69\ Springerville was clearly on an
accelerated schedule, as its original planned schedule was about 38
months. Another example is Dallman Unit 4, a high-sulfur bituminous
coal-fired 200 MW unit with SCR, fabric filter, wet FGD, and wet ESP.
Dallman Unit 4 was first synchronized in May 2009, several months ahead
of schedule, and about 36 months after its turnkey contractor placed
initial major equipment orders.\70\ The main point here is that recent
APC project schedules, and those of large complex power projects, can
be significantly accelerated. Because the scope and complexity of the
work involved for an entire new coal unit and its APC systems is
perhaps five times greater than that of a retrofit wet FGD system
alone, EPA believes it is reasonable to expect that even the most
complex retrofit APC project can be significantly accelerated as well.
Additional factors are discussed below that further support the
feasibility of installing by 2014 the 5.9 GW of FGD retrofits projected
for this rule.
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\69\ Best Coal-fired Projects, Springerville Unit 3 Expansion
Project, Power Engineering, November 2006, http://www.powergenworldwide.com/index/display/articledisplay/282547/articles/power-engineering/volume-111/issue-1/features/projects-of-the-year.html.
\70\ http://www.cwlp.com/electric_division/generation/Dallman%204%20Power%20Plant%20of%20the%20Year.pdf.
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Although IPM modeling provides reliable estimates on a regional
basis, and cannot be as accurate at the level of individual plants or
units, it is informative and relevant to consider IPM's plant level
projections in this case. Although the IPM-projected retrofits named
below may not actually occur, IPM projects that they would be economic
and would allow industry to meet the tighter SO2 emission
standards in Group 1 states in 2014. EPA notes that the owners of the
particular plants mentioned below (Duke Energy, AEP, Edison
International) are large, experienced, versatile utilities that have
done considerable advance planning and should also have above-average
flexibility to comply with state budgets across their fleets. EPA would
expect such owners to have relatively little difficulty in permitting
and financing FGD retrofits.
Of the Transport Rule-related FGD retrofits, 0.2 GW is projected to
use dry FGD, which EPA expects to be simpler and quicker to install
than wet FGD. Half of the 5.9 GW (Muskingum, Rockport) has already been
committed under consent decrees to add controls or retire; \71\ and EPA
reasonably believes that significant preliminary project planning work
has already been done for those projects. An additional 1,200 MW (Homer
City) had completed project planning and was ready to proceed in 2007,
before putting the project on hold.\72\ The latter plant is now facing
EPA legal action and the possibility of a required expeditious FGD
retrofit.\73\ Thus, of the 5.9 GW of projected FGD retrofits resulting
from this rule, nearly 75 percent appears to be in good position for an
early start of construction, and over 3 GW of that would be bringing
forward already committed compliance start dates.
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\71\ http://www.epa.gov/compliance/resources/decrees/civil/caa/americanelectricpower-cd.pdf.
\72\ http://www.businesswire.com/news/home/20060731005193/en/Contractors-Selected-Install-Emissions-Control-System-Pennsylvania.
\73\ http://www.epa.gov/Compliance/resources/complaints/civil/caa/homercity-cp.pdf.
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Any of the above mentioned potential retrofits or any other unit
that might choose to retrofit FGD for a January 2014 compliance date
will likely have to use various methods to accelerate the project
schedule. Such methods could include the use of parallel permitting,
overtime and/or two-shift work schedules during construction, and 5- or
6-day work weeks instead of the 4-day x 10-hour schedules often used to
minimize cost when time is not of the essence. Increased use of offsite
modularization and pre-fabrication of APC components could also shorten
schedules and reduce job hours.
EPA believes that the January 1, 2014 compliance date is as
expeditious as practicable for the sources installing large, complex
control systems. The following additional observations support EPA's
expectation that the limited 5.9 GW of FGD retrofits can be realized in
the 30 month interim between rule signature and the start of 2014:
There are documented instances of large, complex wet FGD
retrofits being deployed in less than 30-months (excluding the time for
owners' project
[[Page 48283]]
planning). Examples are Killen Station Unit 2,\74\ and Asheville Unit
1.\75\
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\74\ Black & Veatch, http://www.bv.com/News_3_Publications/News_Releases/2005/0503.aspx (start), http://www.bv.com/wcm/press_release/07252007_9767.aspx (completion).
\75\ PowerGenWorldwide, Projects of the Year, January 1, 2007,
http://www.powergenworldwide.com/index/display/articledisplay/282547/articles/power-engineering/volume-111/issue-1/features/projects-of-the-year.html.
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In 2009 the APC supply chain deployed more than six times
more GW capacity of FGD and SCR controls than the 5.9 GW of FGD that
would be deployed by 2014 under this Rule.
The APC supply chain has seen a 2-year decline in
deployments since its peak in 2009, but in 2011 is nonetheless putting
into service about three times more GW capacity of FGD and SCR controls
than the 5.9 of FGD that would be deployed under this Rule.
Because the supply chain has been in decline, but remains
quite active, there are now adequate supply chain resources available
that can be quickly reengaged to support a rapid deployment of 5.9 GW
of FGD.
EPA recognizes that the installation of any amount of scrubbers in
this short time frame will require aggressive action by plant owners
and that the owners who can meet this schedule will already have done
their project planning and will be ready to place orders. An example of
such ``early movers'' was seen in the power sector's anticipation of
CAIR. EPA data indicate that solely CAIR-driven FGD and SCR deployments
of about 6 GW occurred within two and one-half years after CAIR's
finalization in mid-2005, showing that at least 20 percent of the total
CAIR-only controls effort through a 2010 compliance date was
sufficiently planned for installation to start before or immediately
upon finalization of the rule. EPA reasonably expects that similar
advance planning has already been done for units that would retrofit
under this rule.
In the event that a particular control installation requires
additional time into 2014 to come online, EPA believes compliance would
not be jeopardized given the ability of sources to purchase allowances
during that time. This approach could be supported by some sources with
FGD that have the ability to increase their SO2 removal
above historic rates, perhaps through relatively low cost upgrades to
improve scrubber effectiveness, or by operating scrubbers at higher
chemistry ratios. The ability of sources to temporarily or permanently
substitute dry DSI for FGD serves as another backstop for any
feasibility issues regarding FGD. Note that the updated modeling for
this rule projects the addition by 2014 of about 3 GW of DSI for
SO2 control using trona or other sorbent. DSI is a
relatively low capital cost technology that readily can be installed in
the time frame available for compliance.76 77
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\76\ ICAC letter to Senator Carper, November 3, 2010, http://www.icac.com/files/public/ICAC_Carper_Response_110310.pdf.
\77\ Assessment of Technology Options Available to Achieve
Reductions of Hazardous Air Pollutants, URS Corporation, April 5,
2011, http://www.supportcleanair.com/resources/studies/file/4-8-11-URSTechnologyReport.pdf.
---------------------------------------------------------------------------
It should also be noted that most APC retrofits will involve a
source outage for final ``tie-in'' of retrofitted systems to existing
systems, during which time emissions from the affected units are zero.
For some sources, the duration of this tie-in outage may effectively
extend the deadline by which all of the projected emission reductions
need to occur.
Although EPA believes that installation of 5.9 GW of FGD at
facilities by January 1, 2014 is feasible, EPA also conducted an IPM
sensitivity analysis to examine a scenario in which FGD retrofitting by
2014 is not allowed. Results of EPA's ``no FGD build in 2014'' analysis
indicate that if the power industry were subjected to the requirements
of this rule without an FGD retrofit option for compliance until after
2014, covered units would still be able to meet the Transport Rule
requirements in every state while respecting each state's assurance
level. (See the docket to this rulemaking for the IPM run titled ``TR--
No--FGD-- in2014--Scenario--Final.'')
In this scenario without the availability of new FGD by 2014,
sources in covered states complied with the Transport Rule budgets by
using moderate additional amounts of DSI retrofits, switching to larger
shares of sub-bituminous coal, and dispatching larger amounts of
natural gas-fired generation in lieu of the FGD retrofits that are
projected as being most economic under modeling of the Transport Rule
remedy. Because new FGD capacity is included in EPA's projection of the
least-cost set of SO2 emission reductions required in Group
1 states, the ``no FGD'' sensitivity scenario did project higher system
costs, although these costs were still substantially lower than the
remedy EPA modeled in the Transport Rule proposal.
The ``no FGD'' analysis indicates that while the ability of Group 1
states to meet their 2014 SO2 budgets is facilitated by FGD
retrofits, they are by no means required, nor is Transport Rule
compliance jeopardized by their absence. Even under a scenario in which
sources fail to complete FGD retrofits by 2014, sources in the affected
states would have other compliance options available at reasonable cost
to meet the state's budget requirements. This analysis shows that Group
1 states would be able to comply with their 2014 SO2 budgets
by relying on other emission reduction opportunities that do not
require FGD retrofits. EPA analysis confirms that those alternatives
are feasible both in terms of cost and timing.
Finally, EPA recognizes that, when finalized later this year as
currently scheduled, the Mercury and Air Toxics Standards (MATS) will
require significant retrofit activity at covered sources in the power
sector with a 2015 compliance date for that rule. EPA's projections of
retrofit activity under the final Transport Rule are highly compatible
with its projections of retrofit activity under the proposed MATS
(which included the proposed Transport Rule in its baseline). EPA
therefore anticipates that the Transport Rule's projected retrofit
activity will not only be the least-cost compliance pathway to meeting
state budgets in 2014 but will also accelerate emission reductions
subsequently required by the effective date of MATS. The final
Transport Rule's projected 2014 retrofit installations will also
further incentivize the power sector to ramp up its retrofit
installation capabilities to achieve broader deployment of the
projected pollution control retrofits under the proposed MATS.
Considering all the reasons given above, EPA has concluded that the
2014 requirements for SO2 emissions in the states covered by
the Transport Rule are reasonable and can be met by the power industry
by a variety of means.
c. Coal Switching for SO2 Compliance in 2012 and 2014
Coal switching is another mechanism which can be used along with
operating pollution controls in 2012 for compliance. It will be a
complementary activity by many coal-fired units alongside of operating
pollution controls and the addition of more scrubbers and DSI in 2014.
In the proposal, EPA noted that coal switching could serve as a
compliance mechanism for 2012. EPA requested comment on the
reasonableness of EPA's assumption that coal switching will have
relatively little cost or schedule impact on most units. EPA received
substantial comment suggesting that the coal switching and coal
blending projected by EPA modeling are not feasible for all units,
[[Page 48284]]
and that, if feasible, would often incur a cost through the derating of
the unit associated with the switch to a lower sulfur coal or coal
blend. Additionally, sources indicated that coal switching by 2012
would not always be possible in the six month window between final rule
signature and start of compliance. These feasibility concerns stemmed
from restrictions included in existing coal supply contracts and from
boiler design constraints that may hinder coal switching within a 6
month window.
EPA agrees with these concerns and revised its IPM modeling to
limit coal switching capability in 2012 for particular units that may
have trouble switching coals or coal blends in a six month time frame.
A cost adder was also included in the IPM modeling for coal switching
to capture the potential cost burden of deratings that might accompany
switching to a very low sulfur subbituminous coal or coal blend.
A particular commenter concern regarding switching to lower sulfur
within the eastern bituminous coals related to a possible impact on the
performance of a cold-side electrostatic precipitator (ESP). Some ESPs
that operate at acceptably high collection efficiency when using a
high- or medium-sulfur bituminous coal may experience some loss in
collection efficiency when a lower sulfur coal is used. Whether this
occurs on a specific unit, and the extent to which it occurs, would
depend on the design margins built into the existing ESP, the
percentage change in coal sulfur content, and other factors. In any
case, industry experience indicates that relatively inexpensive
practices to maintain high ESP performance on lower sulfur bituminous
coals are available and can be used successfully where necessary. These
include a range of upgrades to ESP components and flue gas
conditioning.\78\ EPA therefore assumes that it will not be necessary
for units that switch from higher to lower sulfur bituminous to make a
costly replacement of the ESP.
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\78\ Assessment of Technology Options Available to Achieve
Reductions of Hazardous Air Pollutants, URS Corporation, April 5,
2011, http://www.supportcleanair.com/resources/studies/file/4-8-11-URSTechnologyReport.pdf.
---------------------------------------------------------------------------
Coal switching as a SO2 compliance option might also
include switching from bituminous to subbituminous coal. EPA's analysis
does not assume that a unit designed for bituminous can switch to (very
low sulfur) subbituminous coal unless the unit's historical data
demonstrate that capability in the past. EPA assumes that units with
that demonstrated capability have already made any investments needed
to handle a switch back to the use of subbituminous coal at a similar
percentage of its heat input as in the past. For IPM analysis in the
final rule EPA also introduced a coal switching option that assumes
that units can increase a historically low percentage use of
subbituminous to a ``maximum'' level, if economic. This option includes
an appropriate derate in output, increase in heat rate, and additional
capital and operating costs. Details of this and other IPM updates for
this rule are provided in the IPM Modeling Documentation in the docket
for this rulemaking (``Documentation Supplement for EPA Base Case
v.4.10--FTransport--Updates for Final Transport Rule'').
Some commenters also expressed concern with the assumption that
coal-switching from lignite to subbituminous is a cost-effective or
feasible emission reduction strategy, particularly at Texas EGUs. EPA
carefully considered these comments and adjusted its modeling of cost-
effective reductions to address this concern. Specifically, EPA made
adjustment in the model so that it assumes coal-switching is not a
compliance option at the specific units where commenters identified
technical barriers to subbituminous coal consumption. The Transport
Rule emission budgets are based on this adjusted modeling which does
not assume any infeasible coal-switching from lignite to subbituminous.
In addition, EPA's analysis of cost-effective reductions in each state
presented in section VI.B shows that Texas is capable of cost-
effectively meeting its Transport Rule emission budgets; however, EPA
also conducted sensitivity analysis that shows Texas can also achieve
the required cost-effective emission reductions even while maintaining
current levels of lignite consumption at affected EGUs. More details
regarding this analysis, including a table comparing key parameters
between the main Transport Rule remedy analysis and this Texas lignite
sensitivity, can be found in the response to comments document and the
IPM model output files included in the docket for this rulemaking.
D. Allocation of Emission Allowances
Under the final rule, EPA distributes a number of SO2,
annual NOX, and ozone-season NOX emission
allowances to covered units in each state equal to the SO2,
annual NOX, and ozone-season NOX budgets for
those states. These budgets are addressed in section VI.D of this
preamble. This section discusses the methodology EPA uses to allocate
allowances to covered units in each state.
As discussed later in section VII.D.2, EPA is setting aside a base
2 percent of each state's budgets for allowance allocations for new
units, with 5 percent of that 2 percent, or 0.1 percent of the total
state budget being set aside for new units located in Indian country.
To this base 2 percent, EPA is setting aside an additional percentage
on a state-by-state basis, ranging from 0 to 6 percent (yielding total
set asides of 2 percent to 8 percent), for units planned to be built.
The remainder of the state budget is allocated to existing units.
Tables VI.D.-3 and VI.D.-4 in this preamble show the SO2,
annual NOX, and ozone-season NOX budgets for each
covered state (without the variability limits). In allocating
allowances to existing and new units, EPA distributes four discrete
types of emission allowances for four separate programs: SO2
Group 1 allowances, SO2 Group 2 allowances, annual
NOX allowances, and ozone-season NOX allowances.
In the SO2 Group 1 and SO2 Group 2 programs,
each SO2 allowance authorizes the emission of one ton of
SO2 in that vintage year or earlier and is usable for
compliance only in the program for which the allowance was issued. In
the annual NOX program, each annual NOX allowance
authorizes the emission of one ton of NOX in that vintage
year or earlier in that program. In the ozone-season NOX
program, each ozone-season NOX allowance authorizes the
emission of one ton of NOX during the regulatory ozone
season (May through September for this final rule) in that vintage year
or earlier for that program.
In each of the four trading programs, a covered source is required
to hold sufficient allowances (issued in the respective trading
program) to cover the emissions from all covered units at the source
during the control period. EPA assesses compliance with these
allowance-holding requirements at the source (i.e., facility) level.
This section explains how, in this final rule, EPA allocates a
state's budget to existing units and new units in that state. This
section also describes the new unit set-asides and Indian country new
unit set-asides in each state, allocations to units that are not
operating, and the recordation of allowance allocations in source
compliance accounts.
1. Allocations to Existing Units
This subsection describes the methodology EPA will use in the FIPs
finalized in this action to allocate to
[[Page 48285]]
existing units.\79\ The same methodology will be used to allocate
allowances to existing units for all four trading programs.
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\79\ In this rule, existing units are defined as covered units
that commenced commercial operation prior to January 1, 2010. As
explained in greater detail in Section VII.B. of this preamble, EPA
decided to use this definition to ensure that EPA would have at
least 1 full year of quality-assured data on which to base a unit's
allocation.
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For the reasons explained below, EPA has decided to base
allocations made under the FIPs on historic heat input, subject to a
maximum allocation limit to any individual unit based on that unit's
maximum historic emissions. This methodology gives each existing unit
an allocation equal to its share of the state's historic heat input for
all the covered units in the program, except where that allocation
would exceed its maximum historic emissions; this methodology
constrains the heat input-based allocations from exceeding any unit's
maximum historic emissions. Further detail on the implementation of
this approach is provided in section VII.D.1.c below as well as in the
Allowance Allocation Final Rule TSD in the docket for this rulemaking.
All existing-unit allocations for 2012 will be made pursuant to the
FIPs. However, as described in section X, states may submit SIPs or
abbreviated SIPs to use different allocation methodologies for
allowances of vintage year 2013 and later.
a. Summary of Allocation Methodologies and Comments
EPA took comment on three distinct allocation methodologies for
existing units. The first--an emissions-based option--was presented in
the original Transport Rule proposal (75 FR 45309). The second and
third--heat input option 1 and heat input option 2--were presented in a
Notice of Data Availability (76 FR 1113). EPA received numerous
comments on all three options.
i. Emission-Based Allocation Methodology
The emission-based option presented in the original Transport Rule
proposal would base allowance allocations to existing units on each
covered unit's calculated emission ``share'' of that state's budget for
a given pollutant under the Transport Rule. The proposed rule stated
that ``for 2012, each existing unit in a given state receives
allowances commensurate with the unit's emissions reflected in
whichever total emissions amount is lower for the state, 2009 emissions
or 2012 base case emissions projections. In either case, the allocation
is adjusted downward, if the unit has additional pollution controls
projected to be online by 2012. * * * For states with lower
SO2 budgets in 2014 (SO2 Group 1 states), each
unit's allocation for 2014 and later is determined in proportion to its
share of the 2014 state budget, as projected by IPM'' (75 FR 45309).
Many commenters objected to this projected emission allocation
methodology. Commenters offered two principle objections. First, they
argued EPA should not use unit-level model projections to allocate
allowances. Second, they argued the use of any emission-based allowance
methodology is improper. Many of these commenters argued that instead
of an emission-based allocation methodology, EPA should use a heat-
input-based allocation methodology.
Commenters' objections to the use of unit level model projections
focused primarily on the accuracy of such projections. While many
commenters supported the use of modeling projections in determining
state emission budgets, they argued that the unit-level model
projections were not sufficiently accurate to use as a basis for
allocating allowances to individual units. Among other things, they
argued that the modeling used for the proposal did not recognize
certain non-economic factors that may cause individual units to operate
differently than the model projects. Commenters also argued that EPA's
modeling does not capture all up-to-date contracts and other economic
arrangements made at the unit-level which may affect operational
decision-making. Some of these commenters continued to support the use
of an emission-based allocation approach, but urged EPA to use more up-
to-date and specific unit-level data in its modeling projections.
Others opposed the use of any emission-based allocation approach.
EPA acknowledges that the model may not, at this time, capture all
relevant operational decision factors for each individual unit. EPA
also recognizes that there are unit-level details of operational
decision-making and economic arrangements (such as certain contracts
for electricity sales) that are private and thus unavailable to EPA on
an ongoing basis for modeling purposes. EPA believes these potential
omissions would not have a significant impact on EPA's determination of
significant contribution at the state level; however, EPA recognizes
they could conceivably have a significant impact on projections at the
individual unit level. EPA thus agrees with commenters that the unit-
level emission projections from its modeling may not reflect all
possible operational decisions at a given unit and are therefore not an
appropriate proxy measure to use as a basis for allocating allowances
to individual units.
Many commenters also argued that, even if the emission projections
could be adjusted to capture all known and up-to-date unit-level
operational factors, EPA should not use any emission-based allocation
approach. They argued that an emission-based approach should not be
used because it is not fuel-neutral. That is to say, the type of fuel
consumed significantly affects the emissions from, and therefore the
allocation to, a given unit under an emission-based approach.
Commenters argued that an approach that is not fuel-neutral effectively
awards higher-emitting units. Commenters also argued that a projected
emission-based approach should not be used because it is not control-
neutral. In other words, whether or not a unit has installed controls
would significantly affect the allocation for a given unit under an
emission-based approach. Under an emission-based approach, controlled
units receive significantly fewer allowances than uncontrolled units.
Such an approach, commenters pointed out, effectively penalizes sources
who have taken action to reduce emissions.
EPA acknowledges that an emission-based approach would not be fuel-
neutral or control-neutral. EPA notes that the DC Circuit rejected the
fuel adjustment factors that were used in CAIR to adjust state budgets
based on the type of fuel burned at each covered unit. North Carolina,
531 F.3d 918-21 (rejecting use of fuel adjustments in setting state
NOX budgets). While the proposal's allocation methodology
did not explicitly adopt ``fuel adjustment factors'' for allocation
purposes, EPA recognizes that an emission-based allocation methodology
effectively advantages or disadvantages units based on the type of fuel
they combust.
In addition, several commenters argued that the proposal's
emission-based methodology would inappropriately reward the highest
emitters under the program with more allowances than their lower-
emitting counterparts would receive. EPA acknowledges that such a
methodology would allocate more allowances to units whose emissions
make up a larger share of the proposed Transport Rule programs' state
budgets. EPA notes that because any allocation patterns under the
Transport Rule FIPs would be established in advance of covered sources'
compliance decisions (i.e., decisions regarding how much to emit under
the programs), covered sources
[[Page 48286]]
cannot be ``rewarded'' by adjusting their future emissions. However,
EPA notes commenters' observations that the proposal's methodology
would reduce allocations to units that previously installed pollution
control technology or invested in cleaner forms of generation in
anticipation of CAIR. EPA concluded in review of these comments that
the proposed Transport Rule's allocation methodology unintentionally
yielded this distributional outcome. EPA therefore considered
alternative allocation methodologies described below.
A substantial portion of the commenters who objected to the
proposal's emission-based allocation option urged EPA to consider
historic heat input based approaches. EPA agreed it should accept
comment on the use of historic heat input-based approaches and
published a NODA to provide an opportunity for comment on two specific
heat input options and the allocations that would result from
application of those options to the proposed Transport Rule state
budgets.
ii. Heat Input Allocation Option 1
The first heat input option presented by EPA in the NODA (``Option
1'') allocates allowances to units based solely on their historic heat
input. Under this option, EPA would establish a 5-year historic heat
input baseline for each covered unit and allocate allowances to sources
at levels proportional to the each unit's share of the total historic
heat input at all covered units in that state.
Numerous commenters supported the use of a heat-input based
allocation methodology. These commenters stated that basing allocations
on historic heat input has the following advantages over the proposal's
emission-based allocation methodology:
(A) For certain types of units, historic heat input data may offer
a better representation of unit-level operation than model projections
of unit-level emissions; furthermore, for all units, historic heat
input is typically represented by quality-assured data reported by
sources from continuous emission monitoring systems, which strengthens
its accuracy.
(B) Historic heat input data are generally fuel-neutral in that
they do not generally yield higher allocations for units burning or
projected to burn higher emitting fuels.
(C) Historic heat input data are generally emission-control-neutral
in that they do not generally yield reduced allocations for units that
installed or are projected to install pollution control technology.
Many commenters also argued that a heat input-based allocation
methodology should be used because, unlike the proposal's emission-
based methodology, a heat-input based methodology would be generally
fuel-neutral and control-neutral and would rely on unit-level quality-
assured data instead of on modeling projections.
Several commenters expressed support for specific aspects of heat
input option number one. From a technical standpoint, commenters noted
that heat input option 1 relied on the highest-quality and most
transparent data EPA had provided as a basis for allocating allowances
under the Transport Rule programs. They argued that the calculation
methodology for heat input option 1 is more readily re-created and
understood by sources than either the proposal's methodology or EPA's
application of the ``reasonable upper-bound capacity utilization factor
and a well-controlled emission rate'' in heat input option 2 (described
in greater detail below). They also pointed out that it is similar to
methodologies used in previous trading programs, such as the
NOX Budget Trading Program (see 40 CFR 96.42(a) & (b)
(calculating each existing EGU's allocation by multiplying each unit's
historic heat input by 0.15 lb/mmBtu)). In addition, commenters
supported the reliance of heat input option 1 on continuous emission
monitoring system (CEMS) data that are reported to EPA and certified by
the source's designated representative (DR) as accurate and complete.
In addition, many commenters supported EPA's use of historic data
without further transformation by any calculation factors created by
EPA.
From a policy perspective, commenters highlighted the fuel
neutrality and emission-control neutrality aspects of heat input option
1. They noted that this option does not, in contrast to the proposal's
emission-based methodology, penalize a source, through a reduced
allowance allocation, for having chosen a generation technology or
emission control technology that was more favorable to public health
and the environment. EPA agrees with these observations. The allocation
pattern associated with this option does not advantage or disadvantage
units based on either the fuel consumed or the presence or absence of a
pollution control technology. In this respect, it is a neutral approach
that does not ``reward'' high-emitting units or ``penalize'' low-
emitting units, including, for example, those units on which pollution
control technology was installed in anticipation of CAIR.
EPA agrees with the aforementioned arguments from these commenters
regarding the technical and policy merits of this heat input-based
allocation methodology. EPA believes that the quality-assured heat
input data reported by EGUs under its programs are among the most
detailed and sound unit-level data accessible by EPA. EPA believes the
calculation of any individual unit's share of this historic heat input
data is a straightforward, clear, and simple calculation to perform,
such that EPA's calculated allowance allocations under this approach
can be relatively easily replicated.
EPA also agrees with commenters that such data has previously
supported allowance allocation procedures for highly successful program
implementation of the ARP and the NOX Budget Trading Program
(NBP). Notably, Congress chose a heat input-based allocation approach
when authorizing the ARP in title IV of the Clean Air Act, suggesting
that Congress viewed heat input as a reasonable basis for allocation.
Additionally, EPA's selection of a heat input-based approach for the
NBP was not legally challenged, implying that stakeholders generally
saw a heat input-based approach as reasonable.
EPA also agrees with comments observing that allocations made under
this heat input approach do not advantage or disadvantage units based
on their choice of fuel combustion or pollution control technology, and
that allocations under this approach would thus be ``fuel-neutral'' and
``control-neutral.'' EPA also agrees with commenters that unlike the
proposed rule's emission-based methodology, this heat input methodology
does not yield lower allocation to units that reduced emissions in
advance of the Transport Rule relative to units that did not make such
emission reductions.
Other commenters objected to the use of a heat-input based
allocation methodology. These commenters argued that the allocation
pattern associated with a heat-input allocation methodology would yield
``windfall profits''--in the form of allowance allocations greatly in
excess of likely emissions--for certain units, particularly with regard
to SO2 allowance allocations for units combusting natural
gas. EPA disagrees with the characterization of the excess allowances
as ``windfall profits.'' Allocations based on heat-input alone are
fuel-neutral and control-neutral. The characterization of the heat-
input allocation methodology as creating ``windfall profits'' for any
unit is based on the assumption that all units should
[[Page 48287]]
be allocated allowances based on emissions, not heat input. In arguing
the heat-input approach creates a ``windfall'' for some units,
commenters are assuming that the allocation of allowances above a
unit's projected emissions constitutes a ``windfall''--a conclusion EPA
does not accept. EPA believes that under market-based regulatory
programs, it is appropriate to base initial allowance allocations on a
neutral factor and allow the market to determine the least-cost pattern
of emission reductions in each state to achieve the reductions that
address the state's significant contribution and interference with
maintenance under the final Transport Rule programs. EPA disagrees that
future allowance transactions (following a neutral-factor initial
allocation) in response to these market forces can be characterized as
``windfall profits.'' As explained above, EPA believes it is
appropriate to allocate allowances based on a neutral factor.
Commenters appear to ask EPA, instead of allocating based on a neutral
factor, to consider the unit-level distributional impacts of each
allocation methodology and to select an allocation methodology on the
basis of equity. EPA does not believe it would be appropriate for the
agency to pick an allocation methodology to achieve any particular
distributional outcome as such considerations are not related to the
statutory mandate of CAA section 110(a)(2)(D)(i)(I). Instead, EPA
believes it is appropriate to allocate allowances to sources covered by
its trading programs based on a neutral factor. Furthermore, CAA
section 110(a)(2)(D)(i)(I) requires prohibition of certain emissions
within a state (i.e., a state's significant contribution and
interference with maintenance). It does not direct EPA to use any
particular methodology for allocating allowances under a trading
program designed to ensure all such emissions are prohibited. As such,
EPA believes it is appropriate to allocate allowances based on a
neutral factor representing fossil energy content used to produce
electricity. Detailed considerations of equity, as the DC Circuit
reminded EPA, are not related to the statutory mandate of section
110(a)(2)(D)(i)(I). North Carolina, 531 F.3d 921.
Some commenters objected to the use of a heat input-based approach
by arguing that higher-emitting units would not receive an initial
allocation sufficient to cover their emissions. EPA does not believe it
is reasonable to expect initial allocations to cover each unit's
emissions under a trading program aimed at producing meaningful
emission reductions. In its administration of prior trading programs
such as the ARP and the NBP, EPA has made initial allowance allocations
using a heat input-based approach, and virtually all covered sources
have successfully complied at the end of each compliance period by
making cost-effective emission reductions, purchasing additional
allowances through robust markets to cover emissions, or undertaking
both types of activities. EPA disagrees with commenters' arguments that
allowance allocations should be used to compensate units with higher
emissions.
iii. Heat Input Allocation Methodology Option 2
The second heat input option presented by EPA for public comment
also would use historic heat input but would apply a constraint to
unit-level allocations under certain circumstances. Specifically, under
this option unit-level allocations would not be allowed to exceed what
EPA determines, based on historic emissions and other factors, to be
the units' ``reasonably foreseeable maximum emissions.''
To apply this constraint, EPA first would determine whether the
allocation to a unit under an unconstrained heat-input methodology
would exceed that unit's maximum historic emissions of the relevant
pollutant since 2003 ``in order to reflect unit-level emissions before
and after the promulgation of the CAIR'' (76 FR 1115). Using this
baseline would enhance the neutrality of the maximum historic emissions
data because it would capture the highest emissions of the unit during
that period regardless of what fuels it combusted or what pollution
control devices were installed and used at any particular time during
that period. In other words, a unit's allocation would not be reduced
due to a recent decision to switch fuels or install pollution controls.
Second, for this option, EPA then would adjust that maximum
historic emissions data by applying a ``well-controlled rate maximum,''
designed to place ``a reasonably foreseeable maximum emissions level
reflecting a reasonable upper-bound capacity utilization factor and a
well-controlled emission rate that all units (regardless of the type of
fuel they combust) can meet for the pollutant'' (76 FR 1115). This
option would constrain certain units' allocations that, if based solely
on historic heat input, would be determined by EPA to be ``in excess of
their reasonably foreseeable maximum emissions'' under the Transport
Rule programs (76 FR 1115).
As noted above, commenters offered numerous arguments in favor of
using a historic heat input approach. These arguments apply equally to
heat input option 1 and heat input option 2. EPA also received numerous
comments comparing the two heat input options presented.
Many commenters preferred heat input option 1's reliance purely on
historic data as compared with heat input option 2's reliance on that
data modified by the application of EPA-determined ``reasonable upper
bound capacity factors'' and ``well-controlled emission rates.''
Commenters also criticized the complexity of these modification factors
in heat input option 2. While EPA believes both options represent
viable approaches, the Agency agrees with commenters that the
application of these factors increase the complexity of allocation
determinations and would adjust unit-specific historic data by applying
EPA-created factors generically determined for broad categories of
units.
Some commenters suggested that EPA's application of these
modification factors could also represent legal vulnerabilities for the
Transport Rule. In particular, they were concerned that the capacity
factors and well controlled emission rates presented as part of heat
input option 2 could be perceived as arbitrary. While EPA does not
agree that these modification factors are arbitrary, the Agency does
recognize that application of such EPA-created generic factors in
determining unit-specific allocations increases the complexity of the
allocation approach and raises issues regarding whether such generic
factors are appropriately applied to each individual unit.
iv. General Comments on EPA's Authority To Allocate Allowances
Numerous commenters also noted that EPA has generally broad
authority in selecting an allocation methodology under CAA sections
110(a)(2)(D)(i)(I) and 302(y).\80\ EPA agrees with commenters that the
Agency has broad discretion in this area. Neither the CAA nor the D.C.
Circuit Court's opinion in North Carolina specifies a particular
methodology that EPA must use to allocate allowances to individual
units.
[[Page 48288]]
CAA section 110(a)(2)(D)(i)(I) requires prohibition of emissions
``within the state'' that significantly contribute to nonattainment or
interfere with maintenance and gives states broad discretion to develop
a control program in a SIP that achieves this objective. EPA has
similarly broad discretion when issuing a FIP to realize this
objective. Moreover, while the definition of FIP in CAA section 302(y)
clarifies that a FIP may include ``enforceable emission limitations or
other control measures, means or techniques (including economic
incentives, such as marketable permits or auctions of emissions
allowances),'' this section does not require EPA to use any particular
methodology to allocate allowances under a FIP trading program. In
light of this lack of direction in the CAA concerning allowance
allocation, EPA has broad discretion to select an allocation
methodology that is reasonable and consistent with the goals of CAA
section 110(a)(2)(D)(i)(I).
---------------------------------------------------------------------------
\80\ CAA section 302(y) defines the term ``Federal
implementation plan'' as ``a plan (or portion thereof) promulgated
by the Administrator to fill all or a portion of a gap or otherwise
correct all or a portion of an inadequacy in a State implementation
plan, and which includes enforceable emission limitations or other
control measures, means or techniques (including economic
incentives, such as marketable permits or auctions of emissions
allowances), and provides for attainment of the relevant national
ambient air quality standard.''
---------------------------------------------------------------------------
The body of public comment makes it clear that no allocation option
could be deemed satisfactory from the perspective of all stakeholders.
Public comments from most states and industrial stakeholders with a
substantial interest in how EPA allocates allowances under the
Transport Rule FIPs expressed support for an historical heat input-
based approach as opposed to the proposal's emission-based approach.
Most commenters favored this historical heat input data basis as the
most sound and offered technical data corrections, which EPA considered
and generally used in the final rule. EPA believes it is reasonable to
select a heat input-based approach for the final Transport Rule because
this approach is consistent with the rule's statutory objectives and
has been found, when implemented in prior trading programs, to be a
credible, workable allocation approach.
b. Final FIP Allocation Methodology
After consideration of all comments, EPA decided to allocate
allowances to individual units based on that units' share of the
state's historic heat-input, but to ensure that no unit's allocations
exceed that unit's historic emissions. EPA decided to use the
allocation methodology originally presented as heat input option 2,
modified in response to public comments. EPA decided to use heat input
option 2 but without the application of the ``reasonable upper-bound
capacity utilization factor and a well-controlled emission rate''
factors. This allocation approach reflects the Agency's response to
extensive public comment on the options presented in the proposed
Transport Rule and subsequent NODAs and is a logical outgrowth of those
actions. EPA is using this approach to allocate allowances under the
FIPs for all four trading programs. Further details on the calculation
and implementation of this approach are provided below in section
VII.D.1.c and can also be found in the Allowance Allocation Final Rule
TSD in the docket for this rulemaking.
The principal reasons for this decision are:
EPA believes that existing-unit allowance allocation under
the Transport Rule should not generally advantage or disadvantage units
based on the selection of fuels consumed or of pollution controls
installed at a given unit in anticipation of either the Clean Air
Interstate Rule or the Transport Rule, i.e., fuel or control decisions
taken from 2003 onward. An approach that does not advantage or
disadvantage units in this way avoids allocating in a way that would
effectively penalize units that have already invested in cleaner fuels
or other pollution reduction measures that will continue to deliver
important emission reductions under this rulemaking. The approach
selected in the final rule generally does not penalize such units and
is thus generally fuel-neutral and control-neutral in its allocation
determinations.
EPA finds that the selected approach maximizes
transparency and clarity of allowance allocations. EPA has already made
public the historic heat input and historic emissions data on which
this approach is based, and its application to calculate unit-level
allocations in each state under that state's emission budgets finalized
in this Transport Rule can be relatively easily replicated.
EPA finds that quality-assured historic CEMS-quality data
used to implement this approach represent the most technically superior
data available to EPA at the time of this rulemaking for calculating
unit-level allocations. The selected approach relies on unmodified
historic data reported directly by the vast majority of covered
sources, whose designated representatives have already attested to the
validity and accuracy of this data. EPA agrees with commenters that
allowance allocations should be based on quality-assured data to the
maximum extent possible. This approach uses the most accurate data
currently available to EPA.
Heat-input based approaches were used to allocate
allowances under both the NOX Budget Trading Program and the
Acid Rain Program. Allocation under these programs was readily and
easily administered, and the programs achieved or exceeded their
environmental goals. The selected approach's use of heat input as a
basis for allocations builds on prior legislative and administrative
approaches to allowance allocations for trading programs.
EPA also finds that the selected approach's addition of a
constraint to heat input-based allocations where such allocations would
otherwise exceed a unit's maximum historic emissions is a reasonable
extension of a heat input-based allocation approach. The Transport Rule
trading programs are established to achieve overall emission reductions
in each covered state. As a group, covered sources within each state
must make the necessary reductions under these programs. In light of
each program's goal to reduce each state's overall emissions, it is
logical and consistent with that goal that the starting point for each
source under these programs--i.e., the initial allocations of shares of
the state budget to covered units--be an amount of allowances no
greater than each unit's maximum historic emissions. Under the trading
programs, any source may emit a ton of SO2 or NOX
for which it holds a corresponding allowance, which it may acquire
either by initial allocation or by subsequent purchase, to the extent
consistent with the assurance provisions (discussed elsewhere in this
preamble) that ensure achievement of the requisite overall reductions
in each state. Consequently, the initial allocations to the units at
each source are the starting point for each source's efforts to comply
with the allowance-holding and assurance provision requirements, but do
not determine the source's strategies for compliance and ultimate level
of emissions. EPA believes that a starting point of unit-level heat
input-based allocations constrained not to exceed each specific units'
maximum historic emissions is reasonable and consistent with the
program goals of reducing overall emissions in each state: Each
existing unit is allocated an amount that either reflects reduced unit
emissions or does not exceed historic emissions, and, from that
starting point, the units, as a group, reduce overall emissions to the
level required for each state. Conversely, EPA believes that a starting
point allocating some units more than they have ever emitted would be
illogical in programs aimed at reducing overall emissions.
EPA believes that this selected allocation methodology for the
final Transport Rule FIPs is within its authority under the Clean Air
Act. Section 110(a)(2)(D)(i)(I) of the CAA
[[Page 48289]]
requires that emissions ``within a state'' that significantly
contribute to nonattainment or interfere with maintenance in another
state be prohibited. In the final Transport Rule, EPA analyzed each
individual state's significant contribution and interference with
maintenance and calculated budgets that represent each state's
emissions after the elimination of prohibited emissions in an average
year. The methodology used to allocate allowances in a state budget to
individual units in the state has no impact on that state's budget or
on the requirement that the state's emissions not exceed that budget
plus variability. Regardless of the allocation methodology used, the
state's responsibility for eliminating its significant contribution and
interference with maintenance remains unchanged. This is reflected by
the fact that allocations under each state's budget, regardless of how
they are made, cannot change that state's budget. In sum, the
allocation methodology has no impact on the final rule's ability to
satisfy the statutory mandate of CAA section 110(a)(2)(D)(i)(I) to
eliminate significant contribution to nonattainment and interference
with maintenance.
Consistent with its broad authority in CAA sections
110(a)(2)(D)(i)(II) and 302(y), EPA believes that data quality, fuel-
neutrality, control-neutrality, transparency, clarity, consistency with
program goals, and successful experience in previous trading programs
are reasonable factors on which to base the selection of an allowance
allocation methodology for existing units for the final Transport Rule.
EPA believes that the transparency and clarity of this allocation
approach builds credibility with the public that the government is
distributing a public resource--i.e., allowances--precisely as stated
in this rulemaking, with clear execution that can be relatively easily
verified.
EPA also believes that the final Transport Rule's heat input-based
approach for existing units is consistent with the goals of the Clean
Air Act because it allocates allowances to existing units on the basis
of a neutral factor that does not advantage or disadvantage a unit
based on what fuel the unit burns or whether or not a unit has
installed controls in anticipation of these regulations. In contrast,
allocations under the proposal's emission-based methodology would give
a greater share of allowances to units with higher emission rates,
which are generally responsible for a greater share of a state's total
emissions. Because these higher-emitting rate units are generally
responsible for a greater share of emissions, it follows that they are
also responsible for a greater share of a state's significant
contribution to nonattainment and interference with maintenance. The
proposal's emission-based allocation methodology would disadvantage one
of two otherwise identical existing units if it invested in emission
reductions in anticipation of the Clean Air Interstate Rule or this
final Transport Rule.
The heat-input allocation methodology selected for the final
Transport Rule does not have this flaw. In contrast to the proposal's
emission-based allocation approach, the heat input allocation
methodology selected by EPA yields a smaller proportion of allowances
relative to emissions to higher-emission-rate units and a higher
proportion of allowances relative to emissions to lower-emission-rate
units. For example, assume that in a state with two units and in a
baseline year, Unit A combusts 100 mmBtu of heat input and emits 1,000
tons while Unit B combusts 100 mmBtu of heat input and emits only 500
tons. Assume also that this state's future Transport Rule emissions
budget for this pollutant is only 500 tons. Because Units A and B each
make up an even share of historic heat input for the state, the final
rule's heat input-based approach would allocate the same share of
allowances (250 tons) to each unit. In this example, Unit A's initial
allocation of 250 is a smaller proportion of its historic emissions (25
percent of its baseline 1,000-ton emissions), while Unit B's initial
allocation of 250 is a larger proportion of its historic emissions (50
percent of its baseline 500-ton emissions). Therefore, Unit B's ability
to emit fewer tons per mmBtu of heat content used for generating
electricity (as compared with Unit A) results in Unit B receiving a
larger proportion of its historic emissions as an initial allocation
share than Unit A receives.
This relative distributional pattern yielded is consistent with the
goals of CAA section 110(a)(2)(D)(i)(I) because under this
distribution, higher-emitting units, which are responsible for a
greater share of the state's significant contribution to nonattainment
and interference with maintenance, would require relatively more
allowances in order to cover their pre-existing emissions than would
lower-emitting units. EPA believes this initial allocation pattern is
an appropriate reflection of the goals of CAA section
110(a)(2)(D)(i)(I).
The heat input-based allowance methodology selected by EPA is fuel-
neutral, control-neutral, transparent, based on reliable data, and
similar to the allocation methodologies used in the NOX SIP
Call and Acid Rain Program. For all these reasons, EPA determined that
it is appropriate to use a heat input-based allocation methodology in
this rule.
In addition, this allocation methodology is similar to an output-
based allocation approach, which would base allocations on the quantity
of electricity generated (rather than energy content combusted) and
would also be fuel-neutral, control-neutral, and able to reward
generation units that operate the most efficiently. Many state and
industry commenters advocated using an output-based approach due to its
reported strong value in promoting efficiency. However, at this time
EPA does not have access to unit-level output data that is as quality-
assured or comprehensive as its data sets on heat input across the
units considered. Therefore, EPA is using a heat input-based approach
under the Transport Rule in part due to its ability to serve as a
reasonable proxy for an output-based standard using the most quality-
assured data that EPA has to date.
In the NODA, EPA noted that final state budgets and allocations may
differ from the proposed budgets and allocations because EPA was still
in the process of updating its emission inventories and modeling in
response to public comments, including comments on IPM. Thus, unit-
level allocations in the NODA provided an indication of the
proportional share of a state's budget that would be allocated to
individual existing units if the alternative methodologies were used.
The allocations made final today are based on budgets that reflect the
updated modeling and comments received during the comment period.
c. Calculation of Existing Unit Allocations Under the Final Transport
Rule FIPs
Allocations under this final methodology for each existing unit are
determined by applying the following steps.
1. For each unit in the list of potential existing Transport Rule
units, annual heat input values for the baseline period of 2006 through
2010 are identified using data reported to EPA or, where EPA data is
unavailable, using data reported to the Energy Information
Administration (EIA). For a baseline year for which a unit has no data
on heat input (e.g., for a baseline year before the year when a unit
started operating), the unit is assigned a zero value. (Step 2 explains
how such zero values are treated in the calculations.) The allocation
method uses a 5-year
[[Page 48290]]
baseline to approximate a unit's normal operating conditions over time.
2. For each unit, the three highest, non-zero annual heat input
values within the 5-year baseline are selected and averaged. Selecting
the three highest, non-zero annual heat input values within the five-
year baseline reduces the likelihood that any particular single year's
operations (which might be negatively affected by outages or other
unusual events) would determine a unit's allocation. If a unit does not
have three non-zero heat input values during the 5-year baseline
period, EPA averages only those years for which a unit does have non-
zero heat input values. For example, if a unit has only reported data
for 2008 and 2009 among the baseline years and the reported heat input
values are 2 and 4 mmBtus, respectively, then the unit's average heat
input used to determine its pro-rata share of the state budget is
(2+4)/2 = 3.
3. Each unit is assigned a baseline heat input value calculated as
described in step 2, above, referred to as the ``3-year average heat
input.''
4. The 3-year average heat inputs of all covered existing units in
a state are summed to obtain that state's total ``3-year average heat
input.''
5. Each unit's 3-year average heat input is divided by the state's
total 3-year average heat input to determine that unit's share of the
state's total 3-year average heat input.
6. Each unit's share of the state's total 3-year average heat input
is multiplied by the existing-unit portion of the state budget (i.e.,
the state budget minus the state's new unit set-aside and, if
applicable, minus the Indian country new unit set-aside) to determine
that unit's initial allocation.
7. An 8-year (2003-2010) historic emissions baseline is established
for SO2, NOX, and ozone-season NOX
based on data reported to EPA or, where EPA data is unavailable, based
on EIA data. This approach uses this 8-year historic emissions baseline
in order to capture the unit-level emissions before and after the
promulgation of CAIR.
8. For each unit, the maximum annual historic SO2 and
NOX emissions are identified within the 8-year baseline.
Similarly, the maximum ozone season NOX emissions from the
8-year baseline for each unit are identified. These values are referred
to as the ``maximum historic baseline emissions'' for each unit.
9. If a unit has an initial historic heat-input based allocation
(as determined in step 6) that exceeds its maximum historic baseline
emissions (as determined in step 8), then its allocation equals the
maximum historic baseline emissions for that unit.
10. The difference (if positive) under step 9 between a unit's
historic heat-input-based allocation and its ``maximum historic
baseline emissions'' is reapportioned on the same basis as described in
steps 1 through 6 to units whose historic heat-input-based allocation
does not exceed its maximum historic baseline emissions. Steps 7, 8,
and 9 are repeated with each revised allocation distribution until the
entire existing-unit portion of the state budget is allocated. The
resulting allocation value is rounded to the nearest whole ton using
conventional rounding.
Table VI.D-1 below provides an illustrative application of the
steps 1-10 in a hypothetical state.
Table VI.D-1--Demonstration of Allocations Using Final Allocation Methodology in a Three-Unit State With an 80-
Ton State Budget
----------------------------------------------------------------------------------------------------------------
Steps 1-6 Steps 7, 8, 9 Steps 1-9 Step 10
---------------------------------- reiterated ----------------
-----------------
Initial Maximum Revised
historic heat historic historic heat Final
input-based baseline input-based allocation
allocation emissions allocation
----------------------------------------------------------------------------------------------------------------
Unit A...................................... 20 16 N/A 16
Unit B...................................... 30 50 32 32
Unit C...................................... 30 50 32 32
----------------------------------------------------------------------------------------------------------------
2. Allocations to New Units
EPA is finalizing--similar to the proposal (75 FR 45310)--an
approach to allocate emission allowances to new units from new unit
set-asides in each state. A ``new unit'' may be any of the following:
(1) A covered unit commencing commercial operation on or after January
1, 2010; (2) any unit that becomes a covered unit by meeting
applicability criteria subsequent to January 1, 2010; (3) any unit that
relocates into a different state covered by the Transport Rule; \81\
and (4) any existing covered unit that stopped operating for 2
consecutive years but resumes commercial operation at some point
thereafter.
---------------------------------------------------------------------------
\81\ Existing- or new-unit allocations drawn from the budget of
the relocated unit's original state are replaced by new unit set-
aside allocations from the budget of the unit's relocation state in
order to generally ensure that allocations are drawn from the
correct state budget.
---------------------------------------------------------------------------
The proposed Transport Rule would have required that owners and
operators initially request allowances from the new unit set-aside when
the unit first became eligible for an allocation. EPA now believes that
it can identify which units become eligible and when they become
eligible, based on information provided in other submissions (e.g.,
certificates of representation, monitoring system certifications, and
quarterly emissions reports) that the final rule already requires such
units to make to EPA. EPA concludes that requiring owners and operators
to submit requests of new unit set-aside allocations would impose an
unnecessary burden on the owners and operators, as well as on EPA, and
therefore EPA has removed this requirement in the final rule.
The following sections describe the methodology in the final
Transport Rule for allocating to new units, how EPA determined the size
of new unit set-asides in the final rule, and how EPA has provided for
allocations to new units that locate in Indian Country.
a. New Unit Allocation Methodology
The proposal's new unit allocation methodology did not provide any
allocation for a new unit's first control period of commercial
operation. Some commenters expressed concern about the lack of new unit
allocations the first year of commercial operation. In order to address
this concern, EPA is modifying the new unit allocation methodology in
this final rule to include allocations to new units for the first
control period in which the units are in commercial operation, as well
as for control periods in subsequent years.
[[Page 48291]]
The final rule's allocation to new units is performed in two
``rounds.'' The first round is the same as the new unit allocation
procedures in the proposal (except for elimination of the requirements
that owners and operators request the allocations) and occurs during
the control period for which the allocations are made. These first
round allocations are based on new unit emissions during the prior
control period and are recorded in allowance accounts in the Allowance
Management System for the units by August 1 of each control period. For
example, for the 2012 vintage year, ``first-round'' allocations would
be made to new units by August 1, 2012 based on their emissions in the
2011 control period (as monitored and reported in accordance with Part
75 of the Acid Rain Program regulations). If the new unit set-aside is
insufficient to accommodate first round allocations reflecting all new
units' prior control period emissions, the first round allocations are
made pro rata to new units based on their share of total new unit
emissions in the prior control period.
The second round of allocations accommodates new units that come
online during the control period for which the allocations are made and
did not therefore receive any allocation in the first round. The second
round also accommodates new units that come online partway into the
prior control period and therefore received an allocation in the first
round that did not extend to cover operations in a full control period.
This second round of new unit allocation is therefore applicable only
to new units coming online either during the control period of the
allocation or during the control period immediately prior. New units
coming online earlier than the previous control period only receive
first-round allocations from the new unit set-asides, as first-round
allocations to those units are based on operational data spanning an
entire control period.
Second-round allocations are based on new unit emissions during the
same control period as the vintage year of the allowances allocated.
For example, for the 2012 vintage year, ``second-round'' allocations
are based on the difference between the new unit's emissions in the
2012 control period and the new unit allocation (if any) that the unit
received in the first round of allocations. For a unit coming online in
2012, this amount equals its total emissions during the 2012 control
period. For a unit coming online in 2011, this amount equals its
incremental emissions in 2012 beyond its emissions in 2011, as such a
unit would have already received a first-round allocation from the new
unit set-aside based on its emissions in 2011. Second-round allocations
are recorded in allowance accounts by November 15 for the
NOX ozone season trading program (ahead of the December 1
compliance deadline) and by February 15 of the following calendar year
for NOX and SO2 annual trading programs (ahead of
the March 1 compliance deadline).
This methodology only allocates in the second round whatever
allowances remain in the new unit set-asides after the first-round
allocations have been recorded. If the new unit set-aside available for
second round allocations is insufficient to accommodate allocations
based on the difference between control period emissions and any first
round allocations for the units involved, then the second round
allocations are made pro rate to the new units based on their share of
the total of such differences.
b. Determination of New Unit Set-Asides
The proposed Transport Rule identified new units using a threshold
online date of January 1, 2012, whereas the final Transport Rule uses a
threshold online date of January 1, 2010. As explained above, EPA
adjusted this cutoff date because the final Transport Rule's allocation
methodology for existing units requires that EPA possess at least 1
full year of historic data in order to calculate allocations. As a
consequence, EPA recognizes that the proposal's methodology to
determine the size of the new unit set-asides based only on new EGUs
forecast by the model would fail to account for known EGUs that have
come online, or are planned to come online, after January 1, 2010.
Therefore, EPA has modified its approach to determining the size of the
new unit set-asides in the final rule to account for both ``potential''
units (i.e., those that are not yet planned or under construction but
are projected by modeling to be built) and ''planned'' units (i.e.,
those that are known units with planned online dates after January 1,
2010). EPA uses the distinction between ``potential'' and ``planned''
new units to determine the ultimate size of each state's new unit set-
aside (as a percentage of that state's budgets for each pollutant
covered); however, the new unit allocation methodology described above
applies the same to ``potential'' and ``planned'' new units.
The first step of EPA's analysis to determine the new unit set-
asides accounts for likely future emissions from potential units, and
its methodology is taken directly from the Transport Rule proposal but
reflects updated modeling (see ``Allowance Allocation to Existing and
New Units Under the Transport Rule Federal Implementation Plans'' TSD
for detailed findings). This analysis informed EPA's decision to
establish a minimum new unit set-aside size of 2 percent of each
state's budget for each pollutant that is configured to accommodate
future emissions from potential units.
For the final rule, EPA augmented its new unit set-aside
determination to account for ``planned'' units through an additional
step. Because the location of these ``planned'' units is known and
identified in EPA modeling, this second step is a state-specific
modification of the size of the new unit set-asides. That is, EPA only
increased new unit set-asides above the 2 percent minimum established
in the first step for states that had additional known units coming
online between January 1, 2010, and January 1, 2012.
The increases made to the new unit set-asides for these planned
units reflect the projected emissions from these units. Therefore, if
the expected emissions of a given pollutant from all ``planned'' new
units in a given state were equal to 3 percent of that state's budget
for that pollutant, then EPA added that amount to the base 2 percent
new unit set-aside (creating a hypothetical new unit set-aside of 5
percent for that pollutant in that state). See ``Allowance Allocation
to Existing and New Units Under the Transport Rule Federal
Implementation Plans'' TSD for detailed results showing how EPA
determined the size of each new unit set-aside reflecting the
application of both of the steps described above. This approach to
determining the size of state new unit set-asides is a logical
outgrowth of the proposal, the NODA on allowance allocations, and
updated modeling results. In fact, EPA received comments that using a
January 1, 2010 cutoff date for distinguishing between existing and new
units would result in the new unit set-aside, as proposed, being
insufficient to meet the needs of units already under construction. EPA
believes that the approach adopted in the final rule results in new
unit set-asides that reasonably accommodate the foreseeable emissions
from both planned and potential new units in each state.
The new unit allocation percentages for each state are shown in
Table VII.D.2-1.
[[Page 48292]]
Table VII.D.2-1--Percentage of State Emission Budgets for Allowances in State New Unit Set-Asides
----------------------------------------------------------------------------------------------------------------
Ozone-season
Annual SO2 Annual NOX NOX
----------------------------------------------------------------------------------------------------------------
Alabama......................................................... 2% 2% 2%
Arkansas........................................................ .............. .............. 2%
Florida......................................................... .............. .............. 2%
Georgia......................................................... 2% 2% 2%
Illinois........................................................ 5% 8% 8%
Indiana......................................................... 3% 3% 3%
Iowa............................................................ 2% 2% ..............
Kansas.......................................................... 2% 2% ..............
Kentucky........................................................ 6% 4% 4%
Louisiana....................................................... .............. .............. 3%
Maryland........................................................ 2% 2% 2%
Michigan........................................................ 2% 2% ..............
Minnesota....................................................... 2% 2% ..............
Mississippi..................................................... .............. .............. 2%
Missouri........................................................ 2% 3% ..............
Nebraska........................................................ 4% 7% ..............
New Jersey...................................................... 2% 2% 2%
New York........................................................ 2% 3% 3%
North Carolina.................................................. 8% 6% 6%
Ohio............................................................ 2% 2% 2%
Pennsylvania.................................................... 2% 2% 2%
South Carolina.................................................. 2% 2% 2%
Tennessee....................................................... 2% 2% 2%
Texas........................................................... 5% 3% 3%
Virginia........................................................ 4% 5% 5%
West Virginia................................................... 7% 5% 5%
Wisconsin....................................................... 5% 6% ..............
----------------------------------------------------------------------------------------------------------------
c. Procedures for Allocating New Unit Set-Asides
For the first round of new unit set-aside allocations, the
Administrator will promulgate a notice of data availability informing
the public of the specific new unit allocations and provide an
opportunity for submission of objections on the grounds that the
allocations are not consistent with the requirements of the relevant
final rule provisions. A second notice of data availability will
subsequently be promulgated in order to make any necessary corrections
in the specific new unit allocations. As discussed elsewhere in this
preamble, the final rule establishes a different schedule for
promulgation of these notices of data availability than the proposed
rule. In particular, a single set of deadlines (i.e., for the first
notice in the first round of allocations, June 1 of the year for which
the new unit allocations are described in the notice and, for the
second notice of the first round, August 1 of that year) for
promulgation of the notices is established for all of the Transport
Rule trading programs. EPA believes that these deadlines will provide
sufficient time for EPA to obtain final emissions data for the prior
year for the units involved and to calculate the allocations and
promulgate the notices. Further, the approach of using the same
deadline for all of the Transport Rule trading programs will simplify
EPA's implementation and reduce the complexity of the process for
source owners and operators.
For the second round of new unit set-aside allocations, the
Administrator will also promulgate two notices of data availability.
However, the deadlines for the notices differ for the NOX
ozone season trading program and for the SO2 and
NOX annual trading programs because control period emissions
data (used in making second round allocations) become available sooner,
and the compliance deadline for holding allowances covering emissions
is sooner, in the NOX ozone season trading program. The
control period in the NOX ozone season program ends on
September 30, and fourth quarter emissions reports must be submitted to
EPA by October 30, while the control periods in the SO2 and
NOX annual programs end on December 31 and fourth quarter
emission reports are due by January 30. Further, in order for the
second round allocations to be available to be used for compliance with
the allowance-holding requirement, the second round needs to be
completed before the compliance dates, which are December 1 in the
NOX ozone season program and March 1 in the SO2
and NOX annual programs. Consequently, for the
NOX ozone season program the Administrator will promulgate
by September 15 a notice of data availability identifying the units
eligible for second round allocations and by November 15 a second NODA
of the list of eligible units and their second round allocations, which
will also be recorded in the allowance accounts by that date. The
comparable deadlines for the SO2 and NOX annual
programs are December 15 and February 15. EPA believes that these
deadlines will provide sufficient time for EPA to identify the units
and obtain their needed emissions data and to calculate the allocations
and promulgate the notices.
d. Addition of Allowances to New Unit Set-Asides
As discussed elsewhere in this preamble, EPA proposed that, if a
unit with an existing-unit allocation does not operate for 3
consecutive years, the allowances that would otherwise have been
allocated to that unit, starting in the seventh year after the first
year of non-operation, would be allocated to the new unit set-aside for
the state in which the retired unit is located. EPA is retaining this
provision in the final rule but is changing the time of non-operation
to 2 years and the time of allowance allocation to a non-operating unit
to 4 years. Starting in the fifth year of non-operation, allowances
will be allocated to the new unit set-aside for the state in which the
non-operating unit is located.
EPA received comments that the new unit set-asides were not
sufficient to
[[Page 48293]]
encourage the operation of new units. One commenter suggested that
allowance allocations should cease after 3 years of non-operation
because the financial incentive gained from receiving allowances beyond
the 3-year period is insignificant relative to operating and fuel
costs. Another commenter said that providing allowances to non-
operating units is unnecessary and distorts the market.
In addition to increasing the size of the new unit set-aside in
this final rule, as described above, EPA is terminating existing unit
allocations starting in the fifth year after the unit does not operate
for 2 consecutive years and reallocating to the new unit set-aside the
allowances that the unit otherwise would have received for the fifth
and subsequent years in order to make them available for new units in
the state. This approach allows the new unit set-asides to grow over
time.
e. Allocations to New Units Locating in Indian Country
EPA received several comments on the proposed rule that it did not
explicitly address the distribution of allowances to potential new
units built in Indian country. EPA recognized this concern and
requested comment on this topic in the January 7, 2011 NODA.
In the final rule, EPA is providing a mechanism to make allowances
available in the future for new units built in Indian country. The
final rule establishes an Indian country new unit set-aside for each
pollutant in each state whose borders encompass Indian country (i.e.,
Florida, Iowa, Kansas, Louisiana, Michigan, Minnesota, Mississippi,
Nebraska, New York, North Carolina, South Carolina, Texas, and
Wisconsin). EPA will retain administration of these Indian country new
unit set-asides as part of the Transport Rule trading programs whether
or not a Transport Rule state elects to modify or replace the Transport
Rule FIPs through approved SIP revisions. EPA does not create Indian
country new unit set-asides for states lacking Indian country within
their borders.
EPA determined the size of each Indian country new unit set-aside
by calculating the ratio of square mileage of Indian country to the
square mileage of the state within whose borders Indian country is
located. This calculation yielded a maximum percentage of 5 percent
when assessing all of the states encompassing Indian country subject to
the final Transport Rule; this is referred to as the ``5 percent Indian
country factor'' below. To determine the maximum percentage, EPA used
the American Indian Reservations/Federally Recognized Tribal Entities
dataset, which contains data for the 562 federally recognized tribal
entities in the contiguous U.S. and Alaska. EPA accessed the data to
analyze the Transport Rule region and compare the square miles of
Indian country with the square miles of the Transport Rule state that
includes the Indian country. EPA then took the highest percentage as
the number to be applied across all states with Indian country to
determine the size of the Indian country new unit set-aside pertinent
to that state's budgets under the Transport Rule. EPA chose to use the
maximum percentage (5 percent) from the Indian country analysis to
determine the Indian country set-aside for each state on the basis that
this approach would reserve a reasonable number of allowances from each
state's budget for potential allocation to new units that may locate in
Indian country within that state's borders. Any allowances from the
Indian country new unit set-aside that are not allocated in a given
control period are redistributed into the state's new unit set-aside.
As discussed above, any allowances not allocated from that new unit
set-aside are redistributed to existing units based on the existing
units' share of the total existing unit allocations.
To calculate the size of each tribal new unit set-aside, EPA
applied this 5 percent Indian country factor to the portion of the
state's new unit set-aside originally determined by accounting for
``potential'' new units, which as described above was set at 2 percent
of each pollutant's budget in each state. Therefore, the Indian country
new unit set-aside is 5 percent of 2 percent of a state's budget, or
0.1 percent of that total state budget. EPA did not apply the 5 percent
Indian country factor to the state-specific planned unit portion of
each state's new unit set-aside because the planned unit portion is
determined using projected emissions from specific, known units coming
online after January 1, 2010, and none of these known units are located
in Indian country.
The Indian country new unit set-asides in the following Transport
Rule states with Indian Country are shown in Table VII.D.2-2.
Table VII.D.2-2--New Unit Set-Aside Allowances for Indian Country
[Tons]
----------------------------------------------------------------------------------------------------------------
Ozone-
SO2 Annual Ozone- season
SO2 2012- 2014 Annual NOX season NOX
2013 and NOX 2012- 2014 NOX 2012- 2014
beyond 2013 and 2013 and
beyond beyond
----------------------------------------------------------------------------------------------------------------
Florida............................................. ......... ....... ......... ....... 28 28
Iowa................................................ 107 75 38 38 ......... .......
Kansas.............................................. 42 42 31 26 ......... .......
Louisiana........................................... ......... ....... ......... ....... 13 13
Michigan............................................ 229 144 60 58 ......... .......
Minnesota........................................... 42 42 30 30 ......... .......
Mississippi......................................... ......... ....... ......... ....... 10 10
Nebraska............................................ 65 65 26 26 ......... .......
New York............................................ 27 19 18 18 8 8
North Carolina...................................... 137 58 51 42 22 18
South Carolina...................................... 89 89 32 32 14 14
Texas............................................... 244 244 134 134 63 63
Wisconsin........................................... 80 40 32 30 ......... .......
----------------------------------------------------------------------------------------------------------------
[[Page 48294]]
Under the FIPs, EPA allocates allowances from Indian country new
unit set-asides in essentially the same manner as it allocates
allowances from state new unit set-asides. The approach for
identifying, and determining the number of allowances allocated to, new
units in Indian country is the same as the approach for identifying and
determining allocations for non-Indian country new units covered by the
state new unit set-aside, and allocations are made in two rounds using
the same schedules for promulgation of notices of data availability.
However, as discussed above, unallocated allowances in the Indian
country set-asides are handled differently from unallocated allowances
in the state new unit set-asides in that unallocated Indian country new
unit set-aside allowances are first transferred back into the state new
unit set-aside and then, if still not allocated to new units, are
distributed to existing units in the state. EPA believes that the
above-described approach in establishing and handling the Indian
country new unit set-asides and state new unit set-asides is a
reasonable way of making a sufficient amount of allowances available
for new units in the state and Indian country located in the state and
ensuring that the entire state budget is available to either new or
existing units in the state and Indian country. EPA retains
administration of these Indian country new unit set-asides (and, of
course, the portions of state budgets that comprise these set-asides)
as part of the Transport Rule trading programs even if a state elects
to modify or replace the Transport Rule FIPs through approved SIP
revisions. EPA continues to manage and distribute the Indian country
new unit set-aside allowances in the same manner as under the FIPs.
Unallocated allowances in the Indian country new unit set-aside will be
returned to the portion of the state budget allocated under the
approved SIP's allocation provisions. EPA believes that this approach
is reasonable because EPA, rather than the states, has the authority
and responsibility of administering the Transport Rule with regard to
new units that locate in Indian country.
E. Assurance Provisions
To ensure that the FIPs require the elimination of all emissions
that EPA has identified that significantly contribute to nonattainment
or interfere with maintenance within each individual state, the Agency
is adopting assurance provisions in addition to the requirement that
sources hold allowances sufficient to cover their emissions. These
assurance provisions limit emissions from each state to an amount equal
to that state's trading budget plus the variability limit for that
state (i.e., the state assurance level). As discussed in section VI of
this preamble, this variability limit takes into account the inherent
variability in baseline EGU emissions and recognizes that state
emissions may vary somewhat after all significant contribution to
nonattainment and interference with maintenance are eliminated. This
approach also provides sources with flexibility to manage growth and
electric reliability requirements, thereby ensuring the country's
electric demand will be met, while meeting the statutory requirement of
eliminating significant contribution to nonattainment and interference
with maintenance.
Starting in 2012, EPA is establishing, as part of the FIPs, limits
on the total emissions that may be emitted from EGUs at sources in each
state. For any single year, the state's emissions must not exceed the
state budget with the variability limit allowed for any single year for
that state (i.e., the state's 1-year variability limit). In other
words, in addition to covered sources being required to hold allowances
sufficient to cover their emissions, the total sum of EGU emissions in
a particular state cannot exceed the state budget with the state's 1-
year variability limit in any 1 year (i.e., the state's assurance
level). EPA is not finalizing 3-year variability limits that were
included in the proposal for the reasons explained previously in
section VI.E of this preamble. The state budgets, variability limits,
and state assurance levels for each state are shown in Tables VI.F-1,
VI.F-2 and VI.F-3 in section VI.F of this preamble. The basis for the
variability limits is also described in section VI.E of this preamble.
Additional details may be found in the Power Sector Variability Final
Rule TSD in the docket to this rule.
To implement this requirement, EPA first evaluates whether any
state's total EGU emissions in a control period exceeded the state's
assurance level. If any state's EGU emissions in a control period
exceed the state assurance level, then EPA applies additional criteria
to determine which owners and operators of units in the state will be
subject to an allowance surrender requirement. In applying the
additional criteria, EPA evaluates which groups of units at the common
designated representative (DR) level had emissions exceeding the
respective common DR's share of the state assurance level (regardless
of whether the source had enough allowances to cover its emissions)
during the control period.\82\
---------------------------------------------------------------------------
\82\ A group of one or more sources and units in a state has a
common designated representative where the same individual is
authorized as the designated representative (not the alternate
designated representative) for that group of sources and units as of
April 1 immediately following the allowance transfer deadline for
the control period involved.
---------------------------------------------------------------------------
The requirement that owners and operators surrender allowances
under the assurance provisions will be triggered only if two criteria
are met: (1) The group of sources and units with a common DR are
located in a state where the total state EGU emissions for a control
period exceed the state assurance level; and (2) that group with the
common DR had emissions exceeding the respective DR's share of the
state assurance level. The share of the assurance penalty borne by the
owners and operators will be based on the amount by which the total
emissions for the units in the group exceed the common DR's share of
the state assurance level as a percentage of the total calculated for
all such groups of sources and units in the state. Thus, the owners and
operators of each such group of sources and units must surrender an
amount of allowances equal to the excess of state EGU emissions over
the state assurance level multiplied by the owners' and operators'
percentage and multiplied by two (to reflect the penalty of two
allowances for each ton of the state's excess EGU emissions). See Table
VII.E-1 below for an illustrative example.
This approach in the final rule of implementing the assurance
provisions on a common designated representative basis contrasts with
the approach in the proposed rule of implementing the assurance
provisions on an owner basis. In the January 7, 2011 NODA, EPA
requested comment on the alternative of basing the assurance provision
penalty using common designated representatives, and some commenters
supported this alternative. The common designated representative
approach is simpler and avoids the need to collect information on
percentage ownership (which information is not used in any other
provisions of the Transport Rule trading programs).
In addition, the common designated representative approach provides
additional flexibility to owners and operators who have only one or a
few units in a given state but have the option of selecting a common
designated representative with owners and operators of other units in
the state. EPA expects companies in various states will readily be able
to manage their
[[Page 48295]]
emissions to stay collectively below their state's assurance levels as
they track emissions quarterly throughout the year and manage their
generation units and pollution control efforts accordingly. However, if
the state appears to be approaching its assurance level, this final
rule also gives companies the ability to further ensure that they will
not have excess emissions by combining multiple units under a common
DR. This flexibility allows utilities to re-balance allowances and
emissions to mitigate penalty risk if the state violates its assurance
level. In a state that does not appear to risk violating its assurance
level in a given period, utilities would not need to consider the
assurance aspect of selecting DRs. However, EPA anticipates that in the
event utilities desire additional certainty or mitigation of assurance
penalty risk, they will take advantage of this common DR provision or
pursue similar private arrangements with each other to cover their
emissions at the lowest possible cost.
While the DR provision could benefit utilities by allowing them to
pool their penalty risk, the utilities would still be subject to the
antitrust laws. As with any joint venture between competitors, the
efficiency benefits of pooling risk would be weighed against any
anticompetitive harm associated with DRs.
This new feature in the final rule, in conjunction with the
simplifications to the final rule's variability limits described in
section VI.E, will give companies under the air quality-assured trading
program greater flexibility in each state to determine the most cost-
effective pattern of emission reductions while EPA ensures each state
meets its assurance level needed to address the significant
contribution in each state.
In the January 7, 2011 NODA, EPA also requested comment on
continuing to link allocations to assurance provision allowance
surrender requirements. Even though the final rule uses a different
allowance allocation methodology than the allocation methodology that
was proposed, the final rule continues to treat the groups of units
with greater emissions than their allocations plus share of state
variability as responsible for the state's excess of emissions over the
state assurance level. EPA believes that this approach is reasonable
because any state that exceeds its state assurance level likely does so
because not all units have made the reductions necessary to eliminate
the state's contribution to nonattainment or interference with
maintenance. Moreover, the groups of units with emissions exceeding
their allocations plus share of variability are the units most likely
to have contributed to the state's exceedance of its state assurance
level and thus to the state's triggering of the assurance provisions.
Consequently, EPA concludes that it is reasonable to penalize owners
and operators of those sources and units (grouped by common DR) for the
state's exceedance through application of the assurance provision
allowance surrender requirement. Some commenters stated that this is a
reasonable approach.
While a few commenters suggested alternative approaches to the
assurance provisions, EPA believes that the suggested alternatives are
not workable and are likely to create implementation problems. These
commenters suggested variations of approaches that would have created
state-specific and vintage year-specific allowances that would have
been traded independently of compliance allowances. These
differentiated allowances would have fragmented the allowance markets
and made the programs resemble the intrastate trading option that EPA
rejected because of market power and other concerns described in the
proposal.
The existence of the assurance provisions with significant
penalties imposed if a state's emissions exceed the state budget with
the variability limit, along with other features of the Transport Rule
trading programs discussed below, will ensure that state emissions stay
below the level of the budget with the variability limit. In making
compliance decisions and determining to what extent to rely on
purchased or banked allowances, owners and operators will have to take
into account the risk of triggering the assurance provisions in the
state involved and of incurring significant assurance provision
penalties. The greater the extent to which units sharing a common DR
have emissions exceeding the DR units' allocations plus share of the
state variability limit, the greater the risk of being subject to the
assurance provision penalties.
As discussed previously in section VII.D.2, EPA allocates
allowances to a new unit for the control period during which the unit
commences commercial operation from the new unit set-aside based on its
emissions. In the case where assurance provisions for a state are
triggered in the year that a new unit commences operation, the unit's
share of the state assurance level is calculated using the unit's
allocation from the new unit set-aside plus its proportional share of
the variability limit. There is the possibility that a new unit would
receive no allocation for the control period during which the unit
commences commercial operation. EPA sees no reasonable basis for
disadvantaging owners and operators because they started up a new unit
and EPA had no emissions data on which to base an allocation from the
new unit set-aside or no allowances were available for the unit in the
state's new unit set-aside.\83\ For these new units, EPA would use a
specific surrogate number to calculate the maximum amount of emissions
that the unit would likely have had during that year. The surrogate
emission number applies only if the state's assurance provisions are
triggered and only in the first year of the new unit's commercial
operation for a new unit that did not receive an allocation from the
set-aside. The methodology for calculating the surrogate emission
number is essentially unchanged from the proposal (75 FR 45313). For
more details on capacity factors for new units, see ``Capacity Factors
Analysis for New Units Final Rule TSD.''
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\83\ Some other units (e.g., those units with no data for the
2006-2010 base period) may have a zero allocation for a control
period. However, those are highly likely to be units that will
continue to operate rarely or not at all and so will incur little or
none of the assurance provision penalties.
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These assurance provisions are above and beyond the fundamental
requirement for each source to hold enough allowances to cover its
emissions in the control period. Failure to hold enough allowances to
cover emissions is a violation of the CAA, subject to an automatic
penalty and discretionary civil penalties, as described in section
VII.F of this preamble.
Several features of the air quality-assured trading programs work
in conjunction with the assurance provisions to ensure state emissions
do not exceed state assurance levels. The air quality-assured trading
programs have: State-specific budgets that do not include the
variability limits and that are the basis for allocating allowances in
each state so that total allocations in a state cannot exceed the state
budget; a requirement that owners and operators of each source hold
enough allowances to cover source emissions for each control period;
assurance provisions that require owners and operators to hold a
significant amount of additional allowances in a state if the assurance
provisions are triggered; and additional penalties for failing to hold
sufficient allowances under the assurance provisions. The underlying
mechanism of cap and trade--with a cap on allowances issued and a
requirement to
[[Page 48296]]
hold allowances covering emissions--has succeeded, even without
assurance provisions, in broadly reducing emissions below allowance
allocation levels. The accumulated data, history, and experience from
cap and trade programs underscore that emission reduction requirements
and environmental and public health goals of the programs have been met
and, in many instances, exceeded. Additionally, EPA has now added
assurance provisions to ensure that emissions within a state do not
exceed the state budget with the variability limitation that eliminates
the state's significant contribution to nonattainment and interference
with maintenance in downwind states.
Emissions from a common DR's group of units in excess of the DR's
share of the state budget with the variability limit are not a
violation of the rule or the CAA, but do lead to strict allowance
surrender requirements. Specifically, the owners and operators with a
common DR will be required to surrender two allowances for each ton of
their proportional share of the exceedance of the state budget with the
variability limit. Failing to hold sufficient allowances to meet the
allowance surrender requirement will be a violation of the regulations
and the CAA and subject to discretionary civil penalties under CAA
section 113. Allowances surrendered to meet an assurance provision
penalty may be from the year immediately following the control period
in which the state assurance level was exceeded (i.e., the year during
which the penalty is assessed) or any prior year. Any future vintage
allowances beyond the year in which the penalty is assessed may not be
used to meet an assurance provision penalty.
This penalty level is a change from the proposal, in which one
allowance was to be surrendered for each ton of emissions over the
state assurance level. EPA ran an IPM modeling scenario in order to
assess the level of penalty that would be sufficient to deter sources
from exceeding state assurance levels. According to the model, no state
would exceed its assurance level and incur the two-for-one allowance
penalty in either 2012 or 2014, although some states emit up to the
assurance level. The two-for-one allowance surrender requirement is
significant, and EPA believes that this penalty--along with the other
elements of the Transport Rule discussed above--will be sufficient to
ensure that the state emissions will not exceed the budgets plus the
variability limits. See the Assurance Penalty Level Analysis Final Rule
TSD for further details of the analysis.
Below are examples of how the penalty will be assessed for four
common designated representatives in the same state if the assurance
provisions are triggered. In the first case, DR1's combined units were
allowed to emit up to 71 tons of SO2 (60 * 118 percent), but
actually emitted 75 tons during the control period, or 4 more than
their share of the state assurance level. Since the state, as a whole
exceeded the state assurance level by 15 tons, DR1's share of the
penalty is 25 percent of the total penalty, or 8 allowances (25 percent
of 30).
Figure VII.E-1--Assurance Provision Allowance Surrender Example
--------------------------------------------------------------------------------------------------------------------------------------------------------
Emissions
Allocation + Emissions above Penalty
Allowances share of Total above allocation + Share of state (allowances
allocated variability emissions allocation share of exceedance (%) surrendered)
variability
--------------------------------------------------------------------------------------------------------------------------------------------------------
DR1..................................... 60 71 75 15 4 25% 8
DR2..................................... 20 24 33 13 9 56% 17
DR3..................................... 10 12 15 5 3 19% 6
DR4..................................... 10 12 10 0 -2 0% -
---------------------------------------------------------------------------------------------------------------
Total................................... 100 118 133 33 15 100% 30
--------------------------------------------------------------------------------------------------------------------------------------------------------
DR1, DR2, DR3, and DR4 are all in the same state.
State budget plus 18 percent variability limit is 118 tons (100 + 18 = 118).
State exceeded its assurance level by 15 tons (133-118 = 15).
Penalty is 2 allowances per ton over the assurance level (2 x 15 = 30).
Some numbers may not add up due to rounding.
In the proposal, EPA took comment on whether assurance provisions
should be implemented starting in 2012 or 2014. While a number of
commenters supported the proposal to start in 2014, EPA received
several comments making the case that starting assurance provisions in
2012 would be more compatible with the Court's opinion in North
Carolina, which emphasized EPA's obligation to require elimination of
emissions within the states that significantly contribute to
nonattainment or interfere with maintenance. In this final rule, EPA
makes the assurance provisions effective starting in 2012 because this
approach provides even further assurance, consistent with North
Carolina, that each state's prohibited emissions will be eliminated
from the start of the Transport Rule trading programs.
F. Penalties
Under the final Transport Rule FIPs (like under the proposed rule),
the owners and operators of each covered source must hold, as of the
allowance transfer deadline, an allowance for each ton of
SO2 or NOX emitted by the source and are subject
to penalties if they fail to comply with this allowance-holding
requirement.
In particular, the owners and operators must hold in the source's
compliance account in the Allowance Management System enough allowances
issued for the respective Transport Rule annual trading program
(SO2 Group 1, SO2 Group 2, or annual
NOX program) to cover the annual emissions of the relevant
pollutant from all covered units at the source. The allowances must
have been issued for the year in which the emissions occurred or a
prior year. If the owners and operators fail to meet this allowance-
holding requirement, they must provide--for deduction by the
Administrator from the source's compliance account--one allowance as an
offset, and one allowance as an excess emissions penalty, for each ton
of emissions (i.e., excess emissions) in excess of the amount of
allowances held. The allowances surrendered for the excess emissions
penalty must be allocated for the control period in the year
immediately following the year when the excess emissions occurred or
for a control period in any prior year. The offset and the excess
emissions penalty are automatic requirements in
[[Page 48297]]
that they must be met without any further action by EPA (e.g., any
additional proceedings) regardless of the reason for the occurrence of
the excess emissions. In addition, each ton of excess emissions, as
well as each day in the averaging period (i.e., the control period of
one calendar year), constitute a violation of the CAA, and the maximum
discretionary civil penalty is $25,000 (inflation-adjusted to $37,500
for 2010) per violation under CAA section 113. This means that, if a
source has emissions in excess of allowances held for the source as of
the allowance transfer deadline for a control period, the number of
tons of excess emissions multiplied by the total number of days in that
control period and multiplied by $25,000 (inflation adjusted) equals
the maximum discretionary civil penalty for that occurrence of excess
emissions.
For the ozone-season NOX trading program, the same
provisions apply as for an annual program, except that the averaging
period (i.e., the control period) is the ozone season, not a calendar
year. Consequently, the relevant emissions are for an ozone season, the
allowances usable to meet the allowance-holding requirement are
allowances issued for Transport Rule ozone-season NOX
trading program for the ozone season involved or a prior ozone season,
and the number of days used in calculating the maximum civil penalty is
the number in the ozone season.
Commenters expressed concern that the proposed FIPs expressly
stated that, for purposes of determining the maximum discretionary
civil penalty for failure to meet the allowance-holding requirement,
each ton of emissions lacking a held allowance would be a violation and
each day in the averaging period involved would be a violation. Some
commenters compared the proposed penalty provisions for excess
emissions with the excess emissions penalty provisions under the Acid
Rain Program and claimed that the proposed penalty provisions differed
from the Acid Rain Program provisions and were excessive.
In fact, however, the final FIP provisions concerning discretionary
civil penalties are essentially the same as those under the Acid Rain
Program, as well as those under the NOX Budget Trading
Program and the CAIR trading programs. In particular, the Acid Rain
Program regulations state that each ton of SO2 excess
emissions constitutes ``a separate violation'' of the CAA. 40 CFR
72.9(c)(2). Moreover, while the Acid Rain Program regulations do not
expressly address that each day in the averaging period (i.e., a
calendar year control period under the Acid Rain Program) constitutes a
separate violation when a unit has excess emissions for the calendar
year, the courts have addressed this question. In decisions applying
the discretionary civil penalty provisions in section 309(d) of the
Clean Water Act, which are analogous to the civil penalty provisions in
CAA section 113, the courts have interpreted the provisions to mean
that, when a source violates the emission limitation for a multi-day
control period, the source has a violation for each day in the control
period, as well as for each ton of excess emissions on each such day.
See, e.g., Chesapeake Bay Foun. v. Gwaltney of Smithfield, 791 F.2d
304, 313-15 (4th Cir. 1986), Atlantic States Legal Foun. v. Tyson
Foods, 897 F.2d 1128, 1139-40 (11th Cir. 1990), and U.S. v. Allegheny
Ludlum Corp., 366 F.3d 164, 169 (3d. Cir. 2004). As noted by the
courts, the treatment of each ton and each day as a separate violation
is used for purposes of setting the maximum discretionary civil
penalty. Because CAA section 113 sets the maximum civil penalty, EPA,
of course, has the discretion to tailor the penalty amount that it
seeks in any specific occurrence of excess emissions to reflect the
circumstances of that excess emission occurrence. See 42 U.S.C. 7413(b)
(stating that the Administrator may commence a civil action ``to assess
and recover a civil penalty of not more than $25,000 per day for each
violation''). Moreover, when a district court imposes a civil penalty,
the court ``retains discretion to assess a penalty much smaller than
the maximum, as the situation requires.'' Chesapeake Bay, 791 F.2d at
316. In addition, the Acid Rain Program regulations state that any
allowance deduction, excess emission penalty, or interest under the
Acid Rain Program regulations ``shall not affect liability'' of the
owners and operators ``for any additional fine, penalty, or assessment,
or their obligation to comply with any other remedy, for the same
violation, as ordered under the [CAA],'' including under CAA section
113 providing for discretionary civil penalties. 40 CFR 77.1(b). In
summary, under the Acid Rain Program, each ton of excess emissions and
each day in the averaging period (i.e., the calendar year) constitute a
violation, the resulting number of violations times $2,000 is the
maximum civil penalty for violating owners and operators, and EPA has
the discretion to impose a civil penalty at or below such maximum, in
addition to the automatic requirement to surrender one allowance and
pay $2,000 (inflation adjusted) for each ton of excess emissions.
The final FIPs take an analogous approach to that under the Acid
Rain Program. Specifically, the final FIPs state both that each ton of
excess emissions is a violation of the CAA and that each day in the
averaging period (i.e., a calendar year under the annual programs and
the ozone season under the ozone-season program) is a violation.
Moreover, the imposition of civil penalties at or below the maximum
amount resulting from the maximum penalty calculation is in addition to
the automatic allowance surrender and penalty totaling 2 allowances per
ton of excess emissions. Thus, commenters' assertion that the approach
in the final FIPs is inconsistent with the approach in the Acid Rain
Program is incorrect. Moreover, EPA has taken this same general
approach in two other trading programs (i.e., the NOX Budget
Trading Program and the CAIR trading programs), whose regulations
explicitly state that each ton and each day of the averaging period
constitute a violation. See 40 CFR 96.54(d)(3) (NOX Budget
Trading Program); and 40 CFR 96.106(d) (CAIR).
In any event, EPA maintains that the approach of treating each
excess emission ton and each day in the averaging period as a violation
for purposes of calculating the maximum discretionary civil penalty is
reasonable. Some commenters suggested that only the days on which a
source's cumulative control period emissions exceed the amount of
allowances that the source then holds for that control period should be
treated as a violation. However, this suggested approach makes little
sense in the context of the Transport Rule trading programs.
In order to provide owners and operators compliance flexibility,
the Transport Rule trading programs do not require source owners and
operators to hold any amount of allowances to cover emissions until the
allowance transfer deadline, no matter what the source's cumulative
control period emissions are before that deadline. The commenters'
approach of comparing--each day, cumulative emissions and allowances
held--for purposes of calculating maximum civil penalties would be
inconsistent with the flexibility that EPA intends to provide owners
and operators. For example, under the commenters' suggested approach,
owners and operators that buy or sell allowances in the allowance
market or hold allowances in a company-wide account, do not transfer
allowances into their source's compliance account until just before the
allowance transfer deadline, and end up with some excess emissions for
the calendar year would
[[Page 48298]]
face a significantly higher maximum civil penalty than owners and
operators that every day increase the amount of allowances held in
their source's compliance account as the source's cumulative emissions
increase and end up with the same amount of excess emissions for the
calendar year. In short, the commenters' approach would penalize owners
and operators that use some of the compliance flexibility that the
trading programs are intended to provide.
EPA also maintains that it is reasonable to both impose the
automatic allowance surrender and penalty provisions and to retain the
discretion to impose civil penalties for the same occurrence of excess
emissions. This approach encourages compliance with the allowance-
holding requirement by ensuring that violating owners and operators are
penalized automatically (i.e., without any further administrative or
judicial proceedings, except for appeals) and that EPA can seek
additional penalties where the circumstances warrant discretionary
civil penalties. In fact, the Acid Rain Program, for which CAA Title IV
mandated this approach, has achieved a very high level of compliance
with the requirement to hold allowances covering SO2
emissions and therefore resulted in major reductions in utility
SO2 emissions. See 42 U.S.C.7651j(a). Similarly, the
NOX Budget Trading Program and CAIR trading programs, which
took the same approach, also have achieved very high compliance levels
and major utility emission reductions.
EPA notes that, in calculating maximum civil penalties when owners
and operators fail to hold allowances required under the assurance
provisions in the final FIPs, EPA takes a similar approach in
determining the number of violations. Each ton for which an allowance
is not held as required and each day in the control period involved
constitute a violation of the CAA. As discussed elsewhere in this
preamble, EPA believes that this calculation approach is also
reasonable in the context of the assurance provisions and that taking
an approach like the commenters' suggested approach described above
would be inconsistent with some of the flexibility that the Transport
Rule trading programs are intended to provide.
G. Allowance Management System
The final Transport Rule trading programs, like the proposed
preferred remedy, utilize EPA's allowance management system (AMS),
which currently supports allowance surrender, transfer, and tracking
activity under the Acid Rain Program and CAIR. EPA received no adverse
comment on this aspect of the proposed rule.
The primary role of AMS is to provide an efficient, automated means
for covered sources to comply and for EPA to determine whether covered
sources are complying, with the emissions-related provisions of the
Transport Rule trading programs. As was proposed, each of the final
SO2 trading programs and final NOX trading
programs is separately handled in the AMS, which is used to track
Transport Rule trading program SO2 and NOX
allowances held by covered sources, as well as such allowances held by
other entities or individuals.
In addition, the AMS tracks: The allocation of all SO2
and NOX allowances; holdings of SO2 and
NOX allowances in compliance accounts (i.e., accounts for
individual covered sources), general accounts (i.e., accounts for other
entities such as companies and brokers), and assurance accounts (i.e.,
accounts for allowance surrender by owners and operators of groups of
sources and units with common designated representatives under the
assurance provisions); deduction of SO2 and NOX
allowances for compliance purposes (including deductions from assurance
accounts where necessary); and transfers of allowances between
accounts. The AMS also allows the public to see whether each source is
in compliance and provides information to the allowance market and the
public in general, including information on ownership of allowances,
dates of allowance transfers, buyer and seller information, and the
serial numbers of allowances transferred.
H. Emissions Monitoring and Reporting
Under the proposed rule, units subject to the Transport Rule
trading programs would monitor and report NOX and
SO2 mass emissions in accordance with 40 CFR part 75, as
incorporated in the proposed rule, and with certain other specified
requirements, such as compliance deadlines.
In the final rule, like the proposed rule, covered units must
comply with emissions monitoring and reporting requirements that are
largely incorporated from Part 75 monitoring and reporting
requirements.
Under the final rule and under Part 75, a unit has several options
for monitoring and reporting, namely the use of: a CEMS; an excepted
monitoring methodology (NOX mass monitoring for certain
peaking units and SO2 mass monitoring for certain oil- and
gas-fired units); low mass emissions monitoring for certain non-coal-
fired, low emitting units; or an alternative monitoring system approved
by the Administrator through a petition process. In addition, the
Administrator can approve petitions for alternatives to Transport Rule
and Part 75 monitoring, recordkeeping, and reporting requirements.
Further, the final rule and Part 75 specify that each CEMS must
undergo rigorous initial certification testing and periodic quality
assurance testing thereafter, including the use of relative accuracy
test audits (RATAs) and 24-hour calibrations. In addition, when a
monitoring system is not operating properly, standard substitute data
procedures are applied and result in a conservative estimate of
emissions for the period involved.
In addition, the final rule and Part 75 require electronic
submission, to the Administrator and in a format prescribed by the
Administrator, of a quarterly emissions report. The report must contain
all of the data required concerning NOX annual and ozone-
season and SO2 annual emissions.
Most Transport Rule units are in states subject to CAIR and are
already monitoring and reporting NOX and/or SO2
under CAIR and the Acid Rain Program, which programs also use Part 75
monitoring and reporting. Units under the Transport Rule annual trading
programs and in states subject to CAIR generally have no changes to
their monitoring and reporting requirements. These units must continue
to monitor and submit reports on a year-round basis as they have under
CAIR. Therefore, units in the following states must monitor and report
both SO2 and NOX year-round under the Transport
Rule: Alabama, Georgia, Illinois, Indiana, Iowa, Kansas, Kentucky,
Maryland, Michigan, Minnesota, Missouri, Nebraska, New Jersey, New
York, North Carolina, Ohio, Pennsylvania, South Carolina, Tennessee,
Texas, Virginia, West Virginia and Wisconsin.
Some states (Kansas, Minnesota, and Nebraska) subject to the
Transport Rule annual trading programs were not subject to CAIR.
Transport Rule units in those states must meet monitoring and reporting
requirements that are new except to the extent the units were subject
to Part 75 under some other program (such as the Acid Rain Program).
Further, some states (Florida, Louisiana, and Mississippi) subject
to the Transport Rule ozone-season trading program but not the
Transport Rule annual trading programs were subject to the annual and
ozone-season trading programs under CAIR. Transport Rule
[[Page 48299]]
units in those states must continue to monitor and report in accordance
with Part 75 but have the option of monitoring and reporting on a year-
round or ozone-season-only basis.
In addition, one state (Arkansas) subject to the Transport Rule
ozone-season trading program but not to the Transport Rule annual
trading program was similarly subject to only the ozone-season trading
program in CAIR. Transport Rule units in that state continue to have
the option of monitoring and reporting NOX on a year-round
or ozone-season-only basis.
Finally, some states (Connecticut, Delaware, District of Columbia,
and Massachusetts) that were subject to CAIR are not subject to the
Transport Rule. Electric generating units in those states must continue
to meet monitoring and reporting requirements only to the extent the
units are subject to Part 75 under some other program (such as the Acid
Rain Program or a state adopted program requiring such monitoring and
reporting).
EPA is finalizing requirements for existing Transport Rule units in
states covered by the Transport Rule annual trading programs to monitor
and report SO2 and NOX emissions by January 1,
2012 programs and for existing Transport Rule units in states covered
by the Transport Rule ozone-season trading program to monitor
NOX emissions by May 1, 2012. The use of Part 75 certified
monitoring methodologies is required in both cases. As discussed
previously, most covered existing units will generally have no changes
to their monitoring and reporting requirements and will continue to
monitor and submit reports under Part 75 as they have under CAIR.
Existing units that have not been subject to Part 75 monitoring and
reporting requirements in the past have less than 1 year to install,
certify, and operate the required monitoring systems. EPA believes that
these units will be able to comply with this requirement because the
monitoring equipment needed is not extensive or is largely in place
already for the purpose of meeting other requirements. Quality
assurance and reporting provisions and data system upgrades may be
necessary, but EPA believes that there is sufficient time to accomplish
this by the deadline for existing units in the final rule.
In the proposed rule, the compliance deadline for installing,
certifying, and operating the required monitoring systems at new units
was based upon the date of commencement of commercial operation. A new
unit would have to install and certify its monitoring system within 180
days of the commencement of commercial operation. The final rule adopts
this deadline, which is consistent with the approach recently adopted
in Part 75 under the Acid Rain Program. See 76 FR 17288, 17289 (March
28, 2011).
Using this deadline (rather than a deadline, used previously in
Part 75, of the earlier of the unit's 90th operating day or 180 days
after the unit's commencement of commercial operation) ensures that new
units have sufficient time to complete installation and certification
of monitoring systems and facilitates units' compliance. Because of
unit shakedown problems, some new units have had difficulty meeting a
deadline earlier than 180 days after commencement of commercial
operation. Further, using this deadline facilitates owners' and
operators, and EPA's, ability to track important dates related to
monitoring, reporting, and allowance holding. Under the final rule, the
requirement that a unit hold enough allowances to cover its emissions
starts on the later of the commencement of the Transport Rule trading
program involved or the deadline for installation and certification of
the monitoring system. Having a simple, easily determined deadline (180
days after the commencement of commercial operation) makes it easier
for owners and operators and EPA to determine when allowance-holding
requirements begin, as well as when monitoring and reporting
requirements begin. In contrast, using a deadline involving
determination of a unit's 90th operating day required keeping track of
any days on which the unit did not operate (e.g., due to problems
associated with shakedown of the unit). EPA found that owners and
operators have had more difficulty reporting the 90th operating day
than in reporting the commencement of commercial operation, and once
the latter date is reported, EPA can independently determine the 180th
calendar day after the reported date.
I. Permitting
1. Title V Permitting
The final Transport Rule (like the proposed rule) does not
establish any permitting requirements independent of those under Title
V of the CAA and the regulations implementing Title V, 40 CFR Parts 70
and 71.\84\ All major stationary sources of air pollution and certain
other sources are required to apply for title V operating permits that
include emission limitations and other conditions as necessary to
assure compliance with applicable requirements of the CAA, including
the requirements of the applicable State Implementation Plan. CAA
Sec. Sec. 502(a) and 504(a), 42 U.S.C. 7661a(a) and 7661c(a). The
``applicable requirements,'' that must be addressed in title V permits
are defined in the Title V regulations (40 CFR 70.2 and 71.2
(definition of ``applicable requirement'')).
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\84\ Part 70 addresses requirements for state Title V programs,
and Part 71 governs the federal Title V program.
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EPA anticipates that, given the nature of the units covered by the
final Transport Rule, most of the sources at which they are located are
already or will be subject to Title V permitting requirements. For
sources subject to Title V, the requirements applicable to them under
the final FIPs will be ``applicable requirements'' under Title V and
therefore will need to be addressed in the Title V permits. For
example, requirements under the final FIPs concerning designated
representatives, monitoring, reporting, and recordkeeping, the
requirement to hold allowances covering emissions, the assurance
provisions, and liability will be ``applicable requirements'' to be
addressed in the permits.
The Title V permits program includes, among other things,
provisions for permit applications, permit content, and permit
revisions that will address the applicable requirements under the final
FIPs in a manner that will provide the flexibility necessary to
implement market-based programs such as the Transport Rule trading
programs. For example, the Title V regulations provide that a permit
issued under Title V must include, for any ``approved * * * emissions
trading and other similar programs or processes'' applicable to the
source, a provision stating that no permit revision is required ``for
changes that are provided for in the permit.'' 40 CFR 70.6(a)(8) and
71.6(a)(8). Consistent with this provision in the Title V regulations,
the Transport Rule trading program regulations include a provision
stating that no permit revision is necessary for the allocation,
holding, deduction, or transfer of allowances. Consistent with the
Title V regulations, this provision will also be included in each Title
V permit for a covered source. As a result, allowances can be traded
(or allocated, held, or deducted) under the final FIPs without a
revision of the Title V permit of any of the sources involved.
As a further example of flexibility under Title V, the Title V
regulations allow the use of the minor permit modification procedures
for permit modifications ``involving the use of economic incentives,
marketable permits, emissions trading, and other
[[Page 48300]]
similar approaches, to the extent that such minor permit modification
procedures are explicitly provided for in an applicable implementation
plan or in applicable requirements promulgated by EPA.'' 40 CFR
70.7(e)(2)(i)(B) and 40 CFR 71.7(e)(1)(i)(B). The final FIPs set forth
in detail, and reference relevant provisions in Part 75 concerning, the
approaches that are available for covered units to use for monitoring
and reporting emissions (i.e., approaches using a continuous emission
monitoring system, an excepted monitoring system under appendices D and
E to Part 75, a low mass emissions excepted monitoring methodology
under Sec. 75.19, or an alternative monitoring system under subpart E
of Part 75). The final FIPs also require unit owners and operators to
submit monitoring system certification applications (or, for
alternative monitoring systems, petitions) to EPA establishing the
monitoring and reporting approach actually to be used by the unit and
allow owners and operators to submit petitions for alternatives to any
specific monitoring and reporting requirement. These applications and
petitions are subject to EPA review and approval to ensure consistency
in monitoring and reporting among all trading program participants, and
EPA's responses to any petitions for alternative monitoring systems or
for alternatives to specific monitoring or reporting requirements are
to be posted on EPA's Web site. Moreover, EPA intends that each covered
unit's Title V permit will include a description of the general
approach that the covered unit is required to use for monitoring and
reporting emissions and that the description will reference the
relevant sections of the Transport Rule trading program regulations and
Part 75 and will state that the requirements may be modified through
EPA approval of petitions for alternatives to specific requirements.
Finally, consistent with Sec. Sec. 70.7(e)(2)(i)(B) and
71.7(e)(1)(i)(B) of the Title V regulations, the final FIPs provide
that a description of the general monitoring and reporting approach for
a covered unit can be added to, or an existing description of a unit's
general monitoring and reporting approach can be changed, in a Title V
permit, using minor permit modification procedures, provided that the
approach being described in the changed or new general description and
the requirements applicable to that approach are already incorporated
elsewhere in the permit. As a result, minor permit modification
procedures can be used to revise a covered unit's Title V permit to be
consistent with the monitoring and reporting approach, or any changes
in the approach, allowed for the unit by EPA through the monitoring
system certification or petition process under the Transport Rule
trading programs.
As new applicable requirements under Title V, the requirements for
covered units under the final FIPs will be incorporated into covered
sources' existing Title V permits either pursuant to the provisions for
reopening for cause (40 CFR 70.7(f) and 40 CFR 71.7(f)) or the permit
renewal provisions (40 CFR 70.7(c) and 71.7(c)).\85\ In contrast to the
approach in CAIR of imposing permitting requirements and deadlines
independent of those under Title V, the approach to permitting under
the final FIPS of imposing no independent permitting requirements
should reduce the burden on sources already required to be permitted
under Title V and on permitting authorities. For sources newly subject
to Title V that will also be covered sources under the final FIPs, the
initial Title V permit issued pursuant to 40 CFR 70.7(a) will address
the final FIP requirements.
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\85\ A permit is reopened for cause if any new applicable
requirements (such as those under a FIP) become applicable to a
covered source with a remaining permit term of 3 or more years. If
the remaining permit term is less than 3 years, such new applicable
requirements will be added to the permit during permit renewal. See
40 CFR 70.7(f)(1)(i) and 71.7(f)(1)(i).
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In order to ensure that covered sources' Title V permit provisions
concerning the final FIPs will reflect the Transport Rule trading
program requirements and flexibilities properly and in a manner
consistent from permit to permit, EPA intends to issue guidance to
assist permitting authorities. This guidance would include information
on permit issuance and permit modification requirements, as well as a
permit content template that will identify the applicable requirements
under the applicable Transport Rule trading program and thereby ensure
that they will be correctly and comprehensively reflected in each
permit in a manner that will reduce the burden on sources and
permitting authorities related to the issuance of the permit and will
reduce the need for permit revisions.
2. New Source Review
a. Background
EPA recognizes that, following the vacatur of the new source review
(NSR) pollution control project exemption in New York v. EPA, 413 F.3d
3, 40-41 (D.C. Cir. 2005), pollution control projects, including
pollution control projects constructed to comply with this rule, have
the potential to trigger NSR permitting.
This issue was previously addressed in the context of CAIR. On
December 20, 2005, the EPA agreed to reconsider one specific aspect of
CAIR. In that notice, EPA granted reconsideration and sought comment on
the potential impact of the opinion in New York v. EPA, which vacated
the previously existing NSR exemption for certain environmentally
beneficial pollution control projects. For this reconsideration, EPA
conducted an analysis which showed that the court decision did not
impact the CAIR analyses. Details of this analysis can be found in a
technical support document which is available on EPA's Web site at:
http://epa.gov/cair/pdfs/0053-2263.pdf
Because GHG emissions were not considered by EPA to be air
pollutants within the meaning of the CAA at the time of CAIR, GHG
emissions were not addressed in the 2005 analysis. GHG requirements
related to the component of NSR concerning the Prevention of
Significant Deterioration (``PSD'') program are addressed in EPA's
``Interpretation of Regulations that Determine Pollutants Covered by
Clean Air Act Permitting Programs,'' 75 FR 17004 (April 2, 2010), and
``Prevention of Significant Deterioration and Title V Greenhouse Gas
Tailoring Rule,'' 75 FR (June 3, 2010) (``Tailoring Rule''). Generally,
as discussed in those actions, major stationary sources will be
required to address GHG emissions as part of the PSD program if these
sources emit GHG in amounts that equal or exceed the thresholds in the
Tailoring Rule. Major sources that undergo a modification, including
the addition of pollution control equipment, will trigger PSD
requirements for their emissions of GHG if such emissions increase by
at least 75,000 \86\ tons per year of CO2 equivalent
(CO2e).
---------------------------------------------------------------------------
\86\ We note that, for sources that are modifying and are not
subject to PSD for emissions of a non-GHG pollutant, in order to be
subject to PSD for GHGs the source must not only have an emissions
increase of 75,000 TPY CO2e, but must also have a PTE of
at least 100,000 TPY CO2e and 100 TPY mass GHG. See 40
CFR 52.21(b)(49)(v)(b). However, since it is reasonable to assume
that all sources that are potentially subject to the Transport Rule
will have a PTE of at least 100,000 TPY CO2e and 100 TPY,
for the purposes of discussions in this section we will only note
the requirement to have an emissions increase of 75,000 TPY
CO2e.
---------------------------------------------------------------------------
b. Proposed Rule
In the proposed rule, EPA presented the following conclusions:
(1) The 2005 analysis remains current and relevant for all
pollutants except for GHG, and it shows that NSR requirements would not
significantly impact the construction of controls that
[[Page 48301]]
are installed to comply with the proposed Transport Rule.
(2) It is very unlikely that pollution control projects would cause
GHG increases that would exceed the 75,000 tons per year threshold.
Consistent with these proposed conclusions, EPA also concluded that
there would be no significant impacts from NSR for any pollution
control projects resulting from the proposed rule such as low-
NOX burners, SO2 scrubbers, or SCR. EPA requested
comment on this issue.
c. Public Comments
EPA received a number of comments on the NSR issue, which can be
divided into four types of comments: (1) Comments related to GHGs, (2)
comments related to sulfuric acid mist, (3) comments related to CO
emission increases from low-NOX burners, and (4) suggested
changes to the EPA rules.
Greenhouse Gases. A number of commenters recommended that EPA
should document and substantiate its conclusion that greenhouse gases
would be unlikely to trigger NSR requirements. Other commenters
suggested that some units installing a FGD scrubber could exceed the
75,000 ton threshold for GHGs in the Tailoring Rule by emitting
CO2 produced from the chemical reaction of SO2
with limestone. Commenters also suggested that NSR applicability for
GHGs would also need to consider that an FGD would consume 1-3 percent
of a scrubbed unit's generation, referred to as ``parasitic load,''
which (all else held equal) lowers that unit's net generation.\87\
Commenters argued that any post-retrofit increase in generation to
offset that ``parasitic load'' could lead to GHG increases potentially
exceeding the 75,000 ton threshold.
---------------------------------------------------------------------------
\87\ ``Net generation'' refers to total generation minus the
amount of power consumed on-site for various purposes, including
operation of pollution control equipment.
---------------------------------------------------------------------------
Sulfuric Acid Mist. Two commenters noted that use of high sulfur
fuels, in combination with SCR, can lead to increases in sulfuric acid
mist, a pollutant regulated under NSR. One of these commenters noted
that reagent injection was necessary to avoid triggering NSR for
sulfuric acid mist when their SCR was installed.
Carbon Monoxide (CO). One commenter believed that EPA's 2005
analysis may not be adequate as it related to carbon monoxide emission
increases that result from installation of low-NOX burners.
The commenter noted EPA's statement in the 2005 analysis that read as
follows: ``Since the NOX removal efficiencies used in EPA's
analysis are not aggressive, it is believed that the units installing
combustion controls can opt for moderate levels of overfire air flow
rates and still achieve the NOX reduction levels projected
in EPA's analysis, without causing significant increases in the CO and
unburned carbon emissions.'' The commenter suggested that the transport
rule NOX may be more aggressive than CAIR and thus EPA
should conduct a review to determine whether EPA retains the same
conclusion regarding CO emissions.
Recommended Rule Changes. Some commenters suggested changes to EPA
rules to address their concerns that control equipment installed as a
result of the Transport Rule could trigger NSR. Some commenters
suggested that EPA craft an exclusion from NSR in the Transport Rule.
One of these commenters suggested that EPA could do this by: (1)
Providing special definition of baseline actual emissions; (2) a
causation determination specifically tied to the Transport Rule; or (3)
interpret the term ``stationary source'' in CAA 110(a)(4) in a way that
doesn't impede Transport Rule compliance.
Other commenters expressed the concern that if NSR is triggered,
the proposed Transport Rule did not allow enough time for compliance
for sources needing to install control equipment. These commenters
recommend that EPA should waive Transport Rule requirements or provide
extra allowances until NSR review is complete.
d. Final Rule and Responses to Comments
Greenhouse Gases. EPA has carefully reviewed relevant data in
assessing the comments suggesting that NSR permitting would likely be
triggered for facilities installing FGD scrubbers to comply with this
rule. EPA believes that sources installing FGD to comply with the
Transport Rule can achieve those installations without triggering NSR.
EPA notes that its forecast of the number and extent of FGD
scrubber installations substantially decreased since the time of
proposal. For the proposed rule, EPA modeled 14 GW of FGD retrofit
installations by 2014. For the final rule, EPA models a total of 5.7 GW
of wet FGD installations from 7 units at 5 plants.
There are two factors associated with wet FGD scrubbers that
commenters suggested individually or in combination could lead to
increases above the 75,000 tons per year threshold in the Tailoring
Rule. The first is the CO2 chemically produced from the
reaction of SO2 with limestone in wet FGD scrubbers. The
second is that owners or operators of the affected units may desire to
increase coal usage after the retrofit is made to offset the
``parasitic load'' that is consumed on-site in order to operate the
scrubber.
With respect to chemically produced CO2, EPA concludes
that only in very limited circumstances when installation of a scrubber
is coupled with a change to considerably higher sulfur coal could
installation of a wet limestone scrubber be associated with a more than
75,000 ton increase in CO2 emissions. EPA finds this
possibility unlikely to occur. For example, EPA's acid rain emissions
reporting system shows that the plant with the greatest emissions from
unscrubbed units in 2009 emitted about 103,000 tons of SO2
from those units. If this plant installed a wet limestone scrubber
assumed to reduce those SO2 emissions by 96 percent, EPA
calculates that chemically produced CO2 could increase
emissions by:
103,000 x (0.96) x (44/64) = 67,980 tons CO2.\88\
---------------------------------------------------------------------------
\88\ The factor 44/64 reflects the relative molecular weight of
CO2 and SO2, respectively. A wet FGD's removal
of one ton of SO2 involves a chemical reaction that
releases the equivalent molecular weight of CO2 (thus
equaling 44/64 of a ton of CO2 emissions).
Therefore, EPA finds that all currently uncontrolled units are
technically capable of retrofitting with wet FGD without chemically
produced CO2 increases leading to a triggering of NSR. In
limited circumstances, an owner or operator may elect to switch fuels
to a significantly higher-sulfur coal subsequent to FGD installation
and may risk an increase in chemically produced CO2
emissions that would trigger NSR, but such a decision is not necessary
in order to successfully install and operate the scrubber as a strategy
for compliance with Transport Rule requirements.
With respect to the ``parasitic load'' issue, EPA estimates that
today's wet FGD retrofit technology would consume typically about 1.7
percent of on-site generation.\89\ If a facility made no other changes
to its operation other than installing an FGD retrofit, that facility's
CO2 emissions from fuel combustion would remain constant. It
is possible, however, that a source's owner or operator may elect to
increase coal usage by some amount after retrofitting FGD, if for
example the owner or operator desires to increase net generation after
retrofitting. Under NSR, any such source would be able to
[[Page 48302]]
compare such a CO2 emissions increase against the highest
average annual emissions in any consecutive 24-month period from a 5-
year historic baseline. Therefore, a unit retrofitting a scrubber under
the Transport Rule may be able to increase its CO2 emissions
by more than 75,000 tons without triggering NSR if that increase would
register as less than 75,000 tons against a higher emissions level in
the aforementioned NSR baseline.
---------------------------------------------------------------------------
\89\ Documentation Supplement for EPA Base Case v.4.10--
FTransport--Updates for Final Transport Rule.
---------------------------------------------------------------------------
EPA also notes that scrubber installations provide facilities with
the opportunity to make other capital improvements at the unit on which
the scrubber is installed to improve the efficiency of boilers, steam
turbines, motors, other auxiliary equipment, and plant control systems.
Such improvements could allow a retrofitting unit to lower its
CO2 output rate such that a subsequent decision to increase
net generation may not result in increased coal use, or may limit any
CO2 emission increase to less than the 75,000 tons per year
threshold for triggering NSR.
As discussed in section VII.C, EPA notes that the Transport Rule
does not mandate any specific control activity, including scrubber
retrofitting, as a compliance strategy for units within a state to meet
that state's SO2 budget. As demonstrated by EPA's ``no FGD''
sensitivity analysis described in VII.C, covered sources within the
Group 1 states are capable of meeting their emission reduction
obligations through a variety of emission reduction strategies even if
no unit is able to complete a scrubber installation by 2014. Therefore,
EPA does not believe that NSR permitting presents an obstacle in any
way to Transport Rule compliance, even if a given unit retrofitting
with FGD triggers NSR for CO2.
For some plants, EPA's IPM modeling forecasts installation and
operation of dry sorbent injection (DSI) systems. EPA does not believe
any of these systems would result in CO2 emission increases
above the 75,000 ton threshold. Moreover, given the relatively short
construction schedule for DSI systems, EPA believes that if any of the
plants did require NSR permitting, installation of DSI could still be
accomplished by 2014.
In summary, EPA believes that the operators of plants projected to
install scrubbers for Transport Rule SO2 reductions could
readily develop workable compliance strategies whether or not such an
installation would trigger NSR. Plant owners could readily develop
strategies to avoid emission increases that would trigger NSR,
including but not limited to alternative SO2 reduction
strategies or technologies, efficiency improvements, or the ability to
adjust net electricity generation to prevent a 75,000 ton increase in
CO2 emissions. EPA believes that projected scrubber
installations under the Transport Rule are broadly unlikely to trigger
NSR, but even in the limited conditions where such a triggering may
occur, the NSR permitting process would not infringe on a state's
ability to comply with its budgets under the Transport Rule. (See
section VII.C for more details on EPA's analysis of a ``no FGD''
sensitivity supporting these points.)
Sulfuric Acid Mist. EPA continues to conclude that, consistent with
the 2005 TSD, sulfuric acid mist increases due to compliance with this
rule are very unlikely to trigger NSR permitting. Such increases are
most commonly seen from installation of SCR units on facilities with
relatively high sulfur coal. However, as acknowledged by one of the
commenters, engineering solutions have been developed to prevent such
increases, and EPA believes that facility owners would take this into
account in designing such an SCR system. Moreover, EPA's IPM modeling
of the NOX budgets in the final rule suggests that no new
SCR units will result from the final rule.
Carbon Monoxide. EPA concludes that any NSR permitting required due
to CO increases associated with NOX controls should not
hinder the ability of sources to comply with Transport Rule
requirements. For states that were included in the CAIR for either
ozone, PM2.5, or both, EPA finds no evidence to suggest that
the NOX control requirements of the Transport Rule would
require more aggressive controls triggering NSR. As EPA's baseline
analysis acknowledges, many sources in these states installed
NOX controls to comply with CAIR. In addition, their
historic emissions reflect operation of these controls and there is no
evidence to suggest that the Transport Rule will require sources to
operate these controls more aggressively, thereby increasing CO
emissions above the relevant threshold and triggering NSR. In a few
states that were not covered by CAIR, a limited number of facilities
may install new combustion controls (such as low-NOX
burners, overfire air, or other combustion controls or upgrades) as a
result of the Transport Rule. EPA expects relatively few such
installations, and believes that NSR permitting, if required, is not an
obstacle to compliance with the rule. First, EPA believes that NSR
permitting should be relatively straightforward for these installations
and that the BACT determination for CO will be very straightforward.
EPA expects a relatively short time period for permitting, and as
discussed later, EPA is planning to initiate actions that will further
expedite any required permitting.
Second, EPA notes that the rule achieves reductions through a
trading program rather than direct control requirements. Accordingly,
even if a few installations do not have controls in place at the very
beginning of the compliance period, this should not hinder the ability
of states to meet their ozone-season NOX budgets. Covered
sources have a suite of NOX pollution control strategies and
technologies available to them, including coal selection, selective
non-catalytic reduction, gas re-burn, low-NOX burner and
overfire air installations or upgrades, and neural network optimization
of combustion controls operation. Sources may consider all of these
technologies and strategies, which can be designed and operated so as
to minimize CO emission increases that may otherwise trigger NSR. EPA
also notes that during the downtime for installation of the
construction controls, there would be no NOX emissions, and
thus the source's allowance holding requirements would also be lower
for that period.
Recommended Rule Changes. EPA disagrees with commenters who
suggested rule changes, either to the NSR program or to this rule, to
account for installations triggering NSR. As noted above, EPA concludes
that NSR would be triggered at most for just a few of the projected
control installations. EPA believes, however, that even if required
these NSR permits would likely be issued in a timely manner given the
overall environmental benefits resulting from the control equipment
installation. In addition, this rule's requirements are based on a
flexible trading approach rather than a direct control approach.
Accordingly, if this affect occurs for only a few installations, EPA
believes that any extra emissions that occur during the relatively
short time needed to obtain an NSR permit could be accommodated within
the overall trading system.
Expediting Permitting. In the limited circumstances where pollution
control installations under the Transport Rule may trigger NSR, we also
note that an expedited permitting process can occur with sufficient
time to obtain permits and achieve emission reductions under the
Transport Rule programs. For this reason, we strongly encourage
permitting authorities to expedite
[[Page 48303]]
permitting for any such projects, which are likely to be very limited
in number. To ensure that the permitting decisions are expedited,
separate from this rulemaking EPA will provide assistance and guidance
in order to expedite issuance of any such permits. For example, we are
considering assistance that would serve to expedite BACT reviews or
required air quality analysis. EPA requests early notification of any
specific cases where such guidance and assistance may be needed.
J. How the Program Structure Is Consistent With Judicial Opinions
Interpreting the Clean Air Act
The air quality-assured trading programs established by this rule
eliminate all of the emissions that EPA has identified as significantly
contributing to downwind nonattainment or interference with maintenance
\90\ in a manner that is consistent with section 110(a)(2)(D)(i) of the
CAA as interpreted by the DC Circuit in North Carolina, 531 F.3d 896.
The FIPs finalized in this action require sources to participate in air
quality-assured interstate emission trading programs that include
provisions to ensure that no state's emissions exceed that state's
budget with variability limit. These assurance provisions, combined
with the requirement that all sources hold emission allowances
sufficient to cover their emissions, effectuate the requirement that
emission reductions occur within the state. See 42 U.S.C.
7410(a)(1)(2)(D).
---------------------------------------------------------------------------
\90\ As explained in greater detail in Section VI of this
notice, for each covered state, EPA has identified emissions that
must be prohibited pursuant to section 110(a)(2)(D)(i)(I). In most
instances, EPA has determined that elimination of such emissions is
sufficient to satisfy the requirements of that section. Thus, in
these instances, the budgets represent an estimate of the emissions
that will remain after the elimination of all emissions in that
state that significantly contribute to nonattainment or interfere
with maintenance of the NAAQS in another state. In a few limited
instances, however, EPA determined that elimination of the emissions
is necessary but may not be sufficient to satisfy the requirements
of that section. In these instances, the budgets represent an
estimate of the emissions that will remain after the elimination of
all emissions that EPA, at this time, has determined must be
eliminated.
---------------------------------------------------------------------------
The state budgets developed in this rule represent an estimate of
the emissions that will remain in a given state after the elimination
of all emissions in that state that EPA has determined must be
prohibited pursuant to section 110(a)(2)(D)(i)(I). However, for the
reasons explained above, the amount of emissions that remain after the
requirements of 110(a)(2)(D)(i)(I) are satisfied may vary. EPA
recognizes that shifts in generation due to, among other things,
changing weather patterns, demand growth, or disruptions in electricity
supply from other units can affect the amount of generation needed in a
specific state and thus baseline EGU emissions from that state. Because
a state's significant contribution to nonattainment or interference
with maintenance is defined by EPA as all emissions that can be
eliminated for a specific cost (as explained above, using air quality
considerations to identify this cost threshold), and because EGU
baseline emissions are variable, the amount of emissions remaining in a
state after all significant contribution or interference with
maintenance is eliminated is also variable. In other words, EGU
emissions in a state whose sources have installed all controls and
taken all measures necessary to eliminate its significant contribution
to nonattainment or interference with maintenance could exceed the
state budget without variability.
For this reason, EPA determined that it is appropriate for the
program to recognize the inherent variability in state EGU emissions.
The program does so by identifying a variability range for each state
in the program. The assurance provisions in the program, in turn, limit
a state's emissions to the state's budget with variability limit.
In addition, the requirement that all sources hold emission
allowances sufficient to cover their emissions (and the fact that the
total number of emission allowances allocated will be equal to the sum
of all state budgets without variability) ensures that the use of
variability limits both takes into account the inherent variability of
baseline EGU emissions in individual states (i.e., the variability of
total state EGU emissions before the elimination of significant
contribution or interference with maintenance) and recognizes that this
variability is not as great in a larger region. The variability of
emissions across a larger region is not as large as the variability of
emissions in a single state for several reasons. Increased EGU
emissions in one state in one control period often are offset by
reduced EGU emissions in another state within the control region in the
same control period. In a larger region that includes multiple states,
factors that affect electricity generation, and thus EGU emission
levels, are more likely to vary significantly within the region so that
resulting emission changes in different parts of the region are more
likely to offset each other. For example, a broad region can encompass
states with differing weather patterns, with the result that increased
electricity demand and emissions due to weather in one state may be
offset by decreased demand and emissions due to weather in another
state. By further example, a broad region can encompass states with
differing types of industrial and commercial electricity end-users,
with the result that changes in electricity demand and emissions among
the states due to the effect of economic changes on industrial and
commercial companies may be offsetting. Similarly, because states in a
broad region may vary in their degree of dependence on fossil-fuel-
based electric generation, the impact of an outage of non-fossil-fuel-
based generation (e.g., a nuclear plant) in one state may have a very
different impact in that state than on other states in the region.
Thus, EPA does not believe it is necessary to allow total regional
allowance allocations for the states covered by a given trading program
to exceed the sum of all state budgets without variability for these
states.
For these reasons, the fact that the use of state budgets with
variability limits may allow limited shifting of emissions between
states is not inconsistent with the court's holding that emission
reductions must occur ``within the state.'' North Carolina, 531 F.3d at
907. Under the FIPs, no state may emit more than its budget with
variability limit and total emissions cannot exceed the sum of all
state budgets without variability. This approach takes into account the
inherent variability of the baseline emissions without excusing any
state from eliminating its significant contribution to nonattainment or
interference with maintenance. It is thus consistent with the statutory
mandate of section 110(a)(2)(D)(i)(I) as interpreted by the Court.
Most commenters voiced support for a remedy option that allows some
degree of interstate trading. However, one commenter argued that the
structure of the preferred trading remedy that EPA proposed is legally
problematic. The program, the commenter argues, provides no legal
assurance that the variability margins will be used by market
participants to account for variability. The commenter does not suggest
a solution, but instead says, if a solution cannot be found, EPA should
not allow any amount of interstate trading.
EPA disagrees with the commenter that the structure of the
preferred interstate trading program is legally problematic. In North
Carolina, the Court held that the CAIR interstate trading programs were
inconsistent with section 110(a)(2)(D)(i)(I), concluding that ``EPA's
apportionment decisions have nothing to do with each state's
`significant contribution' '' (531 F.3d at
[[Page 48304]]
907) and that ``EPA is not exercising its section 110(a)(2)(D)(i)(I)
duty unless it is promulgating a rule that achieves something
measurable toward the goal of prohibiting sources `within the State'
from contributing to nonattainment or interfering with maintenance `in
any other State.' '' (531 F.3d at 908). It emphasized that ``[t]he
trading program is unlawful, because it does not connect states'
emission reductions to any measure of their own significant
contributions. To the contrary, it relates their SO2
reductions to their Title IV allowances. * * * The allocation of
NOX caps is similarly arbitrary because EPA distributed
allowances simply in the interest of fairness.'' 531 F.3d at 930. As
explained in this rule, EPA has addressed these concerns by using
source specific analysis to identify each individual state's
significant contribution to nonattainment and interference with
maintenance, and including assurance provisions to ensure that the
necessary reductions occur in each state. The Court did not go further
to prohibit all interstate trading. In fact, it notes that ``after
rebuilding, a somewhat similar CAIR may emerge'' (531 F.3d at 930). For
all of these reasons, EPA does not believe the opinion in North
Carolina can be read to stand for the proposition that no interstate
trading can be allowed unless the specific reasons behind market
participants' decisions to purchase allowances can be ascertained.
Because allowance purchase decisions are likely to be based on multiple
factors, which can include the desire to hedge against potential
emission variability as well as to address actually occurring
variability, requiring ascertainment of the specific reasons for
allowance purchases would be tantamount to prohibiting all interstate
trading.
Moreover, as discussed above, variability is inherent to the
operation of the electric generation system and thus to emissions from
this sector. In fact, variability in emissions occurs every year in
every state and, like variability of year-to-year weather conditions
(which is a major cause of emission variability), cannot be accurately
predicted. See the Power Sector Variability Final Rule TSD in the
docket for this rulemaking. EPA maintains that its approach of allowing
state EGU emissions each year to vary by up to the historically
representative, annual amount of inherent, emission variability
reasonably reflects the realities of the electric generation system and
is consistent with the North Carolina decision. In summary, the
variability limits take into account inherent variability over time of
emissions in each state from this sector while also ensuring that each
state makes necessary emission reductions to eliminate significant
contribution and interference with maintenance. EPA thus concludes that
the commenter's argument that the use of variability limits allows
sources ``within the state'' to avoid eliminating their significant
contribution or interference with maintenance is without merit.
VIII. Economic Impacts of the Transport Rule
A. Emission Reductions
The projected impacts of this final rule as presented throughout
the preamble do not reflect minor technical corrections to
SO2 budgets in three states (KY, MI, and NY) made after the
impact analyses were conducted. These projections also assumed
preliminary variability limits that were smaller than the variability
limits finalized in this rule. EPA conducted sensitivity analysis
confirming that these differences do not meaningfully alter any of the
Agency's findings or conclusions based on the projected cost, benefit,
and air quality impacts presented for the final Transport Rule. The
results of this sensitivity analysis are presented in Appendix F in the
final Transport Rule RIA.
Table VIII.A-1 presents projected power sector emissions in the
base case (i.e., without the Transport Rule or CAIR) compared to
projected emissions with the Transport Rule in 2012 and 2014 for all
covered states. Table VIII.A-2 presents 2005 historical power sector
emissions compared to projected emissions with the Transport Rule in
2012 and 2014. Note that for ozone-season emissions, these tables
present results from a modeling scenario that reflects ozone-season
NOX requirements in 26 states. This modeling differs from
the final Transport Rule because it includes ozone-season
NOX requirements for six states (Iowa, Kansas, Michigan,
Missouri, Oklahoma, and Wisconsin) that the final Transport Rule does
not cover (as discussed previously, EPA is issuing a supplemental
proposal to request comment on inclusion of these six states).
Table VIII.A-1--Projected SO2 and NOX Electric Generating Unit Emission Reductions in Covered States With the
Transport Rule Compared to Base Case Without Transport Rule or CAIR
[Million tons]
----------------------------------------------------------------------------------------------------------------
2012 2014
2012 Base Transport 2012 2014 Base Transport 2014
case rule Emission case rule Emission
emissions emissions reductions emissions emissions reductions
----------------------------------------------------------------------------------------------------------------
SO2............................... 7.0 3.0 4.0 6.2 2.4 3.9
Annual NOX........................ 1.4 1.3 0.1 1.4 1.2 0.2
Ozone-Season NOX.................. 0.7 0.6 0.1 0.7 0.6 0.1
----------------------------------------------------------------------------------------------------------------
Notes: The SO2 and annual NOX emissions in
this table reflect EGUs in the 23 states covered by this rule for
purposes of the 24-hour and/or annual PM2.5 NAAQS
(Alabama, Georgia, Illinois, Indiana, Iowa, Kansas, Kentucky,
Maryland, Michigan, Minnesota, Missouri, Nebraska, New Jersey, New
York, North Carolina, Ohio, Pennsylvania, South Carolina, Tennessee,
Texas, Virginia, West Virginia, and Wisconsin).
The ozone-season NOX emissions reflect EGUs in the 20
states covered by this rule for purposes of the ozone NAAQS
(Alabama, Arkansas, Florida, Georgia, Illinois, Indiana, Kentucky,
Louisiana, Maryland, Mississippi, New Jersey, New York, North
Carolina, Ohio, Pennsylvania, South Carolina, Tennessee, Texas,
Virginia, and West Virginia) and the six states that would be
covered for the ozone NAAQS if EPA finalizes its supplemental
proposal (Iowa, Kansas, Michigan, Missouri, Oklahoma, and
Wisconsin).
Tables VIII.A-3 through VIII.A-5 present projected state-level
emissions with and without the Transport Rule in 2012 and 2014 from
fossil-fuel-fired EGUs greater than 25 MW in covered states.
[[Page 48305]]
Table VIII.A-2--Projected SO2 and NOX Electric Generating Unit Emission Reductions in Covered States With the
Transport Rule Compared to 2005 Actual Emissions
[Million tons]
----------------------------------------------------------------------------------------------------------------
2012 2012 2014 2014
2005 Transport Emission Transport Emission
Actual rule reductions rule reductions
emissions emissions from 2005 emissions from 2005
----------------------------------------------------------------------------------------------------------------
SO2............................................ 8.8 3.0 5.8 2.4 6.4
Annual NOX..................................... 2.6 1.3 1.3 1.2 1.4
Ozone-Season NOX............................... 0.9 0.6 0.3 0.6 0.3
----------------------------------------------------------------------------------------------------------------
Notes: The SO2 and annual NOX emissions in
this table reflect EGUs in the 23 states covered by this rule for
purposes of the 24-hour and/or annual PM2.5 NAAQS
(Alabama, Georgia, Illinois, Indiana, Iowa, Kansas, Kentucky,
Maryland, Michigan, Minnesota, Missouri, Nebraska, New Jersey, New
York, North Carolina, Ohio, Pennsylvania, South Carolina, Tennessee,
Texas, Virginia, West Virginia, and Wisconsin).
The ozone-season NOX emissions reflect EGUs in the 20
states covered by this rule for purposes of the ozone NAAQS
(Alabama, Arkansas, Florida, Georgia, Illinois, Indiana, Kentucky,
Louisiana, Maryland, Mississippi, New Jersey, New York, North
Carolina, Ohio, Pennsylvania, South Carolina, Tennessee, Texas,
Virginia, and West Virginia) and the six states that would be
covered for the ozone NAAQS if EPA finalizes its supplemental
proposal (Iowa, Kansas, Michigan, Missouri, Oklahoma, and
Wisconsin).
[GRAPHIC] [TIFF OMITTED] TR08AU11.001
[[Page 48306]]
[GRAPHIC] [TIFF OMITTED] TR08AU11.002
[[Page 48307]]
[GRAPHIC] [TIFF OMITTED] TR08AU11.003
BILLING CODE 6560-50-C
B. The Impacts on PM2.5 and Ozone of the Final SO2 and NOX Strategy
The air quality modeling platform described in section V was used
by EPA to model the impacts of the final rule SO2 and
NOX emission reductions on annual average PM2.5,
24-hour PM2.5, and 8-hour ozone concentrations. In brief, we
ran the CAMx model for the meteorological conditions in the year of
2005 for the eastern U.S. modeling domain.\91\ Modeling was performed
for the 2014 base case and the 2014 air quality-assured trading (i.e.,
remedy) scenario to assess the expected effects of the final rule on
projected PM2.5 and ozone design value concentrations and
nonattainment and maintenance. The procedures used to project future
design values and nonattainment and maintenance are described in
section V.
---------------------------------------------------------------------------
\91\ As described in the Air Quality Modeling Final Rule TSD,
the eastern U.S. was modeled at a horizontal resolution of 12 x 12
km. The remainder of the U.S. was modeled at a resolution of 36 x 36
km.
---------------------------------------------------------------------------
The projected 2014 concentrations of annual PM2.5, 24-
hour PM2.5, and ozone at each monitoring site in the East
for which projections were made are provided in the Air Quality
Modeling Final Rule TSD. The number of nonattainment and/or maintenance
sites in the East for the 2012 base case, 2014 base case, and 2014
remedy for annual PM2.5, 24-hour PM2.5, and ozone
are provided in Table VIII.B-1.\92\ The average and peak reductions in
annual PM2.5, 24-hour PM2.5, and ozone predicted
at 2012 nonattainment and/or maintenance sites due the emission
reductions between 2012 and the 2014 remedy are provided in Table
VIII.B-2.
---------------------------------------------------------------------------
\92\ To provide a point of reference, Table VIII.B-1 also
includes the number of nonattainment and/maintenance sites based on
ambient design values for the period 2003 through 2007.
[[Page 48308]]
Table VIII.B-1--Projected Reduction in Nonattainment and/or Maintenance Problems for PM2.5 and Ozone in the Eastern U.S.
--------------------------------------------------------------------------------------------------------------------------------------------------------
Percent
reduction:
Ambient (2003- 2012 base case Percent reduction: 2014 base
2007) 2012 Base case 2014 Base case 2014 remedy vs. 2014 case vs. 2014 remedy
remedy
(percent)
--------------------------------------------------------------------------------------------------------------------------------------------------------
Annual PM2.5 Nonattainment Sites \93\.... 103 12 7 0 100 100 percent.
Annual PM2.5 Maintenance-Only Sites...... 22 4 3 0 100 100 percent.
24-hour PM2.5 Nonattainment Sites........ 151 20 10 1 95 90 percent.
24-hour PM2.5 Maintenance-Only Sites..... 48 21 12 4 81 67 percent.
Ozone Nonattainment Sites................ 104 7 4 4 43 No Change.
Ozone Maintenance-Only Sites............. 65 9 6 6 33 No Change.
--------------------------------------------------------------------------------------------------------------------------------------------------------
Table VIII.B-2--Average and Peak Reduction in Annual PM2.5, 24-Hour PM2.5, and Ozone for Sites That Are
Projected to Have Nonattainment and/or Maintenance Problems in the 2012 Base Case
----------------------------------------------------------------------------------------------------------------
Average reduction: 2012 base Case Peak reduction: 2012 base case to
to 2014 remedy 2014 remedy
----------------------------------------------------------------------------------------------------------------
Annual PM2.5 Nonattainment Sites....... 2.73 [mu]g/m\3\.................... 3.32 [mu]g/m\3\.
Annual PM2.5 Maintenance-Only Sites.... 2.99 [mu]g/m\3\.................... 3.26 [mu]g/m\3\.
24-hour PM2.5 Nonattainment Sites...... 6.8 [mu]g/m\3\..................... 11.7 [mu]g/m\3\.
24-hour PM2.5 Maintenance-Only Sites... 6.5 [mu]g/m\3\..................... 11.0 [mu]g/m\3\.
Ozone Nonattainment Sites.............. 1.9 ppb............................ 2.3 ppb.
Ozone Maintenance-Only Sites........... 1.8 ppb............................ 2.1 ppb.
----------------------------------------------------------------------------------------------------------------
The information in Table VIII.B-1 shows that there will be
significant reductions in the extent of nonattainment and maintenance
problems for annual PM2.5, 24-hour PM2.5, and
ozone between 2012 and 2014 as a result of the emission budgets in this
rule coupled with emission reductions during this time period from
other existing control programs. Specifically, the results of the air
quality modeling indicate that no sites are projected to be in
nonattainment or projected to have a maintenance problem for annual
PM2.5 in 2014 with the emission reductions expected from the
Transport Rule. As indicated in Table VIII.B-2, the average reduction
in annual PM2.5 across the twelve 2012 nonattainment sites
is 2.73 [mu]g/m\3\ and the peak reduction at an individual
nonattainment site is 3.32 [mu]g/m\3\. Large reductions are also
projected at annual PM2.5 maintenance-only sites.
---------------------------------------------------------------------------
\93\ ``Nonattainment'' is used to denote sites that are
projected to have both nonattainment and maintenance problems.
---------------------------------------------------------------------------
For 24-hour PM2.5, we project that the number of
nonattainment sites will be reduced by 95 percent and the number of
maintenance-only sites by 81 percent in 2014 compared to the 2012 base
case. The average reduction in 24-hour PM2.5 across the
twenty 2012 nonattainment sites is 6.8 [micro]g/m\3\ and the peak
reduction at an individual nonattainment site is 11.7 [micro]g/m\3\.
Similarly large reductions are projected at 24-hour PM2.5
maintenance-only sites, as indicated in Table VIII.B-2.
The emission reductions in the Transport Rule will result in
considerable progress toward attainment and maintenance at the 5 sites
that remain as nonattainment and/or maintenance for the 24-hour
PM2.5 standard. On average for these 5 sites, the predicted
amount of PM2.5 reduction in 2014 is 64 percent of what is
needed for these sites to attain and/or maintain the 24-hour standard.
Thus, the SO2 and NOX emission reductions
which will result from the Transport Rule will greatly reduce the
extent of PM2.5 nonattainment and maintenance problems by
2014 and beyond. As described previously, these emission reductions are
expected to substantially reduce the number of PM2.5
nonattainment and/or maintenance sites in the East and make attainment
easier for those counties that remain nonattainment by substantially
lowering PM2.5 concentrations in residual nonattainment
sites. The emission reductions will also help those locations that may
have maintenance problems.
Based on the 2012 base air quality modeling for ozone, 16 sites in
the East are projected to be nonattainment or have problems maintaining
the 1997 ozone standard. The summer NOX reductions are
projected to lower 8-hour ozone concentration by 1.8 ppb, on average by
2014, at monitoring sites projected to be nonattainment and/or have
maintenance problems in the 2012 base case. We expect that the number
of nonattainment sites will be reduced by 43 percent and the number of
maintenance-only sites by 33 percent in 2014 compared to the 2012 base
case. Thus, our modeling indicates that by 2014 the summer
NOX emission reductions in this rule, coupled with other
existing control programs, will lower ozone concentrations in the East
and help bring areas closer to attainment for the 8-hour ozone NAAQS.
As discussed in section III of this preamble, EPA plans to finalize its
reconsideration of the 2008 revised ozone NAAQS soon, and these
reductions will help areas achieve those revised NAAQS.
C. Benefits
1. Human Health Benefit Analysis
To estimate the human health benefits of the final Transport Rule,
EPA used the BenMAP model to quantify the changes in PM2.5
and ozone-related health impacts and monetized benefits based on
changes in air quality. For context, it is important to note that the
magnitude of the PM2.5 benefits is largely driven by the
concentration response function for premature mortality. Experts have
advised EPA to consider a variety of assumptions, including estimates
based both on empirical (epidemiological) studies and judgments
elicited from scientific experts, to characterize the uncertainty in
the relationship between PM2.5
[[Page 48309]]
concentrations and premature mortality. For this rule we cite two key
empirical studies, one based on the American Cancer Society cohort
study \94\ and the other based on the extended Six Cities cohort
study.\95\
---------------------------------------------------------------------------
\94\ Pope et al., 2002. ``Lung Cancer, Cardiopulmonary
Mortality, and Long-term Exposure to Fine Particulate Air
Pollution.'' Journal of the American Medical Association. 287:1132-
1141.
\95\ Laden et al., 2006. ``Reduction in Fine Particulate Air
Pollution and Mortality.'' American Journal of Respiratory and
Critical Care Medicine. 173:667-672.
---------------------------------------------------------------------------
The estimated benefits of this rule are substantial, particularly
when viewed within the context of the total public health burden of
PM2.5 and ozone air pollution. A recent EPA analysis
estimated that 2005 levels of PM2.5 and ozone were
responsible for between 130,000 and 320,000 PM2.5-related
and 4,700 ozone-related premature deaths, or about 6.1 percent of total
deaths from all causes in the continental U.S. (using the lower end of
the range for premature deaths).\96\ In other words, 1 in 20 deaths in
the U.S. is attributable to PM2.5 and ozone exposure. This
same analysis attributed almost 200,000 non-fatal heart attacks, 90,000
hospital admissions due to respiratory or cardiovascular illness, 2.5
million cases of aggravated asthma among children, and many other human
health impacts to exposure to these two air pollutants.
---------------------------------------------------------------------------
\96\ Fann N, Lamson A, Wesson K, Risley D, Anenberg SC, Hubbell
BJ. Estimating the National Public Health Burden Associated with
Exposure to Ambient PM2.5 and Ozone. Risk Analysis; 2011
In Press.
---------------------------------------------------------------------------
We estimate that PM2.5 improvements under the Transport
Rule will, starting in 2014, annually reduce between 13,000 and 34,000
PM2.5-related premature deaths, 15,000 non-fatal heart
attacks, 8,700 incidences of chronic bronchitis, 8,500 hospital
admissions, and 400,000 cases of aggravated asthma while also reducing
10 million days of restricted activity due to respiratory illness and
approximately 1.7 million work-loss days. We also estimate substantial
health improvements for children from fewer cases of upper and lower
respiratory illness and acute bronchitis.
Ozone health-related benefits are expected to occur during the
summer ozone season (usually ranging from May to September in the
eastern U.S.). Based upon modeling for 2014, annual ozone related
health benefits are expected to include between 27 and 120 fewer
premature mortalities, 240 fewer hospital admissions for respiratory
illnesses, 86 fewer emergency room admissions for asthma, 160,000 fewer
days with restricted activity levels, and 51,000 fewer days where
children are absent from school due to illnesses.
Table VIII.C-1 presents the primary estimates of annual reduced
incidence of PM2.5 and ozone-related health effects for the
final rule based on 2014 air quality improvements. When adding the PM
and ozone-related mortalities together, we find that the Transport Rule
will yield between 13,000 and 34,000 fewer premature mortalities
annually. By 2014, in combination with other federal and state air
quality actions, the Transport Rule will address a substantial fraction
of the total public health burden of PM2.5 and ozone air
pollution.
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[[Page 48310]]
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[[Page 48311]]
[GRAPHIC] [TIFF OMITTED] TR08AU11.005
2. Quantified and Monetized Visibility Benefits
Only a subset of the expected visibility benefits--those for Class
I areas--are included in the monetary benefit estimates we project for
this rule. We anticipate improvement in visibility in residential areas
where people live, work, and recreate within the Transport Rule region
for which we are currently unable to monetize benefits. For the Class I
areas we estimate annual benefits of $4.1 billion beginning in 2014 for
visibility improvements. The value of visibility benefits in areas
where we are unable to monetize benefits could be substantial.
3. Benefits of Reducing GHG Emissions
When fully implemented in 2014, the Transport Rule will reduce
emissions of CO2 from electrical generating units by about
25 million metric tons annually. Using a ``social cost of carbon''
(SCC) estimate that accounts for the marginal dollar value (i.e., cost)
of climate-related damages resulting from CO2 emissions,
previous analyses, including the RIA for the Final Rulemaking to
Establish Light-Duty Vehicle Greenhouse Gas Emissions Standards and
Corporate Average Fuel Efficiency Standards, have found the total
benefit of CO2 reductions is substantial. The monetary value
of these avoided damages also grows over time. Readers interested in
learning more about the calculation of the SCC metric should refer to
the SCC TSD, Social Cost of Carbon for Regulatory Impact Analysis Under
Executive Order 12866 [Docket No. EPA-HQ-OAR-2009-0472].
4. Total Monetized Benefits
Table VIII.C-2 presents the estimated annual monetary value of
reductions in the incidence of health and welfare effects. These
estimates account for increases in the value of risk reduction over
time. Total monetized benefits are driven primarily by the reduction in
premature fatalities each year, which account for between 89 and 96
percent of total benefits.
[[Page 48312]]
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[[Page 48313]]
[GRAPHIC] [TIFF OMITTED] TR08AU11.007
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5. How do the benefits in 2012 compare to 2014?
The magnitude of SO2 emission reductions achieved under
the rule is actually larger in 2012 than in 2014, due to substantial
emission reductions expected to occur in the baseline (i.e., unrelated
to the Transport Rule) between those years. As a consequence, EPA
expects correspondingly greater reductions in harmful effects to accrue
in 2012 compared to 2014.
As presented in Table VIII.C-1, the Transport Rule is expected to
prevent between 13,000 and 34,000 premature deaths annually from 2014
onward due to reductions in ambient PM2.5 concentrations,
which are most significantly impacted by SO2 emission
reductions. Based on EPA's analysis of power sector emission reductions
under the Transport Rule, the decline in SO2 in 2012 is 4
percent greater than the decline in SO2 in 2014 in the
states modeled. EPA therefore anticipates that the Transport Rule will
deliver greater reductions in ambient PM2.5 concentrations
in 2012 and increased annual benefits to human health and welfare
beyond those presented in this section.
6. How do the benefits compare to the costs of this final rule?
The estimated annual private costs to implement the emission
reduction requirements of the final rule for the Transport Rule states
are $1.85 billion in 2012 and $0.83 billion in 2014 (2007 $). These
costs are the annual incremental electric generation production costs
that are expected to occur with the Transport Rule. The EPA uses these
costs as compliance cost estimates in developing cost-effectiveness
estimates.
In estimating the net benefits of regulation, the appropriate cost
measure is ``social costs.'' Social costs represent the welfare costs
of the rule to society. These costs do not consider transfer payments
(such as taxes) that are simply redistributions of wealth. The social
costs of this rule are estimated to be approximately $0.81 billion in
2014 assuming either a 3 percent discount rate or a 7 percent discount
rate. Thus, the annual net benefit (social benefits minus social costs)
as shown in Table VIII.C-3 for the Transport Rule is approximately $120
to $280 billion or
[[Page 48314]]
$110 to $250 billion (3 percent and 7 percent discount rates,
respectively) in 2014. Implementation of the rule is expected to
provide society with a substantial net gain in social welfare based on
economic efficiency criteria.
A listing of the benefit categories that could not be quantified or
monetized in our benefit estimates is provided in Table VIII.C-4.
Table VIII.C-3--Summary of Annual Benefits, Costs, and Net Benefits of the Final Transport Rule in 2014
[Billions of 2007$] \a\
----------------------------------------------------------------------------------------------------------------
Transport Rule remedy (billions of 2007 $)
Description -------------------------------------------------------------------------
3% discount rate 7% discount rate
----------------------------------------------------------------------------------------------------------------
Social costs.......................... $0.81.............................. $0.81.
Total monetized benefits \b\.......... $120 to $280....................... $110 to $250.
Net benefits (benefits-costs)......... $120 to $280....................... $110 to $250.
----------------------------------------------------------------------------------------------------------------
\a\ All estimates are for 2014, and are rounded to two significant figures.
\b\ The total monetized benefits reflect the human health benefits associated with reducing exposure to PM2.5
and ozone and the welfare benefits associated with improved visibility in Class I areas. The reduction in
premature mortalities account for over 90 percent of total monetized PM2.5 and ozone benefits.
The annualized regional cost of the rule, as quantified here, is
EPA's best assessment of the cost of implementing the Transport Rule.
These costs are generated from rigorous economic modeling of changes in
the power sector expected from the rule. This type of analysis, using
IPM, has undergone peer review and been upheld in federal courts. The
direct cost includes, but is not limited to, capital investments in
pollution controls, operating expenses of the pollution controls,
investments in new generating sources, and additional fuel
expenditures. The EPA believes that these costs reflect, as closely as
possible, the additional costs of the Transport Rule to industry. The
relatively small cost associated with monitoring emissions, reporting,
and recordkeeping for affected sources is not included in these
annualized cost estimates, but EPA has done a separate analysis and
estimated the cost to be about $26 million (see section XII.B,
Paperwork Reduction Act). However, there may exist certain costs that
EPA has not quantified in these estimates. These costs may include
costs of transitioning to this rule, such as the costs associated with
the retirement of smaller or less efficient EGUs, employment shifts as
workers are retrained at the same company or re-employed elsewhere in
the economy, and certain relatively small permitting costs associated
with Title V that new program entrants face.
An optimization model was employed that assumes cost minimization.
Costs may be understated if the regulated community chooses not to
minimize its compliance costs in the same manner to comply with the
rules. Although EPA has not quantified these costs, the Agency believes
that they are small compared with the quantified costs of the program
to the power sector. However, EPA's experience and results of
independent evaluation suggests that costs are likely to be lower by
some degree (see RIA for details). The annualized cost estimates
presented are the best and most accurate based upon available
information. In a separate analysis, EPA estimates the indirect costs
and impacts of higher electricity prices on the entire economy. These
impacts are summarized in the RIA for this final rule.
Every benefit-cost analysis examining the potential effects of a
change in environmental protection requirements is limited to some
extent by data gaps, model capabilities (such as geographic coverage),
and uncertainties in the underlying scientific and economic studies
used to configure the benefit and cost models. Gaps in the scientific
literature often result in the inability to estimate quantitative
changes in health and environmental effects, or to assign economic
values even to those health and environmental outcomes that can be
quantified. While uncertainties in the underlying scientific and
economics literatures (that may result in overestimation or
underestimation of benefits) are discussed in detail in the economic
analyses and its supporting documents and references, the key
uncertainties which have a bearing on the results of the benefit-cost
analysis of this rule include the following:
EPA's inability to quantify potentially significant
benefit categories;
Uncertainties in population growth and baseline incidence
rates;
Uncertainties in projection of emission inventories and
air quality into the future;
Uncertainty in the estimated relationships of health and
welfare effects to changes in pollutant concentrations, including the
shape of the C-R function, the size of the effect estimates, and the
relative toxicity of the many components of the PM mixture;
Uncertainties in exposure estimation; and
Uncertainties associated with the effect of potential
future actions to limit emissions.
Despite these uncertainties, we believe the benefit-cost analysis
provides a reasonable indication of the expected economic benefits of
the rulemaking in future years under a set of reasonable assumptions.
This approach calculates a mean value across value of a statistical
life (VSL) estimates derived from 26 labor market and contingent
valuation studies published between 1974 and 1991. The mean VSL across
these studies is $6.3 million (2000$).\97\ The benefits estimates
generated for this rule are subject to a number of assumptions and
uncertainties, which are discussed throughout the RIA document.
---------------------------------------------------------------------------
\97\ In this analysis, we adjust the VSL to account for a
different currency year (2007$) and to account for income growth to
2014. After applying these adjustments to the $6.3 million value,
the VSL is $8.7 million.
---------------------------------------------------------------------------
As Table VIII.C-2 indicates, total annual monetary benefits are
driven primarily by the reduction in premature mortalities each year.
Some key assumptions underlying the primary estimate for the premature
mortality category include the following:
(1) EPA assumes inhalation of fine particles is causally associated
with premature death at concentrations near those experienced by most
Americans on a 24-hour basis. Plausible biological mechanisms for this
effect have been hypothesized for the endpoints included in the primary
analysis, and the weight of the available epidemiological evidence
supports an assumption of causality.
[[Page 48315]]
(2) EPA assumes all fine particles, regardless of their chemical
composition, are equally potent in causing premature mortality. This is
an important assumption, because the proportion of certain components
in the PM mixture produced via precursors emitted from EGUs may differ
significantly from direct PM released from automotive engines and other
industrial sources, but no clear scientific grounds exist for
supporting differential effects estimates by particle type.
(3) We assume that the health impact function for fine particles is
linear down to the lowest air quality levels modeled in this analysis.
Thus, the estimates include health benefits from reducing fine
particles in areas with varied concentrations of PM2.5,
including both regions that are in attainment with the fine particle
standard and those that do not meet the standard down to the lowest
modeled concentrations.
The EPA recognizes the difficulties, assumptions, and inherent
uncertainties in the overall enterprise. The analyses upon which the
Transport Rule is based were selected from the peer-reviewed scientific
literature. We used up-to-date assessment tools, and we believe the
results are highly useful in assessing this rule.
There are a number of health and environmental effects that we were
unable to quantify or monetize. A complete benefit-cost analysis of the
Transport Rule requires consideration of all benefits and costs
expected to result from the rule, not just those benefits and costs
which could be expressed here in dollar terms. A listing of the benefit
categories that were not quantified or monetized in our estimate are
provided in Table VIII.C-4.
Table VIII.C-4--Unquantified and Non-Monetized Effects of the Transport
Rule
------------------------------------------------------------------------
Pollutant/Effect Endpoint
------------------------------------------------------------------------
PM: Health \a\............... Low birth weight.
Pulmonary function.
Chronic respiratory diseases other than
chronic bronchitis.
Non-asthma respiratory emergency room
visits.
UVb exposure \b\.
PM: Welfare.................. Household soiling.
Visibility in residential areas.
Visibility in non-class I areas and class
1 areas in NW, NE, and Central regions.
UVb exposure \b\.
Global climate impacts \b\.
Ozone: Health................ Chronic respiratory damage.
Premature aging of the lungs.
Non-asthma respiratory emergency room
visits.
UVb exposure \b\.
Ozone: Welfare............... Yields for:
--Commercial forests.
--Fruits and vegetables, and
--Other commercial and noncommercial
crops.
Damage to urban ornamental plants.
Recreational demand from damaged forest
aesthetics.
Ecosystem functions.
Increased exposure to UVb \b\.
Climate impacts.
NO2: Health.................. Respiratory hospital admissions.
Respiratory emergency department visits.
Asthma exacerbation.
Acute respiratory symptoms.
Premature mortality.
Pulmonary function.
NO2: Welfare................. Commercial fishing and forestry from
acidic deposition effects.
Commercial fishing, agriculture and
forestry from nutrient deposition
effects.
Recreation in terrestrial and estuarine
ecosystems from nutrient deposition
effects.
Other ecosystem services and existence
values for currently healthy ecosystems.
Coastal eutrophication from nitrogen
deposition effects.
SO2: Health.................. Respiratory hospital admissions.
Asthma emergency room visits.
Asthma exacerbation.
Acute respiratory symptoms.
Premature mortality.
Pulmonary function.
SO2: Welfare................. Commercial fishing and forestry from
acidic deposition effects.
Recreation in terrestrial and aquatic
ecosystems from acid deposition effects.
Increased mercury methylation.
Mercury: Health.............. Incidence of neurological disorders.
Incidence of learning disabilities.
Incidences in developmental delays.
Mercury: Welfare............. Impact on birds and mammals (e.g.,
reproductive effects).
Impacts to commercial, subsistence and
recreational fishing.
------------------------------------------------------------------------
Source: EPA.
\a\ In addition to primary economic endpoints, there are a number of
biological responses that have been associated with PM health effects
including morphological changes and altered host defense mechanisms.
The public health impact of these biological responses may be partly
represented by our quantified endpoints.
\b\ May result in benefits or disbenefits.
[[Page 48316]]
7. What are the unquantified and non-monetized benefits of the
Transport Rule emission reductions?
Important benefits beyond the human health and welfare benefits
quantified in this section and the RIA are expected to occur from this
rule. These other benefits occur directly from NOX and
SO2 emission reductions and from co-benefits due to
Transport Rule compliance. These benefits are listed in Table VIII.C-4.
Some of the more important examples include: Reduced acidification and,
in the case of NOX, eutrophication of water bodies; possible
reduced nitrate contamination of drinking water; and reduced acid and
particulate deposition that causes damages to cultural monuments, as
well as, soiling and other materials damage. To illustrate the
important nature of benefit categories EPA is currently unable to
monetize, we discuss four categories of public welfare and
environmental impacts related to reductions in emissions required by
the Transport Rule: Reduced acid deposition, reduced eutrophication of
estuaries, reduced mercury methylation and deposition, and reduced
vegetation impairment from ozone.
a. What are the benefits of reduced deposition of sulfur and nitrogen
to aquatic, forest, and coastal ecosystems?
Atmospheric deposition of sulfur and nitrogen, often referred to as
acid rain, occurs when emissions of SO2 and NOX
react in the atmosphere (with water, oxygen, and oxidants) to form
various acidic compounds. These acidic compounds fall to earth in
either a wet form (rain, snow, and fog) or a dry form (gases and
particles). Prevailing winds can transport acidic compounds hundreds of
miles, across state borders. These compounds are deposited onto
terrestrial and aquatic ecosystems across the U.S., contributing to the
problems of acidification.
(1) Acid Deposition and Acidification of Lakes and Streams
The extent of adverse effects of acid deposition on freshwater and
forest ecosystems depends largely upon the ecosystem's ability to
neutralize the acid. The neutralizing ability depends largely on the
watershed's physical characteristics, such as geology, soils, and size.
A key indicator of neutralizing ability is termed Acid Neutralizing
Capacity (ANC). Higher ANC indicates greater ability to neutralize
acidity. Acidic conditions occur more frequently during rainfall and
snowmelt that cause high flows of water, and less commonly during low-
flow conditions except where chronic acidity conditions are severe.
Biological effects are primarily attributable to a combination of low
pH and high inorganic aluminum concentrations. Biological effects of
episodes include reduced fish condition factor--changes in species
composition and declines in aquatic species richness across multiple
taxa, ecosystems and regions--as well as fish mortality. Waters that
are sensitive to acidification tend to be located in small watersheds
that have few alkaline minerals and shallow soils. Conversely,
watersheds that contain alkaline minerals, such as limestone, tend to
have waters with a high ANC. Areas especially sensitive to
acidification include portions of the Northeast (particularly, the
Adirondack and Catskill Mountains, portions of New England, and streams
in the mid-Appalachian highlands) and southeastern streams. This
regulatory action will decrease acid deposition within and downwind of
the transport region and is likely to have positive effects on the
health and productivity of aquatic ecosystems in the region.
(2) Acid Deposition and Forest Ecosystem Impacts
Acidifying deposition has altered major biogeochemical processes in
the U.S. by increasing the nitrogen and sulfur content of soils,
accelerating nitrate and sulfate leaching from soil to drainage waters,
depleting base cations (especially calcium and magnesium) from soils,
and increasing the mobility of aluminum. Inorganic aluminum is toxic to
some tree roots. Plants affected by high levels of aluminum from the
soil often have reduced root growth, which restricts the ability of the
plant to take up water and nutrients, especially calcium.\98\ These
direct effects can, in turn, influence the response of these plants to
climatic stresses such as droughts and cold temperatures. They can also
influence the sensitivity of plants to other stresses, including insect
pests and disease,\99\ leading to increased mortality of canopy trees.
---------------------------------------------------------------------------
\98\ U.S. Environmental Protection Agency (U.S. EPA). 2008.
Integrated Science Assessment for Oxides of Nitrogen and Sulfur--
Ecological Criteria National (Final Report). National
Center for Environmental Assessment, Research Triangle Park, NC.
EPA/600/R-08/139. December. http://cfpub.epa.gov/ncea/cfm/recordisplay.cfm?deid=201485.
\99\ Joslin, J.D., Kelly, J.M., van Miegroet, H. 1992. Soil
chemistry and nutrition of North American spruce-fir stands:
evidence for recent change. Journal of Environmental Quality, 21,
12-30.
---------------------------------------------------------------------------
Both coniferous and deciduous forests throughout the eastern U.S.
are experiencing gradual losses of base cation nutrients from the soil
due to accelerated leaching from acidifying deposition. This change in
nutrient availability may reduce the quality of forest nutrition over
the long term. Evidence suggests that red spruce and sugar maple in
some areas in the eastern U.S. have experienced declining health
because of this deposition. For red spruce (Picea rubens), dieback or
decline has been observed across high elevation landscapes of the
northeastern U.S. and, to a lesser extent, the southeastern U.S.
Acidifying deposition has been implicated as a causal factor.\100\
---------------------------------------------------------------------------
\100\ DeHayes, D.H., P.G. Schaberg, G.J. Hawley, and G.R.
Strimbeck. 1999. Acid rain impacts on calcium nutrition and forest
health. Bioscience 49(10):789-800.
---------------------------------------------------------------------------
This regulatory action will decrease acid deposition within and
downwind of the transport region and is likely to have positive effects
on the health and productivity of forest systems in the region.
b. Coastal Ecosystems
Since 1990, a large amount of research has been conducted on the
impact of nitrogen deposition to coastal waters. Nitrogen is often the
limiting nutrient in coastal ecosystems. Increasing the levels of
nitrogen in coastal waters can cause significant changes to those
ecosystems. In recent decades, human activities have accelerated
nitrogen nutrient inputs, causing excessive growth of algae and leading
to degraded water quality and associated impairments of estuarine and
coastal resources.
Atmospheric deposition of nitrogen is a significant source of
nitrogen to many estuaries. The amount of nitrogen entering estuaries
due to atmospheric deposition varies widely, depending on the size and
location of the estuarine watershed and other sources of nitrogen in
the watershed. A recent assessment of 141 estuaries nationwide by the
National Oceanic and Atmospheric Administration (NOAA) concluded that
19 estuaries (13 percent) suffered from moderately high or high levels
of eutrophication due to excessive inputs of both nitrogen and
phosphorus, and a majority of these estuaries are located in the
coastal area from North Carolina to Massachusetts.\101\ For estuaries
in the Mid-Atlantic region, the contribution of atmospheric
distribution to total nitrogen loads is estimated to range between 10
percent and 58 percent.\102\
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\101\ National Oceanic and Atmospheric Administration (NOAA).
2007. Annual Commercial Landing Statistics. August. http://www.st.nmfs.noaa.gov/st1/commercial/landings/annual_landings.html.
\102\ Valigura, R.A., R.B. Alexander, M.S. Castro, T.P. Meyers,
H.W. Paerl, P.E. Stacy, and R.E. Turner. 2001. Nitrogen Loading in
Coastal Water Bodies: An Atmospheric Perspective. Washington, DC:
American Geophysical Union.
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[[Page 48317]]
Eutrophication in estuaries is associated with a range of adverse
ecological effects. The conceptual framework developed by NOAA
emphasizes four main types of eutrophication effects: low dissolved
oxygen (DO), harmful algal blooms (HABs), loss of submerged aquatic
vegetation (SAV), and low water clarity. Low DO disrupts aquatic
habitats, causing stress to fish and shellfish, which, in the short-
term, can lead to episodic fish kills and, in the long-term, can damage
overall growth in fish and shellfish populations. Low DO also degrades
the aesthetic qualities of surface water. In addition to often being
toxic to fish and shellfish, and leading to fish kills and aesthetic
impairments of estuaries, HABs can, in some instances, also be harmful
to human health. SAV provides critical habitat for many aquatic species
in estuaries and, in some instances, can also protect shorelines by
reducing wave strength. Therefore, declines in SAV due to nutrient
enrichment are an important source of concern. Low water clarity is the
result of accumulations of both algae and sediments in estuarine
waters. In addition to contributing to declines in SAV, high levels of
turbidity also degrade the aesthetic qualities of the estuarine
environment.
Estuaries in the eastern United States are an important source of
food production, in particular fish and shellfish production. The
estuaries are capable of supporting large stocks of resident commercial
species, and they serve as the breeding grounds and interim habitat for
several migratory species.
This rule is anticipated to reduce nitrogen deposition within and
downwind of the Transport Rule states. Thus, reductions in the levels
of nitrogen deposition will have a positive impact upon current
eutrophic conditions in estuaries and coastal areas in the region.
c. Mercury Methylation and Deposition
Mercury is a highly neurotoxic contaminant that enters the food web
as a methylated compound, methylmercury.\103\ The contaminant is
concentrated in higher trophic levels, including fish eaten by humans.
Experimental evidence has established that only inconsequential amounts
of methylmercury can be produced in the absence of sulfate. Current
evidence indicates that in watersheds where mercury is present,
increased SOX deposition very likely results in
methylmercury accumulation in fish.104 105 The
SO2 Integrated Science Assessment concluded that evidence is
sufficient to infer a causal relationship between sulfur deposition and
increased mercury methylation in wetlands and aquatic environments.
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\103\ U.S. Environmental Protection Agency (U.S. EPA). 2008.
Integrated Science Assessment for Sulfur Oxides--Health Criteria
(Final Report). National Center for Environmental Assessment,
Research Triangle Park, NC. September. http://cfpub.epa.gov/ncea/cfm/recordisplay.cfm?deid=198843.
\104\ Drevnick, P.E., D.E. Canfield, P.R. Gorski, A.L.C.
Shinneman, D.R. Engstrom, D.C.G. Muir, G.R. Smith, P.J. Garrison,
L.B. Cleckner, J.P. Hurley, R.B. Noble, R.R. Otter, and J.T. Oris.
2007. Deposition and cycling of sulfur controls mercury accumulation
in Isle Royale fish. Environmental Science and Technology
41(21):7266-7272.
\105\ Munthe, J., R.A. Bodaly, B.A. Branfireun, C.T. Driscoll,
C.C. Gilmour, R. Harris, M. Horvat, M. Lucotte, and O. Malm. 2007.
Recovery of mercury-contaminated fisheries. AMBIO:A Journal of the
Human Environment 36:33-44.
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d. Ozone Vegetation Effects
Ozone causes discernible injury to a wide array of vegetation.\106\
In terms of forest productivity and ecosystem diversity, ozone may be
the pollutant with the greatest potential for regional-scale forest
impacts.\107\ Studies have demonstrated repeatedly that ozone
concentrations commonly observed in polluted areas can have substantial
impacts on plant function.108 109
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\106\ Fox, S., Mickler, R.A. (Eds.). 1996. Impact of Air
Pollutants on Southern Pine Forests. Ecological Studies. (Vol. 118,
513 pp.) New York: Springer-Verlag.
\107\ U.S. Environmental Protection Agency (U.S. EPA). 2006. Air
Quality Criteria for Ozone and Related Photochemical Oxidants
(Final). EPA/600/R-05/004aF-cF. Washington, DC: U.S. EPA. February.
http://cfpub.epa.gov/ncea/CFM/recordisplay.cfm?deid=149923.
\108\ De Steiguer, J., Pye, J., Love, C. 1990. Air Pollution
Damage to U.S. Forests. Journal of Forestry, 88(8), 17-22.
\109\ Pye, J.M. 1988. Impact of ozone on the growth and yield of
trees: A review. Journal of Environmental Quality, 17, 347-360.
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Assessing the impact of ground-level ozone on forests in the
eastern United States involves understanding the risks to sensitive
tree species from ambient ozone concentrations and accounting for the
prevalence of those species within the forest. As a way to quantify the
risks to particular plants from ground-level ozone, scientists have
developed ozone-exposure/tree-response functions by exposing tree
seedlings to different ozone levels and measuring reductions in growth
as ``biomass loss.'' Typically, seedlings are used because they are
easy to manipulate and measure their growth loss from ozone pollution.
The mechanisms of susceptibility to ozone within the leaves of
seedlings and mature trees are identical, and the decreases predicted
using the seedlings should be related to the decrease in overall plant
fitness for mature trees, but the magnitude of the effect may be higher
or lower depending on the tree species.\110\ In areas where certain
ozone-sensitive species dominate the forest community, the biomass loss
from ozone can be significant. Significant biomass loss can be defined
as a more than 2 percent annual biomass loss, which would cause long-
term ecological harm, as the short-term negative effects on seedlings
compound to affect long-term forest health.\111\
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\110\ Chappelka, A.H., Samuelson, L.J. 1998. Ambient ozone
effects on forest trees of the eastern United States: a review. New
Phytologist, 139, 91-108.
\111\ Heck, W.W. & Cowling, E.B. 1997. The need for a long term
cumulative secondary ozone standard--an ecological perspective.
Environmental Management, January, 23-33.
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Urban ornamentals are an additional vegetation category likely to
experience some degree of negative effects associated with exposure to
ambient ozone levels. Because ozone causes visible foliar injury, the
aesthetic value of ornamentals (such as petunia, geranium, and
poinsettia) in urban landscapes would be reduced. Sensitive ornamental
species would require more frequent replacement and/or increased
maintenance (fertilizer or pesticide application) to maintain the
desired appearance because of exposure to ambient ozone.\112\ In
addition, many businesses rely on healthy-looking vegetation for their
livelihoods (e.g., horticulturalists, landscapers, Christmas tree
growers, farmers of leafy crops, etc.) and a variety of ornamental
species have been listed as sensitive to ozone.\113\
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\112\ U.S. Environmental Protection Agency (U.S. EPA). 2007.
Review of the National Ambient Air Quality Standards for Ozone:
Policy assessment of scientific and technical information. Staff
paper. Office of Air Quality Planning and Standards. EPA-452/R-07-
007a. July. http://www.epa.gov/ttn/naaqs/standards/ozone/data/2007_07_ozone_staff_paper.pdf.
\113\ Abt Associates, Inc. 2005. U.S. EPA. Urban ornamental
plants: sensitivity to ozone and potential economic losses.
Memorandum to Bryan Hubbell and Zachary Pekar.
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D. Costs and Employment Impacts
1. Transport Rule Costs and Employment Impacts
For the affected region, the projected annual private incremental
costs of the rule to the power industry are $1.4 billion in 2012 and
$0.8 billion in 2014. These costs represent the private compliance cost
to the electric generating industry of reducing NOX and
SO2 emissions to meet the requirements set forth in the
rule. Estimates are in 2007 dollars.
In estimating the net benefits of regulation, the appropriate cost
measure
[[Page 48318]]
is ``social costs.'' Social costs represent the welfare costs of the
rule to society. These costs do not consider transfer payments (such as
taxes) that are simply redistributions of wealth. The social costs of
this rule are estimated to be approximately $0.8 billion annually in
2014. Overall, the economic impacts of the Transport Rule are modest in
2014, particularly in light of the large benefits ($120 to $280 billion
annually at a 3 percent discount rate and $110 to $250 billion annually
at a 7 percent discount rate) we expect, as shown in section XII.A of
this preamble. Ultimately, we believe the electric power industry will
pass along most of the costs of the rule to consumers, so that the
costs of the rule will largely fall upon the consumers of electricity.
For more information on electricity price changes that result from this
final rule, refer to section XII.H (Statement of Energy Effects) later
in this preamble.
For this rule, EPA analyzed the costs using the Integrated Planning
Model (IPM). The IPM is a dynamic linear programming model that can be
used to examine the economic impacts of air pollution control policies
for SO2 and NOX throughout the contiguous United
States for the entire power system. Documentation for IPM can be found
in the docket for this rulemaking or at http://www.epa.gov/airmarkets/progsregs/epa-ipm/index.html.
EPA also included an analysis of impacts of the final rule to
industries outside of the electric power sector by using the Multi-
Market Model. This model is a partial equilibrium economic impact model
that includes 100 sectors that cover energy, manufacturing, and service
applications and is designed to capture the short-run effects
associated with an environmental regulation. This model was used to
estimate economic impacts for the proposed MATS, and the promulgated
industrial boilers major and area source standards and CISWI standard.
We use the Multi-Market Model to estimate the social costs of the
final rule. Using this model, we estimate the social costs of the final
rule to be approximately $0.8 billion (2007 dollars), which is close to
the compliance costs. Documentation for the Multi-Market Model can be
found in the RIA for this final rule.
Also note that as explained in section V.B (Baseline for Pollution
Transport Analysis), the baseline used in this analysis assumes no
CAIR. As explained in that section, EPA believes that this is the most
appropriate baseline to use for purposes of determining whether an
upwind state has an impact on a downwind monitoring site in violation
of section 110(a)(2)(D).
Although a stand-alone analysis of employment impacts is not
included in a standard cost-benefit analysis, the current economic
climate has led to heightened concerns about potential job impacts.
Such an analysis is of particular concern in the current economic
climate as sustained periods of excess unemployment may introduce a
wedge between observed (market) wages and the social cost of labor. In
such conditions, the opportunity cost of labor required by regulated
sectors to bring their facilities into compliance with an environmental
regulation may be lower than it would be during a period of full
employment (particularly if regulated industries employ otherwise idled
labor to design, fabricate, or install the pollution control equipment
required under this rule). For that reason, EPA also includes estimates
of job impacts associated with the final rule. EPA presents an estimate
of short-term employment opportunities as a result of increased demand
for pollution control equipment. Overall, the results suggest that the
final rule could support a net increase of roughly 2,250 job-years in
direct employment in 2014.
The basic approach to estimate these employment impacts involved
using projections from IPM from the final rule analysis such as the
amount of capacity that will be retrofit with control technologies, for
various energy market implications, along with data on labor and
resource needs of new pollution controls and labor productivity from
secondary sources, to estimate employment impacts for 2014. This
analysis was also applied for the proposed MATS. For more information,
refer to Appendix D of the RIA for the final Transport Rule.''
EPA relied on Morgenstern, et al. (2002), a study that is a basis
for employment impacts estimated for the final industrial boiler major
and area source rules and CISWI standard, and the proposed MATS. The
Morgenstern study identifies three economic mechanisms by which
pollution abatement activities can indirectly influence jobs: (1)
Higher production costs raise market prices, higher prices reduce
consumption, and employment within an industry falls (``demand
effect''); (2) pollution abatement activities require additional labor
services to produce the same level of output (``cost effect''); and (3)
post regulation production technologies may be more or less labor
intensive (i.e., more/less labor is required per dollar of output)
(``factor-shift effect'').
Using plant-level Census information between the years 1979 and
1991, Morgenstern, et al., estimate the size of each effect for four
polluting and regulated industries (petroleum, plastic material, pulp
and paper, and steel). On average across the four industries, each
additional $1 million spending on pollution abatement results in a
small net increase of 1.6 jobs; however, the estimated effect is not
statistically significant. As a result, the authors conclude that
increases in pollution abatement expenditures do not necessarily cause
economically significant employment changes. The conclusion is similar
to Berman and Bui (2001), who found that increased air quality
regulation in Los Angeles did not cause large employment changes. For
more information, please refer to the RIA for this final rule.
The ranges of job effects calculated using the Morgenstern, et al.,
approach are listed in Table VIII.D-1.
Table VIII.D-1--Range of Job Effects for the Electricity Sector
[Estimates using Morgenstern, et al. (2002)]
--------------------------------------------------------------------------------------------------------------------------------------------------------
Demand effect Cost effect Factor shift effect Net effect
--------------------------------------------------------------------------------------------------------------------------------------------------------
Change in Full-Time Jobs per -3.56....................... 2.42........................ 2.68........................ 1.55.
Million Dollars of
Environmental Expenditure \a\.
Standard Error.................. 2.03........................ 0.83........................ 1.35........................ 2.24.
EPA Estimate for Final Rule \b\. + 200 to -3,000............. + 400 to 2,000.............. 0 to 2,000.................. -1,000 to + 3,000.
--------------------------------------------------------------------------------------------------------------------------------------------------------
\a\ Expressed in 1987 dollars. See footnote a of Table 8-3 in the RIA for the inflation adjustment factor used in the analysis.
\b\ According to the 2007 Economic Census, the electric power generation, transmission, and distribution sector (NAICS 2211) had approximately 510,000
paid employees.
[[Page 48319]]
EPA recognizes there may be other job effects which are not
considered in the Morgenstern, et al., study. Although EPA has
considered some economy-wide changes in industry output as shown
earlier with the Multi-Market model, we do not have sufficient
information to quantify other associated job effects associated with
this rule.
2. End-Use Energy Efficiency
EPA believes that achievement of energy efficiency (EE)
improvements in homes, buildings, and industry is an important
component of achieving emission reductions from the power sector while
minimizing associated compliance costs. By reducing electricity demand,
energy efficiency avoids emissions of all pollutants associated with
electricity generation, including emissions of NOX and
SO2 targeted by this final rule, and reduces the need for
investments in EGU emission control technologies in order to meet
emission reduction requirements. Moreover, energy efficiency can often
be implemented at a lower cost than traditional control technologies.
EPA recognizes that significant opportunities remain for energy
efficiency improvements in businesses, homes, and industry. However,
there are several informational and market barriers that limit
investment in cost-effective energy efficient practices. Several
federal programs authorized under the CAA, including ENERGY STAR, are
designed to address these barriers.
Congress, EPA, and states have all recognized the value of
incorporating energy efficiency into air regulatory programs. Several
allowance-based programs--including the Acid Rain Program, EPA's
NOX Budget Trading program, and the Regional Greenhouse Gas
Initiative (an effort of 10 states from the Northeast and Mid-Atlantic
regions) - have provided mechanisms for rewarding energy efficiency
through either the award of allowances, typically through the use of a
fixed set-aside pool, or the use of revenues obtained through the
auction of allowances. The emission caps established by these programs
are unaffected by this approach. However, to the extent electricity
demand reductions are realized, compliance costs are reduced. In
addition to these allowance-based programs, EPA has also provided
guidance \114\ concerning the recognition, in SIPs, of emission
reduction benefits of energy efficiency and has approved the inclusion
of EE measures in individual SIPs.\115\
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\114\ U.S. EPA. 2004. Guidance on State Implementation Plan
(SIP) Credits for Emission Reductions from Electric-Sector Energy
Efficiency and Renewable Energy Measures.
http://www.epa.gov/ttn/oarpg/t1/memoranda/ereseerem_gd.pdf.
\115\ Metropolitan Washington Council of Governments developed a
regional air quality plan for the eight-hour ozone standard for the
DC Region nonattainment area that included an EE measure. The plan
was adopted by Virginia, Maryland, and the District of Columbia and
the respective ozone SIPs were approved by the EPA regions in 2007.
---------------------------------------------------------------------------
While all remedy options considered in the proposed rule would have
lead to an increase in the relative cost-effectiveness of EE
investments by internalizing environmental costs associated with
emission of these pollutants, EPA took comment on whether EPA has
authority, and whether it would be appropriate for EPA, to consider EE
in developing the allowance allocation methodology and to consider
other approaches for encouraging EE in the Transport Rule.
Some commenters suggested that EPA has authority to consider EE in
developing the allocation methodology. Other commenters do not believe
EPA has the authority to consider EE. Some commenters suggested that
EPA should establish an EE set-aside provision. Other commenters
suggested that EPA should allow, and help, states to establish EE set-
asides as states transition from Transport Rule FIPs to SIPs. EPA
believes that, while EE set-asides can be effective at encouraging
incremental investments in EE, EE set-asides are more likely to be
practically and effectively implemented at the state level.
Establishing EE set-asides in the allowance allocation provisions in
the final rule would not allow for the tailoring of the set-asides to
the unique characteristics of individual states and would not build on
the existing EE program delivery infrastructure that many states
already possess. Instead of establishing EPA-administered EE set-asides
in the final rule, EPA is clarifying that it allows and supports EE
set-asides (including auction-based approaches) in abbreviated or full
SIPs that states may submit, as provided in the final rule. Under this
approach states have the ability to implement EE set-asides tailored to
their state circumstances, if they choose. EPA anticipates providing
additional information in the future for states on EE set-asides, as
needed.\116\
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\116\ Because the question of EPA authority to create EE set-
asides in the FIPs would be best addressed in the context of actual
FIP provisions for EPA-created EE set-asides and EPA is, for other
reasons, not adopting such provisions in the final rule, EPA is not
addressing in the final rule the question of EPA's authority.
---------------------------------------------------------------------------
As discussed elsewhere in this preamble, the final rule provides
for submission and approval of abbreviated and full SIPs providing for
continued state participation in the Transport Rule trading programs,
and adopting alternative allowance allocation methodologies (which may
include EE set-asides) to the allocation methodologies adopted in the
FIPs. While the final rule establishes certain requirements for
approval of any such alternative allocation methodology, the final rule
provides states flexibility to create state-implemented EE set-asides.
IX. Related Programs and the Transport Rule
A. Transition From the Clean Air Interstate Rule
1. Key Differences Between the Transport Rule and CAIR
The Transport Rule replaces CAIR and its associated trading
programs. There are a number of differences between implementation of
the Transport Rule and implementation of CAIR. This section describes
key implementation differences including differences in states covered,
compliance deadlines, applicability, structure of the remedy,
provisions for early reductions, and provisions for SIPs. The next
section discusses the transition from CAIR to the Transport Rule.
States covered. The states covered by the Transport Rule differ
somewhat from states covered by CAIR. This section summarizes
differences in state coverage. EPA's approach to determine states
covered by the Transport Rule is discussed in sections V and VI of this
preamble.
The Transport Rule's SO2 and annual NOX
requirements apply to covered sources in the 23 states listed in Table
III-1 in section III of this preamble. CAIR's SO2 and annual
NOX requirements applied to covered sources in 25 states.
There are many states in common between the Transport Rule and CAIR
SO2 and annual NOX programs. The differences are
summarized in Table IX.A-1.
[[Page 48320]]
Table IX.A-1--Differences in SO2 and Annual NOX State Coverage Between
the Transport Rule and CAIR
------------------------------------------------------------------------
Transport rule SO2 CAIR SO2 and
State and annual NOX annual NOX
programs programs
------------------------------------------------------------------------
Kansas......................... Yes................ No.
Minnesota...................... Yes................ No.
Nebraska....................... Yes................ No.
Delaware....................... No................. Yes.
District of Columbia........... No................. Yes.
Florida........................ No................. Yes.
Louisiana...................... No................. Yes.
Mississippi.................... No................. Yes.
------------------------------------------------------------------------
The Transport Rule's ozone-season NOX requirements apply
to covered sources in the 20 states listed in Table III-1 in section
III of this preamble, while CAIR's ozone-season NOX
requirements applied to 26 states. There are many states in common
between the Transport Rule and CAIR ozone-season NOX
programs. The differences are summarized in Table IX.A-2.
Table IX.A-2--Differences in Ozone-Season NOX State Coverage Between the
Transport Rule and CAIR
------------------------------------------------------------------------
Transport rule
State ozone-season NOX CAIR ozone-season
program NOX program
------------------------------------------------------------------------
Georgia........................ Yes................ No.
Texas.......................... Yes................ No.
Connecticut.................... No................. Yes.
Delaware....................... No................. Yes.
District of Columbia........... No................. Yes.
Iowa........................... No................. Yes.
Massachusetts.................. No................. Yes.
Michigan....................... No................. Yes.
Missouri....................... No................. Yes.
Wisconsin...................... No................. Yes.
------------------------------------------------------------------------
In addition, EPA is proposing a supplemental notice to apply
Transport Rule ozone-season requirements to the states of Iowa, Kansas,
Michigan, Missouri, Oklahoma, and Wisconsin, as discussed in section
III of this preamble.
The transition from CAIR to the Transport Rule is discussed in
section IX.A.2 and SIPs are discussed in section X of this preamble.
Compliance deadlines. The Transport Rule reduction requirements
commence January 1, 2012 for annual NOX and SO2
requirements and May 1, 2012 for ozone-season NOX
requirements. More stringent SO2 reduction requirements
commence January 1, 2014 for Group 1 states.
In contrast, the first phase of CAIR NOX reductions
commenced January 1, 2009 for annual NOX requirements and
May 1, 2009 for ozone-season NOX requirements. On January 1,
2010, the first phase of CAIR SO2 requirements commenced.
However, in anticipation of CAIR, SO2 reductions actually
started as early as 2006 because of the incentive to reduce emissions
and bank Title IV Acid Rain Program SO2 allowances for use
when their value would increase under CAIR in 2010 and later. The
second phase of CAIR reductions would have (if not replaced by the
Transport Rule) commenced January 1, 2015 for annual NOX and
SO2 requirements, and May 1, 2015 for ozone-season
NOX requirements.
Applicability. Except for the changes to the states covered, the
general applicability provisions of the final Transport Rule trading
programs are essentially the same as the CAIR general applicability
provisions, with a few exceptions.
First, the final Transport Rule does not allow any non-covered
units to opt into the trading programs, for the reasons discussed in
section VII.B of this preamble. In contrast, under CAIR, through SIPs,
the states could elect to allow boilers, combustion turbines, and other
combustion devices to opt into the CAIR trading programs under opt-in
provisions specified by EPA.
Second, the Transport Rule FIPs' ozone-season NOX
trading program applicability provisions do not cover NOX
SIP Call small EGUs and non-EGUs that a number of CAIR states brought
into the CAIR ozone-season NOX trading program. The
Transport Rule does allow any state in the ozone-season NOX
program, through SIPs, to expand the applicability of the Transport
Rule ozone-season NOX trading program to cover small EGUs.
However, the Transport Rule does not allow states to expand the
applicability to cover NOX SIP Call non-EGUs, for the
reasons discussed elsewhere in this preamble.
In contrast, in the CAIR trading programs, a NOX SIP
Call state could expand the applicability of the CAIR ozone-season
NOX trading program in the state in order to include all
units subject to the NOX Budget Trading Program under the
NOX SIP Call. A number of states chose to expand the CAIR
ozone-season NOX trading program applicability in this way.
The transition from CAIR to the Transport Rule is discussed in section
IX.A.2 and SIPs are discussed in section X of this preamble.
Structure of the remedy. The CAIR FIPs (and CAIR model trading
rules adopted by a number of states in their CAIR SIPs) implemented
reductions through SO2, annual NOX, and ozone-
season NOX interstate emission trading programs covering
primarily large EGUs. The owners and operators of a covered source
could buy allowances
[[Page 48321]]
from or sell allowances to other covered sources (or other market
participants) and were required to surrender allowances equal to the
source's emissions for each compliance period. CAIR's trading programs
did not impose limitations on the aggregate emissions from covered
units within any covered state.
The Transport Rule FIPs will also achieve the required reductions
through SO2, annual NOX, and ozone-season
NOX interstate trading programs. However, in contrast to
CAIR and for the reasons discussed in section VII of this preamble, the
Transport Rule FIPs include assurance provisions specifically designed
to ensure that no state's emissions will exceed that state's emission
budget plus the variability limit, i.e., the state's assurance level.
Another difference in the remedy structure is in the design of the
SO2 trading programs. In CAIR all of the states required to
reduce SO2 emissions were grouped together in one
SO2 trading program with no restriction on the use of
SO2 allowances from any state in the program by any source
in the program. In contrast, and for the reasons discussed in section
VI of this preamble, the Transport Rule divides states required to
reduce SO2 emissions into two groups with emission reduction
requirements of different stringency starting in 2014 (SO2
Group 1, whose reduction requirements become more stringent starting in
2014, and SO2 Group 2, whose reduction requirements in 2014
do not change). A covered source may only use for compliance--with the
requirements to hold allowances covering emissions and, if applicable,
to surrender allowances under the assurance provisions--an
SO2 allowance issued for the SO2 Group in which
the source's state is included. In other words, an SO2 Group
1 source may only use a SO2 Group 1 allowance for
compliance, and likewise an SO2 Group 2 source may only use
a SO2 Group 2 allowance for compliance.
Provisions for early reductions. CAIR included provisions for
covered sources to make early reductions prior to the start of CAIR's
SO2 and NOX trading programs, bank emission
allowances, and carry banked allowances into its trading programs. In
contrast, the Transport Rule does not include provisions for covered
sources to carry over any allowances (i.e., Title IV SO2
allowances or CAIR annual or ozone-season NOX allowances)
into the Transport Rule trading programs. EPA's reasons for not
allowing the use of banked Title IV SO2 allowances or CAIR
annual or ozone-season NOX allowances in the Transport Rule
trading programs are discussed in the next section.
Provisions for SIPs. The following is a summary of the key
differences between the Transport Rule and CAIR provisions for SIPs. A
more detailed discussion of Transport Rule SIPs is in section X of this
preamble.
The SIP provisions in the Transport Rule and CAIR are very similar.
Both include provisions that allow states to submit SIP revisions
(referred to as full SIPs) that replace an applicable FIP trading
program with a comparable SIP trading program that has certain limited
differences from the FIP trading program. Similarly, both rules include
provisions that allow states to submit SIP revisions (referred to as
abbreviated SIPs) that may modify certain limited provisions in the FIP
trading program, which remain in place. Inclusion of this provision in
the Transport Rule allows a state to modify certain elements of a
Transport Rule FIP trading program in order to better meet the needs of
the state. Both the Transport Rule and CAIR allow full or abbreviated
SIPs that involve one or more applicable FIP trading programs. However,
there are a few differences.
In particular, under the Transport Rule, states may submit SIP
revisions under which the state determines allocations for the
applicable trading program using either full or abbreviated SIP
revisions. States could submit similar revisions under CAIR. Under the
Transport Rule, the state may use the same allocation methodology as
that currently used in the Transport Rule FIP trading program or some
other allocation methodology. However, the Transport Rule specifies
certain requirements that must be met concerning, for example, the
timing of such allocation determinations, and expressly allows
allowance auctions to be used. CAIR did not include similar provisions.
Further, the SIP submission deadlines, allocation submission, and
allocation recordation dates are different between the Transport Rule
and CAIR. The Transport Rule SIP submission deadlines and allocation
recordation dates are discussed in section X of this preamble.
In addition, both the Transport Rule and CAIR include provisions
that allow states to submit SIP revisions under which the state expands
the general applicability provisions of the ozone-season NOX
trading programs to cover certain units subject to the NOX
SIP Call. However, for the reasons discussed elsewhere in this
preamble, this flexibility is more limited in the Transport Rule than
it was in CAIR.
While CAIR allowed states to adopt, through full or abbreviated
SIPs, opt-in provisions, the Transport Rule does not allow for opt-in
provisions. The reasons for this are discussed in section VII.B of this
preamble.
Finally, neither full nor abbreviated SIPs can replace FIP
provisions that apply to units in Indian country within the borders of
a state. For example, the FIPs include, for states within whose borders
Indian country is located, an Indian country new unit set-aside. For
states not having Indian country within their borders, abbreviated SIPs
are limited to replacing the allowance allocation provisions of the
FIPs for the state involved and may replace some or all of those
provisions. However, for states having Indian country within their
borders, abbreviated SIPs cannot replace the FIP provisions for the
Indian country new unit set-aside. Similarly, for states not having
Indian country, full SIPs can replace an entire FIP, but, in doing so,
can only change the allowance allocation provisions. For states having
Indian country, full SIPs can replace the FIPs except for the Indian
country new unit set-aside provisions, which will remain under the
applicable FIPs, and, like the abbreviated SIPs, can only change the
allowance allocation provisions that are replaced.
Details of the Transport Rule provisions for abbreviated and full
SIP revisions, including deadlines for submission to EPA, are discussed
in section X of this preamble.
2. Transition From the Clean Air Interstate Rule to the Transport Rule
The Transport Rule replaces CAIR and its associated trading
programs. This section elaborates on areas of transition from CAIR to
the Transport Rule.
a. Sunsetting of CAIR, CAIR SIPs, and CAIR FIPs
The proposal explained that, for control periods in 2012 and
thereafter, CAIR, CAIR SIPs, and CAIR FIPs would be replaced entirely
by the Transport Rule provisions. The proposal outlined implementation
of the sunsetting of CAIR and CAIR FIPs, through revisions to CAIR,
Sec. Sec. 51.123 and 51.124, and the CAIR FIPs, Sec. Sec. 52.35 and
52.36. For the control period in these years, the CAIR trading programs
would not continue, and the Administrator would not carry out any of
the functions established for the Administrator in the CAIR model
trading rule, the CAIR FIPs, or any state trading programs approved
under CAIR. Offset and automatic penalty provisions under CAIR would
not apply to excess emissions for 2011 control periods.
[[Page 48322]]
Also discussed were the processes for modifying provisions in Part
52 reflecting state-specific CAIR SIP and CAIR FIP requirements, which
would vary depending on whether a state has an approved CAIR SIP or a
CAIR FIP. The proposal further explained that sources in some states
covered by CAIR or the CAIR FIPs would not be subject to the Transport
Rule and that to the extent that CAIR reductions were needed or relied
upon to satisfy other SIP requirements, states might need to find
alternative ways to satisfy requirements for their SIPs.
EPA is finalizing regulatory changes to sunset CAIR and the CAIR
FIPs. The final rule revises the general CAIR and CAIR FIP provisions
in Parts 51 and 52 applicable to all CAIR states. For control periods
in 2012 and thereafter, the Administrator rescinds the determination
that states must meet SIP requirements under CAIR, and the requirements
of the CAIR FIPs are not applicable. Further, with regard to these
control periods, the Administrator will no longer carry out any of the
functions established for the Administrator in the CAIR model trading
rule, the CAIR FIPs, or any state trading programs approved under CAIR
with the exception of enforcing the provisions for the previous control
periods, if necessary.
For the reasons discussed in the proposed rule preamble (75 FR
45337), CAIR allowances allocated for these control periods cannot be
used in any CAIR trading program and, as discussed below, in any
Transport Rule trading program. Specifically, for the reasons discussed
in the proposed rule, offset and automatic allowance penalty provisions
in the CAIR trading programs will not be applied to 2011 control period
excess emissions, which will remain subject to discretionary civil
penalties under CAA section 113. EPA still retains all enforcement
options for excess emissions during the 2011 control period. CAIR
allowances allocated for 2012 and thereafter are not usable in any CAIR
or Transport Rule trading program. In light of that fact, in order to
prevent any confusion by owners and operators and other members of the
public concerning the status of such allowances, the final rule
provides that, within 90 days after publication of the final Transport
Rule, the Administrator will remove post-2011 CAIR annual
NOX and ozone-season allowances from the Allowance Tracking
System.
The CAIR SO2 trading program, of course, uses Acid Rain
allowances, which will remain in the Allowance Tracking System because
they were created by CAA Title IV and continue to be usable in the Acid
Rain Program.
The final rule also adopts the discussion in the proposed rule
concerning state-specific Part 52 provisions concerning CAIR (75 FR
45337-38). With regard to Part 52 provisions reflecting EPA's adoption
of ongoing CAIR FIPs for some individual states, the final rule revises
the CAIR FIP provisions to make them inapplicable to control periods in
2012 and thereafter and to require the Administrator to remove from the
Allowance Tracking System, CAIR allowances for these control periods.
The final, state-specific CAIR FIP provisions in Part 52 essentially
echo the language in the final, general CAIR provisions in Part 52
discussed above. In making the CAIR FIP provisions inapplicable to
control periods in 2012 and thereafter, the final, state-specific
provisions sunset the applicable CAIR FIP trading programs whether or
not the CAIR FIPs were revised by approved, abbreviated CAIR SIPs.
(Under CAIR, abbreviated CAIR SIPs were adopted by certain states so
that states, rather than EPA, made NOX allowance
allocations.) Consequently, states with approved, abbreviated CAIR SIPs
will not need to revise their abbreviated CAIR SIPs in order to sunset
the CAIR trading programs to which these abbreviated SIPs applied.
Thus, although such abbreviated SIPs may remain in the state SIPs, they
will have no force and effect, once the CAIR FIPs sunset.
With regard to Part 52 provisions reflecting EPA's approval of full
CAIR SIPs submitted to EPA by many individual states, the Court's North
Carolina decision essentially overrides these Agency approvals of
individual CAIR SIPs. (Under CAIR, full CAIR SIPs were adopted by
certain states to replace CAIR FIPs and continue participation through
the CAIR SIPs in the CAIR trading programs.) The Court found CAIR to be
illegal and only allowed it to remain in effect temporarily. For this
reason, the CAIR SIPs though approved, can have no force and effect
once CAIR is replaced by this rule. For this reason, although the
proposed rule indicated that states would need to submit SIP revisions
to, among other things, make the CAIR SIPs inapplicable to control
periods after 2011, the final rule does not require states to take any
actions to revise their full or abbreviated CAIR SIPs. For states
covered by CAIR or CAIR FIPs that are not subject to the Transport Rule
and have relied on CAIR reductions to satisfy other SIP requirements,
EPA will discuss with states alternative ways to satisfy requirements
for those SIP requirements, e.g., through intrastate cap and trade
programs that require the level of reductions on which the state has
recently relied.
b. NOX SIP Call Units
The NOX Budget Trading program was used by states to
reduce ozone-season NOX emissions from EGUs and large non-
EGUs under NOX SIP Call requirements. The program started in
2003 and ended in 2008. Under CAIR, a state subject to the
NOX SIP Call was allowed to expand the applicability of the
CAIR ozone-season NOX trading program in the state in order
to include all units subject to the NOX Budget Trading
Program under the NOX SIP Call and thereby to continue to
meet the state's NOX SIP Call requirements. Fourteen states
chose to expand the CAIR ozone-season NOX applicability in
this way, while six states chose not to expand the applicability and
instead to meet their NOX SIP Call obligations in other
ways. EPA proposed to not allow this expansion in applicability for the
Transport Rule, primarily because these sources as a group did not
actually reduce emissions for the NOX Budget Trading Program
or CAIR. EPA took comment on the proposed approach.
Several commenters generally advocated allowing, at state
discretion, all NOX Budget Trading Program units to be
regulated under the Transport Rule ozone-season NOX trading
program. Some also questioned how states would otherwise satisfy
NOX SIP Call requirements for these units. Some commenters
argued that some units did in fact make emission reductions in the
NOX Budget Trading Program, but did not provide information
on specific units.
The final rule provides states an option to expand the general
applicability provisions of the Transport Rule ozone-season
NOX trading program to cover small EGUs, but not other units
in the NOX SIP Call. Specifically, consistent with the
comments, EPA determined that it is appropriate to allow states to
expand the applicability of the Transport Rule ozone-season
NOX trading program to include units serving a generator
with a nameplate capacity equal to or greater than 15 MWe producing
electricity for sale. This will allow states with NOX SIP
Call obligations to meet those requirements with respect to these small
EGUs. These units can be brought into the program through abbreviated
or full Transport Rule SIPs. However, if a state chooses to expand the
general applicability provisions, the state Transport Rule ozone-season
NOX budget cannot be increased. EPA believes that the level
of
[[Page 48323]]
emissions from small EGUs is sufficiently small that the existing
Transport Rule state budget can accommodate these units. This is
consistent with the approach taken in the NOX Budget Trading
Program, where the states that added these small EGUs did not increase
their NOX SIP Call EGU budgets. This also removes concern
(expressed in the proposed rule) that increasing state budgets in the
Transport Rule ozone-season NOX trading program, as part of
the expansion of the applicability provisions to include small EGUs,
would jeopardize elimination of a state's significant contribution to
nonattainment and interference with maintenance.
With regard to large non-EGUs that were included in the
NOX Budget Trading Program (the remainder of the sources in
the NOX Budget Trading Program), the final Transport Rule,
like the proposed rule, does not allow expansion of the general
applicability provisions for the ozone-season NOX trading
program to include such units. As explained in the proposed rule (75 FR
43340), while some of these units may have installed controls around
the start of the NOX Budget Trading Program, EPA analysis
shows that, as a group, these units did not collectively reduce
emissions, their current emission rates are nearly identical to their
emission rates before the start of the NOX Budget Trading
Program, and their allocations are about twice their emissions, with
the result that the excess allocations were sold to covered EGUs.\117\
Moreover, EPA believes that there are little or no emission reductions
available by non-EGUs at the cost thresholds used in the final rule and
so no basis for developing non-EGUs state budgets reflecting the
elimination of significant contribution to nonattainment and
interference with maintenance. For these reasons, the final rule allows
states to expand the ozone-season NOX trading program to
cover small EGUs that were in the NOX Budget Trading
Program, but not to cover large non-EGUs that were in that program. As
explained in the proposed rule, if a state were to do so, emissions
from these units could jeopardize elimination of the state's
significant contribution to nonattainment or interference with
maintenance. See 75 FR 45340. For states that relied on large non-EGUs
for emission reductions required by the NOX SIP Call, EPA
will assist in identifying ways to ensure continued, future compliance
with the NOX SIP Call requirements.
---------------------------------------------------------------------------
\117\ Although the proposed rule discussed the EPA analysis in
the context of considering the treatment of both small EGUs and
large non-EGUs from the NOX Budget Trading Program, the
analysis actually addresses, and draws conclusions about emission
reductions, emission rates, and allowance allocations concerning
only large non-EGUs.
---------------------------------------------------------------------------
c. Early Reduction Provisions
Substantial emission reductions have occurred as a result of
previous emission trading programs, under both Title IV and CAIR. This
has lead to substantial ``banks'' of allowances (i.e., holdings of
unused allowances allocated for years before the programs sunset) in
each of the CAIR programs. In the proposal, EPA requested comment on
whether to allow banked CAIR allowances to be used in the Transport
Rule trading programs. EPA recognizes the importance of continuity in
emission trading programs as a general principle. However, for the
reasons explained below, EPA has decided not to allow banked CAIR
allowances to be used in any of the Transport Rule trading programs.
(1) SO2 Allowance Bank
The bank of Title IV allowances was more than 12 million tons at
the end of 2009. This bank is the result of emission reductions under
the Title IV Acid Rain Program. Under the CAIR SO2 trading
program, EPA allowed banked (as well as future year) Title IV
allowances to be used in the CAIR SO2 trading program--in
lieu of being used in the Acid Rain Program--for compliance with the
requirement to hold allowances covering SO2 emissions. This
approach encouraged early reductions for the CAIR SO2
trading program, but was held to be unlawful in North Carolina.
In the proposed rule, EPA took comment on whether sources should be
allowed to use banked Title IV allowances in the Transport Rule
SO2 program. EPA proposed to not allow the use of Title IV
allowances either as the basis for allocating Transport Rule
SO2 allowances or directly for compliance with allowance-
holding requirements, in part, because EPA was concerned that those
approaches would be perceived as inconsistent with the requirements of
CAA section 110(a)(2)(D)(i)(I) as interpreted by the Court in North
Carolina. See 75 FR 45338-39.
A number of commenters advocated that EPA recognize Title IV
allowance holdings in the Transport Rule, either by allowing full or
limited carryover of the allowances or by allocating all or a portion
of the Transport Rule SO2 allowances based on Title IV
allowance holdings. Other commenters agreed with EPA's assessment that
allowing Title IV allowance carryover in the Transport Rule is
inconsistent with North Carolina and that any linkage of Transport Rule
allocations with Title IV allowance holdings would carry unnecessary,
significant legal risk. Therefore, for the reasons explained above and
in the proposal, EPA has decided not to permit sources to use Title IV
allowances for compliance with the Transport Rule SO2
trading programs.
In addition, unlike CAIR, in the Transport Rule, EPA decided not to
base allocation of Transport Rule SO2 allowances on the
specific distribution of existing Title IV allowances. Title IV
allowances continue, of course, to be usable for compliance in the Acid
Rain Program.\118\
---------------------------------------------------------------------------
\118\ The Title IV allowance bank is expected to be about 14
million tons at the beginning of 2012.
---------------------------------------------------------------------------
(2) NOX Allowance Banks
In the proposed rule, EPA estimated that the CAIR ozone-season
NOX bank would contain over 600,000 allowances and the CAIR
annual NOX bank would contain about 720,000 allowances after
completion of true-up of allowance holdings and emissions for 2011. EPA
considered the alternatives of allowing or not allowing pre-2012 CAIR
NOX allowances and CAIR ozone-season NOX
allowances to be used in the Transport Rule NOX trading
programs.
EPA also described and requested comment on several possible
approaches for handling banked pre-2012 CAIR NOX allowances
in the Transport Rule NOX trading programs and the pros and
cons of each (75 FR 45339):
Allow all such banked CAIR allowances to be brought into
the Transport Rule NOX programs, make the assurance
provisions effective starting in 2012, and rely on the assurance
provisions to ensure that each state continues to eliminate all of its
significant contribution to nonattainment and interference with
maintenance;
Allow only a limited amount of banked pre-2012 CAIR
allowances to be brought into the Transport Rule NOX
programs;
Factor the bank into the calculation of state
NOX budgets by reducing the state NOX budgets to
take account of the banked pre-2012 CAIR allowances; and
Do not allow the use of any banked pre-2012 CAIR
allowances in the Transport Rule NOX programs.
EPA proposed the last of these approaches and requested comment on
all of the described approaches or suggestions on other ways to handle
banked pre-2012 CAIR allowances in the Transport Rule NOX
programs.
[[Page 48324]]
Many commenters advocated allowing the carryover of CAIR
NOX allowances to the Transport Rule. Reasons given
included: preservation of early reduction investments; need for market
continuity; increased flexibility during program start up and early
years of the programs; preservation of the credibility of, and
certainty under, trading approaches; and the lack of a prohibition in
North Carolina of carryover of CAIR NOX allowances.
Commenters also suggested that surrender ratios be used to limit the
amount, and negative effects, of a carryover.
Many other commenters were against allowing CAIR
NOX allowance carryover into the Transport Rule. Reasons
given included: unnecessary, significant legal risk; concerns about the
efficacy of the Transport Rule if state budgets are supplemented by a
carryover; and differences in the nature of the programs (the
NOX Budget Trading Program, which addressed the 1-hour ozone
NAAQS, and the CAIR ozone-season NOX trading program, which
addressed the 1997 8-hour ozone NAAQS and was reversed in North
Carolina) under which the allowances were banked, and the Transport
Rule ozone-season NOX trading program, which addresses the
1997 8-hour ozone NAAQS.
For the reasons explained below, after evaluating all comments on
this issue, EPA decided not to allow the use of CAIR NOX
allowances in the Transport Rule NOX trading programs. EPA
reevaluated the estimated size of the potential carryover (allowances
that will remain unused in the CAIR programs at the end of 2011
compliance periods), taking into account 2010 emissions. EPA estimates
that more than 440,000 CAIR ozone-season NOX allowances will
remain and that more than 460,000 CAIR annual NOX allowances
will remain at the end of the 2011 compliance periods. EPA considered
whether to allow these CAIR ozone-season NOX and CAIR annual
NOX allowances to be used in the Transport Rule
NOX trading programs. The CAIR ozone-season NOX
allowances expected to remain unused represent nearly three-quarters of
aggregate state ozone-season NOX budgets \119\ in a single
year under the final Transport Rule. The allowances expected to remain
unused in the annual NOX program represent more than one-
third of aggregate state annual NOX budgets in a single year
under the Transport Rule. As discussed in the proposal, if these
allowances were carried over in addition to the Transport Rule state
budgets, EPA could not be assured that significant contribution to
nonattainment or interference with maintenance would be eliminated. EPA
therefore rejects any approach under which all banked CAIR
NOX allowances would be added to the Transport Rule trading
programs on top of each state's annual NOX and/or ozone-
season NOX budgets.
---------------------------------------------------------------------------
\119\ This analysis is for all states identified to be
contributing significantly to nonattainment or interfering with
maintenance. When the analysis is conducted using the aggregate
state budgets for only those states for which we are finalizing
ozone season requirements in this rule, the percentage increases.
---------------------------------------------------------------------------
In response to public comments, EPA considered whether the
Transport Rule trading programs should allow some form of exchange of
banked CAIR annual NOX and ozone-season allowances for new
Transport Rule NOX allowances within each state's annual
NOX and/or ozone-season budgets, respectively. However, EPA
believes that this type of approach carries substantial legal and
technical problems. First, the state-by-state distribution of CAIR
NOX allowances resulted from the methodology applied by EPA
in CAIR of using fuel factors to set the total amounts of allowance
allocations in each state (i.e., the state NOX budgets). The
CAIR NOX allowance banks therefore are--at least in part--
the result of this methodology, which was reversed in North Carolina.
See North Carolina, 531 F.3d at 918-22. Thus, EPA did not use fuel
factors in developing the Transport Rule state budgets. However, EPA is
concerned that the distribution of some or all Transport Rule
NOX allowances through exchanges of banked CAIR
NOX allowances for Transport Rule NOX allowances
would blur the bright line between the methodology used for setting
budgets in the Transport Rule and the methodology used for setting
budgets in CAIR that was rejected by the Court. At least to some
extent, the parties that were advantaged under EPA's budget-setting
methodology in CAIR would continue to have an advantage under the
Transport Rule by receiving more Transport Rule NOX
allowances. EPA therefore believes that allowing exchange of banked
CAIR NOX allowances for Transport Rule NOX
allowances carries significant legal risk.
Second, establishing a procedure for exchanging banked CAIR
NOX allowances for Transport Rule NOX allowances
within each state's budget would mean that Transport Rule
NOX allowances could not be allocated until after completion
of the process for determining compliance with allowance-holding
requirements for 2011 in the CAIR NOX trading programs. This
process cannot begin until after the allowance transfer deadline for
the 2011 control periods (i.e., March 1, 2012 for the CAIR annual
NOX program and November 1, 2011 for the CAIR ozone-season
NOX program) and will not likely be completed until mid-
2012. At that time, EPA could begin the procedure of implementing,
state-by-state, the exchanges of the remaining CAIR NOX
allowance banks held by parties (owners and operators, brokers, and
other entities) for some or all of the allowances in the state
NOX budgets for 2012. The portion of each state budget that
would be used up by such exchanges would likely vary from state to
state. The resulting delay, and uncertainty about the unit-by-unit
amounts, of Transport Rule NOX allowance allocations for
2012 would undermine Transport Rule allowance market liquidity,
significantly disrupt planning by owners and operators for compliance
with allowance-holding requirements for the 2012 control periods, and
likely impose increased compliance costs under the Transport Rule
NOX trading programs or impact the ability to comply with
the 2012 limits.
In light of the specific circumstances in this case and the above-
described legal and technical problems that would result from a
carryover of CAIR NOX allowances into the Transport Rule
trading programs, the final rule does not allow any such carryover. EPA
agrees that, as a general principle, it is desirable to provide
continuity between sequential regulatory programs involving emission
trading and thereby to ensure that allowances in the past program
continue to have some value in the new program. Balancing the general
desirability of providing program continuity against the potential
negative consequences of a carryover in, and the specific circumstances
of, this case, EPA concludes that the carryover of banked CAIR
NOX allowances into the Transport Rule trading programs
should not be allowed. EPA notes that, in this case, it signaled the
possibility that it would take such an approach in order to provide
markets with full information and avoid unnecessary disruptions. After
CAIR was remanded by the Court in North Carolina, 550 F.3d 1176, in
December 2008, EPA was concerned about the future status of CAIR
NOX allowances and consequently advised the public--through
a statement posted on the EPA Web site in March, 2009--that ``EPA's
continued recording of CAIR NOX allowances does not
guarantee or imply that any allowances will continue to be usable for
[[Page 48325]]
compliance after a replacement rule is finalized or that they will
continue to have value in the future.'' \120\ EPA believes its decision
to disallow carryover of banked allowances here reflects the specific
factors in this case and should not be treated as setting any precedent
for the treatment, in any future trading programs, of any past trading
program's banked allowances.
---------------------------------------------------------------------------
\120\ http://epa.gov/airmarkets/business/cairallowancestatus.html. EPA posed similar statements in the on-
line systems for trading CAIR NOX allowances. See 40 CFR
96.102 and 96.302 (definitions of ``CAIR NOX Allowance
Tracking System'' and ``CAIR NOX Ozone Season Allowance
Tracking System'').
---------------------------------------------------------------------------
However, EPA notes that, under the CAIR ozone-season NOX
trading program, where unused allowances were carried forward from the
preceding NOX Budget Trading Program, and under the CAIR
annual NOX trading program, where extra allowances (from the
compliance supplement pool) were allocated for early reductions made
during the NOX Budget Trading Program, the vast majority of
allowance allocation decisions were made by the states administering
these programs. Moreover, a number of states did not allocate CAIR
allowances to their sources using fuel adjustment factors, whose use
the Court rejected in North Carolina in connection with EPA's setting
of state NOX emission budgets.
In light of the general desirability of providing continuity
between state programs, states may want to address the CAIR
NOX banks when developing, in SIP revisions, the Transport
Rule allowance allocations for control periods after 2012. EPA
encourages each state that wants to allocate Transport Rule
NOX allowances through SIP revisions to consider using
information on the CAIR NOX allowance banks that will remain
after 2011. Any such allowance allocations, of course, must be within
the respective state's NOX trading budget, and must be
submitted to EPA within the applicable submission deadlines,
established in the final rule for the control periods for which the
allocations are made. The Agency intends to contact states concerning
the desirability of holding a workshop to discuss issues related to
state allowance allocations.
B. Interactions With NOX SIP Call
The proposed rule explained that states covered by both the
NOX SIP Call and the Transport Rule would be required to
comply with the requirements of both rules and that the Transport Rule
would not preempt or replace the requirements of the NOX SIP
Call. Most, but not all, NOX SIP Call states would be
included in the Transport Rule. The proposed rule further explained
that the Transport Rule ozone-season NOX trading program
would achieve the emission reductions required by the NOX
SIP Call from EGUs serving generators with a nameplate capacity greater
than 25 MW and producing electricity for sale in most NOX
SIP Call states. (This would not be the case, of course, for those
NOX SIP Call states not covered by the Transport Rule.)
The NOX SIP Call states used the NOX Budget
Trading Program to comply with the NOX SIP Call requirements
for EGUs serving a generator with a nameplate capacity greater than 25
MW and large non-EGUs with a maximum rated heat input capacity greater
than 250 mmBtu/hour. (In some states, EGUs serving a generator with a
nameplate capacity of 25 MW or less were also included in the
NOX Budget Trading Program as a carryover from the Ozone
Transport Commission NOX Budget Trading Program.) EPA
stopped administering the NOX Budget Trading Program under
the NOX SIP Call after the completion of compliance
activities related to the 2008 ozone-season control period, and states
used other mechanisms to comply with the NOX SIP Call
requirements.
The proposal further explained that, if EPA promulgated a final
rule that did not allow the expansion of the Transport Rule to
NOX Budget Trading Program units, any state that allowed
these units to participate in the CAIR ozone-season NOX
trading program would need to submit a SIP revision to address the
state's NOX SIP Call requirement for the reductions. The
proposal also explained that states in the CAIR ozone-season
NOX trading program or the NOX Budget Trading
Program that would not be in the Transport Rule ozone-season
NOX trading program would need to submit SIP revisions
addressing the NOX SIP Call requirements for any emission
reductions (by EGUs and non-EGUs) addressed in the NOX
Budget Trading Program and not addressed in some other way. See 75 FR
45340-41.
As discussed elsewhere in this preamble, the final Transport Rule
allows states to expand the general applicability provisions of the
Transport Rule ozone-season NOX trading program to include
small EGUs, which were included by some states in the NOX
Budget Trading Program, but not for large non-EGUs, which were included
in the NOX Budget Trading Program. This will allow states
with NOX SIP Call obligations to meet those requirements
with respect to small EGUs brought into the Transport Rule trading
program, but not with regard to large non-EGUs.
With the issuance of the final Transport Rule, NOX SIP
Call requirements remain in place. See 40 CFR 51.121. EPA is not
changing any of the NOX SIP Call requirements. The
NOX SIP Call generally requires that states choosing to rely
on large EGUs and large non-EGUs for meeting NOX SIP Call
emission reduction requirements must establish a NOX mass
emissions cap on each source and require Part 75, subpart H monitoring.
As an alternative to source-by-source NOX mass emissions
caps, a state may impose NOX emission rate limits on each
source and use maximum operating capacity for estimating NOX
mass emissions or may rely on other requirements that the state
demonstrates to be equivalent to either the NOX mass
emissions caps or the NOX emission rate limits that assume
maximum capacity. Collectively, the caps or their alternatives cannot
exceed the portion of the state budget for those sources. See 40 CFR
51.121(f)(2) and (i)(4). EPA will work with states to ensure that
NOX SIP Call obligations continue to be met (e.g., through
intrastate cap and trade programs that require the level of reductions
on which the state has recently relied).
C. Interactions With Title IV Acid Rain Program
The final rule does not affect any Acid Rain Program requirements.
Acid Rain Program requirements are established independently in Title
IV of the CAA and are not replaced by the Transport Rule. Title IV
sources that are subject to final Transport Rule provisions still need
to continue to comply with all Acid Rain provisions. Title IV
SO2 and NOX requirements continue to apply
independently of the Transport Rule provisions. For the reasons
explained above, Title IV SO2 allowances are not allowed to
be used in the Transport Rule trading programs. Similarly, Transport
Rule SO2 allowances are not usable in the Acid Rain Program.
The final Transport Rule does not include any opt-in unit
provisions in the FIPs and does not allow SIP revisions to include opt-
in unit provisions in the Transport Rule trading programs.
Consequently, no sources, including those that have opted in to the
Acid Rain Program, can opt-in to the Transport Rule trading programs.
There will likely be changes to emissions at some Acid Rain units
outside of the Transport Rule area as a result of the transition from
CAIR to the Transport Rule. Namely, emissions at some non-Transport
Rule Acid Rain
[[Page 48326]]
units in the states that border the Transport Rule states may increase
because of potential load-shifting from units in Transport Rule states
and because of a potential decrease in the Title IV allowance price.
There is a discussion of possible emission increases in non-covered
states in section VI.C of this preamble.
D. Other State Implementation Plan Requirements
In this final action, EPA has not conducted any technical analysis
to determine whether compliance with the Transport Rule would satisfy
RACT requirements for EGUs in any nonattainment areas, or Regional Haze
BART-related requirements. For that reason, EPA is neither making
determinations nor establishing any presumptions that compliance with
the Transport Rule satisfies any RACT or BART-related requirements for
EGUs. Based on analyses that states conduct on a case-by-case basis,
states may be able to conclude that compliance with the Transport Rule
for certain EGUs fulfills nonattainment area RACT requirements. EPA
intends to undertake a separate analysis to determine if compliance
with the Transport Rule would provide sufficient reductions to satisfy
BART requirements for EGUs in accordance with Regional Haze Rule
requirements for alternative BART compliance options as soon as
practicable following promulgation of the Transport Rule.
X. Transport Rule State Implementation Plans
EPA proposed (75 FR 45342) FIPs setting state-specific emission
reduction requirements for each upwind state covered by the proposed
Transport Rule and with respect to one or more of three air quality
standards--the 1997 annual PM2.5 NAAQS, the 2006 24-hour
PM2.5 NAAQS, and the 1997 ozone NAAQS. In CAIR, EPA allowed
the states to replace the CAIR FIP with SIPs and provided substantial
flexibility. In the proposed Transport Rule, EPA proposed to allow
similar flexibility to states for addressing the CAA section
110(a)(2)(D)(i)(I) transport issues through a SIP. EPA proposed to
allow a state to submit a SIP for the ozone requirements only, for the
PM2.5 requirements only, or for both the ozone and the
PM2.5 requirements with the specific quantity of emission
reductions necessary for a state's SIP determined based on the state
emission budgets provided in the final Transport Rule.
EPA received comments suggesting that if the proposal's remedy were
finalized, EPA should allow states to replace the FIP allowance
allocation provisions in the proposed Transport Rule trading programs
by state-developed allocation provisions. Commenters referenced the two
alternatives provided to states in the CAIR trading programs where: (1)
EPA adopted a rule and model trading regulations under which states
that adopted, as state SIP trading programs, the model regulations
(with only certain limited changes allowed, e.g., in the allocation
provisions) could participate in the EPA-administered CAIR trading
programs; and (2) EPA adopted a rule allowing states to adopt in SIPs
provisions replacing only certain provisions in the CAIR FIPs (e.g.,
the allocation provisions) and to remain in the CAIR trading programs
under the CAIR FIPs. Under both approaches, the covered units in the
state participated in the CAIR trading programs, albeit with state-,
rather than EPA-, determined allocations. Comments on the Transport
Rule proposal supported these two types of approaches for allowing
states to replace EPA allocations under the proposed Transport Rule
trading programs by state allocations. EPA requested additional comment
on this topic in the NODA published January 7, 2011 (76 FR 1109).
Two approaches with associated deadlines were explained in the
NODA. Under the first approach, EPA would adopt new provisions, as part
of the proposed Transport Rule FIP that would allow a state to submit a
SIP (referred as an abbreviated SIP) that would modify specified
provisions of the proposed Transport Rule FIP trading programs.
Specifically, the abbreviated SIP would substitute state allocation
provisions for control periods in years after 2012, applicable to one
or more of the proposed Transport Rule FIP trading programs that apply
to the state. The NODA explained which specific provisions in the FIP
could be replaced. If the state allocation provisions met certain
requirements and the abbreviated SIP did not change any other
provisions in the respective proposed Transport Rule FIP trading
program, then EPA would approve the abbreviated SIP. In the substitute
state allocation provisions, the state could allocate allowances to
Transport Rule units (whether existing or new units) or other entities
(such as renewable energy facilities) or could auction some or all of
the allowances. The NODA went on to describe the requirements for EPA
approval of an abbreviated SIP (76 FR 1119) including that the total
amount of allowances allocated and auctioned each year could not exceed
the applicable budget; allocations and auction results would need to be
reported to EPA by the permitting authority (usually the state) by
particular dates prior to the applicable control period depending on
whether allowances were going to existing or new sources; the reported
allocations and auction results could not be changed; and no other
provisions of the FIP would be changed.
Under the second approach, EPA would adopt a new rule that would
provide that, if a state submitted a SIP (referred to as a full SIP)
that adopted trading program regulations meeting certain requirements
for control periods in years after 2012, then EPA would approve the
full SIP as correcting the deficiency under CAA section
110(a)(2)(D)(i)(I) in the state's SIP that was the basis for issuance
of the comparable proposed Transport Rule FIP. In the state allocation
provisions, the state could allocate allowances to Transport Rule units
(whether existing or new units, except for opt-in units) or other
entities (such as renewable energy facilities) or could auction
allowances. Upon EPA approval of a state's full SIP, the state's SIP-
based trading program would be integrated with the comparable FIP-based
Transport Rule trading program (whether or not modified by an
abbreviated SIP) covering other states. Moreover, covered sources in
the state could participate in the integrated trading program, and the
allowances issued under the SIP-based state trading program would be
interchangeable with the allowances issued in the comparable FIP-based
Transport Rule trading program.
The NODA went on to describe the limited changes that states could
make under the full SIP option. Only allocation provisions could be
modified with the same requirements as for abbreviated SIPs, including,
among other things, that the total amount of allowances allocated each
year could not exceed the applicable budget and that allocations would
need to be reported to EPA by the permitting authority (usually the
state) by particular dates prior to the applicable control period
depending on whether allowances were going to existing or new sources.
The NODA also discussed the option for states to submit SIPs using
emission reduction approaches other than the proposed Transport Rule
trading programs to correct the deficiency under CAA section
110(a)(2)(D)(i)(I) in the state's SIP. EPA would review on a case-by-
case basis SIPs using such alternative approaches (76 FR 1120).
Suggested deadlines for abbreviated and full SIPs were given in
tables in the
[[Page 48327]]
NODA (76 FR 1120). These deadlines generally required states to submit
SIPs about 2 years ahead of a particular control period for which state
allocations would apply in order to give EPA time to review and approve
the SIP and record allowances.
Most commenters on the NODA supported state allocation options,
within the preferred FIP remedy, that would replace FIP allocations
with SIP-based state allocations.
In the final rule, EPA adopts, with some revisions, both of the
approaches described in the January 7, 2011 NODA. Under the first
approach, a state may submit an abbreviated SIP that modifies a final
Transport Rule FIP trading program in only a limited way (i.e., by
replacing the allowance allocation provisions in Sec. Sec. 97.411(a)
and (b)(1) and 97.412(a) for the annual NOX trading program,
Sec. Sec. 97.511(a) and (b)(1) and 97.512(a) for the ozone-season
NOX trading program, Sec. Sec. 97.611(a) and (b)(1) and
97.612(a) for the SO2 Group 1 trading program, and
Sec. Sec. 97.711(a) and (b)(1) and 97.712(a) for the SO2
Group 2 trading program). In the state's replacement provisions, the
state may allocate allowances to Transport Rule units (whether existing
or new units) \121\ or other entities (such as renewable energy
facilities) or may auction allowances. Additionally, state SIPs can
address one or all of the pollutants addressed by the FIPs. For
PM2.5, EPA is finalizing the flexibility for a state SIP to
address either SO2 or NOX, or both. Further, if a
state is required to make ozone-season and annual NOX
reductions, the SIP could address either ozone-season or annual
NOX emissions, or both. In other words, states can replace
provisions in all FIPs that apply or some subset of the FIPs that apply
to a particular state, and leave in place the FIPs for the requirements
not addressed by a SIP.
---------------------------------------------------------------------------
\121\ EPA is not finalizing opt-in provisions, so the reference
to federal-only opt-in allocations in the NODA has been removed.
---------------------------------------------------------------------------
Further, EPA will approve the abbreviated SIP only if the state
replacement for the Transport Rule FIP allocation provisions meets
certain requirements and the abbreviated SIP does not change any other
provisions in the Transport Rule FIP trading program. For EPA approval,
the state allocation and, where applicable, auction provisions (and any
accompanying definitions of terms applying only to terms as used in
these provisions) must meet the following requirements. First, the
provisions must provide that, for each year for which the state
allocation and, where applicable, auction provisions will apply, the
total amount of control period (annual or ozone-season) allowances
allocated and, where applicable, auctioned in accordance with these
provisions cannot exceed the applicable state budget (less any
applicable Indian country new unit set-aside, which will continue to be
administered by EPA) for that year under the relevant Transport Rule
FIP trading program.
Second, to the extent the state provisions provide for allocations
for, or auctions open to, existing units, the provisions must require
that the state or the permitting authority under title V of the CAA for
the state submit to the Administrator final allocations and, if any
auction is to be held, final auction results in accordance with a
schedule of deadlines discussed below. To the extent the provisions
provide for allocations for or auctions open to new units or any other
entities, the provisions must require that the permitting authority
submit to the Administrator final allocations and, if applicable,
auction results by July 1 of the year of the control period for which
the allowances will be distributed. The allocation and auction results
must be final and cannot be subject to modification (e.g., through an
allowance surrender adjusting the allocation or auction results).
As noted above, the state's submission to the Administrator of
allocations or auction results with regard to existing units must meet
a specified schedule of deadlines. These submission deadlines reflect,
and are necessarily coordinated with, the deadlines for recordation by
the Administrator of allowance allocations and any auction results
under the Transport Rule trading programs. The recordation deadlines,
which are discussed in detail in section XI of this preamble, provide
that the Administrator must record existing-unit allowance allocations
and auction results by: July 1, 2013 for the applicable control periods
in 2014 and 2015; July 1, 2014 for the applicable control periods in
2016 and 2017; July 1, 2015 for the applicable control periods in 2018
and 2019; and July 1, 2016 and July 1 of each year thereafter for the
control period in the fourth year after the year of the applicable
recordation deadline. In order to provide the Administrator 1 month to
review the submissions of allocations and auction results to ensure
that the submissions include sufficient information (e.g., the correct
identification for each unit involved) to record correctly the
submitted allocations and auction results, the state or permitting
authority must make these submissions to the Administrator by: June 1,
2013 for the applicable control periods in 2014 and 2015; June 1, 2014
for the applicable control periods in 2016 and 2017; June 1, 2015 for
the applicable control periods in 2018 and 2019; and June 1, 2016 and
June 1 of each year thereafter for the applicable control period in the
fourth year after the year of the applicable submission deadline.
Under the second approach, a state may submit a full SIP adopting a
Transport Rule trading program that differs from the comparable
Transport Rule FIP trading program only with regard to limited
provisions of the FIP trading program. First, the full SIP may include
new allocation or auction provisions instead of the Transport Rule FIP
allowance allocation provisions other than those concerning the Indian
country new unit set-aside. In the state allocation or auction
provisions, the state may allocate allowances to Transport Rule units
(whether existing or new units) or other entities (such as renewable
energy facilities) or may auction allowances. EPA will approve the full
SIP only if the state allocation or auction provisions (and any
accompanying definitions of terms applying only to terms as used in
these provisions) meet certain requirements. Second, the full SIP may
substitute the name of the state for the term ``State'' as used in the
FIP trading program provisions, provided that EPA determines that the
substitutions are not substantive changes. Third, as discussed in more
detail below, all references to units in Indian country, as used in the
FIP trading program provisions, must be removed, and the full SIP
cannot impose any requirements on units in Indian country within the
borders of the state and may not include the Indian country set-aside
provisions. Other than these allowed changes, all other provisions in
the Transport Rule trading program in the full SIP must be the same as
those in the Transport Rule FIP trading program with regard to non-
Indian country units. For EPA approval, the state allocation provisions
must meet the same requirements, as discussed above, that state
allocation or auction provisions in an abbreviated SIP must meet.
A Transport Rule trading program adopted by a state in a full SIP,
and approved by EPA, under the second approach will be fully integrated
with the comparable Transport Rule FIP trading program (i.e., the ``TR
NOX Annual Trading Program'', ``TR NOX Ozone
Season Trading Program'', ``TR SO2 Group 1 Trading
Program'', or ``TR SO2 Group 2 Trading Program''
[[Page 48328]]
respectively) for other states. This will apply whether the comparable
Transport Rule FIP program for other states was modified by an
abbreviated SIP approved by EPA under the first approach or was not
modified by such an abbreviated SIP. The integration of these three
types of trading programs will be accomplished primarily through the
definitions of the terms, ``TR NOX Annual allowance'', ``TR
NOX Ozone Season allowance'', ``TR SO2 Group 1
allowance'', and ``TR SO2 Group 2 allowance'' in the full
SIPs approved by EPA and the TR FIP trading programs (whether or not
the programs were modified by abbreviated SIPs). ``TR NOX
Annual allowance'' will be defined in the state and Transport Rule FIP
trading programs as including allowances issued under any of the
following trading programs: The comparable EPA-approved state Transport
Rule trading programs; the comparable Transport Rule FIP trading
programs with EPA-approved state allocation and auction provisions; and
the Transport Rule FIP trading programs with EPA allocation provisions.
Similarly, the definitions in the state and Transport Rule FIP trading
programs of ``TR NOX Ozone Season allowance'', ``TR
SO2 Group 1 allowance'', and ``TR SO2 Group 2
allowance'' respectively will include allowances issued under all three
types of trading programs. As a result, allowances issued in one
approved state Transport Rule trading program will be interchangeable
with allowances issued in the comparable Transport Rule FIP trading
program (whether or not modified by an abbreviated SIP), and all these
allowances will be available for use for compliance with the allowance-
holding requirements (to cover emissions and to meet assurance
provision requirements) in all three types of trading programs.
The integration of state and the proposed Transport Rule FIP
trading programs will also be reflected in the definitions of ``TR
NOX Annual Trading Program,'' ``TR NOX Ozone
Season Trading Program'', ``TR SO2 Group 1 Trading
Program'', and ``TR SO2 Group 2 Trading Program''. Each of
these definitions in the state Transport Rule and Transport Rule FIP
trading programs will expressly encompass the comparable Transport Rule
FIP trading programs (whether or not modified by an abbreviated SIP)
and the comparable EPA-approved state full SIP trading program.
The final rule also sets deadlines for the submission of complete
abbreviated and full SIPs. These deadlines are based on the first year
for which the state wants to allocate or auction allowances, reflect
the above-discussed deadlines for the Administrator's recordation of
allocations and auction results, and build in a 6-month period for EPA
review, provision of notice and opportunity for public comment, and
approval of the SIP revisions. This 6-month period is built into the
final rule's SIP submission deadlines because that is the period EPA
found was needed for reviewing, providing notice and comment for, and
approving state trading program provisions in abbreviated and full SIPs
under CAIR. As a result, the final rule requires that complete
abbreviated and full SIPs must be submitted to the Administrator by:
December 1, 2012 in order to govern allowance allocation and auction
for control periods in 2014 and 2015; December 1, 2013 in order to
govern control periods in 2016 and 2017; December 1, 2014 in order to
govern allowance allocation and auction for control periods in 2018 and
2019; and December 1, 2015 and by December 1 of any year thereafter in
order to govern allowance allocation and auction for control periods in
the fifth year after such submission deadline.
EPA notes that, in cases where a state that has Indian country
within its borders submits, and EPA approves, a full SIP, the
comparable FIP will not be entirely replaced. In such cases, the FIP
will continue to be in place with regard to the Transport Rule trading
program provisions that concern units in Indian country, and the full
SIP will encompass all other provisions of the trading program.
Specifically, to the extent Transport Rule trading program provisions
reference and apply to Indian country units (including, for example,
references in the applicability provisions and the Indian country new
unit set-aside provisions), those provisions, as they apply to Indian
country units, will remain in the FIP. The full SIP will include those
provisions only as they apply to non-Indian country units.
As a practical matter, this means that the Indian country new unit
set-aside provisions, which apply exclusively to Indian country new
units, will remain entirely in the FIP. Further, other trading program
provisions that reference both non-Indian country units and Indian
country units (such as the applicability provisions) will remain in the
FIP to the extent of their application to Indian country units and will
be included in the full SIP to the extent of their application to non-
Indian country units.
However, EPA notes that the assurance provisions in each Transport
Rule trading program require calculations using the entire state
budget, including any portion of the budget that may be allocated to
Indian country new units. Further, EPA notes that currently no new
units are planned or anticipated to be located in Indian country. Under
these circumstances, EPA will handle the assurance provisions as
follows. The full SIP for a state having Indian country will initially
include the assurance provisions, as set forth in the FIP, except with
removal of any references to sources and units in Indian country. The
FIP will initially not include the assurance provisions, which will be
fully effective and enforceable under the full SIP. In the event that
any new unit is located in Indian country in the state, EPA intends to
modify its approval of the full SIP to take back the assurance
provisions in order to apply, in the FIP, the assurance provisions to
both Indian country and non-Indian country units.
This final rule not only allows a state to choose to submit an
abbreviated or a full SIP; it also allows a state to choose to submit
either form of SIP to replace any or all of the FIPs in this rule as
they apply to a particular state. By promulgating these Transport Rule
FIPs, EPA in no way affects the right of a state to submit, for review
and approval, a SIP that replaces the federal requirements of the FIP
with state requirements that do not involve state participation in the
Transport Rule trading programs. In order to replace the FIP in a
state, the state's SIP taking an approach other than participation in
Transport Rule trading programs must provide adequate provisions to
prohibit NOX and SO2 emissions that are
determined in the Transport Rule to contribute significantly to
nonattainment or interfere with maintenance in another state or states.
EPA will review such a SIP on a case-by-case basis. The Transport Rule
FIPs remain fully in place in each covered state until a state's SIP is
submitted and approved by EPA to revise or replace a FIP.
In response to numerous comments urging EPA to allow states to
determine allowance allocations as soon as possible, EPA has developed
a SIP revision procedure that applies to 2013 allowance allocations
only. In developing this procedure, EPA is balancing the desire to
allow states the flexibility to tailor allowance allocations to the
specific needs and situations in a particular state with the need to
provide certainty to source owners and operators by having allowances
recorded sufficiently ahead of the control period for which the
allocations are made in order to facilitate owners'
[[Page 48329]]
and operators' efforts to optimize their compliance strategies. This
final rule allows states to make 2013 allowance allocations through the
use of a SIP revision that is narrower in scope than the other SIP
revisions states can use to replace the FIPs and/or to make allocation
decisions for 2014 and beyond. For 2013 allocations, the scope of the
SIP revision is limited to allocations made to units that commence
commercial operation before January 1, 2010 and provided in the form of
a list of those units and their corresponding allocations for 2013.
Additionally, this particular SIP revision may allocate only the
portions of the state budgets set forth in Tables X-1 through X-3,
i.e., each state budget minus the new unit set-aside and the Indian
country new unit set-aside.
In developing this procedure, EPA set deadlines for submissions of
the SIP revisions for 2013 allocations and for recordation of the
allocations that balanced the need to record allowances sufficiently
ahead of the control period with the desire to allow state flexibility
for 2013. EPA set deadlines that will allow sufficient time for EPA to
review and approve these SIP revisions, taking into account that EPA
approval must be final and effective before the 2013 allocations can be
recorded and the allowances are available for trading. In order to
ensure that EPA review and approval (which must include public notice
and opportunity for comment) can be completed in time, the final rule
necessarily limits the allowed scope of the SIP revisions for 2013
allocations, as set forth in the requirements discussed below, and
thereby limits the issues that must be considered and addressed in the
review and approval process. Further, the final rule prescribes the
form in which the state allocations for 2013 must be provided to EPA in
order to facilitate rapid recordation of the allocations upon their
approval.
States, along with their sources, will need to weigh the trade-offs
of a relatively short period of recording before the control period for
which the allocation is made (about 6 months) with the desire to have
state allocations in 2013, when deciding whether to pursue a SIP
revision for 2013 allocations. States may choose to submit a SIP
revision for one or more of the trading programs. In other words, state
allocations for 2013 could apply in one trading program while 2013 FIP
allocations apply in another.
States can make 2013 allowance allocations provided the state meets
certain requirements.
By the date 70 days after publication of the final rule in
the Federal Register, a state must provide notification to EPA if the
state intends to submit state allocations for 2013. The notification
must be in a format prescribed by the Administrator and submitted
electronically.
By April 1, 2012, the state must submit a SIP revision to
EPA that:
[cir] Allocates to existing units \122\ only, provides a list of
the units and their state allocations to EPA electronically and in a
format prescribed by EPA, and does not provide for any change in the
units and allocations on the list and in any allocation previously
determined and recorded by the Administrator;
---------------------------------------------------------------------------
\122\ Existing unit means a unit that commenced commercial
operation before January 1, 2010.
---------------------------------------------------------------------------
[cir] Allocates a total amount of allowances for 2013 that does not
exceed the applicable amount in Tables X-1 through X-3 for each trading
program that applies in that particular state; and
[cir] Provides for no set-asides and does not alter the new unit
set-asides, the Indian country new unit set-asides, and any aspect of
the FIP rules other than the existing-unit allocations for 2013.
If EPA does not receive notification from a state by the date 70
days after publication of the final rule in the Federal Register, EPA
will record FIP allocations for 2012 and 2013 as scheduled (by the date
90 days after publication of the final rule). If EPA receives timely
notification from a state, EPA will record FIP allocations for 2012
only and wait to record 2013 allocations. If the state provides a
timely (not later than April 1, 2012) SIP revision meeting all the
above-described requirements and EPA approves the SIP revision by
October 1, 2012, EPA will record state-determined allocations for 2013
by October 1, 2012. Otherwise, EPA will record the EPA-determined
allocations for 2013.
BILLING CODE 6560-50-P
[[Page 48330]]
[GRAPHIC] [TIFF OMITTED] TR08AU11.008
[[Page 48331]]
[GRAPHIC] [TIFF OMITTED] TR08AU11.009
[[Page 48332]]
[GRAPHIC] [TIFF OMITTED] TR08AU11.010
BILLING CODE 6560-50-C
EPA will work with states that wish to submit full SIPs or
abbreviated SIPs to ensure a smooth integration with the relevant
Transport Rule trading programs. The Agency intends to provide
information and tools to assist states in their rulemaking efforts,
including electronic versions of the Transport Rule trading rules and
EPA will work with states that wish to submit full SIPs or abbreviated
SIPs to ensure a smooth integration with the relevant Transport Rule
trading programs. The Agency intends to provide information and tools
to assist states in their rulemaking efforts, including electronic
versions of the Transport Rule trading rules and other products states
feel may be helpful. States that submit approvable full SIPs or
abbreviated SIPs to implement one or all of the Transport Rule trading
programs are not required to include an additional technical
demonstration relating to elimination of emissions that contribute
significantly to nonattainment or contribute to maintenance in downwind
areas.
XI. Structure and Key Elements of Transport Rule Air Quality-Assured
Trading Program Rules
In order to make the final FIP trading program rules as simple and
consistent as possible, EPA designed them so that the final rules (like
the proposed rules) for each of the trading programs (i.e., the ``TR
NOX Annual Trading Program'', ``TR NOX Ozone
Season Trading Program'', ``TR SO2 Group 1 Trading
Program'', and ``TR SO2 Group 2 Trading Program'') are
parallel in structure and contain the same basic elements. For example,
the rules for the Transport Rule annual NOX, ozone-season
NOX, SO2 Group 1, and SO2 Group 2
trading programs are located, respectively, in subparts AAAAA
(Sec. Sec. 97.401, et seq.), BBBBB (Sec. Sec. 97.501, et seq.), CCCCC
(Sec. Sec. 97.601, et seq.), and DDDDD (Sec. Sec. 97.701, et seq.) of
Part 97 in Title 40 of the Code of Federal Regulations. Moreover, the
order of the specific provisions for each trading program is the same,
and the provisions have parallel numbering. The key elements of the
final Transport Rule trading program rules are as follows.
[[Page 48333]]
(1) General Provisions
(i) Sec. Sec. 97.402 and 97.403, 97.502 and 97.503, 97.602 and 97.603,
and 97.702 and 97.703--Definitions and Abbreviations
Most of the definitions in the final Transport Rule trading program
rules are essentially the same as in the proposed rules and for each of
the Transport Rule trading programs (except where necessary to reflect
the different pollutants (NOX and SO2), control
periods (for annual and ozone-season NOX, and for annual
SO2), and geographic coverage involved in the trading
programs). Moreover, many of the definitions in the final rules that
are essentially the same as in the proposed rule are also essentially
the same as in prior EPA-administered trading programs. However, as
discussed in more detail below, some of the definitions in the final
rules clarify, or differ from, the definitions in the proposed rule.
As noted, several definitions in the final rules are essentially
the same as those both in the proposed rules and in prior EPA-
administered trading programs. Examples include the definitions of
``source,'' ``allowance transfer deadline,'' ``owner,'' ``operator'',
``Allowance Management System'' (used instead of the term ``Allowance
Tracking System''), and ``continuous emission monitoring system.''
One example of a definition in the final rules that is the same as
in the proposed rule, but that clarifies the definition used in prior
trading programs is the definition of ``fossil fuel.'' In the final
rule, the term ``fossil fuel'' is defined in general as including
natural gas, petroleum, coal, or any form of fuel derived from such
material, regardless of the purpose for which such material is derived.
For example, with regard to consumer products that are made of
materials derived from natural gas, petroleum, or coal, are used by
consumers, and then are used as fuel, these materials in the consumer
products qualify as fossil fuel. The definition in the final rules also
includes language establishing a narrower meaning of ``fossil fuel''
that is not generally applicable, but rather is applicable only for
purposes of applying the limitation on fossil-fuel use under the solid
waste incineration unit exemption (which is discussed elsewhere in this
preamble). This latter portion of the ``fossil fuel'' definition makes
explicit an interpretation that EPA adopted in CAIR that--solely for
purposes of applying the fossil-fuel use limitation in that exemption--
the term ``fossil fuel'' is limited to natural gas, petroleum, coal, or
any form of fuel derived from such material ``for the purpose of
creating useful heat.'' For example, applying this narrower meaning,
consumer products made from natural gas, petroleum, or coal are not
fossil fuel, for purposes of determining qualification under the
fossil-fuel use limitation, because the products (e.g., tires) were
derived from natural gas, petroleum, or coal in order to meet certain
consumer needs (e.g., to meet transportation needs), not in order to
create fuel (i.e., material that would be combusted to produce useful
heat).
As noted above, some of definitions in the final rules clarify
definitions in the proposed rules. The definitions of ``allowable
NOX emission rate'' and ``allowable SO2 emission
rate'' are clarified by explaining that such a rate is the most
stringent state or federal emission rate limitation, expressed in lb/
MWhr or, if originally expressed in lb/mmBtu, converted to lb/MWhr by
multiplying it by the unit's heat rate in mmBtu/MWhr. This
clarification ensures consistency from unit to unit in determining a
unit's allowable rate.
By further example, while the proposed rules used the same
definition of ``commence commercial operation'' as in prior EPA-
administered trading programs, the final rules clarify the definition.
Under the definition in the proposed rules, a unit that is physically
changed is treated as the same unit. However, the proposed rules were
unclear about the treatment of a unit that is replaced and whether
moving a unit to a different location or source constitutes a physical
change. The definition of ``commence commercial operation'' in the
final rules clarifies that a unit that is physically changed (which
includes a unit that is replaced) continues to be treated, for purposes
of this final rule, as the same unit with the same commence-commercial-
operation date. The definition also clarifies that moving a unit to a
different location or source is treated the same as a physical change,
and so the unit continues to be treated as the same unit. The
definition also clarifies that a unit (the replaced unit) that is
replaced, whether at the same source or a different source, is treated
as the same unit, while the unit (the replacement unit) that replaces
the unit is treated as a separate unit with a new commence-commercial-
operation date. (The definition of ``commence operation'' is removed in
the final rules because they do not use this term.)
By further example, while the proposed rules used the same
definition of ``unit'' as in prior EPA-administered trading programs,
the final rules clarify the definition. The ``unit'' definition is
clarified by expanding it to incorporate explicitly the concepts--set
forth in the definition in the final rules of ``commence commercial
operation'' and thus already applicable to all units--that a unit that
is physically changed, moved to a different location or source, or
replaced at the same or a different source continues to be treated as
the same unit and that a replacement unit at the same source is treated
as a separate unit. EPA believes that it is preferable to provide a
comprehensive definition of ``unit'' in one place because the term is
used so frequently in the final rules.
By further example, the definition of ``nameplate capacity'' is
clarified in the final rules by explaining that it is expressed in MWe
rounded to the nearest tenth. This is the same rounding convention that
is used in the reporting of nameplate capacity to the Energy
Information Administration.
As noted above, some of the definitions in the final rules are
similar to those in the proposed rules but have some substantive
differences. For example, in the proposed rules, the definitions of
``cogeneration unit'' and ``fossil-fuel-fired'' are similar to those in
prior trading programs but with changes to minimize the need for data
concerning individual units or combustion devices for periods before
1990. In order to qualify as fossil-fuel-fired, a unit would have to
combust any amount of fossil fuel in 1990 or thereafter. In order to
qualify as a cogeneration unit, a unit would have to meet certain
efficiency and operating standards during the later of: the 12-month
period starting when the unit begins producing electricity, or 1990.
For a topping-cycle unit, useful power plus one-half of useful thermal
energy output of the unit must equal no less than a certain percentage
of the total energy input and useful thermal energy must be no less
than a certain percentage of total energy output, and, for a bottoming-
cycle unit, useful power must be no less than a certain percentage of
total energy input. EPA proposed to limit to 1990 or later the
historical period for which information on fuel consumption and on
cogeneration unit efficiency and operations would be required to apply
the ``fossil-fuel-fired'' and ``cogeneration unit'' definitions. This
limitation was proposed because EPA was concerned that some owners and
operators could have difficulty obtaining pre-1990 information about
older units, particularly for units whose ownership has changed over
time.
While EPA proposed to use 1990 as the earliest year for which
information
[[Page 48334]]
would be required under these definitions, EPA requested comment on
whether a more recent year should be used. As discussed elsewhere in
this preamble, the final rules use 2005 (about 5 years before this
rule's promulgation), rather than 1990, as the reference year. Further,
because the language describing the historical time period used
(including the reference year), appeared in the proposal both in the
``cogeneration unit'' definition and the provisions concerning
cogeneration units in the applicability provisions, the final rules
removed any language about the historical time period from the
``cogeneration unit'' definition and revised the language in the
applicability provisions to use the 2005 reference year for the
requirements for meeting the exemption for cogeneration units from the
Transport Rule trading programs. Further, consistent with this use of
2005 as the reference year, the ``fossil-fuel-fired'' definition in the
final rule specifically references 2005, rather than 1990, and as
discussed elsewhere in this preamble, the final rules also use January
1, 2005 (rather than November 15, 1990) as the reference date
throughout the applicability provisions.
With this change in the reference date for the requirement to meet
the operating and efficiency standards under the ``cogeneration unit''
definition, a unit would have to meet these standards throughout the
later of 2005 or the 12-month period starting when the unit begins
producing electricity and continuing thereafter. EPA requested comment
on whether these standards should be applied to a calendar year when
the unit involved did not combust any fuel, i.e., did not operate at
all. As discussed elsewhere in this preamble, the final rules expressly
provide that the operating and efficiency standards do not have to be
met for a calendar year throughout which a unit did not operate at all.
In addition, under the proposed rules, if a group of cogeneration
units operating as an integrated cogeneration system met the efficiency
standards, a topping-cycle unit in that system would be deemed to meet
those standards. EPA requested comment on whether this provision should
also apply to a bottoming-cycle unit. As discussed elsewhere in this
preamble, this provision in the final rules is not limited to topping-
cycle units.
By further example of definitions in the final rules that have
substantive differences from the definitions in the proposed rules, the
proposed definitions of ``TR NOX Annual allowance,'' ``TR
NOX Ozone Season allowance,'' ``TR SO2 Group 1
allowance,'' ``TR SO2 Group 1 allowance,'' ``TR
NOX Annual Trading Program,'' ``TR NOX Ozone
Season Trading Program,'' ``TR SO2 Group 1 Trading
Program,'' and ``TR SO2 Group 1 Trading Program'' are
changed in the final rules. Language is added to the definitions in
order to reference comparable allowances and trading programs
established through SIP revisions submitted by states and approved by
the Administrator. As discussed elsewhere in this preamble, the final
Transport Rule provides that, if a state submits SIP revisions meeting
certain specified requirements, the state or permitting authority
(rather than the Administrator) will allocate allowances, and the
covered sources in the state will participate--along with covered
sources in states remaining subject to the Transport Rule FIPs--in an
integrated, region-wide air quality-assured trading program under which
both any allowance allocated by the Administrator and any allowance
allocated by the state or permitting authority will each authorize one
ton of emissions of the relevant pollutant and will be usable by any
source for compliance with the requirement to hold allowances covering
emissions.
As noted above, the final rules include some definitions that were
not used in prior EPA-administered trading programs and that reflect
unique provisions of the Transport Rule trading programs. For example,
the terms, ``assurance account,'' ``TR NOX Annual unit,''
``TR NOX Ozone Season unit,'' ``TR SO2 Group 1
unit,'' ``TR SO2 Group 2 unit,'' ``common designated
representative,'' ``common designated representative's assurance
level,'' and ``common designated representative's share'' are used and
defined in the final rule.
While the proposed rules included definitions for the terms,
``owner's assurance level'' and ``owner's share,'' the final rules
replace these terms and instead define the terms, ``common designated
representative,'' ``common designated representative's assurance
level,'' and ``common designated representative's share.'' This is
because, as discussed elsewhere in this preamble, the final rules
include assurance provisions similar to those in the proposed rules but
that are implemented based on groups of units having a common
designated representative, instead of being implemented on an owner-by-
owner basis. The definition of ``common designated representative'' in
the final rules reflects that the determination of what groups of units
and sources in a State have a common designated representative is made
based on the identity of units' and sources' designated representatives
as of April 1 of the year after the year of the control period when a
state triggers the assurance provisions. EPA believes that the use of
this reference date will give owners and operators greater flexibility
to select common designated representatives after information about
total state control period emissions is available and after the
allowance transfer deadline when owners and operators may prefer to
have a designated representative for their specific source (rather than
a common designated representative for a larger group) who is focused
on ensuring that sufficient allowances are held in or transferred to
the source's account to cover the sources' emissions. EPA notes that
the definition of ``common designated representative's share'' is
simpler than the definition of ``owner's share'' because implementing
the assurance provisions at the designated representative level means
it is no longer necessary to address, in the definition, owner- and
unit-level issues that may arise when a unit has multiple owners or
where two or more units emit through the same stack.
Finally, some definitions are added to the final rules that are not
in the proposed rules. For example, because the term, ``business day,''
was used, but not defined, in the proposed rule, its meaning was
unclear. Specifically, it was unclear whether a day that was uniquely a
state holiday, and not a federal holiday, was a business day for
purposes of the federally administered Transport Rule trading programs,
e.g., whether the allowance transfer deadline applicable to all sources
in all states in a Transport Rule trading program could fall on a day
that was a unique state holiday in one or a few states or whether the
allowance transfer deadline would be advanced to the next business day
for all sources in all states or perhaps only for sources in the state
with the state holiday. EPA believes that, for a federally administered
trading program covering sources in multiple states, the deadlines
should be clear and uniform for all sources, regardless of the state in
which the sources are located, and should not be affected by unique
state holidays of which owners and operators of sources in other states
may not even be aware. Consequently, the ``business day'' definition is
added in the final rules and means a day that does not fall on a
weekend or a federal holiday.
By further example, a definition for ``natural gas'' was added in
the final rules. That definition, as well as the definition for
``coal,'' incorporate the
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corresponding definitions in Part 72 of the Acid Rain Program
regulations. The Part 72 definitions are incorporated because they are
also used in the Part 75 monitoring, reporting, and recordkeeping
provisions, which provisions are already incorporated in the final
Transport Rule Trading Program rules. (ii) Sec. Sec. 97.404 and
97.405, 97.504 and 97.505, 97.604 and 97.605, and 97.704 and 97.705--
Applicability and Retired Units
The applicability provisions in the final rules are, except as
discussed herein, essentially the same as in the proposed rules and for
each of the Transport Rule trading programs. Of course, for each
trading program, the definition of ``State'' reflects differences in
the specific states whose electric generating units are covered by the
respective trading program.
Under the general applicability provisions of the proposed rules,
the Transport Rule trading programs would cover fossil-fuel-fired
boilers and combustion turbines serving--at any time starting November
15, 1990 or later--an electrical generator with a nameplate capacity
exceeding 25 MWe and producing power for sale, with the exception of
certain cogeneration units and solid waste incineration units. As
discussed elsewhere in this preamble, the general applicability
provisions in the final rules reference January 1, 2005 (about 5 years
before this rule's promulgation), rather than November 15, 1990.
Cogeneration unit exemption. Under the final rules (as well as the
proposed rules) certain cogeneration units or solid waste incinerators
otherwise covered by the general category of covered units are exempt
from the FIP requirements. In particular, the final rules include an
exemption for a unit that qualifies as a cogeneration unit throughout
the later of 2005 or the first 12 months during which the unit first
produces electricity and continues to qualify throughout each calendar
year ending after the later of 2005 or such 12-month period and that
meets the limitation on electricity sales to the grid. In order to
qualify as a cogeneration unit (i.e., meet the definition of
``cogeneration unit'') in the final rules, a unit (i.e., a boiler or
combustion turbine) must operate as part of a ``cogeneration system,''
which is defined as an integrated group of equipment at a source
(including a boiler or combustion turbine, and a steam turbine
generator) designed to produce useful thermal energy for industrial,
commercial, heating, or cooling purposes and electricity through the
sequential use of energy. In addition, in order to qualify, a unit must
be a topping-cycle unit or a bottoming cycle unit because units that
produce useful thermal energy and useful power through sequential use
of energy either produce useful power first (i.e., are topping-cycle
units) or produce thermal energy first (i.e., are bottom-cycle units).
Further, in order to qualify as a cogeneration unit, a unit also
must meet, on a 12-month or annual basis, the above described
efficiency and operating standards. As discussed elsewhere in this
preamble, EPA clarifies that the electricity sales limitation under the
exemption is applied in the same way whether a unit serves only one
generator or serves more than one generator. In both cases, the total
amount of electricity produced annually by a unit and sold to the grid
cannot exceed the greater of one-third of the unit's potential electric
output capacity or 219,000 MWhr.
The final rules also clarify when a unit that meets the
requirements for the cogeneration unit exemption and subsequently fails
to meet all these requirements loses the exemption and becomes a
covered unit. Such a unit loses the exemption starting the earlier of
January 1 (or May 1 for the NOX ozone season trading
program) after the first year during which the unit no longer meets the
``cogeneration unit'' definition or January 1 (or May 1) of the first
year during which the unit no longer meets the electricity sales
limitation.
Solid waste incineration unit exemption. The final rules also
include an exemption for a unit that qualifies as a solid waste
incineration unit during the later of 2005 or the first 12 months
during which the unit first produces electricity, that continues to
qualify throughout each calendar year ending after the later of 2005 or
such 12-month period, and that meets the limitation on fossil-fuel use.
In contrast, the exemption for solid waste incineration units in the
proposed rules distinguished between units commencing operation before
January 1, 1985 and those commencing operation on or after that date
and established somewhat different criteria for these two categories of
units. As discussed elsewhere in this preamble, the final rules remove
the distinction based on whether a solid waste incineration unit
commences operation before January 1, 1985 or on or after January 1,
1985. In order to be exempt, the unit must qualify as a solid waste
incineration units during the later of 2005 or the first 12 months
during which the unit first produces electricity, must continue to
qualify throughout each calendar year ending after the later of 2005 or
such 12-month period, and must meet the limitation on fossil-fuel use
on a three-year average basis during the first 3 years of operation
starting no earlier than 2005 and every 3 years of operation
thereafter.
Retired unit exemption. The final rule provisions exempting
permanently retired units from most of the requirements of the
Transport Rule trading programs are essentially the same as in the
proposed rules and for each of the Transport Rule trading programs. The
retired unit provisions exempt these units from the requirements for
emission monitoring, recordkeeping, and reporting and for holding
allowances, as of the allowance transfer deadline, sufficient to cover
their emissions. However, the permanently retired units in a state must
be included in determining whether owners and operators must surrender
allowances, and, if so, how many, to comply with the assurance
provisions (which are discussed elsewhere in this preamble) if the
state's total covered-unit emissions exceed the state assurance level.
Specifically, a common designated representative must include these
units in determining whether his or her share of total emissions of
covered units in a state exceed his or her share (generally based on
the allowances allocated to the units that he or she represents) of the
state trading budget with the variability limit and thus whether the
owners and operators of the units that he or she represents have to
surrender allowances under the assurance provisions.
(iii) Sec. Sec. 97.406, 97.506, 97.606, and 97.706--Standard
Requirements
The basic requirements applicable to owners and operators of units
and sources covered by the Transport Rule trading programs and
presented as standard requirements in the final rules are, except as
discussed herein, essentially the same as in proposed rules and for
each of the Transport Rule trading programs. These basic requirements
include: designated representative requirements; emissions monitoring,
reporting, and recordkeeping requirements; emissions requirements
comprising emissions limitations and assurance provisions; permit
requirements; additional recordkeeping and reporting requirements;
liability provisions; and provisions describing the effect of the
Transport Rule trading program requirements on other CAA provisions.
In particular, the paragraphs addressing emissions requirements for
owners and operators describe these requirements in detail and
reference
[[Page 48336]]
other sections of the final rules that set forth the procedures for
determining compliance with the emissions limitations and assurance
provisions. The paragraphs in the final rules concerning compliance
with the emissions limitations clarify that owners and operators of a
source and each covered unit at the source must hold allowances at
least equaling the total control period emissions of all covered units
at the source. Further, the paragraphs in the final rules concerning
compliance with the assurance provisions differ from those in the
proposed rules in that, as discussed elsewhere in this preamble, the
final rules implement the assurance provisions based on groups of units
with a common designated representative, instead of being implemented
on an owner-by-owner basis, as proposed. Under the final rules, the
assurance provisions are triggered when total control period emissions
by covered units in a state (starting in 2012) exceed the state trading
budget plus variability limit. If the assurance provisions are
triggered for a state for a control period in a given year, owners' and
operators' responsibility for the resulting penalty (i.e., the
surrender of allowances for deduction through the transfer of such
allowances to the assurance account created by the Administrator for
such owners and operators) is determined on a common designated
representative basis.
For purposes of implementing the assurance provisions, covered
units in a state are in effect grouped by common designated
representative (which is defined as an individual (i.e., a natural
person) who is the designated representative, as distinguished from the
alternate designated representative, for a group of one or more units
and sources as of April 1 after the control period for which the state
exceeds the state assurance level). The control period emissions of all
covered units with a common designated representative are compared with
the allowance allocations of such units plus their share of the state
variability limit. The owners and operators of the units and sources in
each group that has emissions in excess of allocations plus share of
variability are subject to the assurance provisions penalty. The owners
and operators of the units and sources in each group must transfer to
the assurance account created for such owners and operators a total
amount of allowances equal to two times such owners' and operators'
proportionate share of the state's excess of covered-unit emissions
over the state trading budget plus variability.
The group's proportionate share is the percentage resulting from
division of the amount of the group's excess of emissions over
allocations plus share of variability by the sum of these excess
amounts for all groups of units with a common designated representative
in the state. The final rule makes it clear that this percentage is not
rounded to the nearest whole number, but rather that the calculated
amount of allowances resulting from application of this percentage is
rounded to the nearest whole number because, in the Transport Rule
trading programs, only whole (not fractional) allowances are used. If
instead this percentage were rounded before its application, each
group's share would be either 100 percent or 0 percent, which would be
contrary to the intent of the assurance provisions in both the final
rules and the proposed rules.
The provisions addressing the assurance requirements in the final
rules reflect this common-designated-representative-based approach. For
example, as discussed elsewhere in this preamble, these provisions use
the terms, ``common designated representative's share'' and ``common
designated representative's assurance level,'' in lieu of the terms,
``owner's share'' and ``owner's assurance level,'' used in the proposed
rules. By further example, these final rule provisions refer to both
``common designated representatives'' and ``owners and operators,''
rather than simply ``owners.''
The final rules also explain what vintage year (i.e., allocation
year) of allowances can be used in order to comply with the requirement
to cover emissions and with the requirements of the assurance
provisions. With regard to emissions during a control period in a given
year, only allowances allocated for that year or any prior year can be
used to cover such emissions. Further, only allowances of the following
vintage can be used to meet excess emissions penalties and assurance
penalties concerning emissions during a control period in a given year:
allowances allocated for that year, any year before that year, or the
year immediately after that year. This approach makes the vintage years
usable for excess emissions and assurance penalties consistent and
helps ensure that allowances will be available to meet these
obligations.
The final rules also clarify the standard emission requirements by
explaining further what is meant by the provision that an allowance is
a limited authorization to emit. The final rules clarify that an
allowance provides authorization to emit during the control period in
one year and is limited in both its use and its duration. For example,
each Transport Rule trading program's final rules state that an
allowance provides an emission authorization that can only be used in
accordance with the requirements of the respective trading program,
such as the requirements specifying what allowances are available for
use, and how such allowances must be held or transferred, in order to
cover emissions or meet the assurance provisions. By further example,
under the final rules, an allowance continues to provide an
authorization to emit one ton of the relevant pollutant until the
allowance is deducted, e.g., in order to be used for compliance with
the requirement to cover emissions or the requirements of the assurance
provisions. Moreover, under the final rules, the Administrator has the
express authority to terminate or limit the authorization to emit, and
thereby change the use and duration of the authorization, described in
the final rules, to the extent he or she determines to be necessary or
appropriate to implement any provision of the CAA.
The remaining paragraphs in the standard requirements section
address permitting, recordkeeping and reporting, liability provisions,
and the effect on other CAA provisions. For example, the paragraphs
concerning permitting requirements are limited to stating that no title
V permit revisions are necessary to account for allowance allocation,
holding, deduction, or transfer and that the minor permit modification
procedures can be used to add or change general descriptions in the
title V permits of the monitoring and reporting approach used by the
units covered by each title V permit. These provisions remain
essentially the same in the final rules as in the proposed rules.
(iv) Sec. Sec. 96.407, 97.507, 97.607, and 97.707--Computation of Time
These sections address how to determine the deadlines referenced in
the Transport Rule trading program rules and are, except as discussed
herein, essentially the same as in the proposed rules and for each of
the Transport Rule trading programs. The final rules revise the
proposed rule provisions concerning the treatment of the final date in
any time period in order to make the provision consistent with the
approach discussed above with regard to the new definition of
``business day.'' The revised provision states that, if the final date
is not a
[[Page 48337]]
``business day'', then the time period is extended to the next
``business day.''
(v) Sec. Sec. 97.408, 97.508, 97.608, 97.708 and Part 78--
Administrative Appeal Procedures
Under the final Transport Rule, final decisions of the
Administrator under the Transport Rule trading programs are appealable
to EPA's Environmental Appeals Board under the regulations set forth in
Part 78 (40 CFR part 78), which are revised by the final Transport Rule
to accommodate such appeals. The provisions in the final Transport Rule
concerning appeals are, except as discussed herein, essentially the
same as in the proposed Transport Rule. The proposed Transport Rule
would add a provision in Part 78 explaining who is an ``interested
person'' with regard to a decision, i.e., a person who submitted
comments, testimony, or objections as part of the process of making the
decision or a person who submitted his or her name to the Administrator
to be placed to an interested persons list. The final Transport Rule
includes that provision, but with additional language that clarifies
the process for submitting a name to be placed on such a list.
(2) Allowance Allocations
Sections 97.410 through 97.412, 97.510 through 97.512, 97.610
through 97.612, and 97.710 through 97.712 set forth: certain
information related to allowance allocation and for implementation of
the assurance provisions; the timing for allocation of allowances to
existing and new units; and the procedures for new unit allocations. In
particular, these sections include tables providing, for each state
covered by the particular Transport Rule trading program and for each
year, the state trading budget (without the variability limit), new
unit set-aside, Indian country new unit set-aside (where applicable),
and variability limit. These provisions in the final rules differ in
several ways, from the proposed rules and are essentially the same for
each of the Transport Rule trading programs.
With regard to the tables in the final rules for the state trading
budgets (without the variability limits), new unit set-asides, and
variability limits, the identity of the specific states involved and
the values for each state differ from the tables in the proposed rules.
The final rule values reflect the determinations and modeling
underlying the final rules and discussed elsewhere in this preamble.
Further, as discussed elsewhere in this preamble, the variability
limits are only those based on one-year variability and not those
proposed to be based on three-year variability, and Indian country set-
asides are shown for states with Indian country within their borders.
With regard to existing unit allocations, the final rules provide
that these allocations will be set forth in a notice of data
availability to be issued by the Administrator. In contrast, the
proposed rules stated that existing unit allocations would be set forth
in an appendix to the rules for each Transport Rule trading program.
EPA believes that including these allocations in a notice of data
availability referencing the EPA Web site (rather than publishing them
in tables requiring a large number of pages in the Federal Register for
each Transport Rule trading program) is a more efficient method of
making these allocations public, particularly since these allocations
may be changed for 2013 and thereafter by states through SIP revisions.
In addition, under the final rules the allocations for an existing unit
can change if the unit does not operate (i.e., has no heat input) for 2
consecutive years starting in 2012. In that case, the unit continues to
receive its existing unit allocation for those years plus only 2 more
years. As explained elsewhere in this preamble, this is a modification
of the proposed rules, under which a unit that did not operate for 3
consecutive years would continue to receive its existing unit
allocation for those years plus 3 more years.
Under the final rule provisions for new units, the Administrator
allocates allowances from the new unit set-aside for the state where
the respective unit is located and for each year when the unit first
becomes eligible for an allocation and each year thereafter. The units
eligible for new unit set-aside allocations include units commencing
commercial operation on or after January 1, 2010, as well as several
other categories of units, such as, for example, existing units that
were not initially but then become covered units, existing units whose
allocations are lost due to lack of unit operation and that
subsequently begin operating again, and units that lost their
allocations because they changed location from one state to another.
The approach in the final rules differs from the proposed rules, which
required that owners and operators initially request allowances from
the new unit set-aside when the unit first became eligible for an
allocation. As discussed elsewhere in this preamble, under the final
rules, EPA identifies which units become eligible and when they become
eligible, based on information provided in other submissions (e.g.,
certificates of representation, monitoring system certifications, and
quarterly emissions reports) that such units must make to EPA, and the
requirement that owners and operators submit requests for new unit set-
aside allocations is removed in the final rules.
The final rules also provide for two rounds of allocations from the
new unit set-aside, in contrast with the proposed rules that provided
for only one round. In the first round in the final rules (as in the
single round in the proposed rules), a unit's new unit set-aside
allocation initially equals that unit's emissions--as determined in
accordance with Sec. Sec. 97.430-97.435, 97.530-97.535, 97.630-97.635,
and 97.730-97.735 of the final rules and Part 75 (40 CFR part 75)--for
the control period (annual or ozone season, depending on the Transport
Rule trading program involved) in the preceding year. If the new unit
set-aside lacks sufficient allowances to provide this initial
allocation for all of the new units, then each new unit is allocated
its proportionate share (based on its initial allocation amount) of the
allowances in the new unit set-aside. The Administrator issues a notice
of data availability informing the public of the specific new unit
allocations and provides an opportunity for submission of objections on
the grounds that the allocations are not consistent with the
requirements of the relevant final rule provisions. A second notice of
data availability is subsequently issued in order to make any necessary
corrections in the specific new unit allocations. As discussed
elsewhere in this preamble, the final rules establish a somewhat
different schedule for issuance of these notices of data availability
than the proposed rules. In particular, a single set of dates (i.e.,
for the first notice, June 1 of the year for which the new unit
allocations are described in the notice and, for the second notice,
August 1 of that year) is established for all of the Transport Rule
trading programs. For the reasons discussed elsewhere in this preamble,
the final rules provide for a second round of allocations to the extent
that any allowances remain in the new unit set-aside after the
allocations are made to new units in the first round. (In the proposed
rules, remaining allowances were immediately allocated to existing
units.) The units eligible for allocations in the second round are new
units that commenced commercial operation during the control period for
which allocations are being made and during the prior control period.
The second round allocation for each such unit initially equals the
positive difference (if any) between the unit's
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first round allocation (if any) and the unit's emissions during the
control period for which allocations are being made. If the amount of
allowances remaining in the new unit set-aside after the first round is
insufficient to provide this initial allocation for all of the second
round new units, then each such new unit is allocated its proportionate
share of the allowances remaining in the new unit set-aside. The
Administrator uses notices of data availability (which are issued by
December 15 (for the annual trading programs) and September 15 (for the
ozone season trading program) of the control period involved and
February 15 (for the annual trading programs) and November 15 (for the
ozone season trading program) before the allowance transfer deadline
for the control period involved, in a manner analogous to the use of
such notices in the first round, to inform the public about the
identification of the new units in the second round allocations and
obtain and consider any objections. The February 15 and November 15
notices also inform the public about the amounts of the second round
allocations. If, after both rounds of allocations, any allowances
remain in the new unit set-aside, those allowances are allocated to
existing units in proportion to such units' allocations.
The final rules also establish a separate Indian country new unit
set-aside in each state where Indian country is located (i.e., in
Florida, Iowa, Kansas, Louisiana, Michigan, Minnesota, Mississippi,
Nebraska, New York, North Carolina, South Carolina, Texas, and
Wisconsin). As discussed elsewhere in this preamble, the Administrator
operates the Indian country new unit set-aside in essentially the same
manner as state new unit set-aside, except that unallocated allowances
remaining in the Indian country new unit set-aside after the two rounds
of new unit set-aside allocations are first placed in the new unit set-
aside in the state where the Indian country involved is located and
then, if still unallocated, are allocated to existing units in the
state. As with the state new unit set-aside, EPA will identify the new
units qualifying for the Indian country new unit set-aside, calculate
the allocations, and issue notices of data availability using the same
schedules as notices for the state new unit set-aside.
Under the final rules (like under the proposed rules), if a unit in
certain specified categories is allocated allowances that should not
have received them, the Administrator applies procedures under which
the allocation is not recorded or the amount of the recorded
allocations is deducted as an incorrect allocation, with one exception.
The exception is where the determination of compliance with the
emissions limitation (i.e., requirement to hold allowances covering
emissions, as distinguished from the assurance provisions) for the
source that includes the unit has already been completed, in which case
no action is taken to account for the erroneous allocation for the
control period involved.
While this procedure concerning recordation or deduction of
allocations is the same as under the proposed rules, the final rules
change the description of the circumstances under which this procedure
concerning recordation or deduction of allocations is applied. Under
both the final rules and the proposed rules, this procedure is applied
to a unit (whether an existing unit or a new unit) that receives an
allocation but is not actually a covered unit. However, under the final
rules, another category of units--i.e., any existing unit that is not
located--as of January 1 of the control period for which the allocation
is received--in the state from whose trading budget the allocation was
made is also subject to this procedure. Although relatively few units
are moved from one state to another, EPA believes that it is important
to address what happens to such units' allocations, both because each
state has a limited trading budget out of which all allocations for a
year to existing and new units in that state must be made and because,
under the assurance provisions, determinations are made about owners'
and operators' surrender of allowances based on, among other things,
the allocations for units in a specific state. Because, under the final
rules, a unit that is moved from one state to another may lose its
existing unit allocation in the first state under the above-described
procedure, the final rules also makes such a unit eligible for
allocations from the new-unit set-aside of the second state.
Finally, the final rules remove, as no longer necessary, one
category of units that the proposed rules included as subject to this
procedure. The proposed rules, treated, as existing units, some units
that had not yet operated but were projected to operate by January 1,
2012, and so the proposed rules made these units subject to the
procedure for not recording or for deducting allocations if they
actually were not required to certify their monitoring systems and hold
allowances covering emissions starting January 1, 2012. The final rule
does not treat projected units as existing units and so this category
of units no longer needs to be made subject to this procedure.
(3) Designated Representatives and Alternate Designated Representatives
Sections 97.413 through 97.418, 97.513 through 97.518, 97.613
through 97.618, and 97.713 through 97.718 establish the procedures for
certifying and authorizing the designated representative, and alternate
designated representative, of the owners and operators of a source and
the units at the source, and for changing the designated representative
and alternate designated representative. These sections also describe
the designated representative's and alternate designated
representative's responsibilities and the process through which he or
she can delegate to an agent the authority to make electronic
submissions to the Administrator. Except as discussed herein, the
provisions in the final rules are essentially the same as in the
proposed rules and for each of the Transport Rule trading programs.
The designated representative is the individual (i.e., the natural
person) authorized to represent the owners and operators of each
covered source and covered unit at the source in matters pertaining to
all Transport Rule trading programs to which the source and units were
subject. One alternate designated representative (also an individual)
can be selected to act on behalf of, and legally bind, the designated
representative and thus the owners and operators. Because the actions
of the designated representative and alternate legally bind the owners
and operators, the designated representative and alternate must submit
a certificate of representation certifying that each was selected by an
agreement binding on all such owners and operators and is authorized to
act on their behalf.
In the final rules (like in the proposed rules), the certificate of
representation must contain: Specified identifying information for the
covered source (including location) and the covered units at the source
and for the designated representative and alternate; the name of every
owner and operator of the source and units; and certification language
and signatures of the designated representative and alternate. The
final rules require an additional piece of identifying information,
i.e., whether the unit is located in Indian country. This is necessary
in order for the Administrator to implement the above-described Indian
country new unit set-aside. All submissions (e.g., monitoring plans,
monitoring system certifications, and allowance transfers) under the
final rules for a covered
[[Page 48339]]
source or covered unit must be submitted, signed, and certified by the
designated representative or alternate, except that electronic
submission may be delegated.
In order to change the designated representative or alternate, a
new certificate of representation must be received by the
Administrator. A new certificate of representation must also be
submitted to reflect changes in the owners and operators of the source
and units involved. The new certificate must be submitted within 30
days of such changes.
The final rules make explicit an implied requirement of the
proposed rules, i.e., that, if a unit is added to a source or is moved
from one source to a second source, a certificate of representation
needs to be submitted to reflect the change. This requirement is
implicit in the proposed rules when a unit is added to a source because
the designated representative would not be authorized to make
submissions concerning the added unit unless that unit were included on
the certificate of representation. Similarly, where a unit is moved to
another source, new certificates of representation would need to be
submitted in order for the correct designated representative to be
authorized to make submissions concerning the moved unit. Moreover,
because compliance accounts in the Allowance Management System would
cover all units at a given source and would be based on the information
in the certificate of representation submitted by the designated
representative for the source, when a unit is moved from a source to a
second source, the designated representative of the second source would
need to submit a certificate of representation removing the moved unit
from the list of units.
The final rules explicitly require that a new certificate of
representation be submitted to reflect changes (whether caused by the
addition or removal of units) in which units are located at a source.
In addition, the final rules impose a deadline on the submission
requirement of 30 days from the date of the change in the units. This
is analogous to the maximum time period between a change in a unit's
owner or operator and the deadline for submission of a new certificate
of representative reflecting to the change. Long before any actual move
of a unit to a new location, owners and operators will need to make
decisions about, and plan the implementation of, such a move.
Consequently, EPA believes that a 30-day deadline after any move for
reflecting the move in the certificate of representation is reasonable.
In the event the change involves the addition of a unit that operated
before being located at the source, the final Transport Rule also
requires that the designated representative provide in the certificate
of representation information on the entity from which the unit was
obtained, the date on which the unit was obtained, and the date on
which the unit became located at the source. In the event of a change
involving the removal of a unit, the designated representative must
provide in the certificate of representation information on the entity
that obtained the unit, the date on which that entity obtained the
unit, and the date on which the unit became no longer located at the
source. This information will enable the Administrator to determine
what actions are necessary to reflect the change in units located at
the sources involved. For example, if a covered unit is moved from one
source to second source, the Administrator will have the information
necessary to determine whether the unit's allocation should be changed
to reflect movement of the unit from one state to another.
(4) Allowance Management System
Sections 97.420 through 97.428, 97.520 through 97.528, 97.620
through 97.628, and 97.720 through 97.728 establish the procedures and
requirements for using and operating the Allowance Management System
(which is the electronic data system through which the Administrator
handles allowance allocation, holding, transfer, and deduction), and
for determining compliance with the emissions limitations and assurance
provisions, in an efficient and transparent manner. The Allowance
Management System also provides the allowance markets with a record of
ownership of allowances, dates of allowance transfers, buyer and seller
information, and the serial numbers of allowances transferred. Except
as discussed herein, these sections of the final rules are essentially
the same as in the proposed rules and for each of the Transport Rule
trading programs.
(i) Sec. Sec. 97.420, 97.520, 97.620, and 97.720--Compliance,
Assurance, and General Accounts
Under the final rules, the Allowance Management System contains
three types of accounts. One type comprises compliance accounts, one of
which the Administrator establishes for each covered source upon
receipt of the certificate of representation for the source. A
compliance account is the account in which all allowance allocations
must be recorded and in which any allowances used by the covered source
for compliance with the emission limitations must be held. The
designated representative and alternate for the source are also the
authorized account representative and alternate for the compliance
account.
A second type comprises general accounts, which can be established
by any entity upon receipt by the Administrator of an application for a
general account. General accounts can be used by any person or group
for holding or trading allowances. To open a general account, a person
or group must submit an application for a general account, which is
similar in many ways to a certificate of representation. The provisions
for changing the authorized account representative and alternate, for
submitting a superseding application to take account of changes in the
persons having an ownership interest with respect to allowances, and
for delegating authority to make electronic submissions are analogous
to those applicable to comparable matters for designated
representatives and alternates.
A third type comprises assurance accounts. The Administrator
establishes one assurance account for each group of units having a
common designated representative and located in a state where the
assurance provisions are triggered by total emissions exceeding the
state trading budget plus variability.
(ii) Sec. Sec. 97.421 Through 97.423, 97.521 Through 97.523, 97.621
Through 97.623, and 97.721 Through 97.723--Recordation of Allowance
Allocations and Transfers
Under the final rules, by November 7, 2011, the Administrator must
record allowance allocations for existing units, as set forth in a
required notice of data availability, for the Transport Rule annual
NOX, ozone-season NOX, and SO2 trading
programs for 2012 and 2013, unless, as discussed elsewhere in this
preamble, a state notifies the Administrator that the state will submit
a SIP revision with existing-unit allocations for 2013 by May 1, 2012.
If the Administrator approves that SIP revision by October 1, 2012, the
Administrator will record the state-determined existing-unit
allocations for 2013, and, in the absence of such approval by that
date, the Administrator will record the EPA-determined existing-unit
allocations for 2013. By July 1, 2013, the Administrator must record
existing-unit allowance allocations (whether EPA- or state-determined)
for each Transport Rule trading program for 2014 and 2015. By July 1,
2014, the Administrator must
[[Page 48340]]
record existing-unit allowance allocations for each Transport Rule
trading program for 2016 and 2017. By July 1, 2015, the Administrator
must record existing-unit allowance allocations for each Transport Rule
trading program for 2018 and 2019. By July 1, 2016 and July 1 of each
year thereafter, the Administrator must record existing-unit allowance
allocations for each Transport Rule trading program for the control
period in the fourth year after the year of the applicable recordation
deadline. By August 1, 2012 and August 1 of each year thereafter, the
Administrator must record new-unit allowance allocations for each
Transport Rule trading program for that year. These recordation
deadlines differ from those in the proposed rules for two reasons.
First, as discussed elsewhere in this preamble, EPA is adopting
provisions that allow states to submit, and EPA to approve, SIP
revisions (abbreviated or full SIPs) under which the state, rather than
the Administrator, determines the distribution of allowances under one
or more of the Transport Rule trading programs applicable in the state.
In selecting allocation recordation deadlines, EPA took into account
and balanced certain countervailing factors. On one hand, EPA
considered the need to provide a reasonable time for a state to
develop, propose, and finalize, and for EPA to review and propose and
finalize approval of, the SIP revision and the desirability of
providing a reasonable opportunity for state distributions to become
effective for a year relatively soon after the 2012 commencement of the
Transport Rule trading programs. EPA's experience with prior trading
programs has shown that the process for development and submission of
SIP revisions by states and approval by EPA in many cases is about 18
months and in some cases even longer. On the other hand, EPA considered
the desirability of owners and operators having allocations in their
compliance accounts a reasonable time before the year for which the
allocations are made (i.e., the vintage year). Having the allocations
recorded, to the extent possible, before the vintage year facilitates
compliance decisions and use of the allowance market in implementing
such decisions. EPA believes that optimally allocations would be
recorded at least 3 years in advance of the vintage year.
In balancing these countervailing factors, EPA is adopting an
allocation recordation schedule that provides initially for recordation
ranging from 6 months to 18 months before the beginning of the control
period in the first 2 years (i.e., 2012 and 2013) for which allocations
are made and that, as allocations for control periods in subsequent
years are recorded, gradually increases the amount of time between
recordation and the beginning of the year of the control period
involved until allocations are recorded about three and one-half years
in advance. With regard to the need to facilitate states' distribution
of allowances, this approach gives states multiple opportunities to
develop, submit, and obtain EPA approval for SIPs under which the
states (rather than EPA) will distribute allowances under the Transport
Rule trading programs for control periods relatively early in the
programs. Because of time (which has in the past ranged from about 6
months to about 2 years) it may take for a state to develop and submit
such a SIP and because of the time (which has in the past been at least
6 months) it will likely take EPA to review and approve such a SIP, EPA
believes that 2013 is the first year for which a state can determine
allowance distributions and have them recorded some minimal time before
the control period involved. With regard to the need to record
allowances in advance, this approach achieves recordation at least 6
months in advance and eventually achieves recordation by what EPA
believes is an optimal amount of time (greater than 3 years) before the
control period for which recorded allowances are issued.
As discussed elsewhere in this preamble, the approach to allowance
recordation in the final rules results in following schedule for
submission of abbreviated or full SIPs under the final Transport Rule.
SIP revisions with existing-unit allocations for 2013 control periods
must be submitted to the Administrator by April 1, 2012. Complete
abbreviated and full SIPs must be submitted to the Administrator by:
December 1, 2012 in order to govern allowance allocation and auction
for control periods in 2014 and 2015; December 1, 2013 in order to
govern control periods in 2016 and 2017; December 1, 2014 in order to
govern allowance allocation and auction for control periods in 2018 and
2019; and December 1, 2015 and by January 1 of any year thereafter in
order to govern allowance allocation and auction for control periods in
the fifth year after the year of such submission deadline.
The second reason for the differences in the recordation deadlines
in the final rules, as compared to the proposed rules, is that, in
order to simplify the recordation schedule for owners and operators and
EPA, EPA set uniform recordation deadlines for all of the Transport
Rule trading programs. EPA believes that these deadlines provide the
Agency sufficient time, after receipt of any information necessary to
determine allocations (e.g., for new unit set-aside allocations, the
emission data from the control period in the prior year), to complete
the recordation of allocations and, as discussed above, makes the
allocations available to owners and operators before the year for which
the allocations are made. EPA notes that these are deadlines and that
the Administrator has the discretion, where feasible and appropriate,
to record allocations before such deadlines.
Under the final rules (as under the proposed rules), the process
for transferring allowances from one account to another is quite
simple. A transfer is submitted providing, in a format prescribed by
the Administrator, the account numbers of the accounts involved, the
serial numbers of the allowances involved, and the name and signature
of the transferring authorized account representative or alternate. If
the transfer form containing all the required information is submitted
to the Administrator and, when the Administrator attempts to record the
transfer, the transferor account includes the allowances identified in
the form, the Administrator records the transfer by moving the
allowances from the transferor account to the transferee account within
5 business days of the receipt of the transfer form.
(iii) Sec. Sec. 97.424, 97.524, 97.624, and 97.724--Compliance With
Emissions Limitations
Under the final rules (as under the proposed rules), once a control
period has ended (i.e., December 31 for the Transport Rule
NOX and SO2 annual trading programs and September
30 for the ozone-season NOX trading program), covered
sources have a window of opportunity--until the allowance transfer
deadline of midnight on March 1 or December 1 following the control
period for the annual and ozone season trading programs respectively--
to evaluate their reported emissions and obtain any allowances that
they need to cover their emissions during that control period. Each
allowance issued in each Transport Rule trading program authorizes
emission of one ton of the pollutant involved, and so is usable for
compliance in that trading program, for a control period in the year
for which the allowance was allocated or a later year. Consequently,
each source needs--as of the allowance transfer deadline--to have in
its compliance account, or
[[Page 48341]]
properly submit a transfer that moves into its compliance account,
enough allowances usable for compliance to authorize the source's total
emissions for the control period.
If a source fails to hold sufficient allowances for compliance to
cover the emissions, then the owners and operators must provide, for
deduction by the Administrator, two allowances allocated for the
control period, in the year of when the emissions occurred, any prior
year, or the year immediately after the year of the emissions, for
every allowance that the owners and operators failed to hold as
required to cover emissions. In addition, the owners and operators are
subject to discretionary civil penalties for each violation.
(iv) Sec. Sec. 97.425, 97.525, 97.625, and 97.725--Compliance With
Assurance Provisions
Under the final rules (as under the proposed rules), the assurance
provisions ensure that each state will eliminate its significant
contribution to nonattainment and interference with maintenance that
EPA identifies in this action. A requirement that owners and operators
surrender allowances under the assurance provisions is triggered only
for certain owners and operators of sources and units in a state where
the total state covered-unit emissions for a control period exceed the
applicable state trading budget with the variability limit. Moreover,
the surrender requirement is implemented based on groups of sources and
units with a common designated representative. For each group of
sources and units with a common designated representative, the owners
and operators of such sources and units must surrender allowances only
if the units' emissions (referred to as the common designated
representative's share of emissions) during the control period involved
exceed the units' allocations plus share of the state variability limit
(referred to as the common designated representative's share of the
state trading budget with variability).
As discussed elsewhere in this preamble, EPA decided to implement
the assurance provisions on a common designated representative basis,
rather than on an owner basis. The final rules implement in a series of
steps the process of determining which states have total covered-unit
emissions sufficient to trigger the allowance surrender requirement for
a given control period and determining, using the approach based on
common designated representatives, which owners and operators are
subject to the allowance surrender and whether those owners and
operators are in compliance. This common-designated-representative-
based process is more streamlined than the owner-based process in the
proposed rules.
First, the Administrator performs the calculations necessary to
determine whether any state has total covered-unit emissions for a
control period greater than the state trading budget with the 1-year
variability limit. As discussed elsewhere in this preamble, EPA decided
not to use a 3-year variability limit because, among other things, such
a limit seems unnecessary to ensuring elimination of significant
contribution to nonattainment and interference with maintenance and
would make compliance planning extremely difficult for owners and
operators. By June 1, 2013 and June 1 of each year thereafter, the
Administrator promulgates a notice of data availability of the results
of these calculations.
Second, by July 1, for states identified in the June 1 notice of
data availability as having emissions exceeding the state trading
budget with variability, the designated representative of each new unit
in the state that operated during but did not receive an allocation for
the year involved must submit a statement to the Administrator with
certain information about the unit. This information--i.e., the unit's
allowable emission rate for the pollutant involved (NOX or
SO2) and heat rate--is used to calculate a surrogate
allocation for the unit to be used solely for the purposes of
determining whether the group of units with a common designated
representative that includes the unit had emissions exceeding
allocations plus share of the state's variability limit.
Third, the Administrator calculates, for each state identified in
the June 1 notice of data availability and for each common designated
representative of a group of units (which groups can include one or
more units and sources) in the state, the common designated
representative's share of emissions, the common designated
representative's share of the state trading budget with the variability
limit, and the amount (if any) that the groups of owners and operators
of units represented by the common designated representative (which
groups can include one or more owners and operators) in the state must
surrender under the assurance provisions (i.e., the common designated
representative's proportionate share of the excess of state emissions
over the state trading budget with the variability limit). The
Administrator promulgates by August 1 a notice of data availability of
the results of these calculations, provides an opportunity for
submission of objections, and promulgates by October 1 a second notice
of data availability of any necessary adjustments to the calculations.
In contrast with the proposed rules, objections may be submitted
concerning information in the August 1 notice, whether or not that
information was also provided in the June 1 notice. In short, the
process of issuing notices is shortened in the final rules by providing
one, comprehensive opportunity to submit objections to the June 1 and
August 1 notices, rather than two separate opportunities, one for each
notice.
Also in contrast with the proposed rules, the deadlines for
issuance of notices of data availability for implementation of the
assurance provisions are made uniform under the final rules for all of
the Transport Rule trading programs. EPA is taking this approach for
the same reasons that the deadlines for issuance of notices of data
availability for new unit set-aside allocations are made uniform for
all of these trading programs.
Fourth, the owners and operators identified in the October 1 notice
of data availability as being required to surrender allowances under
the assurance provisions must transfer, by November 1, to the assurance
account created by the Administrator for such owners and operators the
amount of allowances (usable for compliance) that the Administrator
determined in the October 1 notice of data availability. Where the
October 1 notice indicates that a specified surrender amount is owed by
a group of two or more owners and operators, all the group members are
liable for the surrender amount, and it is up to the owners and
operators in the group to decide who will actually surrender
allowances. This is analogous to the situation where a group of two or
more owners and operators of covered units at a source is required to
hold allowances covering the unit's emissions and therefore the group
of owners and operators is liable. See 58 FR 3590, 3599 (January 11,
1993) (discussing liability of owners and operators under allowance-
holding requirements of the Acid Rain Program).
EPA believes that the approach of making the owners and operators
responsible for deciding which of them will actually surrender the
necessary allowances under the assurance provisions is reasonable
because the identity of who is an owner or operator (particularly who
is an owner) of a unit or source and the percentage of an owner's share
can change during the year and this information is available to the
owners and operators on an ongoing
[[Page 48342]]
basis, and not to EPA unless EPA were to impose new requirements for
reporting this information. Further, EPA believes that it is reasonable
to leave to private agreements the establishment of procedures for
determining when, and under what conditions, specific owners and
operators will provide the allowances for surrender. Owners and
operators already make these types of determinations with regard to the
surrender requirements in meeting the emissions limitations and any
excess emission penalties.
As part of implementing the common-designated-representative-based
approach of the assurance provisions in the final Transport Rule, the
final rules provide that the Administrator (instead of the owners, as
in the proposed rules) will create an assurance account for each group
of the owners and operators of units and sources with a common
designated representative in each state where the assurance provisions
are triggered. Because the final rules require owners and operators to
transfer surrendered allowances to the appropriate assurance account
(rather than requiring the Administrator to deduct from accounts
established by the owners), there is no need for the proposed rule
provisions concerning identification of which allowances are to be
deducted and first-in, first-out deduction in the absence of such
identification.
The final rules provide that, in general, the surrender amounts
specified in the October 1 notice for owners and operators are final
and will not be revised even if the underlying data (e.g., emission
data) used in the calculations underlying the October 1 notice are
subsequently revised. However, the final rules set forth limited
exceptions to this: Where such data are revised as a result of a
decision in or settlement of litigation concerning the data on appeal.
EPA believes that the limitation on revisions of the surrender amounts
specified in the October 1 notice are necessary to provide some
certainty to owners and operators and avoid the potential for multiple
changes in owners' and operators' required surrender amounts. Because
the surrender amount for each group of owners and operators of units
and sources with a common designated representative in a state is
calculated using emission data from all of the covered units in that
state, each change in one or a few units' emission data that might
occur after issuance of the October 1 notice could otherwise change the
calculated surrender amounts for all or many groups in the state. For
the limited exceptions where the final rules provide that the surrender
amounts specified in the August 1 notice may be revised, the final
rules require the Administrator to set a new surrender deadline for any
additional surrender required and to transfer allowances back out of
the assurance account involved for any reduced surrender requirement,
as appropriate.
Under the final rules (as under the proposed rules), it is not a
violation of the CAA for total state covered-unit emissions to exceed
the state trading budget with the variability limit or for a group of
owners and operators to become subject to the allowance surrender
requirement under the assurance provisions. However, the failure of any
group of owners and operators to surrender the required amount of
allowances in the assurance account created for such owners and
operators violates the CAA and is subject to discretionary penalties,
with each required allowance that was not surrendered and each day of
the control period involved constituting a violation.
(v) Sec. Sec. 97.426 Through 97.428, 97.526 Through 97.528, 97.626
Through 97.628, and 97.726 Through 97.728--Miscellaneous Provisions
These sections in the final rules (as in the proposed rules)
include provisions allowing banking of the allowances issued in the
Transport Rule trading programs, i.e., the retention of unused
Transport Rule allowances allocated for a given control period for use
or trading in a later control period. While this can potentially cause
emissions from sources in some states in some control periods to be
greater than the allowances allocated for those control periods, the
assurance provisions limit such emissions in a way that ensures that
each state's significant contribution to nonattainment and interference
with maintenance that EPA has identified in this action will be
eliminated.
These sections also include provisions stating that the
Administrator can, at his or her discretion and on his or her own
motion, correct any type of error that he or she finds in an account in
the Allowance Management System. In addition, the Administrator can
review any submission under the Transport Rule trading programs, make
adjustments to the information in the submission, and deduct or
transfer allowances based on such adjusted information.
(5) Emissions Monitoring, Recordkeeping, and Reporting
Sections 97.430 through 97.435, 97.530 through 97.535, 97.630
through 97.635, and 97.730 through 97.735 establish emissions
monitoring, recordkeeping, and reporting requirements for Transport
Rule units. These provisions reference the relevant sections of Part 75
(40 CFR part 75), where the specific procedures and requirements for
monitoring and reporting NOX and SO2 mass
emissions are set forth. The provisions in the final rules are
virtually the same as the monitoring, recordkeeping, and reporting
requirements in the proposed rules and under previous EPA-administered
trading programs, e.g., the Acid Rain Program and NOX Budget
and CAIR trading programs. The final rule provisions are also
essentially the same for each of the Transport Rule trading programs,
except for differences reflecting the different pollutants and control
periods involved.
Under the provisions of the final rules and under Part 75, a unit
has several options for monitoring and reporting. A unit's options are
to use: a CEMS; an excepted monitoring methodology (NOX mass
monitoring for certain peaking units and SO2 mass monitoring
for certain oil- and gas-fired units); low mass emissions monitoring
for certain, non-coal-fired, low emitting units; or an alternative
monitoring system approved by the Administrator through a petition
process. In addition, unit owners and operators may submit, and the
Administrator can approve, petitions for alternatives to Transport Rule
and Part 75 monitoring, recordkeeping, and reporting requirements.
As discussed elsewhere in this preamble, the final rules and Part
75 specify that each CEMS must undergo rigorous initial certification
testing and periodic quality assurance testing thereafter. In addition,
when a monitoring system is not operating properly, standard substitute
data procedures are applied and result in a conservative estimate of
emissions for the period involved. Further, the final rules and Part 75
require electronic submission, to the Administrator and in a format
prescribed by the Administrator, of a quarterly emissions report.
The final rules include revised language in Sec. Sec.
97.430(b)(3), 97.530(b)(3), 97.630(b)(3), and 97.730(b)(3) that
incorporates by reference, and thereby applies to units in the
Transport Rule trading programs, clarification that EPA recently
adopted in Sec. 75.4(e) of Part 75 (for Acid Rain Program units)
[[Page 48343]]
concerning the requirements for certification, recertification, and
diagnostic testing of emission monitoring systems when a unit adds a
new stack or new add-on SO2 or NOX emission
control device. See 76 FR 17288, 17298-300 (March 28, 2011). The
revised language is adopted for the reasons set forth in the preamble
of that Acid Rain Program final rule and in order to continue the
approach, in the Transport Rule trading program rules, of adopting
monitoring, recordkeeping, and reporting requirements that are
generally consistent with those in the Acid Rain Program, which covers
many units in the Transport Rule trading programs.
XII. Statutory and Executive Order Reviews
The projected impacts of this final rule as presented throughout
the preamble do not reflect minor technical corrections to
SO2 budgets in three states (KY, MI, and NY) made after the
impact analyses were conducted. These projections also assumed
preliminary variability limits that were smaller than the variability
limits finalized in this rule. EPA conducted sensitivity analysis
confirming that these differences do not meaningfully alter any of the
Agency's findings or conclusions based on the projected cost, benefit,
and air quality impacts presented for the final Transport Rule. The
results of this sensitivity analysis are presented in Appendix F in the
final Transport Rule RIA.
A. Executive Order 12866: Regulatory Planning and Review and Executive
Order 13563: Improving Regulation and Regulatory Review
Under EO 12866 (58 FR 51735, October 4, 1993), this action is an
``economically significant regulatory action'' because it is likely to
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.
Accordingly, EPA submitted this action to the OMB for review under
EO 12866 and EO 13563 (76 FR 3821, January 21, 2011) and any changes in
response to OMB recommendations have been documented in the docket for
this action. In addition, EPA prepared an analysis of the potential
costs and benefits for this action. This analysis is contained in the
Regulatory Impact Analysis (RIA) for this action. For more information
on the costs and benefits for this rule, please refer to Table VIII.C-3
of this preamble.
When estimating the human health benefits and compliance costs in
Table VIII.C-3 of this preamble, EPA applied methods and assumptions
consistent with the state-of-the-science for human health impact
assessment, economics, and air quality analysis. EPA applied its best
professional judgment in performing this analysis and believes that
these estimates provide a reasonable indication of the expected
benefits and costs to the nation of this rulemaking. The RIA available
in the docket describes in detail the empirical basis for EPA's
assumptions and characterizes the various sources of uncertainties
affecting the estimates below. In doing what is laid out above in this
paragraph, EPA adheres to EO 13563, ``Improving Regulation and
Regulatory Review,'' (76 FR 3,821, January 21, 2011), which is a
supplement to EO 12866.
In addition to estimating costs and benefits, EO 13563 focuses on
the importance of a ``regulatory system [that] * * * promote[s]
predictability and reduce[s] uncertainty'' and that ``identify[ies] and
use[s] the best, most innovative, and least burdensome tools for
achieving regulatory ends.'' EO 13563 also states that ``[i]n
developing regulatory actions and identifying appropriate approaches,
each agency shall attempt to promote such coordination, simplification,
and harmonization. Each agency shall also seek to identify, as
appropriate, means to achieve regulatory goals that are designed to
promote innovation.'' We recognize that the utility sector has
compliance obligations related to multiple environmental statutes
authorizing regulatory action, including this rule's requirements to
reduce interstate transport of harmful ozone and fine particles and
their precursors, as well as other rules' requirements to reduce air
toxic emissions, to reduce greenhouse gas emissions, to safely manage
coal combustion wastes, and to protect aquatic wildlife from water
intake procedures. In the wake of promulgating this final rule, EPA
recognizes that moving forward the agency needs to approach these
rulemakings in ways that allow the industry to make practical
investment decisions that minimize costs in complying with all of the
final rules, while still securing the fundamentally important
environmental and public health benefits that led Congress to enact
those authorities in the first place. At the same time, EPA notes that
the flexibility inherent in the allowance-trading mechanism included in
this rule affords utilities themselves a degree of latitude to
determine how best to integrate compliance with the emission reduction
requirements of this rule and those of the other rules.
The final rule will also reduce emissions of directly emitted PM
and ozone precursors, and estimates of the PM2.5-related
benefits of these air quality improvements may be found in Tables
VIII.C-1 and VIII.C-2 of this preamble. When characterizing uncertainty
in the PM-mortality relationship, EPA has historically presented a
sensitivity analysis applying alternate assumed thresholds in the PM
concentration-response relationship. In its synthesis of the current
state of the PM science, EPA's 2009 Integrated Science Assessment for
Particulate Matter concluded that a no-threshold log-linear model most
adequately portrays the PM-mortality concentration-response
relationship. In the RIA accompanying this rulemaking, rather than
segmenting out impacts predicted to be associated levels above and
below a ``bright line'' threshold, EPA includes a ``lowest measured
level'' (LML) analysis that illustrates the increasing uncertainty that
characterizes exposure attributed to levels of PM2.5 below
the LML of each epidemiological study used to estimate
PM2.5-related premature death. Figures provided in the RIA
show the distribution of baseline exposure to PM2.5, as well
as the lowest air quality levels measured in each of the epidemiology
cohort studies. This information provides a context for considering the
likely portion of PM-related mortality benefits occurring above or
below the LML of each study; in general, our confidence in the size of
the estimated reduction PM2.5-related premature mortality
diminishes as baseline concentrations of PM2.5 are lowered.
Approximately 69 percent of the avoided impacts occur at or above an
annual mean PM2.5 level of 10 [mu]g/m\3\ (the LML of the
Laden et al. 2006 study); about 96 percent occur at or above an annual
mean PM2.5 level of 7.5 [mu]g/m\3\ (the LML of the Pope et
al. 2002 study). Although the LML analysis provides some insight into
the level of uncertainty in the estimated PM mortality benefits, EPA
does not view the LML as a threshold and continues to quantify PM-
related mortality impacts using a full range of modeled air quality
concentrations. It is important to note that the monetized benefits
include many but not all health effects associated with
PM2.5 exposure. Benefits are shown as a range from Pope, et
al., (2002) to Laden, et al., (2006). These models assume that all fine
particles,
[[Page 48344]]
regardless of their chemical composition, are equally potent in causing
premature mortality because there is no clear scientific evidence that
would support the development of differential effects estimates by
particle type.
The cost analysis is also subject to uncertainties. Estimating the
cost conversion from one process to another is more difficult than
estimating the cost of adding control equipment because it is more
dependent on plant specific information. More information on the cost
uncertainties can be found in the RIA.
A summary of the monetized benefits and net benefits for the final
rule at discount rates of 3 percent and 7 percent is in Table VIII.C-3
of this preamble. For more information on the benefits analysis, please
refer to the RIA for this rulemaking, which is available in the docket.
B. Paperwork Reduction Act
EPA is required to document the information collection burden
imposed by the Transport Rule on industry, states, and EPA in an
information collection request (ICR). The ICR describes the information
collection requirements associated with the Transport Rule and
estimates the incremental costs of compliance with all such
requirements, such as the requirement for industry to monitor, record,
and report emission data to EPA.
The ICR for the final Transport Rule has been submitted for
approval by OMB under the Paperwork Reduction Act, 44 U.S.C. 3501 et
seq., and the information collection requirements it documents are not
enforceable until such approval has been granted. An ICR was also
submitted to OMB in support of the proposed Transport Rule; no adverse
comment was received by EPA on either the information collection
requirements or their associated cost estimates as described in that
document.
The costs associated with the information collection requirements
of the Transport Rule include start-up and capital costs for units
newly affected by an emission trading program, or whose reporting
status has changed (e.g., from ozone-season-only to annual reporting),
as well as the additional operation and maintenance costs for Transport
Rule-affected units already participating in an EPA-administered cap
and trade program. More information on the ICR analysis is included in
the final Transport Rule docket.
The records and reports generated by these activities will be used
by EPA and states to ensure that affected facilities comply with
emission limits and other requirements. Such records and reports are
also helpful to EPA and states in both identifying affected facilities
that may not be in compliance with applicable requirements and in
discerning which units and what records or processes should be
inspected.
The incremental capital and operating costs associated with the
recordkeeping and reporting burden to Transport Rule-affected sources
in states participating in the Transport Rule trading programs are
approximately $26 million annually in 2010 dollars. The total number of
burden hours associated with the recordkeeping and reporting burden to
Transport Rule-affected sources in states participating in the
Transport Rule trading programs is approximately 185,000 hours
annually. These estimates include the annualized cost of installing and
operating appropriate SO2 and NOX emission
monitoring equipment to measure and report the total emissions of these
pollutants from affected EGUs (serving generators greater than 25 MW).
The burden to state and local air agencies, as documented in the ICR,
includes any necessary SIP revisions, performance of monitor
certifications, and fulfillment of audit responsibilities. Burden is
defined at 5 CFR 1320.3(b).
The amendments do not require any notifications or reports beyond
those required by the General Provisions. The recordkeeping
requirements require only the specific information needed to determine
compliance, which is specifically authorized by CAA section 114 (42
U.S.C. 7414). All information submitted to EPA for which a claim of
confidentiality is made will be safeguarded according to EPA policies
in 40 CFR part 2, subpart B, Confidentiality of Business 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
in 40 CFR are listed in 40 CFR part 9. When this ICR is approved by
OMB, the Agency will publish a technical amendment to 40 CFR part 9 in
the Federal Register to display the OMB control number for the approved
information collection requirements contained in this final rule.
C. Regulatory Flexibility Act
The Regulatory Flexibility Act (RFA) generally requires an agency
to prepare a regulatory flexibility analysis of any rule subject to
notice and comment rulemaking requirements under the Administrative
Procedure Act or any other statute unless the agency certifies that the
rule will not have a significant economic impact on a substantial
number of small entities. Small entities include small businesses,
small organizations, and small governmental jurisdictions.
For purposes of assessing the impacts of this final rule on small
entities, small entity is defined as:
(1) A small business as defined by the Small Business
Administration's (SBA) regulations at 13 CFR 121.201. For the electric
power generation industry, the small business size standard is an
ultimate parent entity defined as having a total electric output of 4
million megawatt-hours (MWh) or less in the previous fiscal year.
(2) A small governmental jurisdiction that is a government of a
city, county, town, school district or special district with a
population of less than 50,000; and
(3) A small organization that is any not-for-profit enterprise
which is independently owned and operated and is not dominant in its
field.
Table XII.C-1--Potentially Regulated Categories and Entities a
------------------------------------------------------------------------
Examples of potentially
Category NAICS code \b\ regulated entities
------------------------------------------------------------------------
Industry....................... 221112 Fossil-fuel-fired
electric utility steam
generating units.
Federal Government............. \c\ 221112 Fossil-fuel-fired
electric utility steam
generating units owned
by the federal
government.
State/Local Government......... 2\c\ 21112 Fossil-fuel-fired
electric utility steam
generating units owned
by municipalities.
Tribal Government.............. 921150 Fossil-fuel-fired
electric utility steam
generating units in
Indian Country.
------------------------------------------------------------------------
\a\ Include NAICS categories for source categories that own and operate
electric generating units only.
\b\ North American Industry Classification System.
\c\ Federal, state, or local government-owned and operated
establishments are classified according to the activity in which they
are engaged.
[[Page 48345]]
EPA used Velocity Suite's Ventyx data as a basis for identifying
plant ownership and compiling the list of potentially affected small
entities. For plants burning fossil fuel as the primary fuel, plant-
level boiler and generator capacity, heat input, generation, and
emission data were aggregated by owner and then parent company. For
cooperatives, investor-owned utilities, and subdivisions that generate
less than 4 billion kWh of electricity annually but may be part of a
large entity, additional research on power sales, operating revenues,
and other business activities was performed to make a final
determination regarding size.
After considering the economic impacts of this final rule on small
entities, EPA certifies that this action will not have a significant
economic impact on a substantial number of small entities (No SISNOSE).
This certification is based on the economic impact of this final rule
to all affected small entities across all industries affected. EPA
assessed the potential impact of this action on small entities and
found that there are about 660 potentially affected small units (i.e.,
greater than 25 MW and generating less than 4 million MWh) out of 3,625
existing units in the Transport Rule states. The majority of these EGUs
are owned by entities that do not meet the small entity definition. The
remaining 271 of the 660 EGUs are owned by 108 potentially affected
small entities and are likely to be affected by this rule. EPA
estimates that 24 of the 108 identified small entities will have
annualized costs greater than 1 percent of their revenues, and the
other 84 are projected to incur costs less than 1 percent of revenues.
Eleven small entities out of 108--approximately 10 percent--are
estimated to have annualized costs greater than 3 percent of their
revenues. EPA has lessened the impacts for small entities by excluding
all units smaller than 25 MWe. This exclusion, in addition to the
exemptions for cogeneration units and solid waste incineration units,
eliminates the burden of higher costs for a substantial number of small
entities located in the Transport Rule states.
While the total number of small entities has increased compared to
the proposal as a result of updated modeling and changes in geographic
coverage, the number with compliance costs greater than 1 percent of
revenues has fallen, and both the number and percentage of
significantly impacted small entities (costs greater than 3 percent of
revenues) are lower--now 10 percent compared to 17 percent in the
proposal. The share of significantly impacted small entities has fallen
because of updated modeling and the change in the allowance allocation
methodology (see section VII.D for more information about allowance
allocations).
Although this final rule will not have a significant economic
impact on a substantial number of small entities, EPA nonetheless has
tried to reduce the impact of this rule on small entities. In EPA's
modeling, most of the cost impacts for these small entities and their
associated units are driven by lower electricity generation relative to
the base case. Specifically, two small units reduce their generation by
significant amounts, driving the bulk of the costs for all small
entities. Excluding these two units, one of the main drivers of small
entity impacts is higher fuel costs, which the affected units would
incur irrespective of whether they had to comply with this rule. In
addition, EPA's decision to exclude units smaller than 25 MWe has
already significantly reduced the burden on approximately 390 small
entities.
For more information on the small entity impacts associated with
the final rule, refer to the Regulatory Impact Analysis for this final
rule, which can be found in the docket for this rule and on the Web
site http://www.epa.gov/airtransport.
D. Unfunded Mandates Reform Act
Title II of the Unfunded Mandates Reform Act of 1995 (UMRA), 2
U.S.C. 1531-1538, requires federal agencies, unless otherwise
prohibited by law, to assess the effects of their regulatory actions on
state, local, and tribal governments, and the private sector. This rule
contains a federal mandate that may result in expenditures of $100
million or more for state, local, and tribal governments, in the
aggregate, or the private sector in any 1 year. Accordingly, EPA has
prepared, under section 202 of the UMRA, a written statement which is
summarized later.
Consistent with the intergovernmental consultation provisions of
section 204 of the UMRA, EPA held consultations with the governmental
entities affected by this rule during the proposal phase. Subsequently,
EPA sent a letter to the ten Representative National Organizations to
draw their attention to the Transport Rule Notice of Data Availability
(NODA) on allowance allocations and other related matters and to invite
their comments. During the NODA comment period, EPA participated in
informational calls with the Environmental Council of the States (ECOS)
and the National Governors Association to provide information about the
NODA directly to state and local officials. There were no new concerns
raised during these informational calls. In addition, EPA also
conducted consultations with federally recognized tribes prior to
finalizing this rule and invited them to comment on the allowance
allocation NODA. EPA has added a new unit set-aside provision to this
final rule specifically for EGUs constructed in Indian country to
ensure allowances are available to tribes and tribal sovereignty is
respected.
Consistent with section 205, EPA identified and considered a
reasonable number of regulatory alternatives. In the proposal, EPA
included three remedy options that it considered when developing this
final rule: (1) The preferred remedy trading programs, (2) State
Budgets/Intrastate Trading, and (3) Direct Controls. Moreover, section
205 allows EPA to adopt an alternative other than the least costly,
most cost-effective, or least burdensome alternative if the
Administrator publishes with the final rule an explanation why that
alternative was not adopted.
EPA examined the potential economic impacts on state- and
municipality-owned entities associated with this rulemaking based on
assumptions of how the affected states will implement control measures
to meet program requirements. Although EPA does not conclude that the
requirements of the UMRA apply to the Transport Rule, these impacts
have been calculated to provide additional understanding of the nature
of potential impacts and additional information.
EPA has determined that this rule contains a federal mandate that
may result in expenditures of $100 million or more in 1 year. EPA has
determined that this rule contains no regulatory requirements that
might significantly or uniquely affect small governments and that
development of a small government plan under section 203 of the Act is
not required. The costs of compliance will be borne predominately by
sources in the private sector although a small number of sources owned
by state and local governments may also be impacted. The requirements
in this action do not distinguish EGUs based on ownership, either for
those units that are included within the scope of the rule or for those
units that are exempted by the generating capacity cut-off. Therefore,
this rule is not subject to the requirements of section 203 of UMRA
because it contains no regulatory requirements that might significantly
or uniquely affect small governments.
[[Page 48346]]
E. Executive Order 13132: Federalism
This final rule does not have federalism implications. It will not
have substantial direct effects on the states, on the relationship
between the national government and the states, or on the distribution
of power and responsibilities among the various levels of government,
as specified in Executive Order 13132. The final rule primarily affects
private industry, and does not impose significant economic costs on
state or local governments. Thus, Executive Order 13132 does not apply
to the final rule.
Although section 6 of Executive Order 13132 does not apply to the
final rule, EPA did provide information to state and local officials
during development of both the proposal and final rule. EPA sent a
letter to the ten Representative National Organizations to draw their
attention to the Transport Rule NODA on allowance allocations and other
related matters and to invite their comments. Following that letter in
early 2011, EPA participated in informational calls with the
Environmental Council of the States (ECOS) and the National Governors
Association to provide information about the NODA directly to state and
local officials. There were no new concerns raised during these
informational calls.
F. Executive Order 13175: Consultation and Coordination With Indian
Tribal Governments
Under Executive Order 13175 (65 FR 67249, November 9, 2000), EPA
may not issue a regulation that has tribal implications, that imposes
substantial direct compliance costs, and that is not required by
statute, unless the federal government provides the funds necessary to
pay the direct compliance costs incurred by tribal governments, or EPA
consults with tribal officials early in the process of developing the
proposed regulation and develops a tribal summary impact statement.
EPA has concluded that this action may have tribal implications if
a new unit covered by the rule is built in Indian country.
Additionally, tribes have a vested interest in how this final rule
affects their air quality. However, it will neither impose substantial
direct compliance costs on tribal governments, nor preempt tribal law.
EPA consulted with tribal officials during the process of finalizing
this regulation to permit them to have meaningful and timely input into
its development.
EPA received comments on the proposed Transport Rule that the
Agency did not properly conduct consultation during the proposal phase
of the rulemaking process. In response to these comments, EPA sent a
letter to all federally-recognized tribes in the country offering
consultation. In addition, several commenters also noted that the
Agency did not adequately consider opportunities for tribes to enter
into any of the trading programs and, in particular, did not consider
sovereignty issues when addressing how to distribute allowances to
potential new units in Indian country. On January 7, 2011, EPA issued a
NODA requesting comment on allocations for new units in Indian country,
among other topics.
The Agency held a consultation call with three tribes on January
21, 2011. A follow-up call was held on February 4, 2011 with two of the
three original tribes plus 13 additional tribes, as well as
representatives from the National Tribal Air Association. In all ten
tribes participated in these calls as consultation and six participated
as information-sharing. EPA considered the additional input from these
consultation and information calls, in conjunction with the public
comments, in the development of the final rule. Accordingly, EPA
created an Indian country new unit set-aside to specifically address
tribes' concerns regarding the protection of tribal sovereignty in the
distribution of allowances for new units in Indian country. See section
VII.D.2 of this preamble for details on the Indian country set-aside
for new units constructed in Indian country within states covered by
the Transport Rule.
As required by section 7(a) of the Executive Order, EPA's Tribal
Consultation Official has certified that the requirements of the
Executive Order have been met in a meaningful and timely manner. A copy
of the certification is included in the docket for this action.
G. Executive Order 13045: Protection of Children From Environmental
Health and Safety Risks
Executive Order 13045 (62 FR 19,885, April 23, 1997) applies to any
rule that: (1) Is determined to be ``economically significant'' as
defined under EO 12866, and (2) concerns an environmental health or
safety risk that EPA has reason to believe may have a disproportionate
effect on children. If the regulatory action meets both criteria, the
Agency must evaluate the environmental health or safety effects of this
planned rule on children, and explain why this planned regulation is
preferable to other potentially effective and reasonably feasible
alternatives considered by the Agency.
This action is not subject to Executive Order 13045 because it does
not involve decisions on environmental health or safety risks that may
disproportionately affect children. EPA believes that the emission
reductions from the strategies in this rule will further improve air
quality and will further improve children's health. Analyses by EPA
that show how the emission reductions from the strategies in this rule
will further improve air quality and children's health can be found in
the RIA for this rule.
H. Executive Order 13211: Actions That Significantly Affect Energy
Supply, Distribution, or Use
Executive Order 13211 (66 FR 28355, May 22, 2001) provides that
agencies shall prepare and submit to the Administrator of the Office of
Regulatory Affairs, OMB, a Statement of Energy Effects for certain
actions identified as ``significant energy actions.'' Section 4(b) of
Executive Order 13211 defines ``significant energy action'' as ``any
action by an agency (normally published in the Federal Register) that
promulgates or is expected to lead to the promulgation of a final rule
or regulation, including notices of inquiry, advance notices of
proposed rulemaking, and notices of proposed rulemaking: (1)(i) That is
a significant regulatory action under Executive Order 12866 or any
successor order, and (ii) is likely to have a significant adverse
effect on the supply, distribution, or use of energy; or (2) that is
designated by the Administrator of the Office of Information and
Regulatory Affairs as a significant energy action.'' This rule is a
significant regulatory action under Executive Order 12866, and this
rule is likely to have a significant adverse effect on the supply,
distribution, or use of energy. EPA prepared a Statement of Energy
Effects for this action as follows.
Under the provisions of this rule, EPA projects that approximately
4.8 GW of additional coal-fired generation may be removed from
operation by 2014. In practice, however, the units projected to be
uneconomic to maintain may be ``mothballed,'' retired, or kept in
service to ensure transmission reliability in certain parts of the
grid. These units are predominantly small and infrequently-used
generating units dispersed throughout the area affected by the rule. If
current forecasts of either natural gas prices or electricity demand
were revised in the future to be higher, that would create a greater
incentive to keep these units operational.
EPA estimates that average retail electricity prices could increase
in the
[[Page 48347]]
contiguous U.S. by about 1.7 percent in 2012 and 0.8 percent in 2014.
This is generally less of an increase than often occurs with
fluctuating fuel prices and other market factors. Related to this, EPA
projects limited impacts on coal and gas prices. The average delivered
coal price decreases by about 1.4 percent in 2012 and 0.9 percent in
2014 relative to the base case as a result of decreased coal demand and
shifts in the type of coal demanded. EPA also projects that the
electric power sector-delivered natural gas price will increase by
about 0.3 percent over the 2012-2030 timeframe and that natural gas use
for electricity generation will increase by approximately 200 billion
cubic feet (BCF) by 2014. These impacts are well within the range of
price variability that is regularly experienced in natural gas markets.
Finally, under the Transport Rule, EPA projects that coal production
for use by the power sector will increase above 2009 levels by 21
million tons in 2012 and a further 14 million tons in 2014, as opposed
to 30 million tons in 2012 and a further 26 million tons in 2014
without the Transport Rule in place. The Transport Rule is not
projected to impact production of coal for uses outside the power
sector (e.g., export, industrial sources), which represent
approximately 6 percent of total coal production in 2009. EPA does not
believe that this rule will have any other impacts (e.g., on oil
markets) that exceed the significance criteria.
EPA believes that a number of features of the rulemaking serve to
reduce its impact on energy supply. First, the trading component of the
Transport Rule provides flexibility to the power sector and enables
industry to comply with the emission reduction requirements in the most
cost-effective manner compared to the alternative remedy approaches on
which EPA took comment in the proposal, thus minimizing overall costs
and the ultimate impact on energy supply. Second, the more stringent
budgets for SO2 are set in two phases, providing adequate
time for EGUs to install pollution controls. In addition, both the
operational flexibility of trading and the ability to bank allowances
for future years helps industry plan for and ensure reliability in the
electrical system.
For more details concerning energy impacts, see the RIA for the
Transport Rule.
I. National Technology Transfer Advancement Act
Section 12(d) of the National Technology Transfer and Advancement
Act of 1995 (NTTAA), Public Law 104-113, 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. NTTAA directs EPA to provide
Congress, through OMB, explanations when the Agency decides not to use
available and applicable voluntary consensus standards. This rule will
require all sources to meet the applicable monitoring requirements of
40 CFR part 75. Part 75 already incorporates a number of voluntary
consensus standards. Consistent with the Agency's Performance Based
Measurement System (PBMS), Part 75 sets forth performance criteria that
allow the use of alternative methods to the ones set forth in Part 75.
The PBMS approach is intended to be more flexible and cost effective
for the regulated community; it is also intended to encourage
innovation in analytical technology and improved data quality. At this
time, EPA is not recommending any revisions to Part 75; however, EPA
periodically revises the test procedures set forth in Part 75. When EPA
revises the test procedures set forth in Part 75 in the future, EPA
will address the use of any new voluntary consensus standards that are
equivalent. Currently, even if a test procedure is not set forth in
Part 75, 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 through the petition process under 40 CFR 75.66 before
they are used.
J. Executive Order 12898: Federal Actions To Address Environmental
Justice in Minority Populations and Low-Income Populations
Executive Order (EO) 12898 (59 FR 7629 (Feb. 16, 1994)) establishes
federal executive policy on environmental justice. Its main provision
directs federal agencies, to the greatest extent practicable and
permitted by law, to make environmental justice part of their mission
by identifying and addressing, as appropriate, disproportionately high
and adverse human health or environmental effects of their programs,
policies, and activities on minority, low-income, and Tribal
populations in the United States. During development of this final
Transport Rule, EPA considered its impacts on low-income, minority, and
tribal communities in several ways and provided multiple opportunities
for these communities to meaningfully participate in the rulemaking
process. The proposed Transport Rule included an analysis of its
effects on these populations; this section describes additional
analysis conducted since proposal, EPA's responses to key comments on
environmental justice issues raised during the comment period, and the
public outreach and comment opportunities for this rule.
A summary of the history, statutory authority, and key components
of this final Transport Rule are described in the Executive Summary
(section III) of this preamble. That section also summarizes a
supplemental notice of proposed rulemaking (SNPR) that EPA is
publishing to correct a procedural flaw by providing an opportunity for
public comment on issues that arose from new analyses with updated
inventories and modeling platforms.
Briefly, this final Transport Rule will reduce emissions of
SO2 and NOX in 23 eastern and central states in
2012 and 2014 that contribute to annual and/or 24-hour PM2.5
nonattainment or interfere with maintenance in downwind states. It will
also reduce emissions of ozone-season NOX in 20 eastern and
central states in 2012 and 2014 that contribute to the 1997 ozone
nonattainment or interfere with maintenance in downwind states. This
rule is replacing an earlier rule (the 2005 Clean Air Interstate Rule
(CAIR)) that was first vacated and then remanded to EPA by the U.S.
Court of Appeals for the District of Columbia Circuit in 2008.
1. Consideration of Environmental Justice in the Transport Rule
Development Process and Response to Comments
The effects of this final Transport Rule on the most highly exposed
populations were integral in its development. This rule uses EPA's
authority in CAA section 110(a)(2)(d) to reduce sulfur dioxide
(SO2) and (nitrogen oxides) NOX pollution that
significantly contributes to downwind PM2.5 and ozone
nonattainment or maintenance areas. As a result, the rule will reduce
exposures to ozone and PM2.5 in the most-contaminated areas
(i.e., areas that are not meeting the 1997 ozone and 1997 and 2006
PM2.5 National Ambient Air Quality Standards (NAAQS)). In
addition, the rule separately identifies both nonattainment areas and
maintenance areas (maintenance areas are those that are projected to
meet the NAAQS but that, based on past data, are in danger of
[[Page 48348]]
exceeding the standards in the future). This requirement reduces the
likelihood that any areas close to the level of the standard will
exceed the current health-based standards in the future.
This final Transport Rule implements these emission reductions
using an emission trading mechanism with assurance provisions for power
plants. EPA recognizes that many environmental justice communities have
voiced concerns in the past about emission trading and the potential
for any emission increases in any location. EPA also received several
comments on this issue during the comment period for the proposed
Transport Rule. As described below, we believe this final rule
addresses the concerns raised on this issue during the comment period.
PM2.5 and ozone pollution from power plants have both
local and regional components: Part of the pollution in a given
location--even in locations near emission sources--is due to emissions
from nearby sources and part is due to emissions that travel hundreds
of miles and mix with emissions from other sources. Therefore, in many
instances the exact location of the upwind reductions does not affect
the levels of air pollution downwind.
It is important to note that the section of the Clean Air Act
providing authority for this rule, section 110(a)(2)(D), unlike some
other provisions, does not dictate levels of control for particular
facilities. As at least one commenter noted, none of the alternatives
put forward by EPA in the proposed rule could have ensured no emission
increases at any facility. Under the direct control alternative, the
emission rate for each facility would have been limited but each
facility could emit more by increasing their power output in order to
meet electricity reliability or other goals. Under the intrastate
trading option, sources could not trade allowances with sources in
other states but individual facilities within each state could have
increased their emissions as long as another facility in the state had
decreased theirs at some time.
The final Transport Rule allows sources to trade allowances with
other sources in the same or different states while firmly constraining
any emissions shifting that may occur by requiring a strict emission
ceiling in each state (the budget plus variability limit). In addition,
assurance provisions in the rule outline the allowance surrender
penalties for failing to meet the budget plus variability limits; there
are additional allowance penalties as well as financial penalties for
failing to hold an adequate number of allowances to cover emissions.
This approach eliminates emissions in each state that significantly
contribute to downwind nonattainment or maintenance areas, while
allowing power companies to adjust generation as needed and ensure that
the country's electricity needs will continue to be met. EPA maintains
that the existence of these assurance provisions, including the
penalties imposed when triggered, will ensure that state emissions will
stay below the level of the budget plus variability limit.
In addition, all sources must hold enough allowances to cover their
emissions. Therefore, if a source emits more than its allocation in a
given year, either another source must have used less than its
allocation and be willing to sell some of its excess allowances, or the
source itself had emitted less than its allocation in one or more
previous years (i.e., banked allowances for future use).
In summary, the final remedy addresses commenter concerns about
localized hot spots and reduces ambient concentrations of pollution
where they are most needed by sensitive and vulnerable populations by:
Considering the science of ozone and PM2.5 transport to set
strict state budgets to eliminate significant contributions to ozone
and PM2.5 nonattainment and maintenance (i.e., the most
polluted) areas; implementing air quality-assured trading; requiring
any emissions above the level of the allocations to be offset by
emission decreases; and imposing strict penalties for sources that
contribute to a state's exceedance of its budget plus variability
limit. In addition, it is important to note that nothing in this final
rule allows sources to violate their title V permit or any other
federal, state, or local emissions or air quality requirements.
EPA received comments from several tribal commenters regarding the
lack of allocations in the proposal to new units in Indian Country. EPA
responded to these comments by changing the allocation approach in the
final rule to create Indian country new unit set-asides. In order to
protect tribal sovereignty, these set-asides will be managed and
distributed by the federal government regardless of whether the
Transport Rule in the adjoining or surrounding state is implemented
through a FIP or SIP. While there are no existing power plants in
Indian country covered by this Transport Rule, the Indian country set-
asides will ensure that any future new units built in Indian country
will be able to get the necessary allowances. A full discussion of the
Indian country new unit set-asides can be found in section VII.D.2.
EPA also received several comments during the comment period from
individuals and groups requesting additional emission reductions to
further protect sensitive and vulnerable communities. While EPA has
adjusted the emission requirements somewhat in the final rule to
accommodate revised data and updated modeling results, we are
finalizing emission reductions very similar to the level in the
proposal. This is because EPA believes that the emission reductions
required by this final rule are appropriate to meet the statutory
requirements of CAA section 110(a)(2)(d) and respond to the concerns
raised by the Court's opinion in North Carolina that remanded CAIR to
the Agency in 2008.
In addition, it is important to note that CAA section 110(a)(2)(d),
which addresses transport of criteria pollutants between states, is
only one of many provisions of the CAA that provide EPA, states, and
local governments with authorities to reduce exposure to ozone and
PM2.5 in communities. These legal authorities work together
to reduce exposure to these pollutants in communities, including for
minority, low-income, and tribal populations, and provide substantial
health benefits to both the general public and sensitive sub-
populations.
For example, the recently-proposed Mercury and Air Toxics Standards
(MATS) would also result in significant reductions in SO2
emissions and provide significant health and environmental benefits
nationwide. This and other actions described in section III will have
substantial and long-term effects on both the U.S. power industry and
on communities currently breathing dirty air. Therefore, we anticipate
significant interest in many, if not most, of these actions from
environmental justice communities, among many others. EPA will continue
to provide multiple opportunities for comment on these actions, similar
to the opportunities provided during the comment process for this rule,
detailed at the end of this section. We encourage environmental justice
communities to review and comment on these actions.
2. Potential Environmental and Public Health Impacts Among Populations
Susceptible or Vulnerable to Air Pollution
EPA expects that this final rule will provide significant health
and environmental benefits to, among others, people with asthma, people
with heart disease, and people living in ozone or PM2.5
nonattainment areas. EPA's analysis of the effects of this rule,
including information on air quality changes and the resulting health
benefits, is presented both in section
[[Page 48349]]
VIII of this preamble and in the Regulatory Impact Analysis (RIA) for
this rule. These documents can be accessed through the rule docket No.
EPA-HQ-OAR-2009-0491 and from the main EPA webpage for the rule at
http://www.epa.gov/airtransport.
EPA considered several aspects of the effects of the Transport Rule
on minority, low-income, and tribal populations. These included: amount
of emission reductions and where they take place (including any
potential for areas of increased emissions); the changes in ambient
concentrations across the affected area; the estimated health benefits;
and how the estimated health benefits are distributed among different
populations, including those susceptible and vulnerable to air
pollution health impacts.
a. Emission Reductions
EPA's emission modeling data indicate that implementation of the
Transport Rule will substantially reduce SO2 emissions from
electric generating units (EGUs). As noted in section III, emissions in
states covered by the Transport Rule will decrease by 6.4 million tons
(73 percent) in 2014 compared to 2005 (the year the Clean Air
Interstate Rule was finalized). Emissions are also projected to
decrease when compared to the base case (the base case estimates
emissions in 2014 in the absence of this rule or the Clean Air
Interstate Rule it is replacing). EPA estimates that SO2
emissions in 2014 in covered states will be 3.9 million tons lower (62
percent lower) compared to the base case.
EPA also assessed emission changes in states not covered by the
Transport Rule. Emissions in the states not covered by the Transport
Rule are also projected to decrease substantially compared to 2005
levels; in 2014 SO2 emissions are projected to be
approximately 430,000 tons lower (30 percent lower) than in 2005.
As described in section VI.C, EPA's modeling does project that some
states not covered by any of the fine particle control programs in the
final Transport Rule may experience increases of SO2
emissions greater than 5,000 tons compared to the base case. These
states are Arkansas, Colorado, Louisiana, Montana, and Wyoming. These
emission increases are the result of forecasted changes in operation of
power plant units outside of the Transport Rule states due to the
interconnected nature of the utility grid (i.e., shifts in generation
of electricity to sources outside the Transport Rule states) or
influence of the rule on the market for lower sulfur coal. For example,
EPA projects that the rule will raise demand for lower sulfur coal in
the states covered by the Transport Rule for PM2.5 (thereby
raising its price), which may lead sources in states not covered for
PM2.5 to choose higher-sulfur coals that increase
SO2 emissions in those states.
EPA is not requiring SO2 emission reductions in these
states under this rule because our modeling indicates none of these
states' contributions would increase enough to cause them to meet or
exceed the thresholds described in section V.D for either of the
PM2.5 standards. EPA's authority under CAA section
110(a)(2)(d) is limited to addressing this significant contribution to
nonattainment and interference with maintenance. However, as noted
above, EPA has recently proposed the Mercury and Air Toxics Standards
that will apply nationwide and result in substantial additional
SO2 emission reductions, including in states not covered by
the Transport Rule.
EPA's emission modeling data indicates that ozone-season
NOX emissions from EGUs in states covered by the Transport
Rule will be approximately 340,000 tons lower (36 percent lower) in
2014 than they were in 2005. Emissions in states not covered by the
Transport Rule are also expected to decrease somewhat (approximately
82,000 tons or 25 percent). EPA's modeling does project that two states
(California and Pennsylvania) may experience increases of
NOX emissions greater than 5,000 tons in 2014 compared to
2005 levels. California is not covered by the Transport Rule; in
Pennsylvania, 2005 was an unusually low-emitting year and sources are
projected to increase their heat input slightly (usually meaning they
are generating more power) after the rule takes effect.
EPA also assessed the expected changes in seasonal NOX
emissions with implementation of the Transport Rule compared to the
base case (i.e., without the rule) in 2014. The modeling indicates
ozone-season NOX emissions from EGUs in both covered states
and non-Transport Rule states under this rule will be lower than they
would have been in 2014 in the base case. Ozone-season NOX
emissions in covered states are projected to decrease by approximately
74,000 tons (11 percent); ozone-season NOX emissions in non-
Transport Rule states are projected to decrease by approximately 10,000
tons (4 percent). Both California and Pennsylvania are projected to
have lower NOX emissions in 2014 under the Transport Rule as
compared to the base case. In addition, EPA anticipates that additional
upcoming actions, including likely additional interstate transport
reductions to help states attain the upcoming new ozone NAAQS, will
result in significant additional NOX reductions in the
future.
b. Air Quality Improvements
EPA assessed the air quality metrics (called ``design values'') for
each NAAQS addressed in this rule: 24-hour PM2.5, annual
PM2.5, and ozone. We then compared these metrics for the
final rule to the same metrics in the recent past (2003-2007 average
ambient air quality) and for the 2014 base case to assess improvements
in air quality.
EPA's modeling indicates that there will be significant
improvements in air quality as measured by the 24-hour PM2.5
standard. Throughout much of the eastern half of the U.S., 24-hour
PM2.5 design values are projected to improve more than 10
[mu]g/m\3\ compared to the 2003-2007 average levels. In addition,
compared to the 2014 base case levels, we project the Transport Rule
will result in improvements of 8-10 [mu]g/m\3\ in a broad swath of
states stretching from far southwestern New York through Pennsylvania,
Ohio, West Virginia, Maryland, Indiana, southern Illinois, eastern
Missouri, eastern Arkansas, Kentucky, Tennessee, northern Alabama, and
northern Mississippi. Isolated areas of Virginia and northern New
Jersey are also expected to see this level of improvement. Improvements
of 2-6 [mu]g/m\3\ are projected in surrounding states stretching from
New England and New York to Minnesota, Iowa, the far eastern edge of
Nebraska, Missouri, eastern Kansas, Oklahoma, Texas, the Gulf of Mexico
states, and the states bordering the Atlantic Ocean from Florida to New
Hampshire.
EPA modeling indicates that air quality as measured by the annual
PM2.5 design value will also improve. Improvements range
from 2 to over 4 [mu]g/m\3\ compared to the 2003-2007 average levels
throughout the eastern half of the U.S. Annual PM2.5 air
quality with the Transport Rule is also projected to improve compared
to the 2014 base case levels. The largest improvements of up to 4
[mu]g/m\3\ are projected to occur in northern West Virginia and a small
area in northwestern Tennessee. Improvements of up to 3 [mu]g/m\3\ are
projected for portions of the Ohio River valley areas of southwestern
Pennsylvania, Ohio, West Virginia, Kentucky, central Tennessee, and
southern Indiana. Improvements of up to 2 [mu]g/m\3\ are projected to
take place in a ring of surrounding states including all or most of New
York, Michigan, Indiana,
[[Page 48350]]
Illinois, Missouri, Arkansas, the far eastern edge of Oklahoma, the
northeastern edge of Texas, Louisiana, Mississippi, Alabama, Georgia,
South Carolina, North Carolina, Virginia, Maryland, Delaware,
Pennsylvania, and New Jersey. Smaller improvements are projected in New
England, Wisconsin, the Plains states, southeastern New Mexico, and
Florida.
EPA modeling indicates that ozone air quality will improve greatly
(10-12 ppb or more) across much of the eastern U.S. between the average
levels seen in 2003-2007 and implementation of the Transport Rule. Most
of the improvements take place in the base case; that is, they are the
result of federal and state programs other than the Transport Rule.
However, ozone air quality is projected to improve somewhat as a direct
result of the Transport Rule. Improvements in ozone design values
compared to the base case of more than 1 ppb are projected for portions
of Florida, eastern Oklahoma, and areas along the upper reaches of the
Ohio River. In addition, improvements in ozone design values of up to 1
ppb are projected over a wide area across the eastern U.S. from New
England to Texas and north to Minnesota. Improvements are also
projected in north-central Colorado.
EPA's modeling does indicate small increases in annual
PM2.5 air quality design values in the final rule compared
to the 2014 base case in two counties outside of the Transport Rule
states: one county in northern Colorado and one county in eastern
Montana. As noted above in the section on emissions, these increases
are likely the result of forecasted changes in electricity generation
due to the interconnected nature of both the utility grid and the
national low-sulfur coal market. It should be noted that 2003-2007
average air quality levels in these counties are well below the level
of the NAAQS. In addition, other actions, including federal rules such
as the recently proposed Mercury and Air Toxics Standards, state, or
local actions may also improve air quality in these areas over the next
few years.
As described in section VIII.B, EPA anticipates that this final
rule will reduce, but not eliminate, the number of nonattainment and
maintenance areas for the 1997 ozone and PM2.5 and 2006
PM2.5 NAAQS. As noted above, ozone and PM2.5
concentrations are the result of both local emissions and long-range
transport of pollution. Even when the significant contributions of
upwind states are fully eliminated, additional emission reductions
within the nonattainment area and/or the downwind state will be needed
for some areas to attain and maintain the NAAQS.
c. Estimated Health Benefits
This rule reduces concentrations of PM2.5 and ozone
pollution. Exposure to these pollutants can cause, or contribute to,
adverse health effects that affect many minority, low-income, and
tribal individuals and communities. PM2.5 and ozone are
particularly (but not exclusively) harmful to children, the elderly,
and people with existing heart and lung diseases, including asthma.
Exposure to these pollutants can cause premature death and trigger
heart attacks, asthma attacks in those with asthma, chronic and acute
bronchitis, emergency room visits and hospitalizations, as well as
milder illnesses that keep children home from school and adults home
from work. High rates of heart disease (e.g., high blood pressure)
\123\ and asthma \124\ exist in many environmental justice communities,
making these populations more susceptible to air pollution health
impacts. In addition, many individuals in these communities lack access
to high quality health care to treat these illnesses.\125\
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\123\ Neighborhood of Residence and Incidence of Coronary Heart
Disease Ana V. Diez Roux, M.D., PhD et al. N Engl J Med 2001;
345:99-106; July 12, 2001.
\124\ Centers for Disease Control and Prevention. 2007 National
Health 11. Interview Survey Data. Table 4-1. Current Asthma
Prevalence Percents by Age, United States: National Health Interview
Survey, 2007. Atlanta, GA: U.S. Department of Health and Human
Services, CDC, 2010. Accessed June 1, 2010.
\125\ R. Nelson, Eds. National Institute of Medicine, 2003.
---------------------------------------------------------------------------
We estimate that in 2014 the PM-related annual benefits of the
final rule include approximately 13,000 to 34,000 fewer premature
mortalities, 8,700 fewer cases of chronic bronchitis, 15,000 fewer non-
fatal heart attacks, 8,500 fewer hospitalizations (for respiratory and
cardiovascular disease combined), 10 million fewer days of restricted
activity due to respiratory illness, and approximately 1.7 million
fewer lost work days. We also estimate substantial health improvements
for children in the form of fewer cases of upper and lower respiratory
illness, acute bronchitis, and asthma attacks.
Ozone health-related benefits are expected to occur during the
summer ozone season (usually ranging from May to September in the
eastern U.S.). Based upon modeling for 2014, annual ozone related
health benefits are expected to include (in addition to the PM-related
benefits above) between 27-120 fewer premature mortalities, 240 fewer
hospital admissions for respiratory illnesses in children and older
adults, 86 fewer emergency room admissions for asthma, 160,000 fewer
days with restricted activity levels, and 51,000 fewer ``school
absence'' days when children are absent from school due to illnesses.
When adding the PM and ozone-related mortalities together, we find that
the final rule will yield between 13,000 and 34,000 fewer premature
mortalities.
It should be noted that, as discussed in the RIA, there are other
benefits to the emission reductions discussed here, including many
other health benefits beyond reducing the risk of premature mortality.
Additional benefits of reducing emissions of SO2 include
improved visibility, reduced acidification of lakes and streams, and
reduced mercury methylation in contaminated waters; additional benefits
of NOX reductions include improved visibility, reduced
acidification of lakes and streams, and reduced coastal eutrophication.
d. Distribution of Health Benefits Among Different Populations
EPA also estimated the PM2.5 mortality risks according
to race, income, and educational attainment before and after
implementation of this Transport Rule. We used premature mortality for
this analysis for several reasons: It is the most serious health effect
of exposure to PM2.5, and EPA has access to nationwide
incidence and demographic data at an appropriate scale to conduct this
type of analysis. EPA included educational attainment in this
assessment because research on the effects of PM2.5 has
found that educational attainment is inversely related to the risk of
all-cause mortality. That is, populations with lower levels of
education (in particular, less than grade 12) experience higher rates
of PM2.5 mortality. Krewski and colleagues \126\ note in
their analysis of this relationship that the level of education
attainment is likely to be a surrogate for the effects of complex
socioeconomic processes (including factors such as race and income) on
mortality.
---------------------------------------------------------------------------
\126\ Krewski D, Jerrett M, Burnett RT, Ma R, Hughes E, Shi Y,
Turner C, Pope CA, Thurston G, Calle EE, Thunt MJ. Extended follow-
up and spatial analysis of the American Cancer Society study linking
particulate air pollution and mortality. HEI Research Report, 140,
2009; Health Effects Institute, Boston, MA.
---------------------------------------------------------------------------
In the first step of the analysis, we estimated baseline (2005)
PM2.5 mortality risk by race (White, Black, Asian, Native
American) among people living in the counties with the highest (top 5
percent) PM2.5 mortality risk. We
[[Page 48351]]
also estimated baseline PM2.5 mortality risk by race among
people living in the counties with both the highest (top 5 percent)
poverty rate and the highest (top 5 percent) PM2.5 mortality
risk in 2005. And, we estimated the baseline (2005) PM2.5
mortality risk by educational attainment for people living in the
highest PM2.5 mortality risk counties. In the second step,
we estimated the changes in risk for different races among the people
living in these ``high-risk'' and ``high risk and high-poverty''
counties resulting from implementation of other existing rules in 2014
and from implementation of just the Transport Rule in 2014. Finally, in
the third step, we compared the effects of the Transport Rule by race
in the high-risk and high risk/high-poverty counties with the effects
on people (by race) living in all other counties.
In 2005, people living in the highest-risk counties and in the high
risk/high poverty counties had substantially greater risks of
PM2.5-related death than people living in the other 95
percent of counties. This was true regardless of race: The difference
among races in both groups of counties was very small and dwarfed by
the large difference between the two groups of counties for all races.
For educational attainment, in contrast, our analysis found that people
with less than high school education had significantly greater risks
from PM2.5 mortality than people with a greater than high
school education. This was especially true for people living in the
highest-risk counties, but also held true for people living in all
other counties. In summary, in 2005, having less than a high school or
high school education, living in one of the poorest counties, and
living in a high air pollution risk county are associated with higher
PM2.5 mortality risk; race is not.
Our analysis of the effects of the Transport Rule on this
underlying exposure pattern finds that the rule will significantly
reduce the PM2.5 mortality among all populations of
different races living throughout the U.S. compared to both 2005 and
2014 pre-rule (i.e., base case) levels. No group will experience any
increases in PM2.5 related deaths as a result of
implementing the Transport Rule.
The analysis indicates that the populations with the largest
improvement (i.e., largest decline) in PM2.5 mortality risk
as a result of the Transport Rule in 2014 (compared to the base case in
2014) are people living in the highest-risk counties. Among these
counties, the largest improvements are for people with less than high
school or high school education. These reductions in risk within the
highest-risk counties, as well as the reductions in risk within the
other 95 percent of counties, are distributed among populations of
different races fairly evenly. Therefore, there is no indication that
people of particular race receive a greater benefit (or smaller
benefit) than others.
The analysis indicates that people living in the high risk/high
poverty counties will experience larger improvements in risk from the
Transport Rule compared to their counterparts in the other counties.
This result suggests that the Transport Rule is providing the greatest
risk reduction improvements among counties containing the poorest, and
highest risk, populations. There is also little difference in the
improvement in risk among races; in other words, people in the high
risk/high poverty counties experience the same improvement in risk
regardless of race.
The analysis also indicates that this rule, in conjunction with the
implementation of existing or proposed rules (e.g., the proposed
Mercury and Air Toxics Standards), will reduce the disparity in risk
between the highest-risk counties and the other 95 percent of counties
for all races and educational levels. In addition, implementation of
this Transport Rule and other rules will, together, reduce risks in the
poorest and highest risk counties to the approximate level of risk for
the rest of the counties before implementation. This analysis is
presented in more detail in the RIA for this rule which is available in
the rule docket No. EPA-HQ-OAR-2009-0491 and from the main EPA webpage
for the rule at http://www.epa.gov/airtransport.
3. Meaningful Public Participation
EPA defines ``Environmental Justice'' to include meaningful
involvement of all people regardless of race, color, national origin,
or income with respect to the development, implementation, and
enforcement of environmental laws, regulations, and policies. To
promote meaningful involvement, EPA developed a communication and
outreach strategy to ensure that interested communities had access to
the proposed Transport Rule, were aware of its content, and had an
opportunity to comment during the comment period. These efforts are
summarized below.
As EPA began considering approaches to address the court remand of
the 2005 Clean Air Interstate Rule, long before the rule was proposed,
the agency also began gathering input from a large range of
stakeholders. In the spring of 2009, EPA held a series of listening
sessions to gather information and perspectives from stakeholders prior
to the formal start of the rulemaking process. These stakeholders
included a number of environmental groups who requested that EPA
consider several potential environmental justice issues during
development of this rule. In addition, many environmental justice
organizations were represented at a November 2009 EPA-Health and Human
Services White House Stakeholder Briefing titled, ``The Public Health
Benefits of Energy Reform'' in which EPA discussed our intention to
propose this rule in the spring of 2010 and participants had the
opportunity to respond. Finally, EPA notified Indian Tribes of our
intent to propose this rule in the fall of 2009 during a regularly
scheduled meeting to update the National Tribal Air Association members
of upcoming EPA policies and regulations and to receive input from them
on the effects of these efforts in Indian country. These were not
opportunities for stakeholders to comment on the specifics of the
proposal, as they took place prior to its development, but they
provided valuable information that EPA used in developing the proposal.
Just after the rule was proposed in July 2010, EPA presented a
summary of information related to the proposed Transport Rule at the
National Environmental Justice Advisory Council (NEJAC) meeting in
Washington, DC, and responded to questions from NEJAC members regarding
the proposed rule. EPA also solicited suggestions for how to engage
environmental justice communities during the rule comment period.
During the public comment period, EPA held public hearings in
Chicago, Philadelphia, and Atlanta. Each hearing was advertised by EPA
through a variety of products targeted to general audiences (e.g., fact
sheets, press release, slide presentation, etc.); on EPA's
environmental justice listserve; and by non-profit organizations (e.g.,
American Lung Association). The public hearings were held in public
buildings (i.e., no formal identification required to enter or to
speak) and were open for 11 hours (9 a.m.-8 p.m.) to accommodate
commenters with various work schedules. All three hearings were well-
attended by members of the general public. During hearing breaks, EPA
staff spent time talking with individuals, including those representing
environmental justice organizations or communities, to understand their
perspectives in greater detail. As noted above, several commenters at
each hearing made comments related to the need to protect communities
living near power plants and the most vulnerable
[[Page 48352]]
individuals. Some of these commenters specifically mentioned
environmental justice; others mentioned issues often of concern to
environmental justice communities, such as hot spots, interest in
additional emission reductions and greater environmental protection,
and concern over the effects of the rule on the most sensitive and
vulnerable populations.
In September 2010, during the comment period, EPA held a webinar
for EJ communities on the proposed Transport Rule. A presentation
tailored for an audience of environmental justice, community, and
tribal representatives was specifically designed for this webinar. It
was sent to registered participants beforehand and put on the Transport
Rule webpage, where it remains posted. The presentation included both
information on the context of the rule, plain language information
describing the rule itself, and directions on how to comment on the
rule.
EPA staff made a short presentation and answered questions about
the Transport Rule on a standing bi-monthly community conference call
targeted to environmental justice and tribal representatives and
organizations. In addition, at the fall 2010 NEJAC meeting in Kansas
City, Missouri, EPA provided details of the proposed Transport Rule as
part of a larger discussion of a sector-based approach to utility
regulation.
Regarding tribal consultation, EPA sent letters to all 565
federally-recognized Tribes in the country offering consultation on the
proposed Transport Rule. In addition, the January 7 NODA on allowance
allocation methodologies specifically requested comment on allocating
allowances to new units in Indian Country. EPA held two consultation
and information-sharing calls with 16 interested Tribes in late January
and early February 2011. Tribes participating on these consultation and
information calls provided comments on the proposed rule and the
allowance allocation NODA. As noted above, this additional input from
the consultation process was taken into account in the development of
the final rule. See Section XII.F for more information on tribal
consultation.
4. Summary
EPA believes that the vast majority of communities and individuals
in areas covered by this rule, including numerous low-income, minority,
and tribal individuals and communities in both rural areas and inner
cities in the eastern and central U.S., will see significant
improvements in air quality and resulting improvements in health. EPA's
assessment of the effects of the proposed and final Transport Rules on
these communities included: (a) The structure of the rule and responses
to comments received on issues specific to these communities; (b)
expected SO2 and NOX emission reductions; (c)
expected PM2.5 and ozone air quality improvements; (d)
expected health benefits, including asthma and other health effects of
particular concern for environmental justice communities; and (e) a
quantitative assessment of the expected socioeconomic distribution of a
key health benefit (reduction in premature mortality). All of these
analyses indicate large health and environmental benefits for these
communities; none shows evidence of adverse effects. As a result, EPA
concludes that we do not expect disproportionately high and adverse
human health or environmental effects on minority, low-income, or
tribal populations in the United States as a result of implementing
this final Transport Rule.
K. 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. 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.
804(2). This rule will be effective October 7, 2011.
L. Judicial Review
Petitions for judicial review of this action must be filed in the
United States Court of Appeals for the District of Columbia Circuit by
October 7, 2011. 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 Transport Rule is ``nationally
applicable'' within the meaning of section 307(b)(1). Through this
rule, EPA interprets section 110 of the CAA, a provision which has
nationwide applicability. In addition, the Transport Rule applies to 27
States. The Transport Rule is also based on a common core of factual
findings and analyses concerning the transport of pollutants between
the different states subject to it. For these reasons, the
Administrator also is determining that any final action regarding the
Transport Rule is of nationwide scope and effect for purposes of
section 307(b)(1). Thus, pursuant to section 307(b) any petitions for
review of final actions regarding the Transport Rule 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.
Filing a petition for reconsideration of this action does not
affect the finality of this rule for the purposes of judicial review
nor does it extend the time within which a petition for judicial review
may be filed and shall not postpone the effectiveness of such rule or
action. In addition, pursuant to CAA section 307(b)(2) this action may
not be challenged later in proceedings to enforce its requirements.
In addition, this action is subject to the provisions of section
307(d). CAA section 307(d)(1)(B) provides that section 307(d) applies
to, among other things, to ``the promulgation or revision of an
implementation plan by the Administrator under CAA section 110(c)'' (42
U.S.C. 7407(d)(1)(B)). The Agency has complied with procedural
requirements of CAA section 307(d) during the course of this
rulemaking.
List of Subjects
40 CFR Part 51
Administrative practice and procedure, Air pollution control,
Incorporation by reference, Intergovernmental relations, Nitrogen
oxides, Ozone, Particulate matter, Regional haze, Reporting and
recordkeeping requirements, Sulfur dioxide.
40 CFR Part 52
Administrative practice and procedure, Air pollution control,
Incorporation by reference, Intergovernmental relations, Nitrogen
[[Page 48353]]
oxides, Ozone, Particulate matter, Regional haze, Reporting and
recordkeeping requirements, Sulfur dioxide.
40 CFR Part 72
Acid rain, Administrative practice and procedure, Air pollution
control, Electric utilities, Incorporation by reference,
Intergovernmental relations, Nitrogen oxides, Reporting and
recordkeeping requirements, Sulfur dioxide.
40 CFR Part 78
Acid rain, Administrative practice and procedure, Air pollution
control, Electric utilities, Intergovernmental relations, Nitrogen
oxides, Reporting and recordkeeping requirements, Sulfur dioxide.
40 CFR Part 97
Administrative practice and procedure, Air pollution control,
Electric utilities, Nitrogen oxides, Reporting and recordkeeping
requirements, Sulfur dioxide.
Dated: July 6, 2011.
Lisa P. Jackson,
Administrator.
For the reasons set forth in the preamble, parts 51, 52, 72, 78,
and 97 of chapter I of title 40 of the Code of Federal Regulations are
amended as follows:
PART 51--[AMENDED]
0
1. The authority citation for part 51 continues to read as follows:
Authority: 23 U.S.C. 101; 42 U.S.C. 7401-7671q.
Sec. 51.121 [Amended]
0
2. In Sec. 51.121 paragraph (r)(2) is amended by removing the words
``Sec. 51.123(bb)'' and adding, in their place, the words ``Sec.
51.123(bb) with regard to an ozone season that occurs before January 1,
2012''.
0
3. Section 51.123 is amended by adding a new paragraph (ff) to read as
follows:
Sec. 51.123 Findings and requirements for submission of State
implementation plan revisions relating to emissions of oxides of
nitrogen pursuant to the Clean Air Interstate Rule.
* * * * *
(ff) Notwithstanding any provisions of paragraphs (a) through (ee)
of this section, subparts AA through II and AAAA through IIII of part
96 of this chapter, subparts AA through II and AAAA through IIII of
part 97 of this chapter, and any State's SIP to the contrary:
(1) With regard to any control period that begins after December
31, 2011, the Administrator:
(i) Rescinds the determination in paragraph (a) of this section
that the States identified in paragraph (c) of this section must submit
a SIP revision with respect to the fine particles (PM2.5)
NAAQS and the 8-hour ozone NAAQS meeting the requirements of paragraphs
(b) through (ee) of this section; and
(ii) Will not carry out any of the functions set forth for the
Administrator in subparts AA through II and AAAA through IIII of part
96 of this chapter, subparts AA through II and AAAA through IIII of
part 97 of this chapter, or in any emissions trading program provisions
in a State's SIP approved under this section;
(2) The Administrator will not deduct for excess emissions any CAIR
NOX allowances or CAIR NOX Ozone Season
allowances allocated for 2012 or any year thereafter;
(3) By November 7, 2011, the Administrator will remove from the
CAIR NOX Allowance Tracking System accounts all CAIR
NOX allowances allocated for a control period in 2012 and
any subsequent year, and, thereafter, no holding or surrender of CAIR
NOX allowances will be required with regard to emissions or
excess emissions for such control periods; and
(4) By November 7, 2011, the Administrator will remove from the
CAIR NOX Ozone Season Allowance Tracking System accounts all
CAIR NOX Ozone Season allowances allocated for a control
period in 2012 and any subsequent year, and, thereafter, no holding or
surrender of CAIR NOX Ozone Season allowances will be
required with regard to emissions or excess emissions for such control
periods.
0
4. Section 51.124 is amended by adding a new paragraph (s) to read as
follows:
Sec. 51.124 Findings and requirements for submission of State
implementation plan revisions relating to emissions of sulfur dioxide
pursuant to the Clean Air Interstate Rule.
* * * * *
(s) Notwithstanding any provisions of paragraphs (a) through (r) of
this section, subparts AAA through III of part 96 of this chapter,
subparts AAA through III of part 97 of this chapter, and any State's
SIP to the contrary:
(1) With regard to any control period that begins after December
31, 2011, the Administrator:
(i) Rescinds the determination in paragraph (a) of this section
that the States identified in paragraph (c) of this section must submit
a SIP revision with respect to the fine particles (PM2.5)
NAAQS meeting the requirements of paragraphs (b) through (r) of this
section; and
(ii) Will not carry out any of the functions set forth for the
Administrator in subparts AAA through III of part 96 of this chapter,
subparts AAA through III of part 97 of this chapter, or in any
emissions trading program in a State's SIP approved under this section;
and
(2) The Administrator will not deduct for excess emissions any CAIR
SO2 allowances allocated for 2012 or any year thereafter.
Sec. 51.125 [Reserved]
0
5. Section 51.125 is removed and reserved.
PART 52--[AMENDED]
0
6. The authority citation for part 52 continues to read as follows:
Authority: 42 U.S.C. 7401, et seq.
Subpart A--General Provisions
0
7. Section 52.35 is amended by adding a new paragraph (f) to read as
follows:
Sec. 52.35 What are the requirements of the Federal Implementation
Plans (FIPs) for the Clean Air Interstate Rule (CAIR) relating to
emissions of nitrogen oxides?
* * * * *
(f) Notwithstanding any provisions of paragraphs (a) through (d) of
this section, subparts AA through II and AAAA through IIII of part 97
of this chapter, and any State's SIP to the contrary:
(1) With regard to any control period that begins after December
31, 2011,
(i) The provisions in paragraphs (a) through (d) of this section
relating to NOX annual or ozone season emissions shall not
be applicable; and
(ii) The Administrator will not carry out any of the functions set
forth for the Administrator in subparts AA through II and AAAA through
IIII of part 97 of this chapter;
(2) The Administrator will not deduct for excess emissions any CAIR
NOX allowances or CAIR NOX Ozone Season
allowances allocated for 2012 or any year thereafter;
(3) By November 7, 2011, the Administrator will remove from the
CAIR NOX Allowance Tracking System accounts all CAIR
NOX allowances allocated for a control period in 2012 and
any subsequent year, and, thereafter, no holding or surrender of CAIR
NOX allowances will be required with regard to emissions or
excess emissions for such control periods; and
[[Page 48354]]
(4) By November 7, 2011, the Administrator will remove from the
CAIR NOX Ozone Season Allowance Tracking System accounts all
CAIR NOX Ozone Season allowances allocated for a control
period in 2012 and any subsequent year, and, thereafter, no holding or
surrender of CAIR NOX allowances will be required with
regard to emissions or excess emissions for such control periods.
0
8. Section 52.36 is amended by adding a new paragraph (e) to read as
follows:
Sec. 52.36 What are the requirements of the Federal Implementation
Plans (FIPs) for the Clean Air Interstate Rule (CAIR) relating to
emissions of sulfur dioxide?
* * * * *
(e) Notwithstanding any provisions of paragraphs (a) through (c) of
this section, subparts AAA through III of part 97 of this chapter and
any State's SIP to the contrary:
(1) With regard to any control period that begins after December
31, 2011,
(i) The provisions of paragraphs (a) through (e) of this section
relating to SO2 emissions shall not be applicable; and
(ii) The Administrator will not carry out any of the functions set
forth for the Administrator in subparts AAA through III of part 97 of
this chapter; and
(2) The Administrator will not deduct for excess emissions any CAIR
SO2 allowances allocated for 2012 or any year thereafter.
0
9. Sections Sec. Sec. 52.38 and 52.39 are added to subpart A to read
as follows:
Sec. 52.38 What are the requirements of the Federal Implementation
Plans (FIPs) under the Transport Rule (TR) relating to emissions of
nitrogen oxides?
(a)(1) The TR NOX Annual Trading Program provisions set
forth in subpart AAAAA of part 97 of this chapter constitute the TR
Federal Implementation Plan provisions that relate to annual emissions
of nitrogen oxides (NOX).
(2) The provisions of subpart AAAAA of part 97 of this chapter
apply to the sources in the following States and Indian country located
within the borders of such States: Alabama, Georgia, Illinois, Indiana,
Iowa, Kansas, Kentucky, Maryland, Michigan, Minnesota, Missouri,
Nebraska, New Jersey, New York, North Carolina, Ohio, Pennsylvania,
South Carolina, Tennessee, Texas, Virginia, West Virginia, and
Wisconsin.
(3) Notwithstanding the provisions of paragraph (a)(1) of this
section, a State listed in paragraph (a)(2) of this section may adopt
and include in a SIP revision, and the Administrator will approve, as
TR NOX Annual allowance allocation provisions replacing the
provisions in Sec. 97.411(a) of this chapter with regard to the State
and the control period in 2013, a list of TR NOX Annual
units and the amount of TR NOX Annual allowances allocated
to each unit on such list, provided that the list of units and
allocations meets the following requirements:
(i) All of the units on the list must be units that are in the
State and commenced commercial operation before January 1, 2010;
(ii) The total amount of TR NOX Annual allowance
allocations on the list must not exceed the amount, under Sec.
97.410(a) of this chapter for the State and the control period in 2013,
of TR NOX Annual trading budget minus the sum of the new
unit set-aside and Indian country new unit set-aside;
(iii) The list must be submitted electronically in a format
specified by the Administrator; and
(iv) The SIP revision must not provide for any change in the units
and allocations on the list after approval of the SIP revision by the
Administrator and must not provide for any change in any allocation
determined and recorded by the Administrator under subpart AAAAA of
part 97 of this chapter;
(v) Provided that:
(A) By October 17, 2011, the State must notify the Administrator
electronically in a format specified by the Administrator of the
State's intent to submit to the Administrator a complete SIP revision
meeting the requirements of paragraph (a)(3)(i) through (iv) of this
section by April 1, 2012; and
(B) The State must submit to the Administrator a complete SIP
revision described in paragraph (a)(3)(v)(A) of this section by April
1, 2012.
(4) Notwithstanding the provisions of paragraph (a)(1) of this
section, a State listed in paragraph (a)(2) of this section may adopt
and include in a SIP revision, and the Administrator will approve,
regulations revising subpart AAAAA of part 97 of this chapter as
follows and not making any other substantive revisions of that subpart:
(i) The State may adopt, as TR NOX Annual allowance
allocation or auction provisions replacing the provisions in Sec. Sec.
97.411(a) and (b)(1) and 97.412(a) of this chapter with regard to the
State and the control period in 2014 or any subsequent year, any
methodology under which the State or the permitting authority allocates
or auctions TR NOX Annual allowances, and may adopt, in
addition to the definitions in Sec. 97.402 of this chapter, one or
more definitions that shall apply only to terms as used in the adopted
TR NOX Annual allowance allocation or auction provisions, if
such methodology--
(A) Requires the State or the permitting authority to allocate and,
if applicable, auction a total amount of TR NOX Annual
allowances for any such control period not exceeding the amount, under
Sec. Sec. 97.410(a) and 97.421 of this chapter for the State and such
control period, of the TR NOX Annual trading budget minus
the sum of the Indian country new unit set-aside and the amount of any
TR NOX Annual allowances already allocated and recorded by
the Administrator.
(B) Requires, to the extent the State adopts provisions for
allocations or auctions of TR NOX Annual allowances for any
such control period to any TR NOX Annual units covered by
Sec. 97.411(a) of this chapter, that the State or the permitting
authority submit such allocations or the results of such auctions for
such control period (except allocations or results of auctions to such
units of TR NOX Annual allowances remaining in a set-aside
after completion of the allocations or auctions for which the set-aside
was created) to the Administrator no later than the following dates:
------------------------------------------------------------------------
Year of the control period for which TR Deadline for submission of
NOX annual allowances are allocated or allocations or auction
auctioned results to administrator
------------------------------------------------------------------------
2014...................................... June 1, 2013.
2015...................................... June 1, 2013.
2016...................................... June 1, 2014.
2017...................................... June 1, 2014.
2018...................................... June 1, 2015.
2019...................................... June 1, 2015.
2020 and any year thereafter.............. June 1 of the fourth year
before the year of the
control period.
------------------------------------------------------------------------
(C) Requires, to the extent the State adopts provisions for
allocations or auctions of TR NOX Annual allowances for any
such control period to any TR NOX Annual units covered by
Sec. Sec. 97.411(b)(1) and 97.412(a) of this chapter, that the State
or the permitting authority submit such allocations or the results of
such auctions (except allocations or results of auctions to such units
of TR NOX Annual allowances remaining in a set-aside after
completion of the allocations or auctions for which the set-aside was
created) to the Administrator by July 1 of the year of such control
period.
(D) Does not provide for any change, after the submission deadlines
in paragraphs (a)(4)(i)(B) and (C) of this section, in the allocations
submitted to the Administrator by such deadlines and does not provide
for any change in
[[Page 48355]]
any allocation determined and recorded by the Administrator under
subpart AAAAA of part 97 of this chapter;
(ii) Provided that the State must submit a complete SIP revision
meeting the requirements of paragraph (a)(4)(i) of this section by
December 1 of the year before the year of the deadlines for submission
of allocations or auction results under paragraphs (a)(4)(i)(B) and (C)
of this section for the first control period for which the State wants
to make allocations or hold an auction under paragraph (a)(4)(i) of
this section.
(5) Notwithstanding the provisions of paragraph (a)(1) of this
section, a State listed in paragraph (a)(2) of this section may adopt
and include in a SIP revision, and the Administrator will approve, as
correcting in whole or in part, as appropriate, the deficiency in the
SIP that is the basis for the TR Federal Implementation Plan set forth
in paragraphs (a)(1) through (4) of this section, regulations that are
substantively identical to the provisions of the TR NOX
Annual Trading Program set forth in Sec. Sec. 97.402 through 97.435 of
this chapter, except that the SIP revision:
(i) May adopt, as TR NOX Annual allowance allocation or
auction provisions replacing the provisions in Sec. Sec. 97.411(a) and
(b)(1) and 97.412(a) of this chapter with regard to the State and the
control period in 2014 or any subsequent year, any methodology under
which the State or the permitting authority allocates or auctions TR
NOX Annual allowances and that--
(A) Requires the State or the permitting authority to allocate and,
if applicable, auction a total amount of TR NOX Annual
allowances for any such control period not exceeding the amount, under
Sec. Sec. 97.410(a) and 97.421 of this chapter for the State and such
control period, of the TR NOX Annual trading budget minus
the sum of the Indian country new unit set-aside and the amount of any
TR NOX Annual allowances already allocated and recorded by
the Administrator.
(B) Requires, to the extent the State adopts provisions for
allocations or auctions of TR NOX Annual allowances for any
such control period to any TR NOX Annual units covered by
Sec. 97.411(a) of this chapter, that the State or the permitting
authority submit such allocations or the results of such auctions for
such control period (except allocations or results of auctions to such
units of TR NOX Annual allowances remaining in a set-aside
after completion of the allocations or auctions for which the set-aside
was created) to the Administrator no later than the following dates:
------------------------------------------------------------------------
Year of the control period for which TR Deadline for submission of
NOX annual allowances are allocated or allocations or auction
auctioned results to administrator
------------------------------------------------------------------------
2014...................................... June 1, 2013.
2015...................................... June 1, 2013.
2016...................................... June 1, 2014.
2017...................................... June 1, 2014.
2018...................................... June 1, 2015.
2019...................................... June 1, 2015.
2020 and any year thereafter.............. June 1 of the fourth year
before the year of the
control period.
------------------------------------------------------------------------
(C) Requires, to the extent the State adopts provisions for
allocations or auctions of TR NOX Annual allowances for any
such control period to any TR NOX Annual units covered by
Sec. Sec. 97.411(b)(1) and 97.412(a) of this chapter, that the State
or the permitting authority submit such allocations or the results of
such auctions (except allocations or results of auctions to such units
of TR NOX Annual allowances remaining in a set-aside after
completion of the allocations or auctions for which the set-aside was
created) to the Administrator by July 1 of the year of such control
period.
(D) Does not provide for any change, after the submission deadlines
in paragraphs (a)(5)(i)(B) and (C) of this section, in the allocations
submitted to the Administrator by such deadlines and does not provide
for any change in any allocation determined and recorded by the
Administrator under subpart AAAAA of part 97 of this chapter;
(ii) May adopt, in addition to the definitions in Sec. 97.402 of
this chapter, one or more definitions that shall apply only to terms as
used in the TR NOX Annual allowance allocation or auction
provisions adopted under paragraph (a)(5)(i) of this section;
(iii) May substitute the name of the State for the term ``State''
as used in subpart AAAAA of part 97 of this chapter, to the extent the
Administrator determines that such substitutions do not make
substantive changes in the provisions in Sec. Sec. 97.402 through
97.435 of this chapter; and
(iv) Must not include any of the references to, or requirements
imposed on, any unit in Indian country within the borders of the State
in the provisions in Sec. Sec. 97.402 through 97.435 of this chapter
and must not include the provisions in Sec. Sec. 97.411(b)(2) and
97.412(b), all of which provisions will continue to apply under the
portion of the TR Federal Implementation Plan that is not replaced by
the SIP revision;
(v) Provided that, if and when any covered unit is located in
Indian country within the borders of the State, the Administrator may
modify his or her approval of the SIP revision to exclude the
provisions in Sec. Sec. 97.402 (definitions of ``common designated
representative'', ``common designated representative's assurance
level'', and ``common designated representative's share''),
97.406(c)(2), 97.425, and the portions of other provisions referencing
these sections and may modify the portion of the TR Federal
Implementation Plan that is not replaced by the SIP revision to include
these provisions;
(vi) Provided that the State must submit a complete SIP revision
meeting the requirements of paragraphs (a)(5)(i) through (iv) of this
section by December 1 of the year before the year of the deadlines for
submission of allocations or auction results under paragraphs
(a)(5)(i)(B) and (C) of this section applicable to the first control
period for which the State wants to make allocations or hold an auction
under paragraphs (a)(5)(i) and (ii) of this section.
(6) Following promulgation of an approval by the Administrator of a
State's SIP revision as correcting in whole or in part, as appropriate,
the SIP's deficiency that is the basis for the TR Federal
Implementation Plan described in paragraphs (a)(1) through (5) of this
section, the provisions of paragraph (a)(2) of this section will no
longer apply to the sources in the State, unless the Administrator's
approval of the SIP revision is partial or conditional, and will
continue to apply to sources in any Indian country within the borders
of the State.
(7) Notwithstanding the provisions of paragraph (a)(6) of this
section, if, at the time of such approval of the State's SIP revision,
the Administrator has already started recording any allocations of TR
NOX Annual allowances under subpart AAAAA of part 97 of this
chapter to units in a State for a control period in any year, the
provisions of subpart AAAAA of part 97 of this chapter authorizing the
Administrator to complete the allocation and recordation of TR
NOX Annual allowances to units in the State for each such
control period shall continue to apply, unless provided otherwise by
such approval of the State's SIP revision.
(b)(1) The TR NOX Ozone Season Trading Program
provisions set forth in part 97 of this chapter constitute the TR
Federal Implementation Plan provisions that relate to emissions of
NOX during the ozone season, defined as May 1 through
September 30 of a calendar year.
(2) The provisions of subpart BBBBB of part 97 of this chapter
apply to
[[Page 48356]]
sources in each of the following States and Indian country located
within the borders of such States: Alabama, Arkansas, Florida, Georgia,
Illinois, Indiana, Kentucky, Louisiana, Maryland, Mississippi, New
Jersey, New York, North Carolina, Ohio, Pennsylvania, South Carolina,
Tennessee, Texas, Virginia, and West Virginia.
(3) Notwithstanding the provisions of paragraph (b)(1) of this
section, a State listed in paragraph (b)(2) of this section may adopt
and include in a SIP revision, and the Administrator will approve, as
TR NOX Ozone Season allowance allocation provisions
replacing the provisions in Sec. 97.511(a) of this chapter with regard
to the State and the control period in 2013, a list of TR
NOX Ozone Season units and the amount of TR NOX
Ozone Season allowances allocated to each unit on such list, provided
that the list of units and allocations meets the following
requirements:
(i) All of the units on the list must be units that are in the
State and commenced commercial operation before January 1, 2010;
(ii) The total amount of TR NOX Ozone Season allowance
allocations on the list must not exceed the amount, under Sec.
97.510(a) of this chapter for the State and the control period in 2013,
of TR NOX Ozone Season trading budget minus the sum of the
new unit set-aside and Indian country new unit set-aside;
(iii) The list must be submitted electronically in a format
specified by the Administrator; and
(iv) The SIP revision must not provide for any change in the units
and allocations on the list after approval of the SIP revision by the
Administrator and must not provide for any change in any allocation
determined and recorded by the Administrator under subpart BBBBB of
part 97 of this chapter;
(v) Provided that:
(A) By October 17, 2011, the State must notify the Administrator
electronically in a format specified by the Administrator of the
State's intent to submit to the Administrator a complete SIP revision
meeting the requirements of paragraph (b)(3)(i) through (iv) of this
section by April 1, 2012; and
(B) The State must submit to the Administrator a complete SIP
revision described in paragraph (b)(3)(v)(A) of this section by April
1, 2012.
(4) Notwithstanding the provisions of paragraph (b)(1) of this
section, a State listed in paragraph (b)(2) of this section may adopt
and include in a SIP revision, and the Administrator will approve,
regulations revising subpart BBBBB of part 97 of this chapter as
follows and not making any other substantive revisions of that subpart:
(i) The State may adopt, as applicability provisions replacing the
provisions in Sec. Sec. 97.504(a)(1) and (2) of this chapter,
provisions substantively identical to those provisions, except that the
words ``more than 25 MWe'' are replaced, whenever such words appear, by
words specifying a uniform lower limit on the amount of megawatts that
is not greater than the amount specified by the words ``more than 25
MWe'' and is not less than the amount specified by the words ``15 MWe
or more''; or
(ii) The State may adopt, as TR NOX Ozone Season
allowance allocation or auction provisions replacing the provisions in
Sec. Sec. 97.511(a) and (b)(1) and 97.512(a) of this chapter with
regard to the control period in 2014 or any subsequent year, any
methodology under which the State or the permitting authority allocates
or auctions TR NOX Ozone Season allowances, and may adopt,
in addition to the definitions in Sec. 97.502 of this chapter, one or
more definitions that shall apply only to terms as used in the adopted
TR NOX Ozone Season allowance allocation or auction
provisions, if such methodology--
(A) Requires the State or the permitting authority to allocate and,
if applicable, auction a total amount of TR NOX Ozone Season
allowances for any such control period not exceeding the amount, under
Sec. Sec. 97.510(a) and 97.521 of this chapter for the State and such
control period, of the TR NOX Ozone Season trading budget
minus the sum of the Indian country new unit set-aside and the amount
of any TR NOX Ozone Season allowances already allocated and
recorded by the Administrator.
(B) Requires, to the extent the State adopts provisions for
allocations or auctions of TR NOX Ozone Season allowances
for any such control period to any TR NOX Ozone Season units
covered by Sec. 97.511(a) of this chapter, that the State or the
permitting authority submit such allocations or the results of such
auctions for such control period (except allocations or results of
auctions to such units of TR NOX Ozone Season allowances
remaining in a set-aside after completion of the allocations or
auctions for which the set-aside was created) to the Administrator no
later than the following dates:
------------------------------------------------------------------------
Year of the control period for which TR Deadline for submission of
NOX Ozone Season allowances are allocated allocations or auction
or auctioned results to administrator
------------------------------------------------------------------------
2014...................................... June 1, 2013.
2015...................................... June 1, 2013.
2016...................................... June 1, 2014.
2017...................................... June 1, 2014.
2018...................................... June 1, 2015.
2019...................................... June 1, 2015.
2020 and any year thereafter.............. June 1 of the fourth year
before the year of the
control period.
------------------------------------------------------------------------
(C) Requires, to the extent the State adopts provisions for
allocations or auctions of TR NOX Ozone Season allowances
for any such control period to any TR NOX Ozone Season units
covered by Sec. Sec. 97.511(b)(1) and 97.512(a) of this chapter, that
the State or the permitting authority submit such allocations or the
results of such auctions (except allocations or results of auctions to
such units of TR NOX Ozone Season allowances remaining in a
set-aside after completion of the allocations or auctions for which the
set-aside was created) to the Administrator by July 1 of the year of
such control period.
(D) Does not provide for any change, after the submission deadlines
in paragraphs (b)(4)(ii)(B) and (C) of this section, in the allocations
submitted to the Administrator by such deadlines and does not provide
for any change in any allocation determined and recorded by the
Administrator under subpart BBBBB of part 97 of this chapter;
(iii) Provided that the State must submit a complete SIP revision
meeting the requirements of paragraph (b)(4)(i) or (ii) of this section
by December 1 of the year before the year of the deadlines for
submission of allocations or auction results under paragraphs
(b)(4)(ii)(B) and (C) of this section applicable to the first control
period for which the State wants to replace the applicability
provisions, make allocations, or hold an auction under paragraph
(b)(4)(i) or (ii) of this section.
(5) Notwithstanding the provisions of paragraph (b)(1) of this
section, a State listed in paragraph (b)(2) of this section may adopt
and include in a SIP revision, and the Administrator will approve, as
correcting in whole or in part, as appropriate, the deficiency in the
SIP that is the basis for the TR Federal Implementation Plan set forth
in paragraphs (b)(1) through (4) of this section, regulations that are
substantively identical to the provisions of the TR NOX
Ozone Season Trading Program set forth in Sec. Sec. 97.502 through
97.535 of this chapter, except that the SIP revision:
[[Page 48357]]
(i) May adopt, as applicability provisions replacing the provisions
in Sec. Sec. 97.504(a)(1) and (2) of this chapter, provisions
substantively identical to those provisions, except that the words
``more than 25 MWe'' are replaced, whenever such words appear, by words
specifying a uniform lower limit on the amount of megawatts that is not
greater than the amount specified by the words ``more than 25 MWe'' and
is not less than the amount specified by the words ``15 MWe or more'';
or
(ii) May adopt, as TR NOX Ozone Season allowance
allocation provisions replacing the provisions in Sec. Sec. 97.511(a)
and (b)(1) and 97.512(a) of this chapter with regard to the control
period in 2014 and any subsequent year, any methodology under which the
State or the permitting authority allocates auctions TR NOX
Ozone Season allowances and that--
(A) Requires the State or the permitting authority to allocate and,
if applicable, auction a total amount of TR NOX Ozone Season
allowances for any such control period not exceeding the amount, under
Sec. Sec. 97.510(a) and 97.521 of this chapter for the State and such
control period, of the TR NOX Ozone Season trading budget
minus the sum of the Indian country new unit set-aside and the amount
of any TR NOX Ozone Season allowances already allocated and
recorded by the Administrator.
(B) Requires, to the extent the State adopts provisions for
allocations or auction of TR NOX Ozone Season allowances for
any such control period to any TR NOX Ozone Season units
covered by Sec. 97.511(a) of this chapter, that the State or the
permitting authority submit such allocations or the results of such
auctions for such control period (except allocations or results of
auctions to such units of TR NOX Ozone Season allowances
remaining in a set-aside after completion of the allocations or
auctions for which the set-aside was created) to the Administrator no
later than the following dates:
------------------------------------------------------------------------
Year of the control period for which TR Deadline for submission of
NOX Ozone Season allowances are allocated allocations or auction
or auctioned results to administrator
------------------------------------------------------------------------
2014...................................... June 1, 2013.
2015...................................... June 1, 2013.
2016...................................... June 1, 2014.
2017...................................... June 1, 2014.
2018...................................... June 1, 2015.
2019...................................... June 1, 2015.
2020 and any year thereafter.............. June 1 of the fourth year
before the year of the
control period.
------------------------------------------------------------------------
(C) Requires, to the extent the State adopts provisions for
allocations or auctions of TR NOX Ozone Season allowances
for any control period to any TR NOX Ozone Season units
covered by Sec. Sec. 97.511(b)(1) and 97.512(a) of this chapter, that
the State or the permitting authority submit such allocations or the
results of such auctions (except allocations or results of auctions to
such units of TR NOX Ozone Season allowances remaining in a
set-aside after completion of the allocations or auctions for which the
set-aside was created) to the Administrator by July 1 of the year of
such control period.
(D) Does not provide for any change, after the submission deadlines
in paragraphs (b)(5)(ii)(B) and (C) of this section, in the allocations
submitted to the Administrator by such deadlines and does not provide
for any change in any allocation determined and recorded by the
Administrator under subpart BBBBB of part 97 of this chapter;
(iii) May adopt in addition to the definitions in Sec. 97.502 of
this chapter, one or more definitions that shall apply only to terms as
used in the TR NOX Ozone Season allowance allocation or
auction provisions adopted under paragraph (b)(5)(ii) of this section;
(iv) May substitute the name of the State for the term ``State'' as
used in subpart BBBBB of part 97 of this chapter, to the extent the
Administrator determines that such substitutions do not make
substantive changes in the provisions in Sec. Sec. 97.502 through
97.535 of this chapter; and
(v) Must not include any of the references to, or requirements
imposed on, any unit in Indian country within the borders of the State
in the provisions in Sec. Sec. 97.502 through 97.535 of this chapter
and must not include the provisions in Sec. Sec. 97.511(b)(2) and
97.512(b), all of which provisions will continue to apply under the
portion of the TR Federal Implementation Plan that is not replaced by
the SIP revision;
(vi) Provided that, if and when any covered unit is located in
Indian country within the borders of the State, the Administrator may
modify his or her approval of the SIP revision to exclude the
provisions in Sec. Sec. 97.502 (definitions of ``common designated
representative'', ``common designated representative's assurance
level'', and ``common designated representative's share''),
97.506(c)(2), 97.525, and the portions of other provisions referencing
these sections and may modify the portion of the TR Federal
Implementation Plan that is not replaced by the SIP revision to include
these provisions;
(vii) Provided that the State must submit a complete SIP revision
meeting the requirements of paragraph (b)(5)(i) through (v) of this
section by December 1 of the year before the year of the deadlines for
submission of allocations or auction results under paragraphs
(5)(ii)(B) and (C) of this section applicable to the first control
period for which the State wants to replace the applicability
provisions, make allocations, or hold an auction under paragraphs
(b)(5)(ii) and (iii) of this section.
(6) Following promulgation of an approval by the Administrator of a
State's SIP revision as correcting in whole or in part, as appropriate,
the SIP's deficiency that is the basis for the TR Federal
Implementation Plan set forth in paragraphs (b)(1) through (5) of this
section, the provisions of paragraph (b)(2) of this section will no
longer apply to sources in the State, unless the Administrator's
approval of the SIP revision is partial or conditional, and will
continue to apply to sources in any Indian country within the borders
of the State.
(7) Notwithstanding the provisions of paragraph (b)(6) of this
section, if, at the time of such approval of the State's SIP revision,
the Administrator has already started recording any allocations of TR
NOX Ozone Season allowances under subpart BBBBB of part 97
of this chapter to units in a State for a control period in any year,
the provisions of subpart BBBBB of part 97 of this chapter authorizing
the Administrator to complete the allocation and recordation of TR
NOX Ozone Season allowances to units in the State for each
such control period shall continue to apply, unless provided otherwise
by such approval of the State's SIP revision.
Sec. 52.39 What are the requirements of the Federal Implementation
Plans (FIPs) for the Transport Rule (TR) relating to emissions of
sulfur dioxide?
(a) The TR SO2 Group 1 Trading Program provisions and
the TR SO2 Group 2 Trading Program provisions set forth
respectively in subparts CCCCC and DDDDD of part 97 of this chapter
constitute the TR Federal Implementation Plan provisions that relate to
emissions of sulfur dioxide (SO2).
(b) The provisions of subpart CCCCC of part 97 of this chapter
apply to sources in each of the following States and Indian country
located within the borders of such States: Illinois, Indiana, Iowa,
Kentucky, Maryland, Michigan, Missouri, New Jersey, New York, North
Carolina, Ohio, Pennsylvania, Tennessee, Virginia, West Virginia, and
Wisconsin.
[[Page 48358]]
(c) The provisions of subpart DDDDD of part 97 of this chapter
apply to sources in each of the following States and Indian country
located within the borders of such States: Alabama, Georgia, Kansas,
Minnesota, Nebraska, South Carolina, and Texas.
(d) Notwithstanding the provisions of paragraph (a) of this
section, a State listed in paragraph (b) of this section may adopt and
include in a SIP revision, and the Administrator will approve, as TR
SO2 Group 1 allowance allocation provisions replacing the
provisions in Sec. 97.611(a) of this chapter with regard to the State
and the control period in 2013, a list of TR SO2 Group 1
units and the amount of TR SO2 Group 1 allowances allocated
to each unit on such list, provided that the list of units and
allocations meets the following requirements:
(1) All of the units on the list must be units that are in the
State and commenced commercial operation before January 1, 2010;
(2) The total amount of TR SO2 Group 1 allowance
allocations on the list must not exceed the amount, under Sec.
97.610(a) of this chapter for the State and the control period in 2013,
of TR SO2 Group 1 trading budget minus the sum of the new
unit set-aside and Indian country new unit set-aside;
(3) The list must be submitted electronically in a format specified
by the Administrator; and
(4) The SIP revision must not provide for any change in the units
and allocations on the list after approval of the SIP revision by the
Administrator and must not provide for any change in any allocation
determined and recorded by the Administrator under subpart CCCCC of
part 97 of this chapter;
(5) Provided that:
(i) By October 17, 2011, the State must notify the Administrator
electronically in a format specified by the Administrator of the
State's intent to submit to the Administrator a complete SIP revision
meeting the requirements of paragraph (d)(1) through (4) of this
section by April 1, 2012; and
(ii) The State must submit to the Administrator a complete SIP
revision described in paragraph (d)(5)(i) of this section by April 1,
2012.
(e) Notwithstanding the provisions of paragraph (a) of this
section, a State listed in paragraph (b) of this section may adopt and
include in a SIP revision, and the Administrator will approve,
regulations revising subpart CCCCC of part 97 of this chapter as
follows and not making any other substantive revisions of that subpart:
(1) The State may adopt, as TR SO2 Group 1 allowance
allocation or auction provisions replacing the provisions in Sec. Sec.
97.611(a) and (b)(1) and 97.612(a) of this chapter with regard to the
control period in 2014 or any subsequent year, any methodology under
which the State or the permitting authority allocates or auctions TR
SO2 Group 1 allowances and may adopt, in addition to the
definitions in Sec. 97.602 of this chapter, one or more definitions
that shall apply only to terms as used in the adopted TR SO2
Group 1 allowance allocation or auction provisions, if such
methodology--
(i) Requires the State or the permitting authority to allocate and,
if applicable, auction a total amount of TR SO2 Group 1
allowances for any such control period not exceeding the amount, under
Sec. Sec. 97.610(a) and 97.621 of this chapter for the State and such
control period, of the TR SO2 Group 1 trading budget minus
the sum of the Indian country new unit set-aside and the amount of any
TR SO2 Group 1 allowances already allocated and recorded by
the Administrator.
(ii) Requires, to the extent the State adopts provisions for
allocations or auction of TR SO2 Group 1 allowances for any
such control period to any TR SO2 Group 1 units covered by
Sec. 97.611(a) of this chapter, that the State or the permitting
authority submit such allocations or the results of such auctions for
such control period (except allocations or results of auctions to such
units of TR SO2 Group 1 allowances remaining in a set-aside
after completion of the allocations or auctions for which the set-aside
was created) to the Administrator no later than the following dates:
------------------------------------------------------------------------
Year of the control period for which TR Deadline for submission of
SO2 Group 1 allowances are allocated or allocations or auction
auctioned results to administrator
------------------------------------------------------------------------
2014...................................... June 1, 2013.
2015...................................... June 1, 2013.
2016...................................... June 1, 2014.
2017...................................... June 1, 2014.
2018...................................... June 1, 2015.
2019...................................... June 1, 2015.
2020 and any year thereafter.............. June 1 of the fourth year
before the year of the
control period.
------------------------------------------------------------------------
(iii) Requires, to the extent the State adopts provisions for
allocations or auctions of TR SO2 Group 1 allowances for any
such control period to any TR SO2 Group 1 units covered by
Sec. Sec. 97.611(b)(1) and 97.612(a) of this chapter, that the State
or the permitting authority submit such allocations or the results of
such auctions (except allocations or results of auctions to such units
of TR SO2 Group 1 allowances remaining in a set-aside after
completion of the allocations or auctions for which the set-aside was
created) to the Administrator by July 1 of the year of such control
period.
(iv) Does not provide for any change, after the submission
deadlines in paragraphs (e)(1)(ii) and (iii) of this section, in the
allocations submitted to the Administrator by such deadlines and does
not provide for any change in any allocation determined and recorded by
the Administrator under subpart CCCCC of part 97 of this chapter;
(2) Provided that the State must submit a complete SIP revision
meeting the requirements of paragraph (e)(1) of this section by
December 1 of the year before the year of the deadlines for submission
of allocations or auction results under paragraphs (e)(1)(ii) and (iii)
of this section applicable to the first control period for which the
State wants to make allocations or hold an auction under paragraph
(e)(1) of this section.
(f) Notwithstanding the provisions of paragraph (a) of this
section, a State listed in paragraph (b) of this section may adopt and
include in a SIP revision, and the Administrator will approve, as
correcting in whole or in part, as appropriate, the deficiency in the
SIP that is the basis for the TR Federal Implementation Plan set forth
in paragraphs (a), (b), (d), and (e) of this section, regulations that
are substantively identical to the provisions of the TR SO2
Group 1 Trading Program set forth in Sec. Sec. 97.602 through 97.635
of this chapter, except that the SIP revision:
(1) May adopt, as TR SO2 Group 1 allowance allocation or
auction provisions replacing the provisions in Sec. Sec. 97.611(a) and
(b)(1) and 97.612(a) of this chapter with regard to the control period
in 2014 and any subsequent year, any methodology under which the State
or the permitting authority allocates or auctions TR SO2
Group 1 allowances and that--
(i) Requires the State or the permitting authority to allocate and,
if applicable, auction a total amount of TR SO2 Group 1
allowances for such control period not exceeding the amount, under
Sec. Sec. 97.610(a) and 97.621 of this chapter for the State and such
control period, of the TR SO2 Group 1 trading budget minus
the sum of the Indian country new unit set-aside and the amount of any
TR SO2 Group 1 allowances already allocated and recorded by
the Administrator.
(ii) Requires, to the extent the State adopts provisions for
allocations or auction of TR SO2 Group 1 allowances for any
such control period to any TR
[[Page 48359]]
SO2 Group 1 units covered by Sec. 97.611(a) of this
chapter, that the State or the permitting authority submit such
allocations or the results of such auctions for such control period
(except allocations or results of auctions to such units of TR
SO2 Group 1 allowances remaining in a set-aside after
completion of the allocations or auctions for which the set-aside was
created) to the Administrator no later than the following dates:
------------------------------------------------------------------------
Year of the control period for which TR Deadline for submission of
SO2 Group 1 allowances are allocated or allocations or auction
auctioned results to administrator
------------------------------------------------------------------------
2014...................................... June 1, 2013.
2015...................................... June 1, 2013.
2016...................................... June 1, 2014.
2017...................................... June 1, 2014.
2018...................................... June 1, 2015.
2019...................................... June 1, 2015.
2020 and any year thereafter.............. June 1 of the fourth year
before the year of the
control period.
------------------------------------------------------------------------
(iii) Requires, to the extent the State adopts provisions for
allocations or auctions of TR SO2 Group 1 allowances for any
such control period to any TR SO2 Group 1 units covered by
Sec. Sec. 97.611(b)(1) and 97.612(a) of this chapter, that the State
or the permitting authority submit such allocations or the results of
such auctions (except allocations or results of auctions to such units
of TR SO2 Group 1 allowances remaining in a set-aside after
completion of the allocations or auctions for which the set-aside was
created) to the Administrator by July 1 of the year of such control
period.
(iv) Does not provide for any change, after the submission
deadlines in paragraphs (f)(2)(ii) and (iii) of this section, in the
allocations submitted to the Administrator by such deadlines and does
not provide for any change in any allocation determined and recorded by
the Administrator under subpart CCCCC of part 97 of this chapter;
(2) May adopt, in addition to the definitions in Sec. 97.602 of
this chapter, one or more definitions that shall apply only to terms as
used in the TR SO2 Group 1 allowance allocation or auction
provisions adopted under paragraph (f)(1) of this section;
(3) May substitute the name of the State for the term ``State'' as
used in subpart CCCCC of part 97 of this chapter, to the extent the
Administrator determines that such substitutions do not make
substantive changes in the provisions in Sec. Sec. 97.602 through
97.635 of this chapter; and
(4) Must not include any of the references to, or requirements
imposed on, any unit in Indian country within the borders of the State
in the provisions in Sec. Sec. 97.602 through 97.635 of this chapter
and must not include the provisions in Sec. Sec. 97.611(b)(2) and
97.612(b), all of which provisions will continue to apply under the
portion of the TR Federal Implementation Plan that is not replaced by
the SIP revision;
(5) Provided that, if and when any covered unit is located in
Indian country within the borders of the State, the Administrator may
modify his or her approval of the SIP revision to exclude the
provisions in Sec. Sec. 97.602 (definitions of ``common designated
representative'', ``common designated representative's assurance
level'', and ``common designated representative's share''),
97.606(c)(2), 97.625, and the portions of other provisions referencing
these sections and may modify the portion of the TR Federal
Implementation Plan that is not replaced by the SIP revision to include
these provisions;
(6) Provided that the State must submit a complete SIP revision
meeting the requirements of paragraphs (f)(1) through (4) of this
section by December 1 of the year before the year of the deadlines for
submission of allocations or auction results under paragraphs
(f)(1)(ii) and (iii) of this section applicable to the first control
period for which the State wants to make allocations or hold an auction
under paragraph (f)(1)(ii) and (iii) of this section.
(g) Notwithstanding the provisions of paragraph (a) of this
section, a State listed in paragraph (c) of this section may adopt and
include in a SIP revision, and the Administrator will approve, as TR
SO2 Group 2 allowance allocation provisions replacing the
provisions in Sec. 97.711(a) of this chapter with regard to the
control period in 2013, a list of TR SO2 Group 2 units and
the amount of TR SO2 Group 2 allowances allocated to each
unit on such list, provided that the list of units and allocations
meets the following requirements:
(1) All of the units on the list must be units that are in the
State and commenced commercial operation before January 1, 2010;
(2) The total amount of TR SO2 Group 2 allowance
allocations on the list must not exceed the amount, under Sec.
97.710(a) of this chapter for the State and the control period in 2013,
of TR SO2 Group 2 trading budget minus the sum of the new
unit set-aside and Indian country new unit set-aside;
(3) The list must be submitted electronically in a format specified
by the Administrator; and
(4) The SIP revision must not provide for any change in the units
and allocations on the list after approval of the SIP revision by the
Administrator and must not provide for any change in any allocation
determined and recorded by the Administrator under subpart DDDDD of
part 97 of this chapter;
(5) Provided that:
(i) By October 17, 2011, the State must notify the Administrator
electronically in a format specified by the Administrator of the
State's intent to submit to the Administrator a complete SIP revision
meeting the requirements of paragraph (g)(1) through (4) of this
section by April 1, 2012; and
(ii) The State must submit to the Administrator a complete SIP
revision described in paragraph (g)(5)(i) of this section by April 1,
2012.
(h) Notwithstanding the provisions of paragraph (a) of this
section, a State listed in paragraph (c) of this section may adopt and
include in a SIP revision, and the Administrator will approve,
regulations revising subpart DDDDD of part 97 of this chapter as
follows and not making any other substantive revisions of that subpart:
(1) The State may adopt, as TR SO2 Group 2 allowance
allocation or auction provisions replacing the provisions in Sec. Sec.
97.711(a) and (b)(1) and 97.712(a) of this chapter with regard to the
control period in 2014 and any subsequent year, any methodology under
which the State or the permitting authority allocates or auctions TR
SO2 Group 2 allowances and may adopt, in addition to the
definitions in Sec. 97.702 of this chapter, one or more definitions
that shall apply only to terms as used in the adopted TR SO2
Group 2 allowance allocation or auction provisions, if such
methodology--
(i) Requires the State or the permitting authority to allocate and,
if applicable, auction a total amount of TR SO2 Group 2
allowances for any such control period not exceeding the amount, under
Sec. Sec. 97.710(a) and 97.721 of this chapter for the State and such
control period, of the TR SO2 Group 2 trading budget minus
the sum of the Indian country new unit set-aside and the amount of any
TR SO2 Group 2 allowances already allocated and recorded by
the Administrator.
(ii) Requires, to the extent the State adopts provisions for
allocations or auction of TR SO2 Group 2 allowances for any
such control period to any TR SO2 Group 2 units covered by
Sec. 97.711(a) of this chapter, that the State or the permitting
authority submit such
[[Page 48360]]
allocations or the results of such auctions for such control period
(except allocations or results of auctions to such units of TR
SO2 Group 2 allowances remaining in a set-aside after
completion of the allocations or auctions for which the set-aside was
created) to the Administrator no later than the following dates:
------------------------------------------------------------------------
Year of the control period for which TR Deadline for submission of
SO2 Group 2 allowances are allocated or allocations or auction
auctioned results to administrator
------------------------------------------------------------------------
2014...................................... June 1, 2013.
2015...................................... June 1, 2013.
2016...................................... June 1, 2014.
2017...................................... June 1, 2014.
2018...................................... June 1, 2015.
2019...................................... June 1, 2015.
2020 and any year thereafter.............. June 1 of the fourth year
before the year of the
control period.
------------------------------------------------------------------------
(iii) Requires, to the extent the State adopts provisions for
allocations or auctions of TR SO2 Group 2 allowances for any
such control period to any TR SO2 Group 2 units covered by
Sec. Sec. 97.711(b)(1) and 97.712(a) of this chapter, that the State
or the permitting authority submit such allocations or the results of
such auctions (except allocations or results of auctions to such units
of TR SO2 Group 2 allowances remaining in a set-aside after
completion of the allocations or auctions for which the set-aside was
created) to the Administrator by July 1 of the year of such control
period.
(iv) Does not provide for any change, after the submission
deadlines in paragraphs (h)(1)(ii) and (iii) of this section, in the
allocations submitted to the Administrator by such deadlines and does
not provide for any change in any allocation determined and recorded by
the Administrator under subpart DDDDD of part 97 of this chapter;
(2) Provided that the State must submit a complete SIP revision
meeting the requirements of paragraph (h)(1) of this section by
December 1 of the year before the year of the deadlines for submission
of allocations or auction results under paragraphs (h)(1)(ii) and (iii)
of this section applicable to the first control period for which the
State wants to make allocations or hold an auction under paragraph
(h)(1)(ii) and (iii) of this section.
(i) Notwithstanding the provisions of paragraph (a) of this
section, a State listed in paragraph (c) of this section may adopt and
include in a SIP revision, and the Administrator will approve, as
correcting in whole or in part, as appropriate, the deficiency in the
SIP that is the basis for the TR Federal Implementation Plan set forth
in paragraphs (a), (c), (g), and (h) of this section, regulations that
are substantively identical to the provisions of the TR SO2
Group 2 Trading Program set forth in Sec. Sec. 97.702 through 97.735
of this chapter, except that the SIP revision:
(1) May adopt, as TR SO2 Group 2 allowance allocation or
auction provisions replacing the provisions in Sec. Sec. 97.711(a) and
(b)(1) and 97.712(a) of this chapter with regard to the control period
in 2014 and any subsequent year, any methodology under which the State
or the permitting authority allocates or auctions TR SO2
Group 2 allowances and that--
(i) Requires the State or the permitting authority to allocate and,
if applicable, auction a total amount of TR SO2 Group 2
allowances for any such control period not exceeding the amount, under
Sec. Sec. 97.710(a) and 97.721 of this chapter for the State and such
control period, of the TR SO2 Group 2 trading budget minus
the sum of the Indian country new unit set-aside and the amount of any
TR SO2 Group 2 allowances already allocated and recorded by
the Administrator.
(ii) Requires, to the extent the State adopts provisions for
allocations or auction of TR SO2 Group 2 allowances for any
such control period to any TR SO2 Group 2 units covered by
Sec. 97.711(a) of this chapter, that the State or the permitting
authority submit such allocations or the results of such auctions for
such control period (except allocations or results of auctions to such
units of TR SO2 Group 1 allowances remaining in a set-aside
after completion of the allocations or auctions for which the set-aside
was created) to the Administrator no later than the following dates:
------------------------------------------------------------------------
Year of the control period for which TR Deadline for submission of
SO2 Group 2 allowances are allocated or allocations or auction
auctioned results to administrator
------------------------------------------------------------------------
2014...................................... June 1, 2013.
2015...................................... June 1, 2013.
2016...................................... June 1, 2014.
2017...................................... June 1, 2014.
2018...................................... June 1, 2015.
2019...................................... June 1, 2015.
2020 and any year thereafter.............. June 1 of the fourth year
before the year of the
control period.
------------------------------------------------------------------------
(iii) Requires, to the extent the State adopts provisions for
allocations or auctions of TR SO2 Group 2 allowances for any
such control period to any TR SO2 Group 2 units covered by
Sec. Sec. 97.711(b)(1) and 97.712(a) of this chapter, that the State
or the permitting authority submit such allocations or the results of
such auctions (except allocations or results of auctions to such units
of TR SO2 Group 2 allowances remaining in a set-aside after
completion of the allocations or auctions for which the set-aside was
created) to the Administrator by July 1 of the year of such control
period.
(iv) Does not provide for any change, after the submission
deadlines in paragraphs (i)(1)(ii) and (iii) of this section, in the
allocations submitted to the Administrator by such deadlines and does
not provide for any change in any allocation determined and recorded by
the Administrator under subpart DDDDD of part 97 of this chapter;
(2) May adopt, in addition to the definitions in Sec. 97.702 of
this chapter, one or more definitions that shall apply only to terms as
used in the TR SO2 Group 2 allowance allocation or auction
provisions adopted under paragraph (i)(1) of this section;
(3) May substitute the name of the State for the term ``State'' as
used in subpart DDDDD of part 97 of this chapter, to the extent the
Administrator determines that such substitutions do not make
substantive changes in the provisions in Sec. Sec. 97.702 through
97.735 of this chapter; and
(4) Must not include any of the references to, or requirements
imposed on, any unit in Indian country within the borders of the State
in the provisions in Sec. Sec. 97.702 through 97.735 of this chapter
and must not include the provisions in Sec. Sec. 97.711(b)(2) and
97.712(b), all of which provisions will continue to apply under the
portion of the TR Federal Implementation Plan that is not replaced by
the SIP revision;
(5) Provided that, if and when any covered unit is located in
Indian country within the borders of the State, the Administrator may
modify his or her approval of the SIP revision to exclude the
provisions in Sec. Sec. 97.702 (definitions of ``common designated
representative'', ``common designated representative's assurance
level'', and ``common designated representative's share''),
97.706(c)(2), 97.725, and the portions of other provisions referencing
these sections and may modify the portion of the TR Federal
Implementation Plan that is not replaced by the SIP revision to include
these provisions;
(6) Provided that the State must submit a complete SIP revision
meeting the requirements of paragraphs (i)(1) through (4) of this
section by December 1 of the year before the year of the deadlines for
submission of allocations or auction results under paragraphs
[[Page 48361]]
(i)(1)(ii) and (iii) of this section applicable to the first control
period for which the State wants to make allocations or hold an auction
under paragraphs (i)(1)(ii) and (iii) of this section.
(j) Following promulgation of an approval by the Administrator of a
State's SIP revision as correcting in whole or in part, as appropriate,
the SIP's deficiency that is the basis for the TR Federal
Implementation Plan, the provisions of paragraph (b) and (c) of this
section, as applicable, will no longer apply to sources in the State,
unless the Administrator's approval of the SIP revision is partial or
conditional, and will continue to apply to sources in any Indian
country within the borders of the State.
(k) Notwithstanding the provisions of paragraph (j) of this
section, if, at the time of such approval of the State's SIP revision,
the Administrator has already started recording any allocations of TR
SO2 Group 1 allowances under subpart CCCCC of part 97 of
this chapter, or allocations of TR SO2 Group 2 allowances
under subpart DDDDD of part 97 of this chapter, to units in a State for
a control period in any year, the provisions of subpart CCCCC of part
97 of this chapter authorizing the Administrator to complete the
allocation and recordation of TR SO2 Group 1 allowances, or
of subpart DDDDD of part 97 of this chapter authorizing the
Administrator to complete the allocation and recordation of TR
SO2 Group 2 allowances, as applicable, to units in the State
for each such control period shall continue to apply, unless provided
otherwise by such approval of the State's SIP revision.
Subpart B--Alabama
0
10. Section 52.54 is added to read as follows:
Sec. 52.54 Interstate pollutant transport provisions; What are the
FIP requirements for decreases in emissions of nitrogen oxides?
(a)(1) The owner and operator of each source and each unit located
in the State of Alabama and for which requirements are set forth under
the TR NOX Annual Trading Program in subpart AAAAA of part
97 of this chapter must comply with such requirements. The obligation
to comply with such requirements will be eliminated by the promulgation
of an approval by the Administrator of a revision to Alabama's State
Implementation Plan (SIP) as correcting the SIP's deficiency that is
the basis for the TR Federal Implementation Plan under Sec. 52.38(a),
except to the extent the Administrator's approval is partial or
conditional.
(2) Notwithstanding the provisions of paragraph (a)(1) of this
section, if, at the time of the approval of Alabama's SIP revision
described in paragraph (a)(1) of this section, the Administrator has
already started recording any allocations of TR NOX Annual
allowances under subpart AAAAA of part 97 of this chapter to units in
the State for a control period in any year, the provisions of subpart
AAAAA of part 97 of this chapter authorizing the Administrator to
complete the allocation and recordation of TR NOX Annual
allowances to units in the State for each such control period shall
continue to apply, unless provided otherwise by such approval of the
State's SIP revision.
(b)(1) The owner and operator of each source and each unit located
in the State of Alabama and for which requirements are set forth under
the TR NOX Ozone Season Trading Program in subpart BBBBB of
part 97 of this chapter must comply with such requirements. The
obligation to comply with such requirements will be eliminated by the
promulgation of an approval by the Administrator of a revision to
Alabama's State Implementation Plan (SIP) as correcting the SIP's
deficiency that is the basis for the TR Federal Implementation Plan
under Sec. 52.38(b), except to the extent the Administrator's approval
is partial or conditional.
(2) Notwithstanding the provisions of paragraph (b)(1) of this
section, if, at the time of the approval of the Alabama's SIP revision
described in paragraph (b)(1) of this section, the Administrator has
already started recording any allocations of TR NOX Ozone
Season allowances under subpart BBBBB of part 97 of this chapter to
units in the State for a control period in any year, the provisions of
subpart BBBBB of part 97 of this chapter authorizing the Administrator
to complete the allocation and recordation of TR NOX Ozone
Season allowances to units in the State for each such control period
shall continue to apply, unless provided otherwise by such approval of
the State's SIP revision.
0
11. Section 52.55 is added to read as follows:
Sec. 52.55 Interstate pollutant transport provisions; What are the
FIP requirements for decreases in emissions of sulfur dioxide?
(a) The owner and operator of each source and each unit located in
the State of Alabama and for which requirements are set forth under the
TR SO2 Group 2 Trading Program in subpart DDDDD of part 97
of this chapter must comply with such requirements. The obligation to
comply with such requirements will be eliminated by the promulgation of
an approval by the Administrator of a revision to Alabama's State
Implementation Plan (SIP) as correcting the SIP's deficiency that is
the basis for the TR Federal Implementation Plan under Sec. 52.39,
except to the extent the Administrator's approval is partial or
conditional.
(b) Notwithstanding the provisions of paragraph (a) of this
section, if, at the time of the approval of Alabama's SIP revision
described in paragraph (a) of this section, the Administrator has
already started recording any allocations of TR SO2 Group 2
allowances under subpart DDDDD of part 97 of this chapter to units in
the State for a control period in any year, the provisions of subpart
DDDDD of part 97 of this chapter authorizing the Administrator to
complete the allocation and recordation of TR SO2 Group 2
allowances to units in the State for each such control period shall
continue to apply, unless provided otherwise by such approval of the
State's SIP revision.
Subpart E--Arkansas
0
12. Section 52.184 is added to read as follows:
Sec. 52.184 Interstate pollutant transport provisions; What are the
FIP requirements for decreases in emissions of nitrogen oxides?
(a) The owner and operator of each source and each unit located in
the State of Arkansas and for which requirements are set forth under
the TR NOX Ozone Season Trading Program in subpart BBBBB of
part 97 of this chapter must comply with such requirements. The
obligation to comply with such requirements will be eliminated by the
promulgation of an approval by the Administrator of a revision to
Arkansas' State Implementation Plan (SIP) as correcting the SIP's
deficiency that is the basis for the TR Federal Implementation Plan
under Sec. 52.38(b), except to the extent the Administrator's approval
is partial or conditional.
(b) Notwithstanding the provisions of paragraph (a) of this
section, if, at the time of the approval of Arkansas' SIP revision
described in paragraph (a) of this section, the Administrator has
already started recording any allocations of TR NOX Ozone
Season allowances under subpart BBBBB of part 97 of this chapter to
units in the State for a control period in any year, the provisions of
subpart BBBBB of part 97 of this chapter authorizing the Administrator
to complete the allocation and recordation of TR NOX Ozone
Season allowances to
[[Page 48362]]
units in the State for each such control period shall continue to
apply, unless provided otherwise by such approval of the State's SIP
revision.
Subpart I--Delaware
0
13. Section 52.440 is amended by adding a new paragraph (c) to read as
follows:
Sec. 52.440 Interstate pollutant transport provisions; What are the
FIP requirements for decreases in emissions of nitrogen oxides?
* * * * *
(c) Notwithstanding any provisions of paragraphs (a) and (b) of
this section and subparts AA through II and AAAA through IIII of part
97 of this chapter to the contrary:
(1) With regard to any control period that begins after December
31, 2011,
(i) The provisions in paragraphs (a) and (b) of this section
relating to NOX annual or ozone season emissions shall not
be applicable; and
(ii) The Administrator will not carry out any of the functions set
forth for the Administrator in subparts AA through II and AAAA through
IIII of part 97 of this chapter; and
(2) The Administrator will not deduct for excess emissions any CAIR
NOX allowances or CAIR NOX Ozone Season
allowances allocated for 2012 or any year thereafter;
(3) By November 7, 2011, the Administrator will remove from the
CAIR NOX Allowance Tracking System accounts all CAIR
NOX allowances allocated for a control period in 2012 and
any subsequent year, and, thereafter, no holding or surrender of CAIR
NOX allowances will be required with regard to emissions or
excess emissions for such control periods; and
(4) By November 7, 2011, the Administrator will remove from the
CAIR NOX Ozone Season Allowance Tracking System accounts all
CAIR NOX Ozone Season allowances allocated for a control
period in 2012 and any subsequent year, and, thereafter, no holding or
surrender of CAIR NOX Ozone Season allowances will be
required with regard to emissions or excess emissions for such control
periods.
0
14. Section 52.441 is amended by designating the existing text as
paragraph (a) and adding a new paragraph (b) to read as follows:
Sec. 52.441 Interstate pollutant transport provisions; What are the
FIP requirements for decreases in emissions of sulfur dioxide?
* * * * *
(b) Notwithstanding any provisions of paragraph (a) of this section
and subparts AAA through III of part 97 of this chapter and any State's
SIP to the contrary:
(1) With regard to any control period that begins after December
31, 2011,
(i) The provisions of paragraph (a) of this section relating to
SO2 emissions shall not be applicable; and
(ii) The Administrator will not carry out any of the functions set
forth for the Administrator in subparts AAA through III of part 97 of
this chapter; and
(2) The Administrator will not deduct for excess emissions any CAIR
SO2 allowances allocated for 2012 or any year thereafter.
Subpart J--District of Columbia
0
15. Section 52.484 is amended by adding a new paragraph (c) to read as
follows:
Sec. 52.484 Interstate pollutant transport provisions; What are the
FIP requirements for decreases in emissions of nitrogen oxides?
* * * * *
(c) Notwithstanding any provisions of paragraphs (a) and (b) of
this section and subparts AA through II and AAAA through IIII of part
97 of this chapter to the contrary:
(1) With regard to any control period that begins after December
31, 2011,
(i) The provisions in paragraphs (a) and (b) of this section
relating to NOX annual or ozone season emissions shall not
be applicable; and
(ii) The Administrator will not carry out any of the functions set
forth for the Administrator in subparts AA through II and AAAA through
IIII of part 97 of this chapter; and
(2) The Administrator will not deduct for excess emissions any CAIR
NOX allowances or CAIR NOX Ozone Season
allowances allocated for 2012 or any year thereafter;
(3) By November 7, 2011, the Administrator will remove from the
CAIR NOX Allowance Tracking System accounts all CAIR
NOX allowances allocated for a control period in 2012 and
any subsequent year, and, thereafter, no holding or surrender of CAIR
NOX allowances will be required with regard to emissions or
excess emissions for such control periods; and
(4) By November 7, 2011, the Administrator will remove from the
CAIR NOX Ozone Season Allowance Tracking System accounts all
CAIR NOX Ozone Season allowances allocated for a control
period in 2012 and any subsequent year, and, thereafter, no holding or
surrender of CAIR NOX Ozone Season allowances will be
required with regard to emissions or excess emissions for such control
periods.
0
16. Section 52.485 is amended by designating the existing text as
paragraph (a) and adding a new paragraph (b) to read as follows:
Sec. 52.485 Interstate pollutant transport provisions; What are the
FIP requirements for decreases in emissions of sulfur dioxide?
* * * * *
(b) Notwithstanding any provisions of paragraph (a) of this section
and subparts AAA through III of part 97 of this chapter and any State's
SIP to the contrary:
(1) With regard to any control period that begins after December
31, 2011,
(i) The provisions of paragraph (a) of this section relating to
SO2 emissions shall not be applicable; and
(ii) The Administrator will not carry out any of the functions set
forth for the Administrator in subparts AAA through III of part 97 of
this chapter; and
(2) The Administrator will not deduct for excess emissions any CAIR
SO2 allowances allocated for 2012 or any year thereafter.
Subpart K--Florida
0
17. Section 52.540 is added to read as follows:
Sec. 52.540 Interstate pollutant transport provisions; What are the
FIP requirements for decreases in emissions of nitrogen oxides?
(a) The owner and operator of each source and each unit located in
the State of Florida and Indian country within the borders of the State
and for which requirements are set forth under the TR NOX
Ozone Season Trading Program in subpart BBBBB of part 97 of this
chapter must comply with such requirements. The obligation to comply
with such requirements with regard to sources and units located in the
State will be eliminated by the promulgation of an approval by the
Administrator of a revision to Florida's State Implementation Plan
(SIP) as correcting in part the SIP's deficiency that is the basis for
the TR Federal Implementation Plan under Sec. 52.38(b), except to the
extent the Administrator's approval is partial or conditional. The
obligation to comply with such requirements with regard to sources and
units located in Indian country within the borders of the State will
not be eliminated by the promulgation of an approval by the
Administrator of a revision to Florida's SIP.
(b) Notwithstanding the provisions of paragraph (a) of this
section, if, at the
[[Page 48363]]
time of the approval of Florida's SIP revision described in paragraph
(a) of this section, the Administrator has already started recording
any allocations of TR NOX Ozone Season allowances under
subpart BBBBB of part 97 of this chapter to units in the State for a
control period in any year, the provisions of subpart BBBBB of part 97
of this chapter authorizing the Administrator to complete the
allocation and recordation of TR NOX Ozone Season allowances
to units in the State for each such control period shall continue to
apply, unless provided otherwise by such approval of the State's SIP
revision.
Subpart L--Georgia
0
18. Section 52.584 is added to read as follows:
Sec. 52.584 Interstate pollutant transport provisions; What are the
FIP requirements for decreases in emissions of nitrogen oxides?
(a)(1) The owner and operator of each source and each unit located
in the State of Georgia and for which requirements are set forth under
the TR NOX Annual Trading Program in subpart AAAAA of part
97 of this chapter must comply with such requirements. The obligation
to comply with such requirements will be eliminated by the promulgation
of an approval by the Administrator of a revision to Georgia's State
Implementation Plan (SIP) as correcting the SIP's deficiency that is
the basis for the TR Federal Implementation Plan under Sec. 52.38(a),
except to the extent the Administrator's approval is partial or
conditional.
(2) Notwithstanding the provisions of paragraph (a)(1) of this
section, if, at the time of the approval of Georgia's SIP revision
described in paragraph (a)(1) of this section, the Administrator has
already started recording any allocations of TR NOX Annual
allowances under subpart AAAAA of part 97 of this chapter to units in
the State for a control period in any year, the provisions of subpart
AAAAA of part 97 of this chapter authorizing the Administrator to
complete the allocation and recordation of TR NOX Annual
allowances to units in the State for each such control period shall
continue to apply, unless provided otherwise by such approval of the
State's SIP revision.
(b)(1) The owner and operator of each source and each unit located
in the State of Georgia and for which requirements are set forth under
the TR NOX Ozone Season Trading Program in subpart BBBBB of
part 97 of this chapter must comply with such requirements. The
obligation to comply with such requirements will be eliminated by the
promulgation of an approval by the Administrator of a revision to
Georgia's State Implementation Plan (SIP) as correcting the SIP's
deficiency that is the basis for the TR Federal Implementation Plan
under Sec. 52.38(b), except to the extent the Administrator's approval
is partial or conditional.
(2) Notwithstanding the provisions of paragraph (b)(1) of this
section, if, at the time of the approval of Georgia's SIP revision
described in paragraph (b)(1) of this section, the Administrator has
already started recording any allocations of TR NOX Ozone
Season allowances under subpart BBBBB of part 97 of this chapter to
units in the State for a control period in any year, the provisions of
subpart BBBBB of part 97 of this chapter authorizing the Administrator
to complete the allocation and recordation of TR NOX Ozone
Season allowances to units in the State for each such control period
shall continue to apply, unless provided otherwise by such approval of
the State's SIP revision.
0
19. Section 52.585 is added to read as follows:
Sec. 52.585 Interstate pollutant transport provisions; What are the
FIP requirements for decreases in emissions of sulfur dioxide?
(a) The owner and operator of each source and each unit located in
the State of Georgia and for which requirements are set forth under the
TR SO2 Group 2 Trading Program in subpart DDDDD of part 97
of this chapter must comply with such requirements. The obligation to
comply with such requirements will be eliminated by the promulgation of
an approval by the Administrator of a revision to Georgia's State
Implementation Plan (SIP) as correcting the SIP's deficiency that is
the basis for the TR Federal Implementation Plan under Sec. 52.39,
except to the extent the Administrator's approval is partial or
conditional.
(b) Notwithstanding the provisions of paragraph (a) of this
section, if, at the time of the approval of Georgia's SIP revision
described in paragraph (a) of this section, the Administrator has
already started recording any allocations of TR SO2 Group 2
allowances under subpart DDDDD of part 97 of this chapter to units in
the State for a control period in any year, the provisions of subpart
DDDDD of part 97 of this chapter authorizing the Administrator to
complete the allocation and recordation of TR SO2 Group 2
allowances to units in the State for each such control period shall
continue to apply, unless provided otherwise by such approval of the
State's SIP revision.
Subpart O--Illinois
0
20. Section 52.745 is added to read as follows:
Sec. 52.745 Interstate pollutant transport provisions; What are the
FIP requirements for decreases in emissions of nitrogen oxides?
(a)(1) The owner and operator of each source and each unit located
in the State of Illinois and for which requirements are set forth under
the TR NOX Annual Trading Program in subpart AAAAA of part
97 of this chapter must comply with such requirements. The obligation
to comply with such requirements will be eliminated by the promulgation
of an approval by the Administrator of a revision to Illinois' State
Implementation Plan (SIP) as correcting the SIP's deficiency that is
the basis for the TR Federal Implementation Plan under Sec. 52.38(a),
except to the extent the Administrator's approval is partial or
conditional.
(2) Notwithstanding the provisions of paragraph (a)(1) of this
section, if, at the time of the approval of Illinois' SIP revision
described in paragraph (a)(1) of this section, the Administrator has
already started recording any allocations of TR NOX Annual
allowances under subpart AAAAA of part 97 of this chapter to units in
the State for a control period in any year, the provisions of subpart
AAAAA of part 97 of this chapter authorizing the Administrator to
complete the allocation and recordation of TR NOX Annual
allowances to units in the State for each such control period shall
continue to apply, unless provided otherwise by such approval of the
State's SIP revision.
(b)(1) The owner and operator of each source and each unit located
in the State of Illinois and for which requirements are set forth under
the TR NOX Ozone Season Trading Program in subpart BBBBB of
part 97 of this chapter must comply with such requirements. The
obligation to comply with such requirements will be eliminated by the
promulgation of an approval by the Administrator of a revision to
Illinois' State Implementation Plan (SIP) as correcting the SIP's
deficiency that is the basis for the TR Federal Implementation Plan
under Sec. 52.38(b), except to the extent the Administrator's approval
is partial or conditional.
(2) Notwithstanding the provisions of paragraph (b)(1) of this
section, if, at the time of the approval of Illinois' SIP revision
described in paragraph (b)(1) of this section, the Administrator has
already started recording any allocations of TR NOX Ozone
Season allowances under subpart BBBBB of part 97 of this
[[Page 48364]]
chapter to units in the State for a control period in any year, the
provisions of subpart BBBBB of part 97 of this chapter authorizing the
Administrator to complete the allocation and recordation of TR
NOX Ozone Season allowances to units in the State for each
such control period shall continue to apply, unless provided otherwise
by such approval of the State's SIP revision.
0
21. Section 52.746 is added to read as follows:
Sec. 52.746 Interstate pollutant transport provisions; What are the
FIP requirements for decreases in emissions of sulfur dioxide?
(a) The owner and operator of each source and each unit located in
the State of Illinois and for which requirements are set forth under
the TR SO2 Group 1 Trading Program in subpart CCCCC of part
97 of this chapter must comply with such requirements. The obligation
to comply with such requirements will be eliminated by the promulgation
of an approval by the Administrator of a revision to Illinois' State
Implementation Plan (SIP) as correcting the SIP's deficiency that is
the basis for the TR Federal Implementation Plan under Sec. 52.39,
except to the extent the Administrator's approval is partial or
conditional.
(b) Notwithstanding the provisions of paragraph (a) of this
section, if, at the time of the approval of Illinois' SIP revision
described in paragraph (a) of this section, the Administrator has
already started recording any allocations of TR SO2 Group 1
allowances under subpart CCCCC of part 97 of this chapter to units in
the State for a control period in any year, the provisions of subpart
CCCCC of part 97 of this chapter authorizing the Administrator to
complete the allocation and recordation of TR SO2 Group 1
allowances to units in the State for each such control period shall
continue to apply, unless provided otherwise by such approval of the
State's SIP revision.
Subpart P--Indiana
0
22. Section 52.789 is added to read as follows:
Sec. 52.789 Interstate pollutant transport provisions; What are the
FIP requirements for decreases in emissions of nitrogen oxides?
(a)(1) The owner and operator of each source and each unit located
in the State of Indiana and for which requirements are set forth under
the TR NOX Annual Trading Program in subpart AAAAA of part
97 of this chapter must comply with such requirements. The obligation
to comply with such requirements will be eliminated by the promulgation
of an approval by the Administrator of a revision to Indiana's State
Implementation Plan (SIP) as correcting the SIP's deficiency that is
the basis for the TR Federal Implementation Plan under Sec. 52.38(a),
except to the extent the Administrator's approval is partial or
conditional.
(2) Notwithstanding the provisions of paragraph (a)(1) of this
section, if, at the time of the approval of Indiana's SIP revision
described in paragraph (a)(1) of this section, the Administrator has
already started recording any allocations of TR NOX Annual
allowances under subpart AAAAA of part 97 of this chapter to units in
the State for a control period in any year, the provisions of subpart
AAAAA of part 97 of this chapter authorizing the Administrator to
complete the allocation and recordation of TR NOX Annual
allowances to units in the State for each such control period shall
continue to apply, unless provided otherwise by such approval of the
State's SIP revision.
(b)(1) The owner and operator of each source and each unit located
in the State of Indiana and for which requirements are set forth under
the TR NOX Ozone Season Trading Program in subpart BBBBB of
part 97 of this chapter must comply with such requirements. The
obligation to comply with such requirements will be eliminated by the
promulgation of an approval by the Administrator of a revision to
Indiana's State Implementation Plan (SIP) as correcting the SIP's
deficiency that is the basis for the TR Federal Implementation Plan
under Sec. 52.38(b), except to the extent the Administrator's approval
is partial or conditional.
(2) Notwithstanding the provisions of paragraph (b)(1) of this
section, if, at the time of the approval of Indiana's SIP revision
described in paragraph (b)(1) of this section, the Administrator has
already started recording any allocations of TR NOX Ozone
Season allowances under subpart BBBBB of part 97 of this chapter to
units in the State for a control period in any year, the provisions of
subpart BBBBB of part 97 of this chapter authorizing the Administrator
to complete the allocation and recordation of TR NOX Ozone
Season allowances to units in the State for each such control period
shall continue to apply, unless provided otherwise by such approval of
the State's SIP revision.
0
23. Section 52.790 is added to read as follows:
Sec. 52.790 Interstate pollutant transport provisions; What are the
FIP requirements for decreases in emissions of sulfur dioxide?
(a) The owner and operator of each source and each unit located in
the State of Indiana and for which requirements are set forth under the
TR SO2 Group 1 Trading Program in subpart CCCCC of part 97
of this chapter must comply with such requirements. The obligation to
comply with such requirements will be eliminated by the promulgation of
an approval by the Administrator of a revision to Indiana's State
Implementation Plan (SIP) as correcting the SIP's deficiency that is
the basis for the TR Federal Implementation Plan under Sec. 52.39
except to the extent the Administrator's approval is partial or
conditional.
(b) Notwithstanding the provisions of paragraph (a) of this
section, if, at the time of the approval of Indiana's SIP revision
described in paragraph (a) of this section, the Administrator has
already started recording any allocations of TR SO2 Group 1
allowances under subpart CCCCC of part 97 of this chapter to units in
the State for a control period in any year, the provisions of subpart
CCCCC of part 97 of this chapter authorizing the Administrator to
complete the allocation and recordation of TR SO2 Group 1
allowances to units in the State for each such control period shall
continue to apply, unless provided otherwise by such approval of the
State's SIP revision.
Subpart Q--Iowa
0
24. Section 52.840 is added to read as follows:
Sec. 52.840 Interstate pollutant transport provisions; What are the
FIP requirements for decreases in emissions of nitrogen oxides?
(a)(1) The owner and operator of each source and each unit located
in the State of Iowa and Indian country within the borders of the State
and for which requirements are set forth under the TR NOX
Annual Trading Program in subpart AAAAA of part 97 of this chapter must
comply with such requirements. The obligation to comply with such
requirements with regard to sources and units in the State will be
eliminated by the promulgation of an approval by the Administrator of a
revision to Iowa's State Implementation Plan (SIP) as correcting in
part the SIP's deficiency that is the basis for the TR Federal
Implementation Plan under Sec. 52.38(a), except to the extent the
Administrator's approval is partial or conditional. The obligation to
comply with such requirements with regard to
[[Page 48365]]
sources and units located in Indian country within the borders of the
State will not be eliminated by the promulgation of an approval by the
Administrator of a revision to Iowa's SIP.
(2) Notwithstanding the provisions of paragraph (a)(1) of this
section, if, at the time of the approval of Iowa's SIP revision
described in paragraph (a)(1) of this section, the Administrator has
already started recording any allocations of TR NOX Annual
allowances under subpart AAAAA of part 97 of this chapter to units in
the State for a control period in any year, the provisions of subpart
AAAAA of part 97 of this chapter authorizing the Administrator to
complete the allocation and recordation of TR NOX Annual
allowances to units in the State for each such control period shall
continue to apply, unless provided otherwise by such approval of the
State's SIP revision.
(b) [Reserved]
0
25. Section 52.841 is added to read as follows:
Sec. 52.841 Interstate pollutant transport provisions; What are the
FIP requirements for decreases in emissions of sulfur dioxide?
(a) The owner and operator of each source and each unit located in
the State of Iowa and Indian country within the borders of the State
and for which requirements are set forth under the TR SO2
Group 1 Trading Program in subpart CCCCC of part 97 of this chapter
must comply with such requirements. The obligation to comply with such
requirements with regard to sources and units in the State will be
eliminated by the promulgation of an approval by the Administrator of a
revision to Iowa's State Implementation Plan (SIP) as correcting in
part the SIP's deficiency that is the basis for the TR Federal
Implementation Plan under Sec. 52.39, except to the extent the
Administrator's approval is partial or conditional. The obligation to
comply with such requirements with regard to sources and units located
in Indian country within the borders of the State will not be
eliminated by the promulgation of an approval by the Administrator of a
revision to Iowa's SIP.
(b) Notwithstanding the provisions of paragraph (a) of this
section, if, at the time of the approval of Iowa's SIP revision
described in paragraph (a) of this section, the Administrator has
already started recording any allocations of TR SO2 Group 1
allowances under subpart CCCCC of part 97 of this chapter to units in
the State for a control period in any year, the provisions of subpart
CCCCC of part 97 of this chapter authorizing the Administrator to
complete the allocation and recordation of TR SO2 Group 1
allowances to units in the State for each such control period shall
continue to apply, unless provided otherwise by such approval of the
State's SIP revision.
Subpart R--Kansas
0
26. Section 52.882 is added to read as follows:
Sec. 52.882 Interstate pollutant transport provisions; What are the
FIP requirements for decreases in emissions of nitrogen oxides?
(a)(1) The owner and operator of each source and each unit located
in the State of Kansas and Indian country within the borders of the
State and for which requirements are set forth under the TR
NOX Annual Trading Program in subpart AAAAA of part 97 of
this chapter must comply with such requirements. The obligation to
comply with such requirements with regard to sources and units in the
State will be eliminated by the promulgation of an approval by the
Administrator of a revision to Kansas' State Implementation Plan (SIP)
as correcting in part the SIP's deficiency that is the basis for the TR
Federal Implementation Plan under Sec. 52.38(a), except to the extent
the Administrator's approval is partial or conditional. The obligation
to comply with such requirements with regard to sources and units
located in Indian country within the borders of the State will not be
eliminated by the promulgation of an approval by the Administrator of a
revision to Kansas' SIP.
(2) Notwithstanding the provisions of paragraph (a)(1) of this
section, if, at the time of the approval of Kansas' SIP revision
described in paragraph (a)(1) of this section, the Administrator has
already started recording any allocations of TR NOX Annual
allowances under subpart AAAAA of part 97 of this chapter to units in
the State for a control period in any year, the provisions of subpart
AAAAA of part 97 of this chapter authorizing the Administrator to
complete the allocation and recordation of TR NOX Annual
allowances to units in the State for each such control period shall
continue to apply, unless provided otherwise by such approval of the
State's SIP revision.
(b) [Reserved]
0
27. Section 52.883 is added to read as follows:
Sec. 52.883 Interstate pollutant transport provisions; What are the
FIP requirements for decreases in emissions of sulfur dioxide?
(a) The owner and operator of each source and each unit located in
the State of Kansas and Indian country within the borders of the State
and for which requirements are set forth under the TR SO2
Group 2 Trading Program in subpart DDDDD of part 97 of this chapter
must comply with such requirements. The obligation to comply with such
requirements will be eliminated with regard to sources and units in the
State by the promulgation of an approval by the Administrator of a
revision to Kansas' State Implementation Plan (SIP) as correcting in
part the SIP's deficiency that is the basis for the TR Federal
Implementation Plan under Sec. 52.39, except to the extent the
Administrator's approval is partial or conditional. The obligation to
comply with such requirements with regard to sources and units located
in Indian country within the borders of the State will not be
eliminated by the promulgation of an approval by the Administrator of a
revision to Kansas' SIP.
(b) Notwithstanding the provisions of paragraph (a) of this
section, if, at the time of the approval of Kansas' SIP revision
described in paragraph (a) of this section, the Administrator has
already started recording any allocations of TR SO2 Group 2
allowances under subpart DDDDD of part 97 of this chapter to units in
the State for a control period in any year, the provisions of subpart
DDDDD of part 97 of this chapter authorizing the Administrator to
complete the allocation and recordation of TR SO2 Group 2
allowances to units in the State for each such control period shall
continue to apply, unless provided otherwise by such approval of the
State's SIP revision.
Subpart S--Kentucky
0
28. Section 52.940 is added to read as follows:
Sec. 52.940 Interstate pollutant transport provisions; What are the
FIP requirements for decreases in emissions of nitrogen oxides?
(a)(1) The owner and operator of each source and each unit located
in the State of Kentucky and for which requirements are set forth under
the TR NOX Annual Trading Program in subpart AAAAA of part
97 of this chapter must comply with such requirements. The obligation
to comply with such requirements will be eliminated by the promulgation
of an approval by the Administrator of a revision to Kentucky's State
[[Page 48366]]
Implementation Plan (SIP) as correcting the SIP's deficiency that is
the basis for the TR Federal Implementation Plan under Sec. 52.38(a),
except to the extent the Administrator's approval is partial or
conditional.
(2) Notwithstanding the provisions of paragraph (a)(1) of this
section, if, at the time of the approval of Kentucky's SIP revision
described in paragraph (a)(1) of this section, the Administrator has
already started recording any allocations of TR NOX Annual
allowances under subpart AAAAA of part 97 of this chapter to units in
the State for a control period in any year, the provisions of subpart
AAAAA of part 97 of this chapter authorizing the Administrator to
complete the allocation and recordation of TR NOX Annual
allowances to units in the State for each such control period shall
continue to apply, unless provided otherwise by such approval of the
State's SIP revision.
(b)(1) The owner and operator of each source and each unit located
in the State of Kentucky and for which requirements are set forth under
the TR NOX Ozone Season Trading Program in subpart BBBBB of
part 97 of this chapter must comply with such requirements. The
obligation to comply with such requirements will be eliminated by the
promulgation of an approval by the Administrator of a revision to
Kentucky's State Implementation Plan (SIP) as correcting the SIP's
deficiency that is the basis for the TR Federal Implementation Plan
under Sec. 52.38(b), except to the extent the Administrator's approval
is partial or conditional.
(2) Notwithstanding the provisions of paragraph (b)(1) of this
section, if, at the time of the approval of Kentucky's SIP revision
described in paragraph (b)(1) of this section, the Administrator has
already started recording any allocations of TR NOX Ozone
Season allowances under subpart BBBBB of part 97 of this chapter to
units in the State for a control period in any year, the provisions of
subpart BBBBB of part 97 of this chapter authorizing the Administrator
to complete the allocation and recordation of TR NOX Ozone
Season allowances to units in the State for each such control period
shall continue to apply, unless provided otherwise by such approval of
the State's SIP revision.
0
29. Section 52.941 is added to read as follows:
Sec. 52.941 Interstate pollutant transport provisions; What are the
FIP requirements for decreases in emissions of sulfur dioxide?
(a) The owner and operator of each source and each unit located in
the State of Kentucky and for which requirements are set forth under
the TR SO2 Group 1 Trading Program in subpart CCCCC of part
97 of this chapter must comply with such requirements. The obligation
to comply with such requirements will be eliminated by the promulgation
of an approval by the Administrator of a revision to Kentucky's State
Implementation Plan (SIP) as correcting the SIP's deficiency that is
the basis for the TR Federal Implementation Plan under Sec. 52.39,
except to the extent the Administrator's approval is partial or
conditional.
(b) Notwithstanding the provisions of paragraph (a) of this
section, if, at the time of the approval of Kentucky's SIP revision
described in paragraph (a) of this section, the Administrator has
already started recording any allocations of TR SO2 Group 1
allowances under subpart CCCCC of part 97 of this chapter to units in
the State for a control period in any year, the provisions of subpart
CCCCC of part 97 of this chapter authorizing the Administrator to
complete the allocation and recordation of TR SO2 Group 1
allowances to units in the State for each such control period shall
continue to apply, unless provided otherwise by such approval of the
State's SIP revision.
Subpart T--Louisiana
0
30. Section 52.984 is amended by adding new paragraphs (c) and (d) to
read as follows:
Sec. 52.984 Interstate pollutant transport provisions; What are the
FIP requirements for decreases in emissions of nitrogen oxides?
* * * * *
(c) Notwithstanding any provisions of paragraphs (a) and (b) of
this section and subparts AA through II and AAAA through IIII of part
97 of this chapter to the contrary:
(1) With regard to any control period that begins after December
31, 2011,
(i) The provisions in paragraphs (a) and (b) of this section
relating to NOX annual or ozone season emissions shall not
be applicable; and
(ii) The Administrator will not carry out any of the functions set
forth for the Administrator in subparts AA through II and AAAA through
IIII of part 97 of this chapter;
(2) The Administrator will not deduct for excess emissions any CAIR
NOX allowances or CAIR NOX Ozone Season
allowances allocated for 2012 or any year thereafter;
(3) By November 7, 2011, the Administrator will remove from the
CAIR NOX Allowance Tracking System accounts all CAIR
NOX allowances allocated for a control period in 2012 and
any subsequent year, and, thereafter, no holding or surrender of CAIR
NOX allowances will be required with regard to emissions or
excess emissions for such control periods; and
(4) By November 7, 2011, the Administrator will remove from the
CAIR NOX Ozone Season Allowance Tracking System accounts all
CAIR NOX Ozone Season allowances allocated for a control
period in 2012 and any subsequent year, and, thereafter, no holding or
surrender of CAIR NOX Ozone Season allowances will be
required with regard to emissions or excess emissions for such control
periods.
(d)(1) The owner and operator of each source and each unit located
in the State of Louisiana and Indian country within the borders of the
State and for which requirements are set forth under the TR
NOX Ozone Season Trading Program in subpart BBBBB of part 97
of this chapter must comply with such requirements. The obligation to
comply with such requirements with regard to sources and units in the
State will be eliminated by the promulgation of an approval by the
Administrator of a revision to Louisiana's State Implementation Plan
(SIP) as correcting in part the SIP's deficiency that is the basis for
the TR Federal Implementation Plan under Sec. 52.38(b), except to the
extent the Administrator's approval is partial or conditional. The
obligation to comply with such requirements with regard to sources and
units located in Indian country within the borders of the State will
not be eliminated by the promulgation of an approval by the
Administrator of a revision to Louisiana's SIP.
(2) Notwithstanding the provisions of paragraph (d)(1) of this
section, if, at the time of the approval of Louisiana's SIP revision
described in paragraph (d)(1) of this section, the Administrator has
already started recording any allocations of TR NOX Ozone
Season allowances under subpart BBBBB of part 97 of this chapter to
units in the State for a control period in any year, the provisions of
subpart BBBBB of part 97 of this chapter authorizing the Administrator
to complete the allocation and recordation of TR NOX Ozone
Season allowances to units in the State for each such control period
shall continue to apply, unless provided otherwise by such approval of
the State's SIP revision.
Subpart V--Maryland
0
31. Section 52.1084 is added to read as follows:
[[Page 48367]]
Sec. 52.1084 Interstate pollutant transport provisions; What are the
FIP requirements for decreases in emissions of nitrogen oxides?
(a)(1) The owner and operator of each source and each unit located
in the State of Maryland and for which requirements are set forth under
the TR NOX Annual Trading Program in subpart AAAAA of part
97 of this chapter must comply with such requirements. The obligation
to comply with such requirements will be eliminated by the promulgation
of an approval by the Administrator of a revision to Maryland's State
Implementation Plan (SIP) as correcting the SIP's deficiency that is
the basis for the TR Federal Implementation Plan under Sec. 52.38(a),
except to the extent the Administrator's approval is partial or
conditional.
(2) Notwithstanding the provisions of paragraph (a)(1) of this
section, if, at the time of the approval of Maryland's SIP revision
described in paragraph (a)(1) of this section, the Administrator has
already started recording any allocations of TR NOX Annual
allowances under subpart AAAAA of part 97 of this chapter to units in
the State for a control period in any year, the provisions of subpart
AAAAA of part 97 of this chapter authorizing the Administrator to
complete the allocation and recordation of TR NOX Annual
allowances to units in the State for each such control period shall
continue to apply, unless provided otherwise by such approval of the
State's SIP revision.
(b)(1) The owner and operator of each source and each unit located
in the State of Maryland and for which requirements are set forth under
the TR NOX Ozone Season Trading Program in subpart BBBBB of
part 97 of this chapter must comply with such requirements. The
obligation to comply with such requirements will be eliminated by the
promulgation of an approval by the Administrator of a revision to
Maryland's State Implementation Plan (SIP) as correcting the SIP's
deficiency that is the basis for the TR Federal Implementation Plan
under Sec. 52.38(b), except to the extent the Administrator's approval
is partial or conditional.
(2) Notwithstanding the provisions of paragraph (b)(1) of this
section, if, at the time of the approval of Maryland's SIP revision
described in paragraph (b)(1) of this section, the Administrator has
already started recording any allocations of TR NOX Ozone
Season allowances under subpart BBBBB of part 97 of this chapter to
units in the State for a control period in any year, the provisions of
subpart BBBBB of part 97 of this chapter authorizing the Administrator
to complete the allocation and recordation of TR NOX Ozone
Season allowances to units in the State for each such control period
shall continue to apply, unless provided otherwise by such approval of
the State's SIP revision.
0
32. Section 52.1085 is added to read as follows:
Sec. 52.1085 Interstate pollutant transport provisions; What are the
FIP requirements for decreases in emissions of sulfur dioxide?
(a) The owner and operator of each source and each unit located in
the State of Maryland and for which requirements are set forth under
the TR SO2 Group 1 Trading Program in subpart CCCCC of part
97 of this chapter must comply with such requirements. The obligation
to comply with such requirements will be eliminated by the promulgation
of an approval by the Administrator of a revision to Maryland's State
Implementation Plan (SIP) as correcting the SIP's deficiency that is
the basis for the TR Federal Implementation Plan under Sec. 52.39,
except to the extent the Administrator's approval is partial or
conditional.
(b) Notwithstanding the provisions of paragraph (a) of this
section, if, at the time of the approval of Maryland's SIP revision
described in paragraph (a) of this section, the Administrator has
already started recording any allocations of TR SO2 Group 1
allowances under subpart CCCCC of part 97 of this chapter to units in
the State for a control period in any year, the provisions of subpart
CCCCC of part 97 of this chapter authorizing the Administrator to
complete the allocation and recordation of TR SO2 Group 1
allowances to units in the State for each such control period shall
continue to apply, unless provided otherwise by such approval of the
State's SIP revision.
Subpart X--Michigan
0
33. Section 52.1186 is amended by adding new paragraphs (c) and (d) to
read as follows:
Sec. 52.1186 Interstate pollutant transport provisions; What are the
FIP requirements for decreases in emissions of nitrogen oxides?
* * * * *
(c) Notwithstanding any provisions of paragraphs (a) and (b) of
this section and subparts AA through II and AAAA through IIII of part
97 of this chapter to the contrary:
(1) With regard to any control period that begins after December
31, 2011,
(i) The provisions in paragraphs (a) and (b) of this section
relating to NOX annual or ozone season emissions shall not
be applicable; and
(ii) The Administrator will not carry out any of the functions set
forth for the Administrator in subparts AA through II and AAAA through
IIII of part 97 of this chapter;
(2) The Administrator will not deduct for excess emissions any CAIR
NOX allowances or CAIR NOX Ozone Season
allowances allocated for 2012 or any year thereafter;
(3) By November 7, 2011, the Administrator will remove from the
CAIR NOX Allowance Tracking System accounts all CAIR
NOX allowances allocated for a control period in 2012 and
any subsequent year, and, thereafter, no holding or surrender of CAIR
NOX allowances will be required with regard to emissions or
excess emissions for such control periods; and
(4) By November 7, 2011, the Administrator will remove from the
CAIR NOX Ozone Season Allowance Tracking System accounts all
CAIR NOX Ozone Season allowances allocated for a control
period in 2012 and any subsequent year, and, thereafter, no holding or
surrender of CAIR NOX Ozone Season allowances will be
required with regard to emissions or excess emissions for such control
periods.
(d)(1) The owner and operator of each source and each unit located
in the State of Michigan and Indian country within the borders of the
State and for which requirements are set forth under the TR
NOX Annual Trading Program in subpart AAAAA of part 97 of
this chapter must comply with such requirements. The obligation to
comply with such requirements with regard to sources and units in the
State will be eliminated by the promulgation of an approval by the
Administrator of a revision to Michigan's State Implementation Plan
(SIP) as correcting in part the SIP's deficiency that is the basis for
the TR Federal Implementation Plan under Sec. 52.38(a), except to the
extent the Administrator's approval is partial or conditional. The
obligation to comply with such requirements with regard to sources and
units located in Indian country within the borders of the State will
not be eliminated by the promulgation of an approval by the
Administrator of a revision to Michigan's SIP.
(2) Notwithstanding the provisions of paragraph (d)(1) of this
section, if, at the time of the approval of Michigan's SIP revision
described in paragraph (d)(1) of this section, the Administrator has
already started recording any allocations of TR NOX Annual
allowances under subpart AAAAA of part 97 of this chapter to units in
the State for a control period in any year, the provisions of
[[Page 48368]]
subpart AAAAA of part 97 of this chapter authorizing the Administrator
to complete the allocation and recordation of TR NOX Annual
allowances to units in the State for each such control period shall
continue to apply, unless provided otherwise by such approval of the
State's SIP revision.
(e) [Reserved]
0
34. Section 52.1187 is amended by designating the existing text as
paragraph (a) and adding new paragraphs (b) and (c) to read as follows:
Sec. 52.1187 Interstate pollutant transport provisions; What are the
FIP requirements for decreases in emissions of sulfur dioxide?
* * * * *
(b) Notwithstanding any provisions of paragraph (a) of this section
and subparts AAA through III of part 97 of this chapter and any State's
SIP to the contrary:
(1) With regard to any control period that begins after December
31, 2011,
(i) The provisions of paragraph (a) of this section relating to
SO2 emissions shall not be applicable; and
(ii) The Administrator will not carry out any of the functions set
forth for the Administrator in subparts AAA through III of part 97 of
this chapter; and
(2) The Administrator will not deduct for excess emissions any CAIR
SO2 allowances allocated for 2012 or any year thereafter.
(c)(1) The owner and operator of each source and each unit located
in the State of Michigan and Indian country within the borders of the
State and for which requirements are set forth under the TR
SO2 Group 1 Trading Program in subpart CCCCC of part 97 of
this chapter must comply with such requirements. The obligation to
comply with such requirements with regard to sources and units in the
State will be eliminated by the promulgation of an approval by the
Administrator of a revision to Michigan's State Implementation Plan
(SIP) as correcting in part the SIP's deficiency that is the basis for
the TR Federal Implementation Plan under Sec. 52.39, except to the
extent the Administrator's approval is partial or conditional. The
obligation to comply with such requirements with regard to sources and
units located in Indian country within the borders of the State will
not be eliminated by the promulgation of an approval by the
Administrator of a revision to Michigan's SIP.
(2) Notwithstanding the provisions of paragraph (c)(1) of this
section, if, at the time of the approval of Maryland's SIP revision
described in paragraph (c)(1) of this section, the Administrator has
already started recording any allocations of TR SO2 Group 1
allowances under subpart CCCCC of part 97 of this chapter to units in
the State for a control period in any year, the provisions of subpart
CCCCC of part 97 of this chapter authorizing the Administrator to
complete the allocation and recordation of TR SO2 Group 1
allowances to units in the State for each such control period shall
continue to apply, unless provided otherwise by such approval of the
State's SIP revision.
Subpart Y--Minnesota
0
35. Section 52.1240 is amended by adding paragraph (c) to read as
follows:
Sec. 52.1240 Interstate pollutant transport provisions; What are the
FIP requirements for decreases in emissions of nitrogen oxides?
* * * * *
(c)(1) The owner and operator of each source and each unit located
in the State of Minnesota and Indian country within the borders of the
State and for which requirements are set forth under the TR
NOX Annual Trading Program in subpart AAAAA of part 97 of
this chapter must comply with such requirements. The obligation to
comply with such requirements with regard to sources and units in the
State will be eliminated by the promulgation of an approval by the
Administrator of a revision to Minnesota's State Implementation Plan
(SIP) as correcting in part the SIP's deficiency that is the basis for
the TR Federal Implementation Plan under Sec. 52.38(a), except to the
extent the Administrator's approval is partial or conditional. The
obligation to comply with such requirements with regard to sources and
units located in Indian country within the borders of the State will
not be eliminated by the promulgation of an approval by the
Administrator of a revision to Minnesota's SIP.
(2) Notwithstanding the provisions of paragraph (c)(1) of this
section, if, at the time of the approval of Minnesota's SIP revision
described in paragraph (c)(1) of this section, the Administrator has
already started recording any allocations of TR NOX Annual
allowances under subpart AAAAA of part 97 of this chapter to units in
the State for a control period in any year, the provisions of subpart
AAAAA of part 97 of this chapter authorizing the Administrator to
complete the allocation and recordation of TR NOX Annual
allowances to units in the State for each such control period shall
continue to apply, unless provided otherwise by such approval of the
State's SIP revision.
0
36. Section 52.1241 is amended by adding paragraph (c) to read as
follows:
Sec. 52.1241 Interstate pollutant transport provisions; What are the
FIP requirements for decreases in emissions of sulfur dioxide?
* * * * *
(c)(1) The owner and operator of each source and each unit located
in the State of Minnesota and Indian country within the borders of the
State and for which requirements are set forth under the TR
SO2 Group 2 Trading Program in subpart DDDDD of part 97 of
this chapter must comply with such requirements. The obligation to
comply with such requirements with regard to sources and units in the
State will be eliminated by the promulgation of an approval by the
Administrator of a revision to Minnesota's State Implementation Plan
(SIP) as correcting in part the SIP's deficiency that is the basis for
the TR Federal Implementation Plan under Sec. 52.39, except to the
extent the Administrator's approval is partial or conditional. The
obligation to comply with such requirements with regard to sources and
units located in Indian country within the borders of the State will
not be eliminated by the promulgation of an approval by the
Administrator of a revision to Minnesota's SIP.
(2) Notwithstanding the provisions of paragraph (c)(1) of this
section, if, at the time of the approval of Minnesota's SIP revision
described in paragraph (c)(1) of this section, the Administrator has
already started recording any allocations of TR SO2 Group 2
allowances under subpart DDDDD of part 97 of this chapter to units in
the State for a control period in any year, the provisions of subpart
DDDDD of part 97 of this chapter authorizing the Administrator to
complete the allocation and recordation of TR SO2 Group 2
allowances to units in the State for each such control period shall
continue to apply, unless provided otherwise by such approval of the
State's SIP revision.
Subpart Z--Mississippi
0
37. Section 52.1284 is added to read as follows:
Sec. 52.1284 Interstate pollutant transport provisions; What are the
FIP requirements for decreases in emissions of nitrogen oxides?
(a) The owner and operator of each source and each unit located in
the State of Mississippi and Indian country within the borders of the
State and for which requirements are set forth under the TR
NOX Ozone Season Trading Program in subpart BBBBB of part 97
of
[[Page 48369]]
this chapter must comply with such requirements. The obligation to
comply with such requirements with regard to sources and units in the
State will be eliminated by the promulgation of an approval by the
Administrator of a revision to Mississippi's State Implementation Plan
(SIP) as correcting in part the SIP's deficiency that is the basis for
the TR Federal Implementation Plan under Sec. 52.38(b), except to the
extent the Administrator's approval is partial or conditional. The
obligation to comply with such requirements with regard to sources and
units located in Indian country within the borders of the State will
not be eliminated by the promulgation of an approval by the
Administrator of a revision to Mississippi's SIP.
(b) Notwithstanding the provisions of paragraph (a) of this
section, if, at the time of the approval of Mississippi's SIP revision
described in paragraph (a) of this section, the Administrator has
already started recording any allocations of TR NOX Ozone
Season allowances under subpart BBBBB of part 97 of this chapter to
units in the State for a control period in any year, the provisions of
subpart BBBBB of part 97 of this chapter authorizing the Administrator
to complete the allocation and recordation of TR NOX Ozone
Season allowances to units in the State for each such control period
shall continue to apply, unless provided otherwise by such approval of
the State's SIP revision.
Subpart AA--Missouri
0
38. Section 52.1326 is added to read as follows:
Sec. 52.1326 Interstate pollutant transport provisions; What are the
FIP requirements for decreases in emissions of nitrogen oxides?
(a)(1) The owner and operator of each source and each unit located
in the State of Missouri and for which requirements are set forth under
the TR NOX Annual Trading Program in subpart AAAAA of part
97 of this chapter must comply with such requirements. The obligation
to comply with such requirements will be eliminated by the promulgation
of an approval by the Administrator of a revision to Missouri's State
Implementation Plan (SIP) as correcting the SIP's deficiency that is
the basis for the TR Federal Implementation Plan under Sec. 52.38(a),
except to the extent the Administrator's approval is partial or
conditional.
(2) Notwithstanding the provisions of paragraph (a)(1) of this
section, if, at the time of the approval of Missouri's SIP revision
described in paragraph (a)(1) of this section, the Administrator has
already started recording any allocations of TR NOX Annual
allowances under subpart AAAAA of part 97 of this chapter to units in
the State for a control period in any year, the provisions of subpart
AAAAA of part 97 of this chapter authorizing the Administrator to
complete the allocation and recordation of TR NOX Annual
allowances to units in the State for each such control period shall
continue to apply, unless provided otherwise by such approval of the
State's SIP revision.
(b) [Reserved]
0
39. Section 52.1327 is added to read as follows:
Sec. 52.1327 Interstate pollutant transport provisions; What are the
FIP requirements for decreases in emissions of sulfur dioxide?
(a) The owner and operator of each source and each unit located in
the State of Missouri and for which requirements are set forth under
the TR SO2 Group 1 Trading Program in subpart CCCCC of part
97 of this chapter must comply with such requirements. The obligation
to comply with such requirements will be eliminated by the promulgation
of an approval by the Administrator of a revision to Missouri's State
Implementation Plan (SIP) as correcting the SIP's deficiency that is
the basis for the TR Federal Implementation Plan under Sec. 52.39,
except to the extent the Administrator's approval is partial or
conditional.
(b) Notwithstanding the provisions of paragraph (a) of this
section, if, at the time of the approval of Missouri's SIP revision
described in paragraph (a) of this section, the Administrator has
already started recording any allocations of TR SO2 Group 1
allowances under subpart CCCCC of part 97 of this chapter to units in
the State for a control period in any year, the provisions of subpart
CCCCC of part 97 of this chapter authorizing the Administrator to
complete the allocation and recordation of TR SO2 Group 1
allowances to units in the State for each such control period shall
continue to apply, unless provided otherwise by such approval of the
State's SIP revision.
Subpart CC--Nebraska
0
40. Section 52.1428 is added to read as follows:
Sec. 52.1428 Interstate pollutant transport provisions; What are the
FIP requirements for decreases in emissions of nitrogen oxides?
(a) The owner and operator of each source and each unit located in
the State of Nebraska and Indian country within the borders of the
State and for which requirements are set forth under the TR
NOX Annual Trading Program in subpart AAAAA of part 97 of
this chapter must comply with such requirements. The obligation to
comply with such requirements with regard to sources and units in the
State will be eliminated by the promulgation of an approval by the
Administrator of a revision to Nebraska's State Implementation Plan
(SIP) as correcting in part the SIP's deficiency that is the basis for
the TR Federal Implementation Plan under Sec. 52.38(a), except to the
extent the Administrator's approval is partial or conditional. The
obligation to comply with such requirements with regard to sources and
units located in Indian country within the borders of the State will
not be eliminated by the promulgation of an approval by the
Administrator of a revision to Nebraska's SIP.
(b) Notwithstanding the provisions of paragraph (a) of this
section, if, at the time of the approval of Nebraska's SIP revision
described in paragraph (a) of this section, the Administrator has
already started recording any allocations of TR NOX Annual
allowances under subpart AAAAA of part 97 of this chapter to units in
the State for a control period in any year, the provisions of subpart
AAAAA of part 97 of this chapter authorizing the Administrator to
complete the allocation and recordation of TR NOX Annual
allowances to units in the State for each such control period shall
continue to apply, unless provided otherwise by such approval of the
State's SIP revision.
0
41. Section 52.1429 is added to read as follows:
Sec. 52.1429 Interstate pollutant transport provisions; What are the
FIP requirements for decreases in emissions of sulfur dioxide?
(a) The owner and operator of each source and each unit located in
the State of Nebraska and Indian country within the borders of the
State and for which requirements are set forth under the TR
SO2 Group 2 Trading Program in subpart DDDDD of part 97 of
this chapter must comply with such requirements. The obligation to
comply with such requirements with regard to sources and units in the
State will be eliminated by the promulgation of an approval by the
Administrator of a revision to Nebraska's State Implementation Plan
(SIP) as correcting in part the SIP's deficiency that is the basis for
the TR Federal Implementation Plan under Sec. 52.39, except to the
extent the Administrator's approval is partial or conditional. The
obligation to comply with such requirements with regard to
[[Page 48370]]
sources and units located in Indian country within the borders of the
State will not be eliminated by the promulgation of an approval by the
Administrator of a revision to Nebraska's SIP.
(b) Notwithstanding the provisions of paragraph (a) of this
section, if, at the time of the approval of Nebraska's SIP revision
described in paragraph (a) of this section, the Administrator has
already started recording any allocations of TR SO2 Group 2
allowances under subpart DDDDD of part 97 of this chapter to units in
the State for a control period in any year, the provisions of subpart
DDDDD of part 97 of this chapter authorizing the Administrator to
complete the allocation and recordation of TR SO2 Group 2
allowances to units in the State for each such control period shall
continue to apply, unless provided otherwise by such approval of the
State's SIP revision.
Subpart FF--New Jersey
0
42. Section 52.1584 is amended by adding new paragraphs (c), (d), and
(e) to read as follows:
Sec. 52.1584 Interstate pollutant transport provisions; What are the
FIP requirements for decreases in emissions of nitrogen oxides?
* * * * *
(c) Notwithstanding any provisions of paragraphs (a) and (b) of
this section and subparts AA through II and AAAA through IIII of part
97 of this chapter to the contrary:
(1) With regard to any control period that begins after December
31, 2011,
(i) The provisions in paragraphs (a) and (b) of this section
relating to NOX annual or ozone season emissions shall not
be applicable; and
(ii) The Administrator will not carry out any of the functions set
forth for the Administrator in subparts AA through II and AAAA through
IIII of part 97 of this chapter;
(2) The Administrator will not deduct for excess emissions any CAIR
NOX allowances or CAIR NOX Ozone Season
allowances allocated for 2012 or any year thereafter;
(3) By November 7, 2011, the Administrator will remove from the
CAIR NOX Allowance Tracking System accounts all CAIR
NOX allowances allocated for a control period in 2012 and
any subsequent year, and, thereafter, no holding or surrender of CAIR
NOX allowances will be required with regard to emissions or
excess emissions for such control periods; and
(4) By November 7, 2011, the Administrator will remove from the
CAIR NOX Ozone Season Allowance Tracking System accounts all
CAIR NOX Ozone Season allowances allocated for a control
period in 2012 and any subsequent year, and, thereafter, no holding or
surrender of CAIR NOX Ozone Season allowances will be
required with regard to emissions or excess emissions for such control
periods.
(d)(1) The owner and operator of each source and each unit located
in the State of New Jersey and for which requirements are set forth
under the TR NOX Annual Trading Program in subpart AAAAA of
part 97 of this chapter must comply with such requirements. The
obligation to comply with such requirements will be eliminated by the
promulgation of an approval by the Administrator of a revision to New
Jersey's State Implementation Plan (SIP) as correcting the SIP's
deficiency that is the basis for the TR Federal Implementation Plan
under Sec. 52.38(a), except to the extent the Administrator's approval
is partial or conditional.
(2) Notwithstanding the provisions of paragraph (d)(1) of this
section, if, at the time of the approval of New Jersey's SIP revision
described in paragraph (d)(1) of this section, the Administrator has
already started recording any allocations of TR NOX Annual
allowances under subpart AAAAA of part 97 of this chapter to units in
the State for a control period in any year, the provisions of subpart
AAAAA of part 97 of this chapter authorizing the Administrator to
complete the allocation and recordation of TR NOX Annual
allowances to units in the State for each such control period shall
continue to apply, unless provided otherwise by such approval of the
State's SIP revision.
(e)(1) The owner and operator of each source and each unit located
in the State of New Jersey and for which requirements are set forth
under the TR NOX Ozone Season Trading Program in subpart
BBBBB of part 97 of this chapter must comply with such requirements.
The obligation to comply with such requirements will be eliminated by
the promulgation of an approval by the Administrator of a revision to
New Jersey's State Implementation Plan (SIP) as correcting the SIP's
deficiency that is the basis for the TR Federal Implementation Plan
under Sec. 52.38(b), except to the extent the Administrator's approval
is partial or conditional.
(2) Notwithstanding the provisions of paragraph (e)(1) of this
section, if, at the time of the approval of New Jersey's SIP revision
described in paragraph (e)(1) of this section, the Administrator has
already started recording any allocations of TR NOX Ozone
Season allowances under subpart BBBBB of part 97 of this chapter to
units in the State for a control period in any year, the provisions of
subpart BBBBB of part 97 of this chapter authorizing the Administrator
to complete the allocation and recordation of TR NOX Ozone
Season allowances to units in the State for each such control period
shall continue to apply, unless provided otherwise by such approval of
the State's SIP revision.
0
43. Section 52.1585 is amended by designating the existing text as
paragraph (a) and adding new paragraphs (b) and (c) to read as follows:
Sec. 52.1585 Interstate pollutant transport provisions; What are the
FIP requirements for decreases in emissions of sulfur dioxide?
* * * * *
(b) Notwithstanding any provisions of paragraph (a) of this section
and subparts AAA through III of part 97 of this chapter and any State's
SIP to the contrary:
(1) With regard to any control period that begins after December
31, 2011,
(i) The provisions of paragraph (a) of this section relating to
SO2 emissions shall not be applicable; and
(ii) The Administrator will not carry out any of the functions set
forth for the Administrator in subparts AAA through III of part 97 of
this chapter; and
(2) The Administrator will not deduct for excess emissions any CAIR
SO2 allowances allocated for 2012 or any year thereafter.
(c)(1) The owner and operator of each source and each unit located
in the State of New Jersey and for which requirements are set forth
under the TR SO2 Group 1 Trading Program in subpart CCCCC of
part 97 of this chapter must comply with such requirements. The
obligation to comply with such requirements will be eliminated by the
promulgation of an approval by the Administrator of a revision to New
Jersey's State Implementation Plan (SIP) as correcting the SIP's
deficiency that is the basis for the TR Federal Implementation Plan
under Sec. 52.39, except to the extent the Administrator's approval is
partial or conditional.
(2) Notwithstanding the provisions of paragraph (c)(1) of this
section, if, at the time of the approval of New Jersey's SIP revision
described in paragraph (c)(1) of this section, the Administrator has
already started recording any allocations of TR SO2 Group 1
allowances under subpart CCCCC of part 97 of this chapter to units in
the State for a control period in any year, the provisions of subpart
CCCCC of part 97 of this chapter authorizing the Administrator to
complete the allocation and recordation
[[Page 48371]]
of TR SO2 Group 1 allowances to units in the State for each
such control period shall continue to apply, unless provided otherwise
by such approval of the State's SIP revision.
Subpart HH--New York
0
44. Section 52.1684 is revised to read as follows:
Sec. 52.1684 Interstate pollutant transport provisions; What are the
FIP requirements for decreases in emissions of nitrogen oxides?
(a)(1) The owner and operator of each source and each unit located
in the State of New York and Indian country within the borders of the
State and for which requirements are set forth under the TR
NOX Annual Trading Program in subpart AAAAA of part 97 of
this chapter must comply with such requirements. The obligation to
comply with such requirements with regard to sources and units in the
State will be eliminated by the promulgation of an approval by the
Administrator of a revision to New York's State Implementation Plan
(SIP) as correcting in part the SIP's deficiency that is the basis for
the TR Federal Implementation Plan under Sec. 52.38(a), except to the
extent the Administrator's approval is partial or conditional. The
obligation to comply with such requirements with regard to sources and
units located in Indian country within the borders of the State will
not be eliminated by the promulgation of an approval by the
Administrator of a revision to New York's SIP.
(2) Notwithstanding the provisions of paragraph (a)(1) of this
section, if, at the time of the approval of New York's SIP revision
described in paragraph (a)(1) of this section, the Administrator has
already started recording any allocations of TR NOX Annual
allowances under subpart AAAAA of part 97 of this chapter to units in
the State for a control period in any year, the provisions of subpart
AAAAA of part 97 of this chapter authorizing the Administrator to
complete the allocation and recordation of TR NOX Annual
allowances to units in the State for each such control period shall
continue to apply, unless provided otherwise by such approval of the
State's SIP revision.
(b)(1) The owner and operator of each source and each unit located
in the State of New York and Indian country within the borders of the
State and for which requirements are set forth under the TR
NOX Ozone Season Trading Program in subpart BBBBB of part 97
of this chapter must comply with such requirements. The obligation to
comply with such requirements with regard to sources and units in the
State will be eliminated by the promulgation of an approval by the
Administrator of a revision to New York's State Implementation Plan
(SIP) as correcting in part the SIP's deficiency that is the basis for
the TR Federal Implementation Plan under Sec. 52.38(b), except to the
extent the Administrator's approval is partial or conditional. The
obligation to comply with such requirements with regard to sources and
units located in Indian country within the borders of the State will
not be eliminated by the promulgation of an approval by the
Administrator of a revision to New York's SIP.
(2) Notwithstanding the provisions of paragraph (b)(1) of this
section, if, at the time of the approval of New York's SIP revision
described in paragraph (b)(1) of this section, the Administrator has
already started recording any allocations of TR NOX Ozone
Season allowances under subpart BBBBB of part 97 of this chapter to
units in the State for a control period in any year, the provisions of
subpart BBBBB of part 97 of this chapter authorizing the Administrator
to complete the allocation and recordation of TR NOX Ozone
Season allowances to units in the State for each such control period
shall continue to apply, unless provided otherwise by such approval of
the State's SIP revision.
0
45. Section 52.1685 is added to read as follows:
Sec. 52.1685 Interstate pollutant transport provisions; What are the
FIP requirements for decreases in emissions of sulfur dioxide?
(a) The owner and operator of each source and each unit located in
the State of New York and Indian country within the borders of the
State and for which requirements are set forth under the TR
SO2 Group 1 Trading Program in subpart CCCCC of part 97 of
this chapter must comply with such requirements. The obligation to
comply with such requirements with regard to sources and units in the
State will be eliminated by the promulgation of an approval by the
Administrator of a revision to New York's State Implementation Plan
(SIP) as correcting in part the SIP's deficiency that is the basis for
the TR Federal Implementation Plan under Sec. 52.39, except to the
extent the Administrator's approval is partial or conditional. The
obligation to comply with such requirements with regard to sources and
units located in Indian country within the borders of the State will
not be eliminated by the promulgation of an approval by the
Administrator of a revision to New York's SIP.
(b) Notwithstanding the provisions of paragraph (a) of this
section, if, at the time of the approval of New York's SIP revision
described in paragraph (a) of this section, the Administrator has
already started recording any allocations of TR SO2 Group 1
allowances under subpart CCCCC of part 97 of this chapter to units in
the State for a control period in any year, the provisions of subpart
CCCCC of part 97 of this chapter authorizing the Administrator to
complete the allocation and recordation of TR SO2 Group 1
allowances to units in the State for each such control period shall
continue to apply, unless provided otherwise by such approval of the
State's SIP revision.
Subpart II--North Carolina
0
46. Section 52.1784 is revised to read as follows:
Sec. 52.1784 Interstate pollutant transport provisions; What are the
FIP requirements for decreases in emissions of nitrogen oxides?
(a)(1) The owner and operator of each source and each unit located
in the State of North Carolina and Indian country within the borders of
the State and for which requirements are set forth under the TR
NOX Annual Trading Program in subpart AAAAA of part 97 of
this chapter must comply with such requirements. The obligation to
comply with such requirements with regard to sources and units in the
State will be eliminated by the promulgation of an approval by the
Administrator of a revision to North Carolina's State Implementation
Plan (SIP) as correcting in part the SIP's deficiency that is the basis
for the TR Federal Implementation Plan under Sec. 52.38(a), except to
the extent the Administrator's approval is partial or conditional. The
obligation to comply with such requirements with regard to sources and
units located in Indian country within the borders of the State will
not be eliminated by the promulgation of an approval by the
Administrator of a revision to North Carolina's SIP.
(2) Notwithstanding the provisions of paragraph (a)(1) of this
section, if, at the time of the approval of North Carolina's SIP
revision described in paragraph (a)(1) of this section, the
Administrator has already started recording any allocations of TR
NOX Annual allowances under subpart AAAAA of part 97 of this
chapter to units in the State for a control period in any year, the
provisions of subpart AAAAA of part 97 of this chapter authorizing the
Administrator to complete the allocation and recordation of TR
NOX Annual allowances to units in the State for each such
control period shall
[[Page 48372]]
continue to apply, unless provided otherwise by such approval of the
State's SIP revision.
(b)(1) The owner and operator of each source and each unit located
in the State of North Carolina and Indian country within the borders of
the State and for which requirements are set forth under the TR
NOX Ozone Season Trading Program in subpart BBBBB of part 97
of this chapter must comply with such requirements. The obligation to
comply with such requirements with regard to sources and units in the
State will be eliminated by the promulgation of an approval by the
Administrator of a revision to North Carolina's State Implementation
Plan (SIP) as correcting in part the SIP's deficiency that is the basis
for the TR Federal Implementation Plan under Sec. 52.38(b), except to
the extent the Administrator's approval is partial or conditional. The
obligation to comply with such requirements with regard to sources and
units located in Indian country within the borders of the State will
not be eliminated by the promulgation of an approval by the
Administrator of a revision to North Carolina's SIP.
(2) Notwithstanding the provisions of paragraph (b)(1) of this
section, if, at the time of the approval of North Carolina's SIP
revision described in paragraph (b)(1) of this section, the
Administrator has already started recording any allocations of TR
NOX Ozone Season allowances under subpart BBBBB of part 97
of this chapter to units in the State for a control period in any year,
the provisions of subpart BBBBB of part 97 of this chapter authorizing
the Administrator to complete the allocation and recordation of TR
NOX Ozone Season allowances to units in the State for each
such control period shall continue to apply, unless provided otherwise
by such approval of the State's SIP revision.
0
47. Section 52.1785 is revised to read as follows:
Sec. 52.1785 Interstate pollutant transport provisions; What are the
FIP requirements for decreases in emissions of sulfur dioxide?
(a) The owner and operator of each source and each unit located in
the State of North Carolina and Indian country within the borders of
the State and for which requirements are set forth under the TR
SO2 Group 1 Trading Program in subpart CCCCC of part 97 of
this chapter must comply with such requirements. The obligation to
comply with such requirements with regard to sources and units in the
State will be eliminated by the promulgation of an approval by the
Administrator of a revision to North Carolina's State Implementation
Plan (SIP) as correcting in part the SIP's deficiency that is the basis
for the TR Federal Implementation Plan under Sec. 52.39, except to the
extent the Administrator's approval is partial or conditional. The
obligation to comply with such requirements with regard to sources and
units located in Indian country within the borders of the State will
not be eliminated by the promulgation of an approval by the
Administrator of a revision to North Carolina's SIP.
(b) Notwithstanding the provisions of paragraph (a) of this
section, if, at the time of the approval of North Carolina's SIP
revision described in paragraph (a) of this section, the Administrator
has already started recording any allocations of TR SO2
Group 1 allowances under subpart CCCCC of part 97 of this chapter to
units in the State for a control period in any year, the provisions of
subpart CCCCC of part 97 of this chapter authorizing the Administrator
to complete the allocation and recordation of TR SO2 Group 1
allowances to units in the State for each such control period shall
continue to apply, unless provided otherwise by such approval of the
State's SIP revision.
Subpart KK--Ohio
0
48. Section 52.1882 is added to read as follows:
Sec. 52.1882 Interstate pollutant transport provisions; What are the
FIP requirements for decreases in emissions of nitrogen oxides?
(a)(1) The owner and operator of each source and each unit located
in the State of Ohio and for which requirements are set forth under the
TR NOX Annual Trading Program in subpart AAAAA of part 97 of
this chapter must comply with such requirements. The obligation to
comply with such requirements will be eliminated by the promulgation of
an approval by the Administrator of a revision to Ohio's State
Implementation Plan (SIP) as correcting the SIP's deficiency that is
the basis for the TR Federal Implementation Plan under Sec. 52.38(a),
except to the extent the Administrator's approval is partial or
conditional.
(2) Notwithstanding the provisions of paragraph (a)(1) of this
section, if, at the time of the approval of Ohio's SIP revision
described in paragraph (a)(1) of this section, the Administrator has
already started recording any allocations of TR NOX Annual
allowances under subpart AAAAA of part 97 of this chapter to units in
the State for a control period in any year, the provisions of subpart
AAAAA of part 97 of this chapter authorizing the Administrator to
complete the allocation and recordation of TR NOX Annual
allowances to units in the State for each such control period shall
continue to apply, unless provided otherwise by such approval of the
State's SIP revision.
(b)(1) The owner and operator of each source and each unit located
in the State of Ohio and for which requirements are set forth under the
TR NOX Ozone Season Trading Program in subpart BBBBB of part
97 of this chapter must comply with such requirements. The obligation
to comply with such requirements will be eliminated by the promulgation
of an approval by the Administrator of a revision to Ohio's State
Implementation Plan (SIP) as correcting the SIP's deficiency that is
the basis for the TR Federal Implementation Plan under Sec. 52.38(b),
except to the extent the Administrator's approval is partial or
conditional.
(2) Notwithstanding the provisions of paragraph (b)(1) of this
section, if, at the time of the approval of Ohio's SIP revision
described in paragraph (b)(1) of this section, the Administrator has
already started recording any allocations of TR NOX Ozone
Season allowances under subpart BBBBB of part 97 of this chapter to
units in the State for a control period in any year, the provisions of
subpart BBBBB of part 97 of this chapter authorizing the Administrator
to complete the allocation and recordation of TR NOX Ozone
Season allowances to units in the State for each such control period
shall continue to apply, unless provided otherwise by such approval of
the State's SIP revision.
0
49. Section 52.1883 is added to read as follows:
Sec. 52.1883 Interstate pollutant transport provisions; What are the
FIP requirements for decreases in emissions of sulfur dioxide?
(a) The owner and operator of each source and each unit located in
the State of Ohio and for which requirements are set forth under the TR
SO2 Group 1 Trading Program in subpart CCCCC of part 97 of
this chapter must comply with such requirements. The obligation to
comply with such requirements will be eliminated by the promulgation of
an approval by the Administrator of a revision to Ohio's State
Implementation Plan (SIP) as correcting the SIP's deficiency that is
the basis for the TR Federal Implementation Plan under Sec. 52.39,
except to the extent the Administrator's approval is partial or
conditional.
(b) Notwithstanding the provisions of paragraph (a) of this
section, if, at the time of the approval of Ohio's SIP
[[Page 48373]]
revision described in paragraph (a) of this section, the Administrator
has already started recording any allocations of TR SO2
Group 1 allowances under subpart CCCCC of part 97 of this chapter to
units in the State for a control period in any year, the provisions of
subpart CCCCC of part 97 of this chapter authorizing the Administrator
to complete the allocation and recordation of TR SO2 Group 1
allowances to units in the State for each such control period shall
continue to apply, unless provided otherwise by such approval of the
State's SIP revision.
Subpart NN--Pennsylvania
0
50. Section 52.2040 is added to read as follows:
Sec. 52.2040 Interstate pollutant transport provisions; What are the
FIP requirements for decreases in emissions of nitrogen oxides?
(a)(1) The owner and operator of each source and each unit located
in the State of Pennsylvania and for which requirements are set forth
under the TR NOX Annual Trading Program in subpart AAAAA of
part 97 of this chapter must comply with such requirements. The
obligation to comply with such requirements will be eliminated by the
promulgation of an approval by the Administrator of a revision to
Pennsylvania's State Implementation Plan (SIP) as correcting the SIP's
deficiency that is the basis for the TR Federal Implementation Plan
under Sec. 52.38(a), except to the extent the Administrator's approval
is partial or conditional.
(2) Notwithstanding the provisions of paragraph (a)(1) of this
section, if, at the time of the approval of Pennsylvania's SIP revision
described in paragraph (a)(1) of this section, the Administrator has
already started recording any allocations of TR NOX Annual
allowances under subpart AAAAA of part 97 of this chapter to units in
the State for a control period in any year, the provisions of subpart
AAAAA of part 97 of this chapter authorizing the Administrator to
complete the allocation and recordation of TR NOX Annual
allowances to units in the State for each such control period shall
continue to apply, unless provided otherwise by such approval of the
State's SIP revision.
(b)(1) The owner and operator of each source and each unit located
in the State of Pennsylvania and for which requirements are set forth
under the TR NOX Ozone Season Trading Program in subpart
BBBBB of part 97 of this chapter must comply with such requirements.
The obligation to comply with such requirements will be eliminated by
the promulgation of an approval by the Administrator of a revision to
Pennsylvania's State Implementation Plan (SIP) as correcting the SIP's
deficiency that is the basis for the TR Federal Implementation Plan
under Sec. 52.38(b), except to the extent the Administrator's approval
is partial or conditional.
(2) Notwithstanding the provisions of paragraph (b)(1) of this
section, if, at the time of the approval of Pennsylvania's SIP revision
described in paragraph (b)(1) of this section, the Administrator has
already started recording any allocations of TR NOX Ozone
Season allowances under subpart BBBBB of part 97 of this chapter to
units in the State for a control period in any year, the provisions of
subpart BBBBB of part 97 of this chapter authorizing the Administrator
to complete the allocation and recordation of TR NOX Ozone
Season allowances to units in the State for each such control period
shall continue to apply, unless provided otherwise by such approval of
the State's SIP revision.
0
51. Section 52.2041 is added to read as follows:
Sec. 52.2041 Interstate pollutant transport provisions; What are the
FIP requirements for decreases in emissions of sulfur dioxide?
(a) The owner and operator of each source and each unit located in
the State of Pennsylvania and for which requirements are set forth
under the TR SO2 Group 1 Trading Program in subpart CCCCC of
part 97 of this chapter must comply with such requirements. The
obligation to comply with such requirements will be eliminated by the
promulgation of an approval by the Administrator of a revision to
Pennsylvania's State Implementation Plan (SIP) as correcting the SIP's
deficiency that is the basis for the TR Federal Implementation Plan
under Sec. 52.39, except to the extent the Administrator's approval is
partial or conditional.
(b) Notwithstanding the provisions of paragraph (a) of this
section, if, at the time of the approval of Pennsylvania's SIP revision
described in paragraph (a) of this section, the Administrator has
already started recording any allocations of TR SO2 Group 1
allowances under subpart CCCCC of part 97 of this chapter to units in
the State for a control period in any year, the provisions of subpart
CCCCC of part 97 of this chapter authorizing the Administrator to
complete the allocation and recordation of TR SO2 Group 1
allowances to units in the State for each such control period shall
continue to apply, unless provided otherwise by such approval of the
State's SIP revision.
Subpart PP--South Carolina
0
52. Section 52.2140 is revised to read as follows:
Sec. 52.2140 Interstate pollutant transport provisions; What are the
FIP requirements for decreases in emissions of nitrogen oxides?
(a)(1) The owner and operator of each source and each unit located
in the State of South Carolina and Indian country within the borders of
the State and for which requirements are set forth under the TR
NOX Annual Trading Program in subpart AAAAA of part 97 of
this chapter must comply with such requirements. The obligation to
comply with such requirements with regard to sources and units in the
State will be eliminated by the promulgation of an approval by the
Administrator of a revision to South Carolina's State Implementation
Plan (SIP) as correcting in part the SIP's deficiency that is the basis
for the TR Federal Implementation Plan under Sec. 52.38(a), except to
the extent the Administrator's approval is partial or conditional. The
obligation to comply with such requirements with regard to sources and
units located in Indian country within the borders of the State will
not be eliminated by the promulgation of an approval by the
Administrator of a revision to South Carolina's SIP.
(2) Notwithstanding the provisions of paragraph (a)(1) of this
section, if, at the time of the approval of South Carolina's SIP
revision described in paragraph (a)(1) of this section, the
Administrator has already started recording any allocations of TR
NOX Annual allowances under subpart AAAAA of part 97 of this
chapter to units in the State for a control period in any year, the
provisions of subpart AAAAA of part 97 of this chapter authorizing the
Administrator to complete the allocation and recordation of TR
NOX Annual allowances to units in the State for each such
control period shall continue to apply, unless provided otherwise by
such approval of the State's SIP revision.
(b)(1) The owner and operator of each source and each unit located
in the State of South Carolina and Indian country within the borders of
the State and for which requirements are set forth under the TR
NOX Ozone Season Trading Program in subpart BBBBB of part 97
of this chapter must comply with such requirements. The obligation to
comply with such requirements with regard to sources and units in the
State will be
[[Page 48374]]
eliminated by the promulgation of an approval by the Administrator of a
revision to South Carolina's State Implementation Plan (SIP) as
correcting in part the SIP's deficiency that is the basis for the TR
Federal Implementation Plan under Sec. 52.38(b), except to the extent
the Administrator's approval is partial or conditional. The obligation
to comply with such requirements with regard to sources and units
located in Indian country within the borders of the State will not be
eliminated by the promulgation of an approval by the Administrator of a
revision to South Carolina's SIP.
(2) Notwithstanding the provisions of paragraph (b)(1) of this
section, if, at the time of the approval of South Carolina's SIP
revision described in paragraph (b)(1) of this section, the
Administrator has already started recording any allocations of TR
NOX Ozone Season allowances under subpart BBBBB of part 97
of this chapter to units in the State for a control period in any year,
the provisions of subpart BBBBB of part 97 of this chapter authorizing
the Administrator to complete the allocation and recordation of TR
NOX Ozone Season allowances to units in the State for each
such control period shall continue to apply, unless provided otherwise
by such approval of the State's SIP revision.
0
53. Section 52.2141 is revised to read as follows:
Sec. 52.2141 Interstate pollutant transport provisions; What are the
FIP requirements for decreases in emissions of sulfur dioxide?
(a) The owner and operator of each source and each unit located in
the State of South Carolina and Indian country within the borders of
the State and for which requirements are set forth under the TR
SO2 Group 2 Trading Program in subpart DDDDD of part 97 of
this chapter must comply with such requirements. The obligation to
comply with such requirements with regard to sources and units in the
State will be eliminated by the promulgation of an approval by the
Administrator of a revision to South Carolina's State Implementation
Plan (SIP) as correcting in part the SIP's deficiency that is the basis
for the TR Federal Implementation Plan under Sec. 52.39, except to the
extent the Administrator's approval is partial or conditional. The
obligation to comply with such requirements with regard to sources and
units located in Indian country within the borders of the State will
not be eliminated by the promulgation of an approval by the
Administrator of a revision to South Carolina's SIP.
(b) Notwithstanding the provisions of paragraph (a) of this
section, if, at the time of the approval of South Carolina's SIP
revision described in paragraph (a) of this section, the Administrator
has already started recording any allocations of TR SO2
Group 1 allowances under subpart CCCCC of part 97 of this chapter to
units in the State for a control period in any year, the provisions of
subpart CCCCC of part 97 of this chapter authorizing the Administrator
to complete the allocation and recordation of TR SO2 Group 1
allowances to units in the State for each such control period shall
continue to apply, unless provided otherwise by such approval of the
State's SIP revision.
Subpart RR--Tennessee
0
54. Section 52.2240 is amended by adding new paragraphs (c), (d), and
(e) to read as follows:
Sec. 52.2240 Interstate pollutant transport provisions; What are the
FIP requirements for decreases in emissions of nitrogen oxides?
* * * * *
(c) Notwithstanding any provisions of paragraphs (a) and (b) of
this section and subparts AA through II and AAAA through IIII of part
97 of this chapter to the contrary:
(1) With regard to any control period that begins after December
31, 2011,
(i) The provisions in paragraphs (a) and (b) of this section
relating to NOX annual or ozone season emissions shall not
be applicable; and
(ii) The Administrator will not carry out any of the functions set
forth for the Administrator in subparts AA through II and AAAA through
IIII of part 97 of this chapter; and
(2) The Administrator will not deduct for excess emissions any CAIR
NOX allowances or CAIR NOX Ozone Season
allowances allocated for 2012 or any year thereafter;
(3) By November 7, 2011, the Administrator will remove from the
CAIR NOX Allowance Tracking System accounts all CAIR
NOX allowances allocated for a control period in 2012 and
any subsequent year, and, thereafter, no holding or surrender of CAIR
NOX allowances will be required with regard to emissions or
excess emissions for such control periods; and
(4) By November 7, 2011, the Administrator will remove from the
CAIR NOX Ozone Season Allowance Tracking System accounts all
CAIR NOX Ozone Season allowances allocated for a control
period in 2012 and any subsequent year, and, thereafter, no holding or
surrender of CAIR NOX Ozone Season allowances will be
required with regard to emissions or excess emissions for such control
periods.
(d)(1) The owner and operator of each source and each unit located
in the State of Tennessee and for which requirements are set forth
under the TR NOX Annual Trading Program in subpart AAAAA of
part 97 of this chapter must comply with such requirements. The
obligation to comply with such requirements will be eliminated by the
promulgation of an approval by the Administrator of a revision to
Tennessee's State Implementation Plan (SIP) as correcting the SIP's
deficiency that is the basis for the TR Federal Implementation Plan
under Sec. 52.38(a), except to the extent the Administrator's approval
is partial or conditional. The obligation to comply with such
requirements with regard to sources and units located in Indian country
within the borders of the State will not be eliminated by the
promulgation of an approval by the Administrator of a revision to
Tennessee's SIP.
(2) Notwithstanding the provisions of paragraph (d)(1) of this
section, if, at the time of the approval of Tennessee's SIP revision
described in paragraph (d)(1) of this section, the Administrator has
already started recording any allocations of TR NOX Annual
allowances under subpart AAAAA of part 97 of this chapter to units in
the State for a control period in any year, the provisions of subpart
AAAAA of part 97 of this chapter authorizing the Administrator to
complete the allocation and recordation of TR NOX Annual
allowances to units in the State for each such control period shall
continue to apply, unless provided otherwise by such approval of the
State's SIP revision.
(e)(1) The owner and operator of each source and each unit located
in the State of Tennessee and for which requirements are set forth
under the TR NOX Ozone Season Trading Program in subpart
BBBBB of part 97 of this chapter must comply with such requirements.
The obligation to comply with such requirements will be eliminated by
the promulgation of an approval by the Administrator of a revision to
Tennessee's State Implementation Plan (SIP) as correcting the SIP's
deficiency that is the basis for the TR Federal Implementation Plan
under Sec. 52.38(b), except to the extent the Administrator's approval
is partial or conditional. The obligation to comply with such
requirements with regard to sources and units located in Indian country
within the borders of the State will not be eliminated by the
promulgation of an
[[Page 48375]]
approval by the Administrator of a revision to Tennessee's SIP.
(2) Notwithstanding the provisions of paragraph (e)(1) of this
section, if, at the time of the approval of Tennessee's SIP revision
described in paragraph (e)(1) of this section, the Administrator has
already started recording any allocations of TR NOX Ozone
Season allowances under subpart BBBBB of part 97 of this chapter to
units in the State for a control period in any year, the provisions of
subpart BBBBB of part 97 of this chapter authorizing the Administrator
to complete the allocation and recordation of TR NOX Ozone
Season allowances to units in the State for each such control period
shall continue to apply, unless provided otherwise by such approval of
the State's SIP revision.
0
55. Section 52.2241 is amended by designating the existing text as
paragraph (a) and adding new paragraphs (b) and (c) to read as follows:
Sec. 52.2241 Interstate pollutant transport provisions; What are the
FIP requirements for decreases in emissions of sulfur dioxide?
* * * * *
(b) Notwithstanding any provisions of paragraph (a) of this section
and subparts AAA through III of part 97 of this chapter and any State's
SIP to the contrary:
(1) With regard to any control period that begins after December
31, 2011,
(i) The provisions of paragraph (a) of this section relating to
SO2 emissions shall not be applicable; and
(ii) The Administrator will not carry out any of the functions set
forth for the Administrator in subparts AAA through III of part 97 of
this chapter; and
(2) The Administrator will not deduct for excess emissions any CAIR
SO2 allowances allocated for 2012 or any year thereafter.
(c)(1) The owner and operator of each source and each unit located
in the State of Tennessee and for which requirements are set forth
under the TR SO2 Group 1 Trading Program in subpart CCCCC of
part 97 of this chapter must comply with such requirements. The
obligation to comply with such requirements will be eliminated by the
promulgation of an approval by the Administrator of a revision to
Tennessee's State Implementation Plan (SIP) as correcting the SIP's
deficiency that is the basis for the TR Federal Implementation Plan
under Sec. 52.39, except to the extent the Administrator's approval is
partial or conditional. The obligation to comply with such requirements
with regard to sources and units located in Indian country within the
borders of the State will not be eliminated by the promulgation of an
approval by the Administrator of a revision to Tennessee's SIP.
(2) Notwithstanding the provisions of paragraph (c)(1) of this
section, if, at the time of the approval of Tennessee's SIP revision
described in paragraph (c)(1) of this section, the Administrator has
already started recording any allocations of TR SO2 Group 1
allowances under subpart CCCCC of part 97 of this chapter to units in
the State for a control period in any year, the provisions of subpart
CCCCC of part 97 of this chapter authorizing the Administrator to
complete the allocation and recordation of TR SO2 Group 1
allowances to units in the State for each such control period shall
continue to apply, unless provided otherwise by such approval of the
State's SIP revision.
Subpart SS--Texas
0
56. Section 52.2283 is amended by adding new paragraphs (b), (c) and
(d) to read as follows:
Sec. 52.2283 Interstate pollutant transport provisions; What are the
FIP requirements for decreases in emissions of nitrogen oxides?
* * * * *
(b) Notwithstanding any provisions of paragraph (a) of this section
and subparts AA through II of part 97 of this chapter to the contrary:
(1) With regard to any control period that begins after December
31, 2011,
(i) The provisions in paragraph (a) of this section relating to
NOX annual emissions shall not be applicable; and
(ii) The Administrator will not carry out any of the functions set
forth for the Administrator in subparts AA through II of part 97 of
this chapter;
(2) The Administrator will not deduct for excess emissions any CAIR
NOX allowances allocated for 2012 or any year thereafter;
(3) By November 7, 2011, the Administrator will remove from the
CAIR NOX Allowance Tracking System accounts all CAIR
NOX allowances allocated for a control period in 2012 and
any subsequent year, and, thereafter, no holding or surrender of CAIR
NOX allowances will be required with regard to emissions or
excess emissions for such control periods.
(c)(1) The owner and operator of each source and each unit located
in the State of Texas and Indian country within the borders of the
State and for which requirements are set forth under the TR
NOX Annual Trading Program in subpart AAAAA of part 97 of
this chapter must comply with such requirements. The obligation to
comply with such requirements with regard to sources and units in the
State will be eliminated by the promulgation of an approval by the
Administrator of a revision to Texas' State Implementation Plan (SIP)
as correcting in part the SIP's deficiency that is the basis for the TR
Federal Implementation Plan under Sec. 52.38(a), except to the extent
the Administrator's approval is partial or conditional. The obligation
to comply with such requirements with regard to sources and units
located in Indian country within the borders of the State will not be
eliminated by the promulgation of an approval by the Administrator of a
revision to Texas' SIP.
(2) Notwithstanding the provisions of paragraph (c)(1) of this
section, if, at the time of the approval of Texas' SIP revision
described in paragraph (c)(1) of this section, the Administrator has
already started recording any allocations of TR NOX Annual
allowances under subpart AAAAA of part 97 of this chapter to units in
the State for a control period in any year, the provisions of subpart
AAAAA of part 97 of this chapter authorizing the Administrator to
complete the allocation and recordation of TR NOX Annual
allowances to units in the State for each such control period shall
continue to apply, unless provided otherwise by such approval of the
State's SIP revision.
(d)(1) The owner and operator of each source and each unit located
in the State of Texas and Indian country within the borders of the
State and for which requirements are set forth under the TR
NOX Ozone Season Trading Program in subpart BBBBB of part 97
of this chapter must comply with such requirements. The obligation to
comply with such requirements with regard to sources and units in the
State will be eliminated by the promulgation of an approval by the
Administrator of a revision to Texas' State Implementation Plan (SIP)
as correcting in part the SIP's deficiency that is the basis for the TR
Federal Implementation Plan under Sec. 52.38(b), except to the extent
the Administrator's approval is partial or conditional. The obligation
to comply with such requirements with regard to sources and units
located in Indian country within the borders of the State will not be
eliminated by the promulgation of an approval by the Administrator of a
revision to Texas' SIP.
(2) Notwithstanding the provisions of paragraph (d)(1) of this
section, if, at the time of the approval of Texas' SIP revision
described in paragraph (d)(1) of this section, the Administrator has
already started recording any allocations of TR NOX Ozone
Season allowances under subpart BBBBB of part 97 of this
[[Page 48376]]
chapter to units in the State for a control period in any year, the
provisions of subpart BBBBB of part 97 of this chapter authorizing the
Administrator to complete the allocation and recordation of TR
NOX Ozone Season allowances to units in the State for each
such control period shall continue to apply, unless provided otherwise
by such approval of the State's SIP revision.
0
57. Section 52.2284 is amended by designating the existing text as
paragraph (a) and adding new paragraphs (b) and (c) to read as follows:
Sec. 52.2284 Interstate pollutant transport provisions; What are the
FIP requirements for decreases in emissions of sulfur dioxide?
* * * * *
(b) Notwithstanding any provisions of paragraph (a) of this section
and subparts AAA through III of part 97 of this chapter and any State's
SIP to the contrary:
(1) With regard to any control period that begins after December
31, 2011,
(i) The provisions of paragraph (a) of this section relating to
SO2 emissions shall not be applicable; and
(ii) The Administrator will not carry out any of the functions set
forth for the Administrator in subparts AAA through III of part 97 of
this chapter; and
(2) The Administrator will not deduct for excess emissions any CAIR
SO2 allowances allocated for 2012 or any year thereafter.
(c)(1) The owner and operator of each source and each unit located
in the State of Texas and Indian country within the borders of the
State and for which requirements are set forth under the TR
SO2 Group 2 Trading Program in subpart DDDDD of part 97 of
this chapter must comply with such requirements. The obligation to
comply with such requirements with regard to sources and units in the
State will be eliminated by the promulgation of an approval by the
Administrator of a revision to Texas' State Implementation Plan (SIP)
as correcting in part the SIP's deficiency that is the basis for the TR
Federal Implementation Plan under Sec. 52.39, except to the extent the
Administrator's approval is partial or conditional. The obligation to
comply with such requirements with regard to sources and units located
in Indian country within the borders of the State will not be
eliminated by the promulgation of an approval by the Administrator of a
revision to Texas' SIP.
(2) Notwithstanding the provisions of paragraph (c)(1) of this
section, if, at the time of the approval of Texas' SIP revision
described in paragraph (c)(1) of this section, the Administrator has
already started recording any allocations of TR SO2 Group 2
allowances under subpart DDDDD of part 97 of this chapter to units in
the State for a control period in any year, the provisions of subpart
DDDDD of part 97 of this chapter authorizing the Administrator to
complete the allocation and recordation of TR SO2 Group 2
allowances to units in the State for each such control period shall
continue to apply, unless provided otherwise by such approval of the
State's SIP revision.
Subpart VV--Virginia
0
58. Section 52.2440 is added to read as follows:
Sec. 52.2440 Interstate pollutant transport provisions; What are the
FIP requirements for decreases in emissions of nitrogen oxides?
(a)(1) The owner and operator of each source and each unit located
in the State of Virginia and for which requirements are set forth under
the TR NOX Annual Trading Program in subpart AAAAA of part
97 of this chapter must comply with such requirements. The obligation
to comply with such requirements will be eliminated by the promulgation
of an approval by the Administrator of a revision to Virginia's State
Implementation Plan (SIP) as correcting the SIP's deficiency that is
the basis for the TR Federal Implementation Plan under Sec. 52.38(a),
except to the extent the Administrator's approval is partial or
conditional.
(2) Notwithstanding the provisions of paragraph (a)(1) of this
section, if, at the time of the approval of Virginia's SIP revision
described in paragraph (a)(1) of this section, the Administrator has
already started recording any allocations of TR NOX Annual
allowances under subpart AAAAA of part 97 of this chapter to units in
the State for a control period in any year, the provisions of subpart
AAAAA of part 97 of this chapter authorizing the Administrator to
complete the allocation and recordation of TR NOX Annual
allowances to units in the State for each such control period shall
continue to apply, unless provided otherwise by such approval of the
State's SIP revision.
(b)(1) The owner and operator of each source and each unit located
in the State of Virginia and for which requirements are set forth under
the TR NOX Ozone Season Trading Program in subpart BBBBB of
part 97 of this chapter must comply with such requirements. The
obligation to comply with such requirements will be eliminated by the
promulgation of an approval by the Administrator of a revision to
Virginia's State Implementation Plan (SIP) as correcting the SIP's
deficiency that is the basis for the TR Federal Implementation Plan
under Sec. 52.38(b), except to the extent the Administrator's approval
is partial or conditional.
(2) Notwithstanding the provisions of paragraph (b)(1) of this
section, if, at the time of the approval of Virginia's SIP revision
described in paragraph (b)(1) of this section, the Administrator has
already started recording any allocations of TR NOX Ozone
Season allowances under subpart BBBBB of part 97 of this chapter to
units in the State for a control period in any year, the provisions of
subpart BBBBB of part 97 of this chapter authorizing the Administrator
to complete the allocation and recordation of TR NOX Ozone
Season allowances to units in the State for each such control period
shall continue to apply, unless provided otherwise by such approval of
the State's SIP revision.
0
59. Section 52.2241 is added to read as follows:
Sec. 52.2241 Interstate pollutant transport provisions; What are the
FIP requirements for decreases in emissions of sulfur dioxide?
(a) The owner and operator of each source and each unit located in
the State of Virginia and for which requirements are set forth under
the TR SO2 Group 1 Trading Program in subpart CCCCC of part
97 of this chapter must comply with such requirements. The obligation
to comply with such requirements will be eliminated by the promulgation
of an approval by the Administrator of a revision to Virginia's State
Implementation Plan (SIP) as correcting the SIP's deficiency that is
the basis for the TR Federal Implementation Plan under Sec. 52.39,
except to the extent the Administrator's approval is partial or
conditional.
(b) Notwithstanding the provisions of paragraph (a) of this
section, if, at the time of the approval of Virginia's SIP revision
described in paragraph (a) of this section, the Administrator has
already started recording any allocations of TR SO2 Group 1
allowances under subpart CCCCC of part 97 of this chapter to units in
the State for a control period in any year, the provisions of subpart
CCCCC of part 97 of this chapter authorizing the Administrator to
complete the allocation and recordation of TR SO2 Group 1
allowances to units in the State for each such control period shall
continue to apply, unless provided otherwise by such approval of the
State's SIP revision.
[[Page 48377]]
Subpart XX--West Virginia
0
60. Section 52.2540 is added to read as follows:
Sec. 52.2540 Interstate pollutant transport provisions; What are the
FIP requirements for decreases in emissions of nitrogen oxides?
(a)(1) The owner and operator of each source and each unit located
in the State of West Virginia and for which requirements are set forth
under the TR NOX Annual Trading Program in subpart AAAAA of
part 97 of this chapter must comply with such requirements. The
obligation to comply with such requirements will be eliminated by the
promulgation of an approval by the Administrator of a revision to West
Virginia's State Implementation Plan (SIP) as correcting the SIP's
deficiency that is the basis for the TR Federal Implementation Plan
under Sec. 52.38(a), except to the extent the Administrator's approval
is partial or conditional.
(2) Notwithstanding the provisions of paragraph (a)(1) of this
section, if, at the time of the approval of West Virginia's SIP
revision described in paragraph (a)(1) of this section, the
Administrator has already started recording any allocations of TR
NOX Annual allowances under subpart AAAAA of part 97 of this
chapter to units in the State for a control period in any year, the
provisions of subpart AAAAA of part 97 of this chapter authorizing the
Administrator to complete the allocation and recordation of TR
NOX Annual allowances to units in the State for each such
control period shall continue to apply, unless provided otherwise by
such approval of the State's SIP revision.
(b)(1) The owner and operator of each source and each unit located
in the State of West Virginia and for which requirements are set forth
under the TR NOX Ozone Season Trading Program in subpart
BBBBB of part 97 of this chapter must comply with such requirements.
The obligation to comply with such requirements will be eliminated by
the promulgation of an approval by the Administrator of a revision to
West Virginia's State Implementation Plan (SIP) as correcting the SIP's
deficiency that is the basis for the TR Federal Implementation Plan
under Sec. 52.38(b), except to the extent the Administrator's approval
is partial or conditional.
(2) Notwithstanding the provisions of paragraph (b)(1) of this
section, if, at the time of the approval of West Virginia's SIP
revision described in paragraph (b)(1) of this section, the
Administrator has already started recording any allocations of TR
NOX Ozone Season allowances under subpart BBBBB of part 97
of this chapter to units in the State for a control period in any year,
the provisions of subpart BBBBB of part 97 of this chapter authorizing
the Administrator to complete the allocation and recordation of TR
NOX Ozone Season allowances to units in the State for each
such control period shall continue to apply, unless provided otherwise
by such approval of the State's SIP revision.
0
61. Section 52.2541 is added to read as follows:
Sec. 52.2541 Interstate pollutant transport provisions; What are the
FIP requirements for decreases in emissions of sulfur dioxide?
(a) The owner and operator of each source and each unit located in
the State of West Virginia and for which requirements are set forth
under the TR SO2 Group 1 Trading Program in subpart CCCCC of
part 97 of this chapter must comply with such requirements. The
obligation to comply with such requirements will be eliminated by the
promulgation of an approval by the Administrator of a revision to West
Virginia's State Implementation Plan (SIP) as correcting the SIP's
deficiency that is the basis for the TR Federal Implementation Plan
under Sec. 52.39, except to the extent the Administrator's approval is
partial or conditional.
(b) Notwithstanding the provisions of paragraph (a) of this
section, if, at the time of the approval of West Virginia's SIP
revision described in paragraph (a) of this section, the Administrator
has already started recording any allocations of TR SO2
Group 1 allowances under subpart CCCCC of part 97 of this chapter to
units in the State for a control period in any year, the provisions of
subpart CCCCC of part 97 of this chapter authorizing the Administrator
to complete the allocation and recordation of TR SO2 Group 1
allowances to units in the State for each such control period shall
continue to apply, unless provided otherwise by such approval of the
State's SIP revision.
Subpart YY--Wisconsin
0
62. Section 52.2587 is amended by adding new paragraphs (c) and (d) to
read as follows:
Sec. 52.2587 Interstate pollutant transport provisions; What are the
FIP requirements for decreases in emissions of nitrogen oxides?
* * * * *
(c) Notwithstanding any provisions of paragraphs (a) and (b) of
this section and subparts AA through II and AAAA through IIII of part
97 of this chapter to the contrary:
(1) With regard to any control period that begins after December
31, 2011,
(i) The provisions in paragraphs (a) and (b) of this section
relating to NOX annual or ozone season emissions shall not
be applicable; and
(ii) The Administrator will not carry out any of the functions set
forth for the Administrator in subparts AA through II and AAAA through
IIII of part 97 of this chapter; and
(2) The Administrator will not deduct for excess emissions any CAIR
NOX allowances or CAIR NOX Ozone Season
allowances allocated for 2012 or any year thereafter;
(3) By November 7, 2011, the Administrator will remove from the
CAIR NOX Allowance Tracking System accounts all CAIR
NOX allowances allocated for a control period in 2012 and
any subsequent year, and, thereafter, no holding or surrender of CAIR
NOX allowances will be required with regard to emissions or
excess emissions for such control periods; and
(4) By November 7, 2011, the Administrator will remove from the
CAIR NOX Ozone Season Allowance Tracking System accounts all
CAIR NOX Ozone Season allowances allocated for a control
period in 2012 and any subsequent year, and, thereafter, no holding or
surrender of CAIR NOX Ozone Season allowances will be
required with regard to emissions or excess emissions for such control
periods.
(d)(1) The owner and operator of each source and each unit located
in the State of Wisconsin and Indian country within the borders of the
State and for which requirements are set forth under the TR
NOX Annual Trading Program in subpart AAAAA of part 97 of
this chapter must comply with such requirements. The obligation to
comply with such requirements with regard to sources and units in the
State will be eliminated by the promulgation of an approval by the
Administrator of a revision to Wisconsin's State Implementation Plan
(SIP) as correcting in part the SIP's deficiency that is the basis for
the TR Federal Implementation Plan under Sec. 52.38(a), except to the
extent the Administrator's approval is partial or conditional. The
obligation to comply with such requirements with regard to sources and
units located in Indian country within the borders of the State will
not be eliminated by the promulgation of an approval by the
Administrator of a revision to Wisconsin's SIP.
(2) Notwithstanding the provisions of paragraph (d)(1) of this
section, if, at the
[[Page 48378]]
time of the approval of Wisconsin's SIP revision described in paragraph
(d)(1) of this section, the Administrator has already started recording
any allocations of TR NOX Annual allowances under subpart
AAAAA of part 97 of this chapter to units in the State for a control
period in any year, the provisions of subpart AAAAA of part 97 of this
chapter authorizing the Administrator to complete the allocation and
recordation of TR NOX Annual allowances to units in the
State for each such control period shall continue to apply, unless
provided otherwise by such approval of the State's SIP revision.
0
63. Section 52.2588 is amended by designating the existing text as
paragraph (a) and adding new paragraphs (b) and (c) to read as follows:
Sec. 52.2588 Interstate pollutant transport provisions; What are the
FIP requirements for decreases in emissions of sulfur dioxide?
* * * * *
(b) Notwithstanding any provisions of paragraph (a) of this section
and subparts AAA through III of part 97 of this chapter and any State's
SIP to the contrary:
(1) With regard to any control period that begins after December
31, 2011,
(i) The provisions of paragraph (a) of this section relating to
SO2 emissions shall not be applicable; and
(ii) The Administrator will not carry out any of the functions set
forth for the Administrator in subparts AAA through III of part 97 of
this chapter; and
(2) The Administrator will not deduct for excess emissions any CAIR
SO2 allowances allocated for 2012 or any year thereafter.
(c)(1) The owner and operator of each source and each unit located
in the State of Wisconsin and Indian country within the borders of the
State and for which requirements are set forth under the TR
SO2 Group 1 Trading Program in subpart CCCCC of part 97 of
this chapter must comply with such requirements. The obligation to
comply with such requirements with regard to sources and units in the
State will be eliminated by the promulgation of an approval by the
Administrator of a revision to Wisconsin's State Implementation Plan
(SIP) as correcting in part the SIP's deficiency that is the basis for
the TR Federal Implementation Plan under Sec. 52.39, except to the
extent the Administrator's approval is partial or conditional. The
obligation to comply with such requirements with regard to sources and
units located in Indian country within the borders of the State will
not be eliminated by the promulgation of an approval by the
Administrator of a revision to Wisconsin's SIP.
(2) Notwithstanding the provisions of paragraph (c)(1) of this
section, if, at the time of the approval of Wisconsin's SIP revision
described in paragraph (c)(1) of this section, the Administrator has
already started recording any allocations of TR SO2 Group 1
allowances under subpart CCCCC of part 97 of this chapter to units in
the State for a control period in any year, the provisions of subpart
CCCCC of part 97 of this chapter authorizing the Administrator to
complete the allocation and recordation of TR SO2 Group 1
allowances to units in the State for each such control period shall
continue to apply, unless provided otherwise by such approval of the
State's SIP revision.
PART 72--[AMENDED]
0
64. The authority citation for part 72 is revised to read as follows:
Authority: 42 U.S.C. 7401, 7403, 7410, 7411, 7426, 7601, et
seq.
Sec. 72.2 [Amended]
0
65. Section 72.2 is amended by removing the definition of ``Interested
person''.
PART 78--[AMENDED]
0
66. The authority citation for part 78 continues to read as follows:
Authority: 42 U.S.C. 7401, 7403, 7410, 7411, 7426, 7601, et
seq.
0
67. Section 78.1 is amended by adding paragraphs (b)(13) through
(b)(16) to read as follows:
Sec. 78.1 Purpose and scope.
* * * * *
(b) * * *
(13) Under subpart AAAAA of part 97 of this chapter,
(i) The decision on allocation of TR NOX Annual
allowances under Sec. 97.411(a)(2) and (b) of this chapter.
(ii) The decision on the transfer of TR NOX Annual
allowances under Sec. 97.423 of this chapter.
(iii) The decision on the deduction of TR NOX Annual
allowances under Sec. Sec. 97.424 and 97.425 of this chapter.
(iv) The correction of an error in an Allowance Management System
account under Sec. 97.427 of this chapter.
(v) The adjustment of information in a submission and the decision
on the deduction and transfer of TR NOX Annual allowances
based on the information as adjusted under Sec. 97.428 of this
chapter.
(vi) The finalization of control period emissions data, including
retroactive adjustment based on audit.
(vii) The approval or disapproval of a petition under Sec. 97.435
of this chapter.
(14) Under subpart BBBBB of part 97 of this chapter,
(i) The decision on allocation of TR NOX Ozone Season
allowances under Sec. 97.511(a)(2) and (b) of this chapter.
(ii) The decision on the transfer of TR NOX Ozone Season
allowances under Sec. 97.523 of this chapter.
(iii) The decision on the deduction of TR NOX Ozone
Season allowances under Sec. Sec. 97.524 and 97.525 of this chapter.
(iv) The correction of an error in an Allowance Management System
account under Sec. 97.527 of this chapter.
(v) The adjustment of information in a submission and the decision
on the deduction and transfer of TR NOX Ozone Season
allowances based on the information as adjusted under Sec. 97.528 of
this chapter.
(vi) The finalization of control period emissions data, including
retroactive adjustment based on audit.
(vii) The approval or disapproval of a petition under Sec. 97.535
of this chapter.
(15) Under subpart CCCCC of part 97 of this chapter,
(i) The decision on allocation of TR SO2 Group 1
allowances under Sec. 97.611(a)(2) and (b) of this chapter.
(ii) The decision on the transfer of TR SO2 Group 1
allowances under Sec. 97.623 of this chapter.
(iii) The decision on the deduction of TR SO2 Group 1
allowances under Sec. Sec. 97.624 and 97.625 of this chapter.
(iv) The correction of an error in an Allowance Management System
account under Sec. 97.627 of this chapter.
(v) The adjustment of information in a submission and the decision
on the deduction and transfer of TR SO2 Group 1 allowances
based on the information as adjusted under Sec. 97.628 of this
chapter.
(vi) The finalization of control period emissions data, including
retroactive adjustment based on audit.
(vii) The approval or disapproval of a petition under Sec. 97.635
of this chapter.
(16) Under subpart DDDDD of part 97 of this chapter,
(i) The decision on allocation of TR SO2 Group 2
allowances under Sec. 97.711(a)(2) and (b) of this chapter.
(ii) The decision on the transfer of TR SO2 Group 1
allowances under Sec. 97.723 of this chapter.
(iii) The decision on the deduction of TR SO2 Group 1
allowances under Sec. Sec. 97.724 and 97.725 of this chapter.
(iv) The correction of an error in an Allowance Management System
account under Sec. 97.727 of this chapter.
(v) The adjustment of information in a submission and the decision
on the
[[Page 48379]]
deduction and transfer of TR SO2 Group 1 allowances based on
the information as adjusted under Sec. 97.728 of this chapter.
(vi) The finalization of control period emissions data, including
retroactive adjustment based on audit.
(vii) The approval or disapproval of a petition under Sec. 97.735
of this chapter.
* * * * *
0
68. Section 78.2 is revised to read as follows:
Sec. 78.2 General.
(a) Definitions. (1) The terms used in this subpart with regard to
a decision of the Administrator that is appealed under this section
shall have the meaning as set forth in the regulations under which the
Administrator made such decision and as set forth in paragraph (a)(2)
of this section.
(2) Interested person means, with regard to a decision of the
Administrator:
(i) Any person who submitted comments, or testified at a public
hearing, pursuant to an opportunity for comment provided by the
Administrator as part of the process of making such decision;
(ii) Who submitted objections pursuant to an opportunity for
objections provided by the Administrator as part of the process of
making such decision; or
(iii) Who submitted, to the Administrator and in a format
prescribed by the Administrator, his or her name, service address,
telephone number, and facsimile number and identified such decision in
order to be placed on a list of persons interested in such decision;
(iv) Provided that the Administrator may update the list of
interested persons from time to time by requesting additional written
indication of continued interest from the persons listed and may delete
from the list the name of any person failing to respond as requested.
(b) Availability of information. The availability to the public of
information provided to, or otherwise obtained by, the Administrator
under this subpart shall be governed by part 2 of this chapter.
(c) Computation of time. (1) In computing any period of time
prescribed or allowed under this part, except as otherwise provided,
the day of the event from which the period begins to run shall not be
included, and Saturdays, Sundays, and federal holidays shall be
included. When the period ends on a Saturday, Sunday, or federal
holiday, the stated period shall be extended to include the next
business day.
(2) Where a document is served by first class mail or commercial
delivery service, but not by overnight or same-day delivery, 5 days
shall be added to the time prescribed or allowed under this part for
the filing of a responsive document or for otherwise responding.
0
69. Section 78.3 is amended by:
0
a. In paragraphs (a)(1)(iii), (a)(3)(ii), (a)(4)(ii), (a)(5)(ii),
(a)(6)(ii), (a)(7)(ii), (a)(8)(ii), and (a)(9)(ii), adding, after the
word ``person'', the words ``with regard to the decision''.
0
b. Adding paragraph (a)(10);
0
c. In paragraph (b)(3)(i), removing the words ``paragraph (a)(1) and
(2)'' and adding, in their place, the words ``paragraph (a)(1), (2),
and (10)''; and
0
d. Adding paragraph (d)(11) to read as follows:
Sec. 78.3 Petition for administrative review and request or
evidentiary hearing.
(a) * * *
(10) The following persons may petition for administrative review
of a decision of the Administrator that is made under subparts AAAAA,
BBBBB, CCCCC, and DDDDD of part 97 of this chapter:
(i) The designated representative for a unit or source, or the
authorized account representative for any Allowance Management System
account, covered by the decision; or
(ii) Any interested person with regard to the decision.
* * * * *
(d) * * *
(11) Any provision or requirement of subparts AAAAA, BBBBB, CCCCC,
or DDDDD of part 97 of this chapter, including the standard
requirements under Sec. 97.406, Sec. 97.506, Sec. 97.606, or Sec.
97.706 of this chapter and any emission monitoring or reporting
requirements.
* * * * *
0
70. Section 78.4 is amended by:
0
a. Revising paragraph (a) by:
0
i. Removing the first, second, third, fourth, fifth, and last
sentences;
0
ii. In the sixth and seventh sentences, removing the words ``interest
in'' and adding, in their place, the words ``ownership interest with
respect to'';
0
iii. Redesignating the paragraph as paragraph (a)(1)(iii); and
0
b. Adding paragraphs (a)(1) introductory text, (a)(1)(i), and
(a)(1)(ii); and
0
c. Revising paragraph (a)(2) to read as follows:
Sec. 78.4 Filings.
(a)(1) All original filings made under this part shall be signed by
the person making the filing or by an attorney or authorized
representative, in accordance with the following requirements:
(i) Any filings on behalf of owners and operators of a affected
unit or affected source, TR NOX Annual unit or TR
NOX Annual source, TR NOX Ozone Season unit or TR
NOX Ozone Season source, TR SO2 Group 1 unit or
TR SO2 Group 1 source, TR SO2 Group 2 unit or TR
SO2 Group 2 source, or a unit for which a TR opt-in
application is submitted and not withdrawn shall be signed by the
designated representative. Any filing on behalf of persons with an
ownership interest with respect to allowances, TR NOX Annual
allowances, TR NOX Ozone Season allowances, TR
SO2 Group 1 allowances, or TR SO2 Group 2
allowances in a general account shall be signed by the authorized
account representative.
(ii) Any filings on behalf of owners and operators of a
NOX Budget unit or NOX Budget source shall be
signed by the NOX authorized account representative. Any
filing on behalf of persons with an ownership interest with respect to
NOX allowances in a general account shall be signed by the
NOX authorized account representative.
* * * * *
(2) The name, address, e-mail address (if any), telephone number,
and facsimile number (if any) of the person making the filing shall be
provided with the filing.
* * * * *
Sec. 78.5 [Amended]
0
71. Section 78.5 is amended by, in paragraph (a):
0
a. Removing the words ``public comment prior to'' and adding, in their
place, the words ``submission of public comments or objections prior
to'';
0
b. Removing the words ``public comment period'' whenever they appear
and adding, in their place, the words ``period for submission of public
comments or objections''.
Sec. 78.12 [Amended]
0
72. Section 78.12 is amended by, in paragraph (a), removing the words
``public comment'' and adding, in their place, the words ``submission
of public comments or objections''.
PART 97--[AMENDED]
0
73. The authority citation for part 97 continues to read as follows:
Authority: 42 U.S.C. 7401, 7403, 7410, 7426, 7601, and 7651, et
seq.
0
74. Part 97 is amended by adding subpart AAAAA to read as follows:
[[Page 48380]]
Subpart AAAAA--TR NOX Annual Trading Program
97.401 Purpose.
97.402 Definitions.
97.403 Measurements, abbreviations, and acronyms.
97.404 Applicability.
97.405 Retired unit exemption.
97.406 Standard requirements.
97.407 Computation of time.
97.408 Administrative appeal procedures.
97.409 [Reserved]
97.410 State NOX Annual trading budgets, new unit set-
asides, Indian country new unit set-asides and variability limits.
97.411 Timing requirements for TR NOX Annual allowance
allocations.
97.412 TR NOX Annual allowance allocations to new units.
97.413 Authorization of designated representative and alternate
designated representative.
97.414 Responsibilities of designated representative and alternate
designated representative.
97.415 Changing designated representative and alternate designated
representative; changes in owners and operators.
97.416 Certificate of representation.
97.417 Objections concerning designated representative and alternate
designated representative.
97.418 Delegation by designated representative and alternate
designated representative.
97.419 [Reserved]
97.420 Establishment of compliance accounts and general accounts.
97.421 Recordation of TR NOX Annual allowance
allocations.
97.422 Submission of TR NOX Annual allowance transfers.
97.423 Recordation of TR NOX Annual allowance transfers.
97.424 Compliance with TR NOX Annual emissions
limitation.
97.425 Compliance with TR NOX Annual assurance
provisions.
97.426 Banking.
97.427 Account error.
97.428 Administrator's action on submissions.
97.429 [RESERVED]
97.430 General monitoring, recordkeeping, and reporting
requirements.
97.431 Initial monitoring system certification and recertification
procedures.
97.432 Monitoring system out-of-control periods.
97.433 Notifications concerning monitoring.
97.434 Recordkeeping and reporting.
97.435 Petitions for alternatives to monitoring, recordkeeping, or
reporting requirements.
Subpart AAAAA--TR NOX Annual Trading Program
Sec. 97.401 Purpose.
This subpart sets forth the general, designated representative,
allowance, and monitoring provisions for the Transport Rule (TR)
NOX Annual Trading Program, under section 110 of the Clean
Air Act and Sec. 52.38 of this chapter, as a means of mitigating
interstate transport of fine particulates and nitrogen oxides.
Sec. 97.402 Definitions.
The terms used in this subpart shall have the meanings set forth in
this section as follows:
Acid Rain Program means a multi-state SO2 and
NOX air pollution control and emission reduction program
established by the Administrator under title IV of the Clean Air Act
and parts 72 through 78 of this chapter.
Administrator means the Administrator of the United States
Environmental Protection Agency or the Director of the Clean Air
Markets Division (or its successor determined by the Administrator) of
the United States Environmental Protection Agency, the Administrator's
duly authorized representative under this subpart.
Allocate or allocation means, with regard to TR NOX
Annual allowances, the determination by the Administrator, State, or
permitting authority, in accordance with this subpart and any SIP
revision submitted by the State and approved by the Administrator under
Sec. 52.38(a)(3), (4), or (5) of this chapter, of the amount of such
TR NOX Annual allowances to be initially credited, at no
cost to the recipient, to:
(1) A TR NOX Annual unit;
(2) A new unit set-aside;
(3) An Indian country new unit set-aside; or
(4) An entity not listed in paragraphs (1) through (3) of this
definition;
(5) Provided that, if the Administrator, State, or permitting
authority initially credits, to a TR NOX Annual unit
qualifying for an initial credit, a credit in the amount of zero TR
NOX Annual allowances, the TR NOX Annual unit
will be treated as being allocated an amount (i.e., zero) of TR
NOX Annual allowances.
Allowable NOX emission rate means, for a unit, the most
stringent State or federal NOX emission rate limit (in lb/
MWhr or, if in lb/mmBtu, converted to lb/MWhr by multiplying it by the
unit's heat rate in mmBtu/MWhr) that is applicable to the unit and
covers the longest averaging period not exceeding one year.
Allowance Management System means the system by which the
Administrator records allocations, deductions, and transfers of TR
NOX Annual allowances under the TR NOX Annual
Trading Program. Such allowances are allocated, recorded, held,
deducted, or transferred only as whole allowances.
Allowance Management System account means an account in the
Allowance Management System established by the Administrator for
purposes of recording the allocation, holding, transfer, or deduction
of TR NOX Annual allowances.
Allowance transfer deadline means, for a control period in a given
year, midnight of March 1 (if it is a business day), or midnight of the
first business day thereafter (if March 1 is not a business day),
immediately after such control period and is the deadline by which a TR
NOX Annual allowance transfer must be submitted for
recordation in a TR NOX Annual source's compliance account
in order to be available for use in complying with the source's TR
NOX Annual emissions limitation for such control period in
accordance with Sec. Sec. 97.406 and 97.424.
Alternate designated representative means, for a TR NOX
Annual source and each TR NOX Annual unit at the source, the
natural person who is authorized by the owners and operators of the
source and all such units at the source, in accordance with this
subpart, to act on behalf of the designated representative in matters
pertaining to the TR NOX Annual Trading Program. If the TR
NOX Annual source is also subject to the Acid Rain Program,
TR NOX Ozone Season Trading Program, TR SO2 Group
1 Trading Program, or TR SO2 Group 2 Trading Program, then
this natural person shall be the same natural person as the alternate
designated representative, as defined in the respective program.
Assurance account means an Allowance Management System account,
established by the Administrator under Sec. 97.425(b)(3) for certain
owners and operators of a group of one or more TR NOX Annual
sources and units in a given State (and Indian country within the
borders of such State), in which are held TR NOX Annual
allowances available for use for a control period in a given year in
complying with the TR NOX Annual assurance provisions in
accordance with Sec. Sec. 97.406 and 97.425.
Authorized account representative means, for a general account, the
natural person who is authorized, in accordance with this subpart, to
transfer and otherwise dispose of TR NOX Annual allowances
held in the general account and, for a TR NOX Annual
source's compliance account, the designated representative of the
source.
Automated data acquisition and handling system or DAHS means the
component of the continuous emission monitoring system, or other
emissions monitoring system approved for use
[[Page 48381]]
under this subpart, 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 this subpart.
Biomass means--
(1) Any organic material grown for the purpose of being converted
to energy;
(2) Any organic byproduct of agriculture that can be converted into
energy; or
(3) Any material that can be converted into energy and is
nonmerchantable for other purposes, that is segregated from other
material that is nonmerchantable for other purposes, and that is;
(i) A forest-related organic resource, including mill residues,
precommercial thinnings, slash, brush, or byproduct from conversion of
trees to merchantable material; or
(ii) A wood material, including pallets, crates, dunnage,
manufacturing and construction materials (other than pressure-treated,
chemically-treated, or painted wood products), and landscape or right-
of-way tree trimmings.
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.
Bottoming-cycle unit means a unit in which the energy input to the
unit is first used to produce useful thermal energy, where at least
some of the reject heat from the useful thermal energy application or
process is then used for electricity production.
Business day means a day that does not fall on a weekend or a
federal holiday.
Certifying official means a natural person who is:
(1) For a corporation, a president, secretary, treasurer, or vice-
president of the corporation in charge of a principal business function
or any other person who performs similar policy- or decision-making
functions for the corporation;
(2) For a partnership or sole proprietorship, a general partner or
the proprietor respectively; or
(3) For a local government entity or State, federal, or other
public agency, a principal executive officer or ranking elected
official.
Clean Air Act means the Clean Air Act, 42 U.S.C. 7401, et seq.
Coal means ``coal'' as defined in Sec. 72.2 of this chapter.
Coal-derived fuel means any fuel (whether in a solid, liquid, or
gaseous state) produced by the mechanical, thermal, or chemical
processing of coal.
Cogeneration system means an integrated group, at a source, of
equipment (including a boiler, or combustion turbine, and a steam
turbine generator) designed to produce useful thermal energy for
industrial, commercial, heating, or cooling purposes and electricity
through the sequential use of energy.
Cogeneration unit means a stationary, fossil-fuel-fired boiler or
stationary, fossil-fuel-fired combustion turbine that is a topping-
cycle unit or a bottoming-cycle unit:
(1) Operating as part of a cogeneration system; and
(2) Producing on an annual average basis--
(i) For a topping-cycle unit,
(A) Useful thermal energy not less than 5 percent of total energy
output; and
(B) Useful power that, when added to one-half of useful thermal
energy produced, is not less than 42.5 percent of total energy input,
if useful thermal energy produced is 15 percent or more of total energy
output, or not less than 45 percent of total energy input, if useful
thermal energy produced is less than 15 percent of total energy output.
(ii) For a bottoming-cycle unit, useful power not less than 45
percent of total energy input;
(3) Provided that the requirements in paragraph (2) of this
definition shall not apply to a calendar year referenced in paragraph
(2) of this definition during which the unit did not operate at all;
(4) Provided that the total energy input under paragraphs (2)(i)(B)
and (2)(ii) of this definition shall equal the unit's total energy
input from all fuel, except biomass if the unit is a boiler; and
(5) Provided that, if, throughout its operation during the 12-month
period or a calendar year referenced in paragraph (2) of this
definition, a unit is operated as part of a cogeneration system and the
cogeneration system meets on a system-wide basis the requirement in
paragraph (2)(i)(B) or (2)(ii) of this definition, the unit shall be
deemed to meet such requirement during that 12-month period or calendar
year.
Combustion turbine means an enclosed device comprising:
(1) If the device is simple cycle, 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; and
(2) If the device is combined cycle, the equipment described in
paragraph (1) of this definition and any associated duct burner, heat
recovery steam generator, and steam turbine.
Commence commercial operation means, with regard to a unit:
(1) To have begun to produce steam, gas, or other heated medium
used to generate electricity for sale or use, including test
generation, except as provided in Sec. 97.405.
(i) For a unit that is a TR NOX Annual unit under Sec.
97.404 on the later of January 1, 2005 or the date the unit commences
commercial operation as defined in the introductory text of paragraph
(1) of this definition and that subsequently undergoes a physical
change or is moved to a new location or source, such date shall remain
the date of commencement of commercial operation of the unit, which
shall continue to be treated as the same unit.
(ii) For a unit that is a TR NOX Annual unit under Sec.
97.404 on the later of January 1, 2005 or the date the unit commences
commercial operation as defined in the introductory text of paragraph
(1) of this definition and that is subsequently replaced by a unit at
the same or a different source, such date shall remain the replaced
unit's date of commencement of commercial operation, and the
replacement unit shall be treated as a separate unit with a separate
date for commencement of commercial operation as defined in paragraph
(1) or (2) of this definition as appropriate.
(2) Notwithstanding paragraph (1) of this definition and except as
provided in Sec. 97.405, for a unit that is not a TR NOX
Annual unit under Sec. 97.404 on the later of January 1, 2005 or the
date the unit commences commercial operation as defined in introductory
text of paragraph (1) of this definition, the unit's date for
commencement of commercial operation shall be the date on which the
unit becomes a TR NOX Annual unit under Sec. 97.404.
(i) For a unit with a date for commencement of commercial operation
as defined in the introductory text of paragraph (2) of this definition
and that subsequently undergoes a physical change or is moved to a
different location or source, such date shall remain the date of
commencement of commercial operation of the unit, which shall continue
to be treated as the same unit.
(ii) For a unit with a date for commencement of commercial
operation as defined in the introductory text of paragraph (2) of this
definition and that is subsequently replaced by a unit at the same or a
different source, such date shall remain the replaced unit's date of
commencement of commercial operation, and the replacement unit shall be
treated as a separate unit with a separate date for
[[Page 48382]]
commencement of commercial operation as defined in paragraph (1) or (2)
of this definition as appropriate.
Common designated representative means, with regard to a control
period in a given year, a designated representative where, as of April
1 immediately after the allowance transfer deadline for such control
period, the same natural person is authorized under Sec. Sec.
97.413(a) and 97.415(a) as the designated representative for a group of
one or more TR NOX Annual sources and units located in a
State (and Indian country within the borders of such State).
Common designated representative's assurance level means, with
regard to a specific common designated representative and a State (and
Indian country within the borders of such State) and control period in
a given year for which the State assurance level is exceeded as
described in Sec. 97.406(c)(2)(iii), the common designated
representative's share of the State NOX Annual trading
budget with the variability limit for the State for such control
period.
Common designated representative's share means, with regard to a
specific common designated representative for a control period in a
given year:
(1) With regard to a total amount of NOX emissions from
all TR NOX Annual units in a State (and Indian country
within the borders of such State) during such control period, the total
tonnage of NOX emissions during such control period from a
group of one or more TR NOX Annual units located in such
State (and such Indian country) and having the common designated
representative for such control period;
(2) With regard to a State NOX Annual trading budget
with the variability limit for such control period, the amount (rounded
to the nearest allowance) equal to the sum of the total amount of TR
NOX Annual allowances allocated for such control period to a
group of one or more TR NOX Annual units located in the
State (and Indian country within the borders of such State) and having
the common designated representative for such control period and of the
total amount of TR NOX Annual allowances purchased by an
owner or operator of such TR NOX Annual units in an auction
for such control period and submitted by the State or the permitting
authority to the Administrator for recordation in the compliance
accounts for such TR NOX Annual units in accordance with the
TR NOX Annual allowance auction provisions in a SIP revision
approved by the Administrator under Sec. 52.38(a)(4) or (5) of this
chapter, multiplied by the sum of the State NOX Annual
trading budget under Sec. 97.410(a) and the State's variability limit
under Sec. 97.410(b) for such control period and divided by such State
NOX Annual trading budget;
(3) Provided that, in the case of a unit that operates during, but
has no amount of TR NOX Annual allowances allocated under
Sec. Sec. 97.411 and 97.412 for, such control period, the unit shall
be treated, solely for purposes of this definition, as being allocated
an amount (rounded to the nearest allowance) of TR NOX
Annual allowances for such control period equal to the unit's allowable
NOX emission rate applicable to such control period,
multiplied by a capacity factor of 0.85 (if the unit is a boiler
combusting any amount of coal or coal-derived fuel during such control
period), 0.24 (if the unit is a simple combustion turbine during such
control period), 0.67 (if the unit is a combined cycle turbine during
such control period), 0.74 (if the unit is an integrated coal
gasification combined cycle unit during such control period), or 0.36
(for any other unit), multiplied by the unit's maximum hourly load as
reported in accordance with this subpart and by 8,760 hours/control
period, and divided by 2,000 lb/ton.
Common stack means a single flue through which emissions from 2 or
more units are exhausted.
Compliance account means an Allowance Management System account,
established by the Administrator for a TR NOX Annual source
under this subpart, in which any TR NOX Annual allowance
allocations to the TR NOX Annual units at the source are
recorded and in which are held any TR NOX Annual allowances
available for use for a control period in a given year in complying
with the source's TR NOX Annual emissions limitation in
accordance with Sec. Sec. 97.406 and 97.424.
Continuous emission monitoring system or CEMS means the equipment
required under this subpart to sample, analyze, measure, and provide,
by means of readings recorded at least once every 15 minutes and using
an automated data acquisition and handling system (DAHS), a permanent
record of NOX emissions, stack gas volumetric flow rate,
stack gas moisture content, and O2 or CO2
concentration (as applicable), in a manner consistent with part 75 of
this chapter and Sec. Sec. 97.430 through 97.435. The following
systems are the principal types of continuous emission monitoring
systems:
(1) A flow monitoring system, consisting of a stack flow rate
monitor and an automated data acquisition and handling system and
providing a permanent, continuous record of stack gas volumetric flow
rate, in standard cubic feet per hour (scfh);
(2) A NOX concentration monitoring system, consisting of
a NOX pollutant concentration monitor and an automated data
acquisition and handling system and providing a permanent, continuous
record of NOX emissions, in parts per million (ppm);
(3) A NOX emission rate (or NOX-diluent)
monitoring system, consisting of a NOX pollutant
concentration monitor, a diluent gas (CO2 or O2)
monitor, and an automated data acquisition and handling system and
providing a permanent, continuous record of NOX
concentration, in parts per million (ppm), diluent gas concentration,
in percent CO2 or O2, and NOX emission
rate, in pounds per million British thermal units (lb/mmBtu);
(4) A moisture monitoring system, as defined in Sec. 75.11(b)(2)
of this chapter and providing a permanent, continuous record of the
stack gas moisture content, in percent H2O;
(5) A CO2 monitoring system, consisting of a
CO2 pollutant concentration monitor (or an O2
monitor plus suitable mathematical equations from which the
CO2 concentration is derived) and an automated data
acquisition and handling system and providing a permanent, continuous
record of CO2 emissions, in percent CO2; and
(6) An O2 monitoring system, consisting of an
O2 concentration monitor and an automated data acquisition
and handling system and providing a permanent, continuous record of
O2, in percent O2.
Control period means the period starting January 1 of a calendar
year, except as provided in Sec. 97.406(c)(3), and ending on December
31 of the same year, inclusive.
Designated representative means, for a TR NOX Annual
source and each TR NOX Annual unit at the source, the
natural person who is authorized by the owners and operators of the
source and all such units at the source, in accordance with this
subpart, to represent and legally bind each owner and operator in
matters pertaining to the TR NOX Annual Trading Program. If
the TR NOX Annual source is also subject to the Acid Rain
Program, TR NOX Ozone Season Trading Program, TR
SO2 Group 1 Trading Program, or TR SO2 Group 2
Trading Program, then this natural person shall be the same natural
person as the designated representative, as defined in the respective
program.
Emissions means air pollutants exhausted from a unit or source into
the atmosphere, as measured, recorded, and
[[Page 48383]]
reported to the Administrator by the designated representative, and as
modified by the Administrator:
(1) In accordance with this subpart; and
(2) With regard to a period before the unit or source is required
to measure, record, and report such air pollutants in accordance with
this subpart, in accordance with part 75 of this chapter.
Excess emissions means any ton of emissions from the TR
NOX Annual units at a TR NOX Annual source during
a control period in a given year that exceeds the TR NOX
Annual emissions limitation for the source for such control period.
Fossil fuel means--
(1) Natural gas, petroleum, coal, or any form of solid, liquid, or
gaseous fuel derived from such material; or
(2) For purposes of applying the limitation on ``average annual
fuel consumption of fossil fuel'' in Sec. Sec. 97.404(b)(2)(i)(B) and
(ii), natural gas, petroleum, coal, or any form of solid, liquid, or
gaseous fuel derived from such material for the purpose of creating
useful heat.
Fossil-fuel-fired means, with regard to a unit, combusting any
amount of fossil fuel in 2005 or any calendar year thereafter.
General account means an Allowance Management System account,
established under this subpart, that is not a compliance account or an
assurance account.
Generator means a device that produces electricity.
Gross electrical output means, for a unit, electricity made
available for use, including any such electricity used in the power
production process (which process includes, but is not limited to, any
on-site processing or treatment of fuel combusted at the unit and any
on-site emission controls).
Heat input means, for a unit for a specified period of time, the
product (in mmBtu/time) of the gross calorific value of the fuel (in
mmBtu/lb) fed into the unit multiplied by the fuel feed rate (in lb of
fuel/time), as measured, recorded, and reported to the Administrator by
the designated representative and as modified by the Administrator in
accordance with this subpart and excluding the heat derived from
preheated combustion air, recirculated flue gases, or exhaust.
Heat input rate means, for a unit, the amount of heat input (in
mmBtu) divided by unit operating time (in hr) or, for a unit and a
specific fuel, the amount of heat input attributed to the fuel (in
mmBtu) divided by the unit operating time (in hr) during which the unit
combusts the fuel.
Heat rate means, for a unit, the unit's maximum design heat input
(in Btu/hr), divided by the product of 1,000,000 Btu/mmBtu and the
unit's maximum hourly load.
Indian country means ``Indian country'' as defined in 18 U.S.C.
1151.
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 generated by 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 no less 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, for a unit, the maximum amount of
fuel per hour (in Btu/hr) that the unit is capable of combusting on a
steady state basis as of the initial installation of the unit as
specified by the manufacturer of the unit.
Monitoring system means any monitoring system that meets the
requirements of this subpart, including a continuous emission
monitoring system, an alternative monitoring system, or an excepted
monitoring system under part 75 of this chapter.
Nameplate capacity means, starting from the initial installation of
a generator, the maximum electrical generating output (in MWe, rounded
to the nearest tenth) that the generator is capable of producing on a
steady state basis and during continuous operation (when not restricted
by seasonal or other deratings) as of such installation as specified by
the manufacturer of the generator or, starting from the completion of
any subsequent physical change in the generator resulting in an
increase in the maximum electrical generating output that the generator
is capable of producing on a steady state basis and during continuous
operation (when not restricted by seasonal or other deratings), such
increased maximum amount (in MWe, rounded to the nearest tenth) as of
such completion as specified by the person conducting the physical
change.
Natural gas means ``natural gas'' as defined in Sec. 72.2 of this
chapter.
Newly affected TR NOX Annual unit means a unit that was
not a TR NOX Annual unit when it began operating but that
thereafter becomes a TR NOX Annual unit.
Operate or operation means, with regard to a unit, to combust fuel.
Operator means, for a TR NOX Annual source or a TR
NOX Annual unit at a source respectively, any person who
operates, controls, or supervises a TR NOX Annual unit at
the source or the TR NOX Annual unit and shall include, but
not be limited to, any holding company, utility system, or plant
manager of such source or unit.
Owner means, for a TR NOX Annual source or a TR
NOX Annual unit at a source respectively, any of the
following persons:
(1) Any holder of any portion of the legal or equitable title in a
TR NOX Annual unit at the source or the TR NOX
Annual unit;
(2) Any holder of a leasehold interest in a TR NOX
Annual unit at the source or the TR NOX Annual unit,
provided that, 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) on the revenues or income from
such TR NOX Annual unit; and 3) Any purchaser of power from
a TR NOX Annual unit at the source or the TR NOX
Annual unit under a life-of-the-unit, firm power contractual
arrangement.
Permanently retired means, with regard to a unit, a unit that is
unavailable for service and that the unit's owners and operators do not
expect to return to service in the future.
Permitting authority means ``permitting authority'' as defined in
Sec. Sec. 70.2 and 71.2 of this chapter.
Potential electrical output capacity means, for a unit, 33 percent
of the unit's maximum design heat input, divided by 3,413 Btu/kWh,
divided by 1,000 kWh/MWh, and multiplied by 8,760 hr/yr.
Receive or receipt of means, when referring to the Administrator,
to come into possession of a document, information, or correspondence
(whether sent in hard copy or by authorized electronic transmission),
as indicated in an official log, or by a notation made on the document,
information, or correspondence, by the Administrator in the regular
course of business.
Recordation, record, or recorded means, with regard to TR
NOX Annual allowances, the moving of TR NOX
[[Page 48384]]
Annual allowances by the Administrator into, out of, or between
Allowance Management System accounts, for purposes of allocation,
auction, transfer, or deduction.
Reference method means any direct test method of sampling and
analyzing for an air pollutant as specified in Sec. 75.22 of this
chapter.
Replacement, replace, or replaced means, with regard to a unit, the
demolishing of a unit, or the permanent retirement and permanent
disabling of a unit, and the construction of another unit (the
replacement unit) to be used instead of the demolished or retired unit
(the replaced unit).
Sequential use of energy means:
(1) The use of reject heat from electricity production in a useful
thermal energy application or process; or
(2) The use of reject heat from useful thermal energy application
or process in electricity production.
Serial number means, for a TR NOX Annual allowance, the
unique identification number assigned to each TR NOX Annual
allowance by the Administrator.
Solid waste incineration unit means a stationary, fossil-fuel-fired
boiler or stationary, fossil-fuel-fired combustion turbine that is a
``solid waste incineration unit'' as defined in section 129(g)(1) of
the Clean Air Act.
Source means all buildings, structures, or installations located in
one or more contiguous or adjacent properties under common control of
the same person or persons. This definition does not change or
otherwise affect the definition of ``major source'', ``stationary
source'', or ``source'' as set forth and implemented in a title V
operating permit program or any other program under the Clean Air Act.
State means one of the States that is subject to the TR
NOX Annual Trading Program pursuant to Sec. 52.38(a) of
this chapter.
Submit or serve means to send or transmit a document, information,
or correspondence to the person specified in accordance with the
applicable regulation:
(1) In person;
(2) By United States Postal Service; or
(3) By other means of dispatch or transmission and delivery;
(4) Provided that compliance with any ``submission'' or ``service''
deadline shall be determined by the date of dispatch, transmission, or
mailing and not the date of receipt.
Topping-cycle unit means a unit in which the energy input to the
unit is first used to produce useful power, including electricity,
where at least some of the reject heat from the electricity production
is then used to provide useful thermal energy.
Total energy input means, for a unit, total energy of all forms
supplied to the unit, excluding energy produced by the unit. Each form
of energy supplied shall be measured by the lower heating value of that
form of energy calculated as follows:
LHV = HHV - 10.55(W + 9H)
Where:
LHV = lower heating value of the form of energy in Btu/lb,
HHV = higher heating value of the form of energy in Btu/lb,
W = weight % of moisture in the form of energy, and
H = weight % of hydrogen in the form of energy.
Total energy output means, for a unit, the sum of useful power and
useful thermal energy produced by the unit.
TR NOX Annual allowance means a limited authorization issued and
allocated or auctioned by the Administrator under this subpart, or by a
State or permitting authority under a SIP revision approved by the
Administrator under Sec. 52.38(a)(3), (4), or (5) of this chapter, to
emit one ton of NOX during a control period of the specified
calendar year for which the authorization is allocated or auctioned or
of any calendar year thereafter under the TR NOX Annual
Trading Program.
TR NOX Annual allowance deduction or deduct TR NOX Annual
allowances means the permanent withdrawal of TR NOX Annual
allowances by the Administrator from a compliance account (e.g., in
order to account for compliance with the TR NOX Annual
emissions limitation) or from an assurance account (e.g., in order to
account for compliance with the assurance provisions under Sec. Sec.
97.406 and 97.425).
TR NOX Annual allowances held or hold TR NO4 Annual allowances
means the TR NOX Annual allowances treated as included in an
Allowance Management System account as of a specified point in time
because at that time they:
(1) Have been recorded by the Administrator in the account or
transferred into the account by a correctly submitted, but not yet
recorded, TR NOX Annual allowance transfer in accordance
with this subpart; and
(2) Have not been transferred out of the account by a correctly
submitted, but not yet recorded, TR NOX Annual allowance
transfer in accordance with this subpart.
TR NOX Annual emissions limitation means, for a TR NOX
Annual source, the tonnage of NOX emissions authorized in a
control period in a given year by the TR NOX Annual
allowances available for deduction for the source under Sec. 97.424(a)
for such control period.
TR NOX Annual source means a source that includes one or more TR
NOX Annual units.
TR NOX Annual Trading Program means a multi-state NOX
air pollution control and emission reduction program established in
accordance with this subpart and Sec. 52.38(a) of this chapter
(including such a program that is revised in a SIP revision approved by
the Administrator under Sec. 52.38(a)(3) or (4) of this chapter or
that is established in a SIP revision approved by the Administrator
under Sec. 52.38(a)(5) of this chapter), as a means of mitigating
interstate transport of fine particulates and NOX.
TR NOX Annual unit means a unit that is subject to the TR
NOX Annual Trading Program.
TR NOX Ozone Season Trading Program means a multi-state
NOX air pollution control and emission reduction program
established in accordance with subpart BBBBB of this part and Sec.
52.38(b) of this chapter (including such a program that is revised in a
SIP revision approved by the Administrator under Sec. 52.38(b)(3) or
(4) of this chapter or that is established in a SIP revision approved
by the Administrator under Sec. 52.38(b)(5) of this chapter), as a
means of mitigating interstate transport of ozone and NOX.
TR SO2 Group 1 Trading Program means a multi-state SO2
air pollution control and emission reduction program established in
accordance with subpart CCCCC of this part and Sec. 52.39(a), (b), (d)
through (f), (j), and (k) of this chapter (including such a program
that is revised in a SIP revision approved by the Administrator under
Sec. 52.39(d) or (e) of this chapter or that is established in a SIP
revision approved by the Administrator under Sec. 52.39(f) of this
chapter), as a means of mitigating interstate transport of fine
particulates and SO2.
TR SO2 Group 2 Trading Program means a multi-state SO2 air
pollution control and emission reduction program established in
accordance with subpart DDDDD of this part and 52.39(a), (c), and (g)
through (k) of this chapter (including such a program that is revised
in a SIP revision approved by the Administrator under Sec. 52.39(g) or
(h) of this chapter or that is established in a SIP revision approved
by the Administrator under Sec. 52.39(i) of this chapter), as a means
of mitigating interstate transport of fine particulates and
SO2.
[[Page 48385]]
Unit means a stationary, fossil-fuel-fired boiler, stationary,
fossil-fuel-fired combustion turbine, or other stationary, fossil-fuel-
fired combustion device. A unit that undergoes a physical change or is
moved to a different location or source shall continue to be treated as
the same unit. A unit (the replaced unit) that is replaced by another
unit (the replacement unit) at the same or a different source shall
continue to be treated as the same unit, and the replacement unit shall
be treated as a separate unit.
Unit operating day means, with regard to a unit, a calendar day in
which the unit combusts any fuel.
Unit operating hour or hour of unit operation means, with regard to
a unit, an hour in which the unit combusts any fuel.
Useful power means, with regard to a unit, electricity or
mechanical energy that the unit makes available for use, excluding any
such energy used in the power production process (which process
includes, but is not limited to, any on-site processing or treatment of
fuel combusted at the unit and any on-site emission controls).
Useful thermal energy means thermal energy that is:
(1) Made available to an industrial or commercial process (not a
power production process), excluding any heat contained in condensate
return or makeup water;
(2) Used in a heating application (e.g., space heating or domestic
hot water heating); or
(3) Used in a space cooling application (i.e., in an absorption
chiller).
Utility power distribution system means the portion of an
electricity grid owned or operated by a utility and dedicated to
delivering electricity to customers.
Sec. 97.403 Measurements, abbreviations, and acronyms.
Measurements, abbreviations, and acronyms used in this subpart are
defined as follows:
Btu--British thermal unit
CO2--carbon dioxide
H2O--water
hr--hour
kW--kilowatt electrical
kWh--kilowatt hour
lb--pound
mmBtu--million Btu
MWe--megawatt electrical
MWh--megawatt hour
NOX--nitrogen oxides
O2--oxygen
ppm--parts per million
scfh--standard cubic feet per hour
SO2--sulfur dioxide
yr--year
Sec. 97.404 Applicability.
(a) Except as provided in paragraph (b) of this section:
(1) The following units in a State (and Indian country within the
borders of such State) shall be TR NOX Annual units, and any
source that includes one or more such units shall be a TR
NOX Annual source, subject to the requirements of this
subpart: any stationary, fossil-fuel-fired boiler or stationary,
fossil-fuel-fired combustion turbine serving at any time, on or after
January 1, 2005, a generator with nameplate capacity of more than 25
MWe producing electricity for sale.
(2) If a stationary boiler or stationary combustion turbine that,
under paragraph (a)(1) of this section, is not a TR NOX
Annual unit begins to combust fossil fuel or to serve a generator with
nameplate capacity of more than 25 MWe producing electricity for sale,
the unit shall become a TR NOX Annual unit as provided in
paragraph (a)(1) of this section on the first date on which it both
combusts fossil fuel and serves such generator.
(b) Any unit in a State (and Indian country within the borders of
such State) that otherwise is a TR NOX Annual unit under
paragraph (a) of this section and that meets the requirements set forth
in paragraph (b)(1)(i) or (2)(i) of this section shall not be a TR
NOX Annual unit:
(1)(i) Any unit:
(A) Qualifying as a cogeneration unit throughout the later of 2005
or the 12-month period starting on the date the unit first produces
electricity and continuing to qualify as a cogeneration unit throughout
each calendar year ending after the later of 2005 or such 12-month
period; and
(B) Not supplying in 2005 or any calendar year thereafter more than
one-third of the unit's potential electric output capacity or 219,000
MWh, whichever is greater, to any utility power distribution system for
sale.
(ii) If, after qualifying under paragraph (b)(1)(i) of this section
as not being a TR NOX Annual unit, a unit subsequently no
longer meets all the requirements of paragraph (b)(1)(i) of this
section, the unit shall become a TR NOX Annual unit starting
on the earlier of January 1 after the first calendar year during which
the unit first no longer qualifies as a cogeneration unit or January 1
after the first calendar year during which the unit no longer meets the
requirements of paragraph (b)(1)(i)(B) of this section. The unit shall
thereafter continue to be a TR NOX Annual unit.
(2)(i) Any unit:
(A) Qualifying as a solid waste incineration unit throughout the
later of 2005 or the 12-month period starting on the date the unit
first produces electricity and continuing to qualify as a solid waste
incineration unit throughout each calendar year ending after the later
of 2005 or such 12-month period; and
(B) With an average annual fuel consumption of fossil fuel for the
first 3 consecutive calendar years of operation starting no earlier
than 2005 of less than 20 percent (on a Btu basis) and an average
annual fuel consumption of fossil fuel for any 3 consecutive calendar
years thereafter of less than 20 percent (on a Btu basis).
(ii) If, after qualifying under paragraph (b)(2)(i) of this section
as not being a TR NOX Annual unit, a unit subsequently no
longer meets all the requirements of paragraph (b)(1)(i) of this
section, the unit shall become a TR NOX Annual unit starting
on the earlier of January 1 after the first calendar year during which
the unit first no longer qualifies as a solid waste incineration unit
or January 1 after the first 3 consecutive calendar years after 2005
for which the unit has an average annual fuel consumption of fossil
fuel of 20 percent or more. The unit shall thereafter continue to be a
TR NOX Annual unit.
(c) A certifying official of an owner or operator of any unit or
other equipment may submit a petition (including any supporting
documents) to the Administrator at any time for a determination
concerning the applicability, under paragraphs (a) and (b) of this
section or a SIP revision approved under Sec. 52.38(a)(4) or (5) of
this chapter, of the TR NOX Annual Trading Program to the
unit or other equipment.
(1) Petition content. The petition shall be in writing and include
the identification of the unit or other equipment and the relevant
facts about the unit or other equipment. The petition and any other
documents provided to the Administrator in connection with the petition
shall include the following certification statement, signed by the
certifying official: ``I am authorized to make this submission on
behalf of the owners and operators of the unit or other equipment 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
[[Page 48386]]
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) Response. The Administrator will issue a written response to
the petition and may request supplemental information determined by the
Administrator to be relevant to such petition. The Administrator's
determination concerning the applicability, under paragraphs (a) and
(b) of this section, of the TR NOX Annual Trading Program to
the unit or other equipment shall be binding on any State or permitting
authority unless the Administrator determines that the petition or
other documents or information provided in connection with the petition
contained significant, relevant errors or omissions.
Sec. 97.405 Retired unit exemption.
(a)(1) Any TR NOX Annual unit that is permanently
retired shall be exempt from Sec. 97.406(b) and (c)(1), Sec. 97.424,
and Sec. Sec. 97.430 through 97.435.
(2) The exemption under paragraph (a)(1) of this section shall
become effective the day on which the TR NOX Annual unit is
permanently retired. Within 30 days of the unit's permanent retirement,
the designated representative shall submit a statement to the
Administrator. The statement shall state, in a format prescribed by the
Administrator, that the unit was permanently retired on a specified
date and will comply with the requirements of paragraph (b) of this
section.
(b) Special provisions. (1) A unit exempt under paragraph (a) of
this section shall not emit any NOX, starting on the date
that the exemption takes effect.
(2) For a period of 5 years from the date the records are created,
the owners and operators of a unit exempt under paragraph (a) of 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 before the
end of the period, in writing by the Administrator. The owners and
operators bear the burden of proof that the unit is permanently
retired.
(3) The owners and operators and, to the extent applicable, the
designated representative of a unit exempt under paragraph (a) of this
section shall comply with the requirements of the TR NOX
Annual 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 exempt under paragraph (a) of this section shall lose
its exemption on the first date on which the unit resumes operation.
Such unit shall be treated, for purposes of applying allocation,
monitoring, reporting, and recordkeeping requirements under this
subpart, as a unit that commences commercial operation on the first
date on which the unit resumes operation.
Sec. 97.406 Standard requirements.
(a) Designated representative requirements. The owners and
operators shall comply with the requirement to have a designated
representative, and may have an alternate designated representative, in
accordance with Sec. Sec. 97.413 through 97.418.
(b) Emissions monitoring, reporting, and recordkeeping
requirements.
(1) The owners and operators, and the designated representative, of
each TR NOX Annual source and each TR NOX Annual
unit at the source shall comply with the monitoring, reporting, and
recordkeeping requirements of Sec. Sec. 97.430 through 97.435.
(2) The emissions data determined in accordance with Sec. Sec.
97.430 through 97.435 shall be used to calculate allocations of TR
NOX Annual allowances under Sec. Sec. 97.411(a)(2) and (b)
and 97.412 and to determine compliance with the TR NOX
Annual emissions limitation and assurance provisions under paragraph
(c) of this section, provided that, for each monitoring location from
which mass emissions are reported, the mass emissions amount used in
calculating such allocations and determining such compliance shall be
the mass emissions amount for the monitoring location determined in
accordance with Sec. Sec. 97.430 through 97.435 and rounded to the
nearest ton, with any fraction of a ton less than 0.50 being deemed to
be zero.
(c) NOX emissions requirements. (1) TR NOX Annual
emissions limitation. (i) As of the allowance transfer deadline for a
control period in a given year, the owners and operators of each TR
NOX Annual source and each TR NOX Annual unit at
the source shall hold, in the source's compliance account, TR
NOX Annual allowances available for deduction for such
control period under Sec. 97.424(a) in an amount not less than the
tons of total NOX emissions for such control period from all
TR NOX Annual units at the source.
(ii) If total NOX emissions during a control period in a
given year from the TR NOX Annual units at a TR
NOX Annual source are in excess of the TR NOX
Annual emissions limitation set forth in paragraph (c)(1)(i) of this
section, then:
(A) The owners and operators of the source and each TR
NOX Annual unit at the source shall hold the TR
NOX Annual allowances required for deduction under Sec.
97.424(d); and
(B) The owners and operators of the source and each TR
NOX Annual unit at the source shall pay any fine, penalty,
or assessment or comply with any other remedy imposed, for the same
violations, under the Clean Air Act, and each ton of such excess
emissions and each day of such control period shall constitute a
separate violation of this subpart and the Clean Air Act.
(2) TR NOX Annual assurance provisions. (i) If total
NOX emissions during a control period in a given year from
all TR NOX Annual units at TR NOX Annual sources
in a State (and Indian country within the borders of such State) exceed
the State assurance level, then the owners and operators of such
sources and units in each group of one or more sources and units having
a common designated representative for such control period, where the
common designated representative's share of such NOX
emissions during such control period exceeds the common designated
representative's assurance level for the State and such control period,
shall hold (in the assurance account established for the owners and
operators of such group) TR NOX Annual allowances available
for deduction for such control period under Sec. 97.425(a) in an
amount equal to two times the product (rounded to the nearest whole
number), as determined by the Administrator in accordance with Sec.
97.425(b), of multiplying--
(A) The quotient of the amount by which the common designated
representative's share of such NOX emissions exceeds the
common designated representative's assurance level divided by the sum
of the amounts, determined for all common designated representatives
for such sources and units in the State (and Indian country within the
borders of such State) for such control period, by which each common
designated representative's share of such NOX emissions
exceeds the respective common designated representative's assurance
level; and
(B) The amount by which total NOX emissions from all TR
NOX Annual units at TR NOX Annual sources in the
State (and Indian country within the borders of such State) for such
control period exceed the State assurance level.
[[Page 48387]]
(ii) The owners and operators shall hold the TR NOX
Annual allowances required under paragraph (c)(2)(i) of this section,
as of midnight of November 1 (if it is a business day), or midnight of
the first business day thereafter (if November 1 is not a business
day), immediately after such control period.
(iii) Total NOX emissions from all TR NOX
Annual units at TR NOX Annual sources in a State (and Indian
country within the borders of such State) during a control period in a
given year exceed the State assurance level if such total
NOX emissions exceed the sum, for such control period, of
the State NOX Annual trading budget under Sec. 97.410(a)
and the State's variability limit under Sec. 97.410(b).
(iv) It shall not be a violation of this subpart or of the Clean
Air Act if total NOX emissions from all TR NOX
Annual units at TR NOX Annual sources in a State (and Indian
country within the borders of such State) during a control period
exceed the State assurance level or if a common designated
representative's share of total NOX emissions from the TR
NOX Annual units at TR NOX Annual sources in a
State (and Indian country within the borders of such State) during a
control period exceeds the common designated representative's assurance
level.
(v) To the extent the owners and operators fail to hold TR
NOX Annual allowances for a control period in a given year
in accordance with paragraphs (c)(2)(i) through (iii) of this section,
(A) The owners and operators shall pay any fine, penalty, or
assessment or comply with any other remedy imposed under the Clean Air
Act; and
(B) Each TR NOX Annual allowance that the owners and
operators fail to hold for such control period in accordance with
paragraphs (c)(2)(i) through (iii) of this section and each day of such
control period shall constitute a separate violation of this subpart
and the Clean Air Act.
(3) Compliance periods. A TR NOX Annual unit shall be
subject to the requirements under paragraphs (c)(1) and (c)(2) of this
section for the control period starting on the later of January 1, 2012
or the deadline for meeting the unit's monitor certification
requirements under Sec. 97.430(b) and for each control period
thereafter.
(4) Vintage of allowances held for compliance. (i) A TR
NOX Annual allowance held for compliance with the
requirements under paragraph (c)(1)(i) of this section for a control
period in a given year must be a TR NOX Annual allowance
that was allocated for such control period or a control period in a
prior year.
(ii) A TR NOX Annual allowance held for compliance with
the requirements under paragraphs (c)(1)(ii)(A) and (2)(i) through
(iii) of this section for a control period in a given year must be a TR
NOX Annual allowance that was allocated for a control period
in a prior year or the control period in the given year or in the
immediately following year.
(5) Allowance Management System requirements. Each TR
NOX Annual allowance shall be held in, deducted from, or
transferred into, out of, or between Allowance Management System
accounts in accordance with this subpart.
(6) Limited authorization. A TR NOX Annual allowance is
a limited authorization to emit one ton of NOX during the
control period in one year. Such authorization is limited in its use
and duration as follows:
(i) Such authorization shall only be used in accordance with the TR
NOX Annual Trading Program; and
(ii) Notwithstanding any other provision of this subpart, the
Administrator has the authority to terminate or limit the use and
duration of such authorization to the extent the Administrator
determines is necessary or appropriate to implement any provision of
the Clean Air Act.
(7) Property right. A TR NOX Annual allowance does not
constitute a property right.
(d) Title V permit requirements. (1) No title V permit revision
shall be required for any allocation, holding, deduction, or transfer
of TR NOX Annual allowances in accordance with this subpart.
(2) A description of whether a unit is required to monitor and
report NOX emissions using a continuous emission monitoring
system (under subpart H of part 75 of this chapter), an excepted
monitoring system (under appendices D and E to part 75 of this
chapter), a low mass emissions excepted monitoring methodology (under
Sec. 75.19 of this chapter), or an alternative monitoring system
(under subpart E of part 75 of this chapter) in accordance with
Sec. Sec. 97.430 through 97.435 may be added to, or changed in, a
title V permit using minor permit modification procedures in accordance
with Sec. Sec. 70.7(e)(2) and 71.7(e)(1) of this chapter, provided
that the requirements applicable to the described monitoring and
reporting (as added or changed, respectively) are already incorporated
in such permit. This paragraph explicitly provides that the addition
of, or change to, a unit's description as described in the prior
sentence is eligible for minor permit modification procedures in
accordance with Sec. Sec. 70.7(e)(2)(i)(B) and 71.7(e)(1)(i)(B) of
this chapter.
(e) Additional recordkeeping and reporting requirements. (1) Unless
otherwise provided, the owners and operators of each TR NOX
Annual source and each TR NOX Annual unit at the source
shall keep on site at the source each of the following documents (in
hardcopy or electronic format) for a period of 5 years from the date
the document is created. This period may be extended for cause, at any
time before the end of 5 years, in writing by the Administrator.
(i) The certificate of representation under Sec. 97.416 for the
designated representative for the source and each TR NOX
Annual unit at the source and all documents that demonstrate the truth
of the statements in the certificate of representation; provided that
the certificate and documents shall be retained on site at the source
beyond such 5-year period until such certificate of representation and
documents are superseded because of the submission of a new certificate
of representation under Sec. 97.416 changing the designated
representative.
(ii) All emissions monitoring information, in accordance with this
subpart.
(iii) Copies of all reports, compliance certifications, and other
submissions and all records made or required under, or to demonstrate
compliance with the requirements of, the TR NOX Annual
Trading Program.
(2) The designated representative of a TR NOX Annual
source and each TR NOX Annual unit at the source shall make
all submissions required under the TR NOX Annual Trading
Program, except as provided in Sec. 97.418. This requirement does not
change, create an exemption from, or or otherwise affect the
responsible official submission requirements under a title V operating
permit program in parts 70 and 71 of this chapter.
(f) Liability. (1) Any provision of the TR NOX Annual
Trading Program that applies to a TR NOX Annual source or
the designated representative of a TR NOX Annual source
shall also apply to the owners and operators of such source and of the
TR NOX Annual units at the source.
(2) Any provision of the TR NOX Annual Trading Program
that applies to a TR NOX Annual unit or the designated
representative of a TR NOX Annual unit shall also apply to
the owners and operators of such unit.
(g) Effect on other authorities. No provision of the TR
NOX Annual Trading Program or exemption under
[[Page 48388]]
Sec. 97.405 shall be construed as exempting or excluding the owners
and operators, and the designated representative, of a TR
NOX Annual source or TR NOX Annual unit from
compliance with any other provision of the applicable, approved State
implementation plan, a federally enforceable permit, or the Clean Air
Act.
Sec. 97.407 Computation of time.
(a) Unless otherwise stated, any time period scheduled, under the
TR NOX Annual 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
TR NOX Annual 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 TR NOX Annual Trading Program, is not a business
day, the time period shall be extended to the next business day.
Sec. 97.408 Administrative appeal procedures.
The administrative appeal procedures for decisions of the
Administrator under the TR NOX Annual Trading Program are
set forth in part 78 of this chapter.
Sec. 97.409 [Reserved]
Sec. 97.410 State NOX Annual trading budgets, new unit
set-asides, Indian country new unit set-aside, and variability limits.
(a) The State NOX Annual trading budgets, new unit set-
asides, and Indian country new unit set-asides for allocations of TR
NOX Annual allowances for the control periods in 2012 and
thereafter are as follows:
----------------------------------------------------------------------------------------------------------------
Indian country
NOX Annual New unit set- new unit set-
State trading budget aside (tons) aside (tons)
(tons)* for for 2012 and for 2012 and
2012 and 2013 2013 2013
----------------------------------------------------------------------------------------------------------------
Alabama......................................................... 72,691 1,454 ..............
Georgia......................................................... 62,010 1,240 ..............
Illinois........................................................ 47,872 3,830 ..............
Indiana......................................................... 109,726 3,292 ..............
Iowa............................................................ 38,335 729 38
Kansas.......................................................... 30,714 583 31
Kentucky........................................................ 85,086 3,403 ..............
Maryland........................................................ 16,633 333 ..............
Michigan........................................................ 60,193 1,144 60
Minnesota....................................................... 29,572 561 30
Missouri........................................................ 52,374 1,571 ..............
Nebraska........................................................ 26,440 1,825 26
New Jersey...................................................... 7,266 145 ..............
New York........................................................ 17,543 508 18
North Carolina.................................................. 50,587 2,984 51
Ohio............................................................ 92,703 1,854 ..............
Pennsylvania.................................................... 119,986 2,400 ..............
South Carolina.................................................. 32,498 617 33
Tennessee....................................................... 35,703 714 ..............
Texas........................................................... 133,595 3,874 134
Virginia........................................................ 33,242 1,662 ..............
West Virginia................................................... 59,472 2,974 ..............
Wisconsin....................................................... 31,628 1,866 32
----------------------------------------------------------------------------------------------------------------
----------------------------------------------------------------------------------------------------------------
NOX Annual Indian country
trading budget New unit set- new unit set-
State (tons)* for aside (tons) aside (tons)
2014 and for 2014 and for 2014 and
thereafter thereafter thereafter
----------------------------------------------------------------------------------------------------------------
Alabama......................................................... 71,962 1,439 ..............
Georgia......................................................... 40,540 811 ..............
Illinois........................................................ 47,872 3,830 ..............
Indiana......................................................... 108,424 3,253 ..............
Iowa............................................................ 37,498 712 38
Kansas.......................................................... 25,560 485 26
Kentucky........................................................ 77,238 3,090 ..............
Maryland........................................................ 16,574 331 ..............
Michigan........................................................ 57,812 1,098 58
Minnesota....................................................... 29,572 561 30
Missouri........................................................ 48,717 1,462 ..............
Nebraska........................................................ 26,440 1,825 26
New Jersey...................................................... 7,266 145 ..............
New York........................................................ 17,543 508 18
North Carolina.................................................. 41,553 2,451 42
Ohio............................................................ 87,493 1,750 ..............
Pennsylvania.................................................... 119,194 2,384 ..............
South Carolina.................................................. 32,498 617 33
Tennessee....................................................... 19,337 387 ..............
[[Page 48389]]
Texas........................................................... 133,595 3,874 134
Virginia........................................................ 33,242 1,662 ..............
West Virginia................................................... 54,582 2,729 ..............
Wisconsin....................................................... 30,398 1,794 30
----------------------------------------------------------------------------------------------------------------
* Each trading budget includes the new unit set-aside and, where applicable, the Indian country new unit set-
aside and does not include the variability limit.
(b) The States' variability limits for the State NOX
Annual trading budgets for the control periods in 2012 and thereafter
are as follows:
------------------------------------------------------------------------
Variability
Variability limits for
State limits for 2014 and
2012 and 2013 thereafter
------------------------------------------------------------------------
Alabama................................. 13,084 12,953
Georgia................................. 11,162 7,297
Illinois................................ 8,617 8,617
Indiana................................. 19,751 19,516
Iowa.................................... 6,900 6,750
Kansas.................................. 5,529 4,601
Kentucky................................ 15,315 13,903
Maryland................................ 2,994 2,983
Michigan................................ 10,835 10,406
Minnesota............................... 5,323 5,323
Missouri................................ 9,427 8,769
Nebraska................................ 4,759 4,759
New Jersey.............................. 1,308 1,308
New York................................ 3,158 3,158
North Carolina.......................... 9,106 7,480
Ohio.................................... 16,687 15,749
Pennsylvania............................ 21,597 21,455
South Carolina.......................... 5,850 5,850
Tennessee............................... 6,427 3,481
Texas................................... 24,047 24,047
Virginia................................ 5,984 5,984
West Virginia........................... 10,705 9,825
Wisconsin............................... 5,693 5,472
------------------------------------------------------------------------
Sec. 97.411 Timing requirements for TR NOX Annual allowance
allocations.
(a) Existing units. (1) TR NOX Annual allowances are
allocated, for the control periods in 2012 and each year thereafter, as
provided in a notice of data availability issued by the Administrator.
Providing an allocation to a unit in such notice does not constitute a
determination that the unit is a TR NOX Annual unit, and not
providing an allocation to a unit in such notice does not constitute a
determination that the unit is not a TR NOX Annual unit.
(2) Notwithstanding paragraph (a)(1) of this section, if a unit
provided an allocation in the notice of data availability issued under
paragraph (a)(1) of this section does not operate, starting after 2011,
during the control period in two consecutive years, such unit will not
be allocated the TR NOX Annual allowances provided in such
notice for the unit for the control periods in the fifth year after the
first such year and in each year after that fifth year. All TR
NOX Annual allowances that would otherwise have been
allocated to such unit will be allocated to the new unit set-aside for
the State where such unit is located and for the respective years
involved. If such unit resumes operation, the Administrator will
allocate TR NOX Annual allowances to the unit in accordance
with paragraph (b) of this section.
(b) New units. (1) New unit set-asides. (i) By June 1, 2012 and
June 1 of each year thereafter, the Administrator will calculate the TR
NOX Annual allowance allocation to each TR NOX
Annual unit in a State, in accordance with Sec. 97.412(a)(2) through
(7) and (12), for the control period in the year of the applicable
calculation deadline under this paragraph and will promulgate a notice
of data availability of the results of the calculations.
(ii) For each notice of data availability required in paragraph
(b)(1)(i) of this section, the Administrator will provide an
opportunity for submission of objections to the calculations referenced
in such notice.
(A) Objections shall be submitted by the deadline specified in each
notice of data availability required in paragraph (b)(1)(i) of this
section and shall be limited to addressing whether the calculations
(including the identification of the TR NOX Annual units)
are in accordance with Sec. 97.412(a)(2) through (7) and (12) and
Sec. Sec. 97.406(b)(2) and 97.430 through 97.435.
(B) The Administrator will adjust the calculations to the extent
necessary to ensure that they are in accordance with the provisions
referenced in paragraph (b)(1)(ii)(A) of this section. By August 1
immediately after the promulgation of each notice of data availability
required in paragraph (b)(1)(i) of this section, the
[[Page 48390]]
Administrator will promulgate a notice of data availability of any
adjustments that the Administrator determines to be necessary with
regard to allocations under Sec. 97.412(a)(2) through (7) and (12) and
the reasons for accepting or rejecting any objections submitted in
accordance with paragraph (b)(1)(ii)(A) of this section.
(iii) If the new unit set-aside for such control period contains
any TR NOX Annual allowances that have not been allocated in
the applicable notice of data availability required in paragraph
(b)(1)(ii) of this section, the Administrator will promulgate, by
December 15 immediately after such notice, a notice of data
availability that identifies any TR NOX Annual units that
commenced commercial operation during the period starting January 1 of
the year before the year of such control period and ending November 30
of year of such control period.
(iv) For each notice of data availability required in paragraph
(b)(1)(iii) of this section, the Administrator will provide an
opportunity for submission of objections to the identification of TR
NOX annual units in such notice.
(A) Objections shall be submitted by the deadline specified in each
notice of data availability required in paragraph (b)(1)(iii) of this
section and shall be limited to addressing whether the identification
of TR NOX annual units in such notice is in accordance with
paragraph (b)(1)(iii) of this section.
(B) The Administrator will adjust the identification of TR
NOX Annual units in the each notice of data availability
required in paragraph (b)(1)(iii) of this section to the extent
necessary to ensure that it is in accordance with paragraph (b)(1)(iii)
of this section and will calculate the TR NOX Annual
allowance allocation to each TR NOX Annual unit in
accordance with Sec. 97.412(a)(9), (10), and (12) and Sec. Sec.
97.406(b)(2) and 97.430 through 97.435. By February 15 immediately
after the promulgation of each notice of data availability required in
paragraph (b)(1)(iii) of this section, the Administrator will
promulgate a notice of data availability of any adjustments of the
identification of TR NOX Annual units that the Administrator
determines to be necessary, the reasons for accepting or rejecting any
objections submitted in accordance with paragraph (b)(1)(iv)(A) of this
section, and the results of such calculations.
(v) To the extent any TR NOX Annual allowances are added
to the new unit set-aside after promulgation of each notice of data
availability required in paragraph (b)(1)(iv) of this section, the
Administrator will promulgate additional notices of data availability,
as deemed appropriate, of the allocation of such TR NOX
Annual allowances in accordance with Sec. 97.412(a)(10).
(2) Indian country new unit set-asides. (i) By June 1, 2012 and
June 1 of each year thereafter, the Administrator will calculate the TR
NOX Annual allowance allocation to each TR NOX
Annual unit in Indian country within the borders of a State, in
accordance with Sec. 97.412(b)(2) through (7) and (12), for the
control period in the year of the applicable calculation deadline under
this paragraph and will promulgate a notice of data availability of the
results of the calculations.
(ii) For each notice of data availability required in paragraph
(b)(2)(i) of this section, the Administrator will provide an
opportunity for submission of objections to the calculations referenced
in such notice.
(A) Objections shall be submitted by the deadline specified in each
notice of data availability required in paragraph (b)(2)(i) of this
section and shall be limited to addressing whether the calculations
(including the identification of the TR NOX Annual units)
are in accordance with Sec. 97.412(b)(2) through (7) and (12) and
Sec. Sec. 97.406(b)(2) and 97.430 through 97.435.
(B) The Administrator will adjust the calculations to the extent
necessary to ensure that they are in accordance with the provisions
referenced in paragraph (b)(2)(ii)(A) of this section. By August 1
immediately after the promulgation of each notice of data availability
required in paragraph (b)(2)(i) of this section, the Administrator will
promulgate a notice of data availability of any adjustments that the
Administrator determines to be necessary with regard to allocations
under Sec. 97.412(b)(2) through (7) and (12) and the reasons for
accepting or rejecting any objections submitted in accordance with
paragraph (b)(2)(ii)(A) of this section.
(iii) If the Indian country new unit set-aside for such control
period contains any TR NOX Annual allowances that have not
been allocated in the applicable notice of data availability required
in paragraph (b)(2)(ii) of this section, the Administrator will
promulgate, by December 15 immediately after such notice, a notice of
data availability that identifies any TR NOX Annual units
that commenced commercial operation during the period starting January
1 of the year before the year of such control period and ending
November 30 of year of such control period.
(iv) For each notice of data availability required in paragraph
(b)(2)(iii) of this section, the Administrator will provide an
opportunity for submission of objections to the identification of TR
NOX annual units in such notice.
(A) Objections shall be submitted by the deadline specified in each
notice of data availability required in paragraph (b)(2)(iii) of this
section and shall be limited to addressing whether the identification
of TR NOX annual units in such notice is in accordance with
paragraph (b)(2)(iii) of this section.
(B) The Administrator will adjust the identification of TR
NOX Annual units in the each notice of data availability
required in paragraph (b)(2)(iii) of this section to the extent
necessary to ensure that it is in accordance with paragraph (b)(2)(iii)
of this section and will calculate the TR NOX Annual
allowance allocation to each TR NOX Annual unit in
accordance with Sec. 97.412(b)(9), (10), and (12) and Sec. Sec.
97.406(b)(2) and 97.430 through 97.435. By February 15 immediately
after the promulgation of each notice of data availability required in
paragraph (b)(2)(iii) of this section, the Administrator will
promulgate a notice of data availability of any adjustments of the
identification of TR NOX Annual units that the Administrator
determines to be necessary, the reasons for accepting or rejecting any
objections submitted in accordance with paragraph (b)(2)(iv)(A) of this
section, and the results of such calculations.
(v) To the extent any TR NOX Annual allowances are added
to the Indian country new unit set-aside after promulgation of each
notice of data availability required in paragraph (b)(2)(iv) of this
section, the Administrator will promulgate additional notices of data
availability, as deemed appropriate, of the allocation of such TR
NOX Annual allowances in accordance with Sec.
97.412(b)(10).
(c) Units incorrectly allocated TR NOX Annual
allowances. (1) For each control period in 2012 and thereafter, if the
Administrator determines that TR NOX Annual allowances were
allocated under paragraph (a) of this section, or under a provision of
a SIP revision approved under Sec. 52.38(a)(3), (4), or (5) of this
chapter, where such control period and the recipient are covered by the
provisions of paragraph (c)(1)(i) of this section or were allocated
under Sec. 97.412(a)(2) through (7), (9), and (12) and (b)(2) through
(7), (9), and (12), or under a provision of a SIP revision approved
under Sec. 52.38(a)(4) or (5) of this chapter, where such control
period and the recipient are covered by the
[[Page 48391]]
provisions of paragraph (c)(1)(ii) of this section, then the
Administrator will notify the designated representative of the
recipient and will act in accordance with the procedures set forth in
paragraphs (c)(2) through (5) of this section:
(i)(A) The recipient is not actually a TR NOX Annual
unit under Sec. 97.404 as of January 1, 2012 and is allocated TR
NOX Annual allowances for such control period or, in the
case of an allocation under a provision of a SIP revision approved
under Sec. 52.38(a)(3), (4), or (5) of this chapter, the recipient is
not actually a TR NOX Annual unit as of January 1, 2012 and
is allocated TR NOX Annual allowances for such control
period that the SIP revision provides should be allocated only to
recipients that are TR NOX Annual units as of January 1,
2012; or
(B) The recipient is not located as of January 1 of the control
period in the State from whose NOX Annual trading budget the
TR NOX Annual allowances allocated under paragraph (a) of
this section, or under a provision of a SIP revision approved under
Sec. 52.38(a)(3), (4), or (5) of this chapter, were allocated for such
control period.
(ii) The recipient is not actually a TR NOX Annual unit
under Sec. 97.404 as of January 1 of such control period and is
allocated TR NOX Annual allowances for such control period
or, in the case of an allocation under a provision of a SIP revision
approved under Sec. 52.38(a)(3), (4), or (5) of this chapter, the
recipient is not actually a TR NOX Annual unit as of January
1 of such control period and is allocated TR NOX Annual
allowances for such control period that the SIP revision provides
should be allocated only to recipients that are TR NOX
Annual units as of January 1 of such control period.
(2) Except as provided in paragraph (c)(3) or (4) of this section,
the Administrator will not record such TR NOX Annual
allowances under Sec. 97.421.
(3) If the Administrator already recorded such TR NOX
Annual allowances under Sec. 97.421 and if the Administrator makes the
determination under paragraph (c)(1) of this section before making
deductions for the source that includes such recipient under Sec.
97.424(b) for such control period, then the Administrator will deduct
from the account in which such TR NOX Annual allowances were
recorded an amount of TR NOX Annual allowances allocated for
the same or a prior control period equal to the amount of such already
recorded TR NOX Annual allowances. The authorized account
representative shall ensure that there are sufficient TR NOX
Annual allowances in such account for completion of the deduction.
(4) If the Administrator already recorded such TR NOX
Annual allowances under Sec. 97.421 and if the Administrator makes the
determination under paragraph (c)(1) of this section after making
deductions for the source that includes such recipient under Sec.
97.424(b) for such control period, then the Administrator will not make
any deduction to take account of such already recorded TR
NOX Annual allowances.
(5)(i) With regard to the TR NOX Annual allowances that
are not recorded, or that are deducted as an incorrect allocation, in
accordance with paragraphs (c)(2) and (3) of this section for a
recipient under paragraph (c)(1)(i) of this section, the Administrator
will:
(A) Transfer such TR NOX Annual allowances to the new
unit set-aside for such control period for the State from whose
NOX Annual trading budget the TR NOX Annual
allowances were allocated; or
(B) If the State has a SIP revision approved under Sec.
52.38(a)(4) or (5) covering such control period, include such TR
NOX Annual allowances in the portion of the State
NOX Annual trading budget that may be allocated for such
control period in accordance with such SIP revision.
(ii) With regard to the TR NOX Annual allowances that
were not allocated from the Indian country new unit set-aside for such
control period and that are not recorded, or that are deducted as an
incorrect allocation, in accordance with paragraphs (c)(2) and (3) of
this section for a recipient under paragraph (c)(1)(ii) of this
paragraph, the Administrator will:
(A) Transfer such TR NOX Annual allowances to the new
unit set-aside for such control period; or
(B) If the State has a SIP revision approved under Sec.
52.38(a)(4) or (5) covering such control period, include such TR
NOX Annual allowances in the portion of the State
NOX Annual trading budget that may be allocated for such
control period in accordance with such SIP revision.
(iii) With regard to the TR NOX Annual allowances that
were allocated from the Indian country new unit set-aside for such
control period and that are not recorded, or that are deducted as an
incorrect allocation, in accordance with paragraphs (c)(2) and (3) of
this section for a recipient under paragraph (c)(1)(ii) of this
paragraph, the Administrator will transfer such TR NOX
Annual allowances to the Indian country new unit set-aside for such
control period.
Sec. 97.412 TR NOX Annual allowance allocations to new
units.
(a) For each control period in 2012 and thereafter and for the TR
NOX Annual units in each State, the Administrator will
allocate TR NOX Annual allowances to the TR NOX
Annual units as follows:
(1) The TR NOX Annual allowances will be allocated to
the following TR NOX Annual units, except as provided in
paragraph (a)(10) of this section:
(i) TR NOX Annual units that are not allocated an amount
of TR NOX Annual allowances in the notice of data
availability issued under Sec. 97.411(a)(1);
(ii) TR NOX Annual units whose allocation of an amount
of TR NOX Annual allowances for such control period in the
notice of data availability issued under Sec. 97.411(a)(1) is covered
by Sec. 97.411(c)(2) or (3);
(iii) TR NOX Annual units that are allocated an amount
of TR NOX Annual allowances for such control period in the
notice of data availability issued under Sec. 97.411(a)(1), which
allocation is terminated for such control period pursuant to Sec.
97.411(a)(2), and that operate during the control period immediately
preceding such control period; or
(iv) For purposes of paragraph (a)(9) of this section, TR
NOX Annual units under Sec. 97.411(c)(1)(ii) whose
allocation of an amount of TR NOX Annual allowances for such
control period in the notice of data availability issued under Sec.
97.411(b)(1)(ii)(B) is covered by Sec. 97.411(c)(2) or (3).
(2) The Administrator will establish a separate new unit set-aside
for the State for each such control period. Each such new unit set-
aside will be allocated TR NOX Annual allowances in an
amount equal to the applicable amount of tons of NOX
emissions as set forth in Sec. 97.410(a) and will be allocated
additional TR NOX Annual allowances (if any) in accordance
with Sec. Sec. 97.411(a)(2) and (c)(5) and paragraph (b)(10) of this
section.
(3) The Administrator will determine, for each TR NOX
Annual unit described in paragraph (a)(1) of this section, an
allocation of TR NOX Annual allowances for the later of the
following control periods and for each subsequent control period:
(i) The control period in 2012;
(ii) The first control period after the control period in which the
TR NOX Annual unit commences commercial operation;
(iii) For a unit described in paragraph (a)(1)(ii) of this section,
the first control period in which the TR NOX Annual unit
operates in the State after operating in another jurisdiction and for
which
[[Page 48392]]
the unit is not already allocated one or more TR NOX Annual
allowances; and
(iv) For a unit described in paragraph (a)(1)(iii) of this section,
the first control period after the control period in which the unit
resumes operation.
(4)(i) The allocation to each TR NOX annual unit
described in paragraph (a)(1)(i) through (iii) of this section and for
each control period described in paragraph (a)(3) of this section will
be an amount equal to the unit's total tons of NOX emissions
during the immediately preceding control period.
(ii) The Administrator will adjust the allocation amount in
paragraph (a)(4)(i) in accordance with paragraphs (a)(5) through (7)
and (12) of this section.
(5) The Administrator will calculate the sum of the TR
NOX Annual allowances determined for all such TR
NOX Annual units under paragraph (a)(4)(i) of this section
in the State for such control period.
(6) If the amount of TR NOX Annual allowances in the new
unit set-aside for the State for such control period is greater than or
equal to the sum under paragraph (a)(5) of this section, then the
Administrator will allocate the amount of TR NOX Annual
allowances determined for each such TR NOX Annual unit under
paragraph (a)(4)(i) of this section.
(7) If the amount of TR NOX Annual allowances in the new
unit set-aside for the State for such control period is less than the
sum under paragraph (a)(5) of this section, then the Administrator will
allocate to each such TR NOX Annual unit the amount of the
TR NOX Annual allowances determined under paragraph
(a)(4)(i) of this section for the unit, multiplied by the amount of TR
NOX Annual allowances in the new unit set-aside for such
control period, divided by the sum under paragraph (a)(5) of this
section, and rounded to the nearest allowance.
(8) The Administrator will notify the public, through the
promulgation of the notices of data availability described in Sec.
97.411(b)(1)(i) and (ii), of the amount of TR NOX Annual
allowances allocated under paragraphs (a)(2) through (7) and (12) of
this section for such control period to each TR NOX Annual
unit eligible for such allocation.
(9) If, after completion of the procedures under paragraphs (a)(5)
through (8) of this section for such control period, any unallocated TR
NOX Annual allowances remain in the new unit set-aside for
the State for such control period, the Administrator will allocate such
TR NOX Annual allowances as follows--
(i) The Administrator will determine, for each unit described in
paragraph (a)(1) of this section that commenced commercial operation
during the period starting January 1 of the year before the year of
such control period and ending November 30 of year of such control
period, the positive difference (if any) between the unit's emissions
during such control period and the amount of TR NOX Annual
allowances referenced in the notice of data availability required under
Sec. 97.411(b)(1)(ii) for the unit for such control period;
(ii) The Administrator will determine the sum of the positive
differences determined under paragraph (a)(9)(i) of this section;
(iii) If the amount of unallocated TR NOX Annual
allowances remaining in the new unit set-aside for the State for such
control period is greater than or equal to the sum determined under
paragraph (a)(9)(ii) of this section, then the Administrator will
allocate the amount of TR NOX Annual allowances determined
for each such TR NOX Annual unit under paragraph (a)(9)(i)
of this section; and
(iv) If the amount of unallocated TR NOX Annual
allowances remaining in the new unit set-aside for the State for such
control period is less than the sum under paragraph (a)(9)(ii) of this
section, then the Administrator will allocate to each such TR
NOX Annual unit the amount of the TR NOX Annual
allowances determined under paragraph (a)(9)(i) of this section for the
unit, multiplied by the amount of unallocated TR NOX Annual
allowances remaining in the new unit set-aside for such control period,
divided by the sum under paragraph (a)(9)(ii) of this section, and
rounded to the nearest allowance.
(10) If, after completion of the procedures under paragraphs (a)(9)
and (12) of this section for such control period, any unallocated TR
NOX Annual allowances remain in the new unit set-aside for
the State for such control period, the Administrator will allocate to
each TR NOX Annual unit that is in the State, is allocated
an amount of TR NOX Annual allowances in the notice of data
availability issued under Sec. 97.411(a)(1), and continues to be
allocated TR NOX Annual allowances for such control period
in accordance with Sec. 97.411(a)(2), an amount of TR NOX
Annual allowances equal to the following: the total amount of such
remaining unallocated TR NOX Annual allowances in such new
unit set-aside, multiplied by the unit's allocation under Sec.
97.411(a) for such control period, divided by the remainder of the
amount of tons in the applicable State NOX Annual trading
budget minus the sum of the amounts of tons in such new unit set-aside
and the Indian country new unit set-aside for the State for such
control period, and rounded to the nearest allowance.
(11) The Administrator will notify the public, through the
promulgation of the notices of data availability described in Sec.
97.411(b)(1)(iii), (iv), and (v), of the amount of TR NOX
Annual allowances allocated under paragraphs (a)(9), (10), and (12) of
this section for such control period to each TR NOX Annual
unit eligible for such allocation.
(12)(i) Notwithstanding the requirements of paragraphs (a)(2)
through (11) of this section, if the calculations of allocations of a
new unit set-aside for a control period in a given year under paragraph
(a)(7) of this section, paragraphs (a)(6) and (9)(iv) of this section,
or paragraphs (a)(6), (9)(iii), and (10) of this section would
otherwise result in total allocations of such new unit set-aside
exceeding the total amount of such new unit set-aside, then the
Administrator will adjust the results of the calculations under
paragraph (a)(7), (9)(iv), or (10) of this section, as applicable, as
follows. The Administrator will list the TR NOX Annual units
in descending order based on the amount of such units' allocations
under paragraph (a)(7), (9)(iv), or (10) of this section, as
applicable, and, in cases of equal allocation amounts, in alphabetical
order of the relevant source's name and numerical order of the relevant
unit's identification number, and will reduce each unit's allocation
under paragraph (a)(7), (9)(iv), or (10) of this section, as
applicable, by one TR NOX Annual allowance (but not below
zero) in the order in which the units are listed and will repeat this
reduction process as necessary, until the total allocations of such new
unit set-aside equal the total amount of such new unit set-aside.
(ii) Notwithstanding the requirements of paragraphs (a)(10) and
(11) of this section, if the calculations of allocations of a new unit
set-aside for a control period in a given year under paragraphs (a)(6),
(9)(iii), and (10) of this section would otherwise result in a total
allocations of such new unit set-aside less than the total amount of
such new unit set-aside, then the Administrator will adjust the results
of the calculations under paragraph (a)(10) of this section, as
follows. The Administrator will list the TR NOX Annual units
in descending order based on the amount of such units' allocations
under paragraph (a)(10) of this section and, in cases of equal
allocation amounts, in alphabetical order of the relevant source's name
and numerical order of the relevant unit's identification number, and
will increase each unit's
[[Page 48393]]
allocation under paragraph (a)(10) of this section by one TR
NOX Annual allowance in the order in which the units are
listed and will repeat this increase process as necessary, until the
total allocations of such new unit set-aside equal the total amount of
such new unit set-aside.
(b) For each control period in 2012 and thereafter and for the TR
NOX Annual units located in Indian country within the
borders of each State, the Administrator will allocate TR
NOX Annual allowances to the TR NOX Annual units
as follows:
(1) The TR NOX Annual allowances will be allocated to
the following TR NOX Annual units, except as provided in
paragraph (b)(10) of this section:
(i) TR NOX Annual units that are not allocated an amount
of TR NOX Annual allowances in the notice of data
availability issued under Sec. 97.411(a)(1); or
(ii) For purposes of paragraph (b)(9) of this section, TR
NOX Annual units under Sec. 97.411(c)(1)(ii) whose
allocation of an amount of TR NOX Annual allowances for such
control period in the notice of data availability issued under Sec.
97.411(b)(2)(ii)(B) is covered by Sec. 97.411(c)(2) or (3).
(2) The Administrator will establish a separate Indian country new
unit set-aside for the State for each such control period. Each such
Indian country new unit set-aside will be allocated TR NOX
Annual allowances in an amount equal to the applicable amount of tons
of NOX emissions as set forth in Sec. 97.410(a) and will be
allocated additional TR NOX Annual allowances (if any) in
accordance with Sec. 97.411(c)(5).
(3) The Administrator will determine, for each TR NOX
Annual unit described in paragraph (b)(1) of this section, an
allocation of TR NOX Annual allowances for the later of the
following control periods and for each subsequent control period:
(i) The control period in 2012; and
(ii) The first control period after the control period in which the
TR NOX Annual unit commences commercial operation.
(4)(i) The allocation to each TR NOX annual unit
described in paragraph (b)(1)(i) of this section and for each control
period described in paragraph (b)(3) of this section will be an amount
equal to the unit's total tons of NOX emissions during the
immediately preceding control period.
(ii) The Administrator will adjust the allocation amount in
paragraph (b)(4)(i) in accordance with paragraphs (b)(5) through (7)
and (12) of this section.
(5) The Administrator will calculate the sum of the TR
NOX Annual allowances determined for all such TR
NOX Annual units under paragraph (b)(4)(i) of this section
in Indian country within the borders of the State for such control
period.
(6) If the amount of TR NOX Annual allowances in the
Indian country new unit set-aside for the State for such control period
is greater than or equal to the sum under paragraph (b)(5) of this
section, then the Administrator will allocate the amount of TR
NOX Annual allowances determined for each such TR
NOX Annual unit under paragraph (b)(4)(i) of this section.
(7) If the amount of TR NOX Annual allowances in the
Indian country new unit set-aside for the State for such control period
is less than the sum under paragraph (b)(5) of this section, then the
Administrator will allocate to each such TR NOX Annual unit
the amount of the TR NOX Annual allowances determined under
paragraph (b)(4)(i) of this section for the unit, multiplied by the
amount of TR NOX Annual allowances in the Indian country new
unit set-aside for such control period, divided by the sum under
paragraph (b)(5) of this section, and rounded to the nearest allowance.
(8) The Administrator will notify the public, through the
promulgation of the notices of data availability described in Sec.
97.411(b)(2)(i) and (ii), of the amount of TR NOX Annual
allowances allocated under paragraphs (b)(2) through (7) and (12) of
this section for such control period to each TR NOX Annual
unit eligible for such allocation.
(9) If, after completion of the procedures under paragraphs (b)(5)
through (8) of this section for such control period, any unallocated TR
NOX Annual allowances remain in the Indian country new unit
set-aside for the State for such control period, the Administrator will
allocate such TR NOX Annual allowances as follows--
(i) The Administrator will determine, for each unit described in
paragraph (b)(1) of this section that commenced commercial operation
during the period starting January 1 of the year before the year of
such control period and ending November 30 of year of such control
period, the positive difference (if any) between the unit's emissions
during such control period and the amount of TR NOX Annual
allowances referenced in the notice of data availability required under
Sec. 97.411(b)(2)(ii) for the unit for such control period;
(ii) The Administrator will determine the sum of the positive
differences determined under paragraph (b)(9)(i) of this section;
(iii) If the amount of unallocated TR NOX Annual
allowances remaining in the Indian country new unit set-aside for the
State for such control period is greater than or equal to the sum
determined under paragraph (b)(9)(ii) of this section, then the
Administrator will allocate the amount of TR NOX Annual
allowances determined for each such TR NOX Annual unit under
paragraph (b)(9)(i) of this section; and
(iv) If the amount of unallocated TR NOX Annual
allowances remaining in the Indian country new unit set-aside for the
State for such control period is less than the sum under paragraph
(b)(9)(ii) of this section, then the Administrator will allocate to
each such TR NOX Annual unit the amount of the TR
NOX Annual allowances determined under paragraph (b)(9)(i)
of this section for the unit, multiplied by the amount of unallocated
TR NOX Annual allowances remaining in the Indian country new
unit set-aside for such control period, divided by the sum under
paragraph (b)(9)(ii) of this section, and rounded to the nearest
allowance.
(10) If, after completion of the procedures under paragraphs (b)(9)
and (12) of this section for such control period, any unallocated TR
NOX Annual allowances remain in the Indian country new unit
set-aside for the State for such control period, the Administrator
will:
(i) Transfer such unallocated TR NOX Annual allowances
to the new unit set-aside for the State for such control period; or
(ii) If the State has a SIP revision approved under Sec.
52.38(a)(4) or (5) covering such control period, include such
unallocated TR NOX Annual allowances in the portion of the
State NOX Annual trading budget that may be allocated for
such control period in accordance with such SIP revision.
(11) The Administrator will notify the public, through the
promulgation of the notices of data availability described in Sec.
97.411(b)(2)(iii), (iv), and (v), of the amount of TR NOX
Annual allowances allocated under paragraphs (b)(9), (10), and (12) of
this section for such control period to each TR NOX Annual
unit eligible for such allocation.
(12)(i) Notwithstanding the requirements of paragraphs (b)(2)
through (11) of this section, if the calculations of allocations of an
Indian country new unit set-aside for a control period in a given year
under paragraph (b)(7) of this section, paragraphs (b)(6) and (9)(iv)
of this section, or paragraphs (b)(6), (9)(iii), and (10) of this
section would otherwise result in total allocations of such Indian
country new unit set-aside exceeding the total amount of such Indian
country new unit set-aside, then the Administrator will adjust the
results of the calculations
[[Page 48394]]
under paragraph (b)(7), (9)(iv), or (10) of this section, as
applicable, as follows. The Administrator will list the TR
NOX Annual units in descending order based on the amount of
such units' allocations under paragraph (b)(7), (9)(iv), or (10) of
this section, as applicable, and, in cases of equal allocation amounts,
in alphabetical order of the relevant source's name and numerical order
of the relevant unit's identification number, and will reduce each
unit's allocation under paragraph (b)(7), (9)(iv), or (10) of this
section, as applicable, by one TR NOX Annual allowance (but
not below zero) in the order in which the units are listed and will
repeat this reduction process as necessary, until the total allocations
of such Indian country new unit set-aside equal the total amount of
such Indian country new unit set-aside.
(ii) Notwithstanding the requirements of paragraphs (b)(10) and
(11) of this section, if the calculations of allocations of an Indian
country new unit set-aside for a control period in a given year under
paragraphs (b)(6), (9)(iii), and (10) of this section would otherwise
result in a total allocations of such Indian country new unit set-aside
less than the total amount of such Indian country new unit set-aside,
then the Administrator will adjust the results of the calculations
under paragraph (b)(10) of this section, as follows. The Administrator
will list the TR NOX Annual units in descending order based
on the amount of such units' allocations under paragraph (b)(10) of
this section and, in cases of equal allocation amounts, in alphabetical
order of the relevant source's name and numerical order of the relevant
unit's identification number, and will increase each unit's allocation
under paragraph (b)(10) of this section by one TR NOX Annual
allowance in the order in which the units are listed and will repeat
this increase process as necessary, until the total allocations of such
Indian country new unit set-aside equal the total amount of such Indian
country new unit set-aside.
Sec. 97.413 Authorization of designated representative and alternate
designated representative.
(a) Except as provided under Sec. 97.415, each TR NOX
Annual source, including all TR NOX Annual units at the
source, shall have one and only one designated representative, with
regard to all matters under the TR NOX Annual Trading
Program.
(1) The designated representative shall be selected by an agreement
binding on the owners and operators of the source and all TR
NOX Annual units at the source and shall act in accordance
with the certification statement in Sec. 97.416(a)(4)(iii).
(2) Upon and after receipt by the Administrator of a complete
certificate of representation under Sec. 97.416:
(i) The designated representative shall be authorized and shall
represent and, by his or her representations, actions, inactions, or
submissions, legally bind each owner and operator of the source and
each TR NOX Annual unit at the source in all matters
pertaining to the TR NOX Annual Trading Program,
notwithstanding any agreement between the designated representative and
such owners and operators; and
(ii) The owners and operators of the source and each TR
NOX Annual unit at the source shall be bound by any decision
or order issued to the designated representative by the Administrator
regarding the source or any such unit.
(b) Except as provided under Sec. 97.415, each TR NOX
Annual source may have one and only one alternate designated
representative, who may act on behalf of the designated representative.
The agreement by which the alternate designated representative is
selected shall include a procedure for authorizing the alternate
designated representative to act in lieu of the designated
representative.
(1) The alternate designated representative shall be selected by an
agreement binding on the owners and operators of the source and all TR
NOX Annual units at the source and shall act in accordance
with the certification statement in Sec. 97.416(a)(4)(iii).
(2) Upon and after receipt by the Administrator of a complete
certificate of representation under Sec. 97.416,
(i) The alternate designated representative shall be authorized;
(ii) Any representation, action, inaction, or submission by the
alternate designated representative shall be deemed to be a
representation, action, inaction, or submission by the designated
representative; and
(iii) The owners and operators of the source and each TR
NOX Annual unit at the source shall be bound by any decision
or order issued to the alternate designated representative by the
Administrator regarding the source or any such unit.
(c) Except in this section, Sec. 97.402, and Sec. Sec. 97.414
through 97.418, whenever the term ``designated representative'' (as
distinguished from the term ``common designated representative'') is
used in this subpart, the term shall be construed to include the
designated representative or any alternate designated representative.
Sec. 97.414 Responsibilities of designated representative and
alternate designated representative.
(a) Except as provided under Sec. 97.418 concerning delegation of
authority to make submissions, each submission under the TR
NOX Annual Trading Program shall be made, signed, and
certified by the designated representative or alternate designated
representative for each TR NOX Annual source and TR
NOX Annual unit for which the submission is made. Each such
submission shall include the following certification statement by the
designated representative or alternate designated representative: ``I
am authorized to make this submission on behalf of the owners and
operators of the source or 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.''
(b) The Administrator will accept or act on a submission made for a
TR NOX Annual source or a TR NOX Annual unit only
if the submission has been made, signed, and certified in accordance
with paragraph (a) of this section and Sec. 97.418.
Sec. 97.415 Changing designated representative and alternate
designated representative; changes in owners and operators; changes in
units at the source.
(a) Changing designated representative. The designated
representative may be changed at any time upon receipt by the
Administrator of a superseding complete certificate of representation
under Sec. 97.416. Notwithstanding any such change, all
representations, actions, inactions, and submissions by the previous
designated representative before the time and date when the
Administrator receives the superseding certificate of representation
shall be binding on the new designated representative and the owners
and operators of the TR NOX Annual source and the TR
NOX Annual units at the source.
(b) Changing alternate designated representative. The alternate
designated representative may be changed at any
[[Page 48395]]
time upon receipt by the Administrator of a superseding complete
certificate of representation under Sec. 97.416. Notwithstanding any
such change, all representations, actions, inactions, and submissions
by the previous alternate designated representative before the time and
date when the Administrator receives the superseding certificate of
representation shall be binding on the new alternate designated
representative, the designated representative, and the owners and
operators of the TR NOX Annual source and the TR
NOX Annual units at the source.
(c) Changes in owners and operators. (1) In the event an owner or
operator of a TR NOX Annual source or a TR NOX
Annual unit at the source is not included in the list of owners and
operators in the certificate of representation under Sec. 97.416, such
owner or operator shall be deemed to be subject to and bound by the
certificate of representation, the representations, actions, inactions,
and submissions of the designated representative and any alternate
designated representative of the source or unit, and the decisions and
orders of the Administrator, as if the owner or operator were included
in such list.
(2) Within 30 days after any change in the owners and operators of
a TR NOX Annual source or a TR NOX Annual unit at
the source, including the addition or removal of an owner or operator,
the designated representative or any alternate designated
representative shall submit a revision to the certificate of
representation under Sec. 97.416 amending the list of owners and
operators to reflect the change.
(d) Changes in units at the source. Within 30 days of any change in
which units are located at a TR NOX Annual source (including
the addition or removal of a unit), the designated representative or
any alternate designated representative shall submit a certificate of
representation under Sec. 97.416 amending the list of units to reflect
the change.
(1) If the change is the addition of a unit that operated (other
than for purposes of testing by the manufacturer before initial
installation) before being located at the source, then the certificate
of representation shall identify, in a format prescribed by the
Administrator, the entity from whom the unit was purchased or otherwise
obtained (including name, address, telephone number, and facsimile
number (if any)), the date on which the unit was purchased or otherwise
obtained, and the date on which the unit became located at the source.
(2) If the change is the removal of a unit, then the certificate of
representation shall identify, in a format prescribed by the
Administrator, the entity to which the unit was sold or that otherwise
obtained the unit (including name, address, telephone number, and
facsimile number (if any)), the date on which the unit was sold or
otherwise obtained, and the date on which the unit became no longer
located at the source.
Sec. 97.416 Certificate of representation.
(a) A complete certificate of representation for a designated
representative or an alternate designated representative shall include
the following elements in a format prescribed by the Administrator:
(1) Identification of the TR NOX Annual source, and each
TR NOX Annual unit at the source, for which the certificate
of representation is submitted, including source name, source category
and NAICS code (or, in the absence of a NAICS code, an equivalent
code), State, plant code, county, latitude and longitude, unit
identification number and type, identification number and nameplate
capacity (in MWe, rounded to the nearest tenth) of each generator
served by each such unit, actual or projected date of commencement of
commercial operation, and a statement of whether such source is located
in Indian Country. If a projected date of commencement of commercial
operation is provided, the actual date of commencement of commercial
operation shall be provided when such information becomes available.
(2) The name, address, e-mail address (if any), telephone number,
and facsimile transmission number (if any) of the designated
representative and any alternate designated representative.
(3) A list of the owners and operators of the TR NOX
Annual source and of each TR NOX Annual unit at the source.
(4) The following certification statements by the designated
representative and any alternate designated representative--
(i) ``I certify that I was selected as the designated
representative or alternate designated representative, as applicable,
by an agreement binding on the owners and operators of the source and
each TR NOX Annual unit at the source.''
(ii) ``I certify that I have all the necessary authority to carry
out my duties and responsibilities under the TR NOX Annual
Trading Program on behalf of the owners and operators of the source and
of each TR NOX Annual 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 Administrator regarding the source or unit.''
(iii) ``Where there are multiple holders of a legal or equitable
title to, or a leasehold interest in, a TR NOX Annual unit,
or where a utility or industrial customer purchases power from a TR
NOX Annual unit under a life-of-the-unit, firm power
contractual arrangement, I certify that: I have given a written notice
of my selection as the `designated representative' or `alternate
designated representative', as applicable, and of the agreement by
which I was selected to each owner and operator of the source and of
each TR NOX Annual unit at the source; and TR NOX
Annual allowances and proceeds of transactions involving TR
NOX Annual allowances will be deemed to be held or
distributed in proportion to each holder's legal, equitable, leasehold,
or contractual reservation or entitlement, except that, if such
multiple holders have expressly provided for a different distribution
of TR NOX Annual allowances by contract, TR NOX
Annual allowances and proceeds of transactions involving TR
NOX Annual allowances will be deemed to be held or
distributed in accordance with the contract.''
(5) The signature of the designated representative and any
alternate designated representative and the dates signed.
(b) Unless otherwise required by the Administrator, documents of
agreement referred to in the certificate of representation shall not be
submitted to the Administrator. The Administrator shall not be under
any obligation to review or evaluate the sufficiency of such documents,
if submitted.
Sec. 97.417 Objections concerning designated representative and
alternate designated representative.
(a) Once a complete certificate of representation under Sec.
97.416 has been submitted and received, the Administrator will rely on
the certificate of representation unless and until a superseding
complete certificate of representation under Sec. 97.416 is received
by the Administrator.
(b) Except as provided in paragraph (a) of this section, no
objection or other communication submitted to the Administrator
concerning the authorization, or any representation, action, inaction,
or submission, of a designated representative or alternate designated
representative shall affect any representation, action, inaction, or
submission of the designated representative or alternate designated
representative or the finality of any
[[Page 48396]]
decision or order by the Administrator under the TR NOX
Annual Trading Program.
(c) The Administrator will not adjudicate any private legal dispute
concerning the authorization or any representation, action, inaction,
or submission of any designated representative or alternate designated
representative, including private legal disputes concerning the
proceeds of TR NOX Annual allowance transfers.
Sec. 97.418 Delegation by designated representative and alternate
designated representative.
(a) A designated representative may delegate, to one or more
natural persons, his or her authority to make an electronic submission
to the Administrator provided for or required under this subpart.
(b) An alternate designated representative may delegate, to one or
more natural persons, his or her authority to make an electronic
submission to the Administrator provided for or required under this
subpart.
(c) In order to delegate authority to a natural person to make an
electronic submission to the Administrator in accordance with paragraph
(a) or (b) of this section, the designated representative or alternate
designated representative, as appropriate, must submit to the
Administrator a notice of delegation, in a format prescribed by the
Administrator, that includes the following elements:
(1) The name, address, e-mail address, telephone number, and
facsimile transmission number (if any) of such designated
representative or alternate designated representative;
(2) The name, address, e-mail address, telephone number, and
facsimile transmission number (if any) of each such natural person
(referred to in this section as an ``agent'');
(3) For each such natural person, a list of the type or types of
electronic submissions under paragraph (a) or (b) of this section for
which authority is delegated to him or her; and
(4) The following certification statements by such designated
representative or alternate designated representative:
(i) ``I agree that any electronic submission to the Administrator
that is made by an agent identified in this notice of delegation and of
a type listed for such agent in this notice of delegation and that is
made when I am a designated representative or alternate designated
representative, as appropriate, and before this notice of delegation is
superseded by another notice of delegation under 40 CFR 97.418(d) shall
be deemed to be an electronic submission by me.''
(ii) ``Until this notice of delegation is superseded by another
notice of delegation under 40 CFR 97.418(d), I agree to maintain an e-
mail account and to notify the Administrator immediately of any change
in my e-mail address unless all delegation of authority by me under 40
CFR 97.418 is terminated.''.
(d) A notice of delegation submitted under paragraph (c) of this
section shall be effective, with regard to the designated
representative or alternate designated representative identified in
such notice, upon receipt of such notice by the Administrator and until
receipt by the Administrator of a superseding notice of delegation
submitted by such designated representative or alternate designated
representative, as appropriate. The superseding notice of delegation
may replace any previously identified agent, add a new agent, or
eliminate entirely any delegation of authority.
(e) Any electronic submission covered by the certification in
paragraph (c)(4)(i) of this section and made in accordance with a
notice of delegation effective under paragraph (d) of this section
shall be deemed to be an electronic submission by the designated
representative or alternate designated representative submitting such
notice of delegation.
Sec. 97.419 [Reserved]
Sec. 97.420 Establishment of compliance accounts, assurance accounts,
and general accounts.
(a) Compliance accounts. Upon receipt of a complete certificate of
representation under Sec. 97.416, the Administrator will establish a
compliance account for the TR NOX Annual source for which
the certificate of representation was submitted, unless the source
already has a compliance account. The designated representative and any
alternate designated representative of the source shall be the
authorized account representative and the alternate authorized account
representative respectively of the compliance account.
(b) Assurance accounts. The Administrator will establish assurance
accounts for certain owners and operators and States in accordance with
Sec. 97.425(b)(3).
(c) General accounts. (1) Application for general account. (i) Any
person may apply to open a general account, for the purpose of holding
and transferring TR NOX Annual allowances, by submitting to
the Administrator a complete application for a general account. Such
application shall designate one and only one authorized account
representative and may designate one and only one alternate authorized
account representative who may act on behalf of the authorized account
representative.
(A) The authorized account representative and alternate authorized
account representative shall be selected by an agreement binding on the
persons who have an ownership interest with respect to TR
NOX Annual allowances held in the general account.
(B) The agreement by which the alternate authorized account
representative is selected shall include a procedure for authorizing
the alternate authorized account representative to act in lieu of the
authorized account representative.
(ii) A complete application for a general account shall include the
following elements in a format prescribed by the Administrator:
(A) Name, mailing address, e-mail address (if any), telephone
number, and facsimile transmission number (if any) of the authorized
account representative and any alternate authorized account
representative;
(B) An identifying name for the general account;
(C) A list of all persons subject to a binding agreement for the
authorized account representative and any alternate authorized account
representative to represent their ownership interest with respect to
the TR NOX Annual allowances held in the general account;
(D) The following certification statement by the authorized account
representative and any alternate authorized account representative: ``I
certify that I was selected as the authorized account representative or
the alternate authorized account representative, as applicable, by an
agreement that is binding on all persons who have an ownership interest
with respect to TR NOX Annual allowances held in the general
account. I certify that I have all the necessary authority to carry out
my duties and responsibilities under the TR NOX Annual
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 decision or order issued to me by the
Administrator regarding the general account.''
(E) The signature of the authorized account representative and any
alternate authorized account representative and the dates signed.
(iii) Unless otherwise required by the Administrator, documents of
agreement referred to in the application for a
[[Page 48397]]
general account shall not be submitted to the Administrator. The
Administrator shall not be under any obligation to review or evaluate
the sufficiency of such documents, if submitted.
(2) Authorization of authorized account representative and
alternate authorized account representative. (i) Upon receipt by the
Administrator of a complete application for a general account under
paragraph (b)(1) of this section, the Administrator will establish a
general account for the person or persons for whom the application is
submitted, and upon and after such receipt by the Administrator:
(A) The authorized account representative of the general account
shall be authorized and shall represent and, by his or her
representations, actions, inactions, or submissions, legally bind each
person who has an ownership interest with respect to TR NOX
Annual allowances held in the general account in all matters pertaining
to the TR NOX Annual Trading Program, notwithstanding any
agreement between the authorized account representative and such
person.
(B) Any alternate authorized account representative shall be
authorized, and any representation, action, inaction, or submission by
any alternate authorized account representative shall be deemed to be a
representation, action, inaction, or submission by the authorized
account representative.
(C) Each person who has an ownership interest with respect to TR
NOX Annual allowances held in the general account shall be
bound by any decision or order issued to the authorized account
representative or alternate authorized account representative by the
Administrator regarding the general account.
(ii) Except as provided in paragraph (c)(5) of this section
concerning delegation of authority to make submissions, each submission
concerning the general account shall be made, signed, and certified by
the authorized account representative or any alternate authorized
account representative for the persons having an ownership interest
with respect to TR NOX Annual allowances held in the general
account. Each such submission shall include the following certification
statement by the authorized account representative or any alternate
authorized account representative: ``I am authorized to make this
submission on behalf of the persons having an ownership interest with
respect to the TR NOX Annual 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.''
(iii) Except in this section, whenever the term ``authorized
account representative'' is used in this subpart, the term shall be
construed to include the authorized account representative or any
alternate authorized account representative.
(3) Changing authorized account representative and alternate
authorized account representative; changes in persons with ownership
interest. (i) The authorized account representative of 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 (c)(1) of this section. Notwithstanding any such change, all
representations, actions, inactions, and submissions by the previous
authorized account representative before the time and date when the
Administrator receives the superseding application for a general
account shall be binding on the new authorized account representative
and the persons with an ownership interest with respect to the TR
NOX Annual allowances in the general account.
(ii) The alternate authorized account representative of 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 (c)(1) of this section. Notwithstanding any such change, all
representations, actions, inactions, and submissions by the previous
alternate authorized account representative before the time and date
when the Administrator receives the superseding application for a
general account shall be binding on the new alternate authorized
account representative, the authorized account representative, and the
persons with an ownership interest with respect to the TR
NOX Annual allowances in the general account.
(iii)(A) In the event a person having an ownership interest with
respect to TR NOX Annual allowances in the general account
is not included in the list of such persons in the application for a
general account, such person shall be deemed to be subject to and bound
by the application for a general account, the representation, actions,
inactions, and submissions of the authorized account representative and
any alternate authorized account representative of the account, and the
decisions and orders of the Administrator, as if the person were
included in such list.
(B) Within 30 days after any change in the persons having an
ownership interest with respect to NOX Annual allowances in
the general account, including the addition or removal of a person, the
authorized account representative or any alternate 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 TR NOX Annual allowances in the general
account to include the change.
(4) Objections concerning authorized account representative and
alternate authorized account representative. (i) Once a complete
application for a general account under paragraph (c)(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 (c)(4)(i) of this section, no
objection or other communication submitted to the Administrator
concerning the authorization, or any representation, action, inaction,
or submission of the authorized account representative or any alternate
authorized account representative of a general account shall affect any
representation, action, inaction, or submission of the authorized
account representative or any alternate authorized account
representative or the finality of any decision or order by the
Administrator under the TR NOX Annual Trading Program.
(iii) The Administrator will not adjudicate any private legal
dispute concerning the authorization or any representation, action,
inaction, or submission of the authorized account representative or any
alternate authorized account representative of a general account,
including private legal disputes concerning the proceeds of TR
NOX Annual allowance transfers.
(5) Delegation by authorized account representative and alternate
authorized account representative. (i) An authorized account
representative of a general account may delegate, to one or more
natural persons, his or her authority to make an electronic submission
to the Administrator
[[Page 48398]]
provided for or required under this subpart.
(ii) An alternate authorized account representative of a general
account may delegate, to one or more natural persons, his or her
authority to make an electronic submission to the Administrator
provided for or required under this subpart.
(iii) In order to delegate authority to a natural person to make an
electronic submission to the Administrator in accordance with paragraph
(c)(5)(i) or (ii) of this section, the authorized account
representative or alternate authorized account representative, as
appropriate, must submit to the Administrator a notice of delegation,
in a format prescribed by the Administrator, that includes the
following elements:
(A) The name, address, e-mail address, telephone number, and
facsimile transmission number (if any) of such authorized account
representative or alternate authorized account representative;
(B) The name, address, e-mail address, telephone number, and
facsimile transmission number (if any) of each such natural person
(referred to in this section as an ``agent'');
(C) For each such natural person, a list of the type or types of
electronic submissions under paragraph (c)(5)(i) or (ii) of this
section for which authority is delegated to him or her;
(D) The following certification statement by such authorized
account representative or alternate authorized account representative:
``I agree that any electronic submission to the Administrator that is
made by an agent identified in this notice of delegation and of a type
listed for such agent in this notice of delegation and that is made
when I am an authorized account representative or alternate authorized
representative, as appropriate, and before this notice of delegation is
superseded by another notice of delegation under 40 CFR
97.420(c)(5)(iv) shall be deemed to be an electronic submission by
me.''; and
(E) The following certification statement by such authorized
account representative or alternate authorized account representative:
``Until this notice of delegation is superseded by another notice of
delegation under 40 CFR 97.420(c)(5)(iv), I agree to maintain an e-mail
account and to notify the Administrator immediately of any change in my
e-mail address unless all delegation of authority by me under 40 CFR
97.420(c)(5) is terminated.''.
(iv) A notice of delegation submitted under paragraph (c)(5)(iii)
of this section shall be effective, with regard to the authorized
account representative or alternate authorized account representative
identified in such notice, upon receipt of such notice by the
Administrator and until receipt by the Administrator of a superseding
notice of delegation submitted by such authorized account
representative or alternate authorized account representative, as
appropriate. The superseding notice of delegation may replace any
previously identified agent, add a new agent, or eliminate entirely any
delegation of authority.
(v) Any electronic submission covered by the certification in
paragraph (c)(5)(iii)(D) of this section and made in accordance with a
notice of delegation effective under paragraph (c)(5)(iv) of this
section shall be deemed to be an electronic submission by the
designated representative or alternate designated representative
submitting such notice of delegation.
(6) Closing a general account. (i) The authorized account
representative or alternate authorized account representative of a
general account may submit to the Administrator a request to close the
account. Such request shall include a correctly submitted TR
NOX Annual allowance transfer under Sec. 97.422 for any TR
NOX Annual allowances in the account to one or more other
Allowance Management System accounts.
(ii) If a general account has no TR NOX Annual allowance
transfers to or from the account for a 12-month period or longer and
does not contain any TR NOX Annual allowances, the
Administrator may notify the authorized account representative for the
account that the account will be closed after 30 days after the notice
is sent. The account will be closed after the 30-day period unless,
before the end of the 30-day period, the Administrator receives a
correctly submitted TR NOX Annual allowance transfer under
Sec. 97.422 to the account or a statement submitted by the authorized
account representative or alternate authorized account representative
demonstrating to the satisfaction of the Administrator good cause as to
why the account should not be closed.
(d) Account identification. The Administrator will assign a unique
identifying number to each account established under paragraph (a),
(b), or (c) of this section.
(e) Responsibilities of authorized account representative and
alternate authorized account representative. After the establishment of
a compliance account or general account, the Administrator will accept
or act on a submission pertaining to the account, including, but not
limited to, submissions concerning the deduction or transfer of TR
NOX Annual allowances in the account, only if the submission
has been made, signed, and certified in accordance with Sec. Sec.
97.414(a) and 97.418 or paragraphs (c)(2)(ii) and (c)(5) of this
section.
Sec. 97.421 Recordation of TR NOX Annual allowance allocations and
auction results.
(a) By November 7, 2011, the Administrator will record in each TR
NOX Annual source's compliance account the TR NOX
Annual allowances allocated to the TR NOX Annual units at
the source in accordance with Sec. 97.411(a) for the control period in
2012.
(b) By November 7, 2011, the Administrator will record in each TR
NOX Annual source's compliance account the TR NOX
Annual allowances allocated to the TR NOX Annual units at
the source in accordance with Sec. 97.411(a) for the control period in
2013, unless the State in which the source is located notifies the
Administrator in writing by October 17, 2011 of the State's intent to
submit to the Administrator a complete SIP revision by April 1, 2012
meeting the requirements of Sec. 52.38(a)(3)(i) through (iv) of this
chapter.
(1) If, by April 1, 2012, the State does not submit to the
Administrator such complete SIP revision, the Administrator will record
by April 15, 2012 in each TR NOX Annual source's compliance
account the TR NOX Annual allowances allocated to the TR
NOX Annual units at the source in accordance with Sec.
97.411(a) for the control period in 2013.
(2) If the State submits to the Administrator by April 1, 2012, and
the Administrator approves by October 1, 2012, such complete SIP
revision, the Administrator will record by October 1, 2012 in each TR
NOX Annual source's compliance account the TR NOX
Annual allowances allocated to the TR NOX Annual units at
the source as provided in such approved, complete SIP revision for the
control period in 2013.
(3) If the State submits to the Administrator by April 1, 2012, and
the Administrator does not approve by October 1, 2012, such complete
SIP revision, the Administrator will record by October 1, 2012 in each
TR NOX Annual source's compliance account the TR
NOX Annual allowances allocated to the TR NOX
Annual units at the source in accordance with Sec. 97.411(a) for the
control period in 2013.
(c) By July 1, 2013, the Administrator will record in each TR
NOX Annual source's compliance account the TR
[[Page 48399]]
NOX Annual allowances allocated to the TR NOX
Annual units at the source, or in each appropriate Allowance Management
System account the TR NOX Annual allowances auctioned to TR
NOX Annual units, in accordance with Sec. 97.411(a), or
with a SIP revision approved under Sec. 52.38(a)(4) or (5) of this
chapter, for the control period in 2014 and 2015.
(d) By July 1, 2014, the Administrator will record in each TR
NOX Annual source's compliance account the TR NOX
Annual allowances allocated to the TR NOX Annual units at
the source, or in each appropriate Allowance Management System account
the TR NOX Annual allowances auctioned to TR NOX
Annual units, in accordance with Sec. 97.411(a), or with a SIP
revision approved under Sec. 52.38(a)(4) or (5) of this chapter, for
the control period in 2016 and 2017.
(e) By July 1, 2015, the Administrator will record in each TR
NOX Annual source's compliance account the TR NOX
Annual allowances allocated to the TR NOX Annual units at
the source, or in each appropriate Allowance Management System account
the TR NOX Annual allowances auctioned to TR NOX
Annual units, in accordance with Sec. 97.411(a), or with a SIP
revision approved under Sec. 52.38(a)(4) or (5) of this chapter, for
the control period in 2018 and 2019.
(f) By July 1, 2016 and July 1 of each year thereafter, the
Administrator will record in each TR NOX Annual source's
compliance account the TR NOX Annual allowances allocated to
the TR NOX Annual units at the source, or in each
appropriate Allowance Management System account the TR NOX
Annual allowances auctioned to TR NOX Annual units, in
accordance with Sec. 97.411(a), or with a SIP revision approved under
Sec. 52.38(a)(4) or (5) of this chapter, for the control period in the
fourth year after the year of the applicable recordation deadline under
this paragraph.
(g) By August 1, 2012 and August 1 of each year thereafter, the
Administrator will record in each TR NOX Annual source's
compliance account the TR NOX Annual allowances allocated to
the TR NOX Annual units at the source, or in each
appropriate Allowance Management System account the TR NOX
Annual allowances auctioned to TR NOX Annual units, in
accordance with Sec. 97.412(a)(2) through (8) and (12), or with a SIP
revision approved under Sec. 52.38(a)(4) or (5) of this chapter, for
the control period in the year of the applicable recordation deadline
under this paragraph.
(h) By August 1, 2012 and August 1 of each year thereafter, the
Administrator will record in each TR NOX Annual source's
compliance account the TR NOX Annual allowances allocated to
the TR NOX Annual units at the source in accordance with
Sec. 97.412(b)(2) through (8) and (12) for the control period in the
year of the applicable recordation deadline under this paragraph.
(i) By February 15, 2013 and February 15 of each year thereafter,
the Administrator will record in each TR NOX Annual source's
compliance account the TR NOX Annual allowances allocated to
the TR NOX Annual units at the source in accordance with
Sec. 97.412(a)(9) through (12), for the control period in the year
before the year of the applicable recordation deadline under this
paragraph.
(j) By the date on which any allocation or auction results, other
than an allocation or auction results described in paragraphs (a)
through (i) of this section, of TR NOX Annual allowances to
a recipient is made by or are submitted to the Administrator in
accordance with Sec. 97.411 or Sec. 97.412 or with a SIP revision
approved under Sec. 52.38(a)(4) or (5) of this chapter, the
Administrator will record such allocation or auction results in the
appropriate Allowance Management System account.
(k) When recording the allocation or auction of TR NOX
Annual allowances to a TR NOX Annual unit or other entity in
an Allowance Management System account, the Administrator will assign
each TR NOX Annual allowance a unique identification number
that will include digits identifying the year of the control period for
which the TR NOX Annual allowance is allocated or auctioned.
Sec. 97.422 Submission of TR NOX Annual allowance transfers.
(a) An authorized account representative seeking recordation of a
TR NOX Annual allowance transfer shall submit the transfer
to the Administrator.
(b) A TR NOX Annual allowance transfer shall be
correctly submitted if:
(1) The transfer includes the following elements, in a format
prescribed by the Administrator:
(i) The account numbers established by the Administrator for both
the transferor and transferee accounts;
(ii) The serial number of each TR NOX Annual allowance
that is in the transferor account and is to be transferred; and
(iii) The name and signature of the authorized account
representative of the transferor account and the date signed; and
(2) When the Administrator attempts to record the transfer, the
transferor account includes each TR NOX Annual allowance
identified by serial number in the transfer.
Sec. 97.423 Recordation of TR NOX Annual allowance transfers.
(a) Within 5 business days (except as provided in paragraph (b) of
this section) of receiving a TR NOX Annual allowance
transfer that is correctly submitted under Sec. 97.422, the
Administrator will record a TR NOX Annual allowance transfer
by moving each TR NOX Annual allowance from the transferor
account to the transferee account as specified in the transfer.
(b) A TR NOX Annual allowance transfer to or from a
compliance account that is submitted for recordation after the
allowance transfer deadline for a control period and that includes any
TR NOX Annual allowances allocated for any control period
before such allowance transfer deadline will not be recorded until
after the Administrator completes the deductions from such compliance
account under Sec. 97.424 for the control period immediately before
such allowance transfer deadline.
(c) Where a TR NOX Annual allowance transfer is not
correctly submitted under Sec. 97.422, the Administrator will not
record such transfer.
(d) Within 5 business days of recordation of a TR NOX
Annual allowance transfer under paragraphs (a) and (b) of the section,
the Administrator will notify the authorized account representatives of
both the transferor and transferee accounts.
(e) Within 10 business days of receipt of a TR NOX
Annual allowance transfer that is not correctly submitted under Sec.
97.422, the Administrator will notify the 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.
Sec. 97.424 Compliance with TR NOX Annual emissions limitation.
(a) Availability for deduction for compliance. TR NOX
Annual allowances are available to be deducted for compliance with a
source's TR NOX Annual emissions limitation for a control
period in a given year only if the TR NOX Annual allowances:
(1) Were allocated for such control period or a control period in a
prior year; and
[[Page 48400]]
(2) Are held in the source's compliance account as of the allowance
transfer deadline for such control period.
(b) Deductions for compliance. After the recordation, in accordance
with Sec. 97.423, of TR NOX Annual allowance transfers
submitted by the allowance transfer deadline for a control period in a
given year, the Administrator will deduct from each source's compliance
account TR NOX Annual allowances available under paragraph
(a) of this section in order to determine whether the source meets the
TR NOX Annual emissions limitation for such control period,
as follows:
(1) Until the amount of TR NOX Annual allowances
deducted equals the number of tons of total NOX emissions
from all TR NOX Annual units at the source for such control
period; or
(2) If there are insufficient TR NOX Annual allowances
to complete the deductions in paragraph (b)(1) of this section, until
no more TR NOX Annual allowances available under paragraph
(a) of this section remain in the compliance account.
(c)(1) Identification of TR NOX Annual allowances by serial number.
The authorized account representative for a source's compliance account
may request that specific TR NOX Annual allowances,
identified by serial number, in the compliance account be deducted for
emissions or excess emissions for a control period in a given year in
accordance with paragraph (b) or (d) of this section. In order to be
complete, such request shall be submitted to the Administrator by the
allowance transfer deadline for such control period and include, in a
format prescribed by the Administrator, the identification of the TR
NOX Annual source and the appropriate serial numbers.
(2) First-in, first-out. The Administrator will deduct TR
NOX Annual allowances under paragraph (b) or (d) of this
section from the source's compliance account in accordance with a
complete request under paragraph (c)(1) of this section or, in the
absence of such request or in the case of identification of an
insufficient amount of TR NOX Annual allowances in such
request, on a first-in, first-out accounting basis in the following
order:
(i) Any TR NOX Annual allowances that were allocated to
the units at the source and not transferred out of the compliance
account, in the order of recordation; and then
(ii) Any TR NOX Annual allowances that were allocated to
any unit and transferred to and recorded in the compliance account
pursuant to this subpart, in the order of recordation.
(d) Deductions for excess emissions. After making the deductions
for compliance under paragraph (b) of this section for a control period
in a year in which the TR NOX Annual source has excess
emissions, the Administrator will deduct from the source's compliance
account an amount of TR NOX Annual allowances, allocated for
a control period in a prior year or the control period in the year of
the excess emissions or in the immediately following year, equal to two
times the number of tons of the source's excess emissions.
(e) Recordation of deductions. The Administrator will record in the
appropriate compliance account all deductions from such an account
under paragraphs (b) and (d) of this section.
Sec. 97.425 Compliance with TR NOX Annual assurance provisions.
(a) Availability for deduction. TR NOX Annual allowances
are available to be deducted for compliance with the TR NOX
Annual assurance provisions for a control period in a given year by the
owners and operators of a group of one or more TR NOX Annual
sources and units in a State (and Indian country within the borders of
such State) only if the TR NOX Annual allowances:
(1) Were allocated for a control period in a prior year or the
control period in the given year or in the immediately following year;
and
(2) Are held in the assurance account, established by the
Administrator for such owners and operators of such group of TR
NOX Annual sources and units in such State (and Indian
country within the borders of such State) under paragraph (b)(3) of
this section, as of the deadline established in paragraph (b)(4) of
this section.
(b) Deductions for compliance. The Administrator will deduct TR
NOX Annual allowances available under paragraph (a) of this
section for compliance with the TR NOX Annual assurance
provisions for a State for a control period in a given year in
accordance with the following procedures:
(1) By June 1, 2013 and June 1 of each year thereafter, the
Administrator will:
(i) Calculate, for each State (and Indian country within the
borders of such State), the total NOX emissions from all TR
NOX Annual units at TR NOX Annual sources in the
State (and Indian country within the borders of such State) during the
control period in the year before the year of this calculation deadline
and the amount, if any, by which such total NOX emissions
exceed the State assurance level as described in Sec.
97.406(c)(2)(iii); and
(ii) Promulgate a notice of data availability of the results of the
calculations required in paragraph (b)(1)(i) of this section, including
separate calculations of the NOX emissions from each TR
NOX Annual source.
(2) For each notice of data availability required in paragraph
(b)(1)(ii) of this section and for any State (and Indian country within
the borders of such State) identified in such notice as having TR
NOX Annual units with total NOX emissions
exceeding the State assurance level for a control period in a given
year, as described in Sec. 97.406(c)(2)(iii):
(i) By July 1 immediately after the promulgation of such notice,
the designated representative of each TR NOX Annual source
in each such State (and Indian country within the borders of such
State) shall submit a statement, in a format prescribed by the
Administrator, providing for each TR NOX Annual unit (if
any) at the source that operates during, but is not allocated an amount
of TR NOX Annual allowances for, such control period, the
unit's allowable NOX emission rate for such control period
and, if such rate is expressed in lb per mmBtu, the unit's heat rate.
(ii) By August 1 immediately after the promulgation of such notice,
the Administrator will calculate, for each such State (and Indian
country within the borders of such State) and such control period and
each common designated representative for such control period for a
group of one or more TR NOX Annual sources and units in the
State (and Indian country within the borders of such State), the common
designated representative's share of the total NOX emissions
from all TR NOX Annual units at TR NOX Annual
sources in the State (and Indian country within the borders of such
State), the common designated representative's assurance level, and the
amount (if any) of TR NOX Annual allowances that the owners
and operators of such group of sources and units must hold in
accordance with the calculation formula in Sec. 97.406(c)(2)(i) and
will promulgate a notice of data availability of the results of these
calculations.
(iii) The Administrator will provide an opportunity for submission
of objections to the calculations referenced by the notice of data
availability required in paragraph (b)(2)(ii) of this section and the
calculations referenced by the relevant notice of data availability
required in paragraph (b)(1)(i) of this section.
(A) Objections shall be submitted by the deadline specified in such
notice
[[Page 48401]]
and shall be limited to addressing whether the calculations referenced
in the relevant notice required under paragraph (b)(1)(ii) of this
section and referenced in the notice required under paragraph
(b)(2)(ii) of this section are in accordance with Sec.
97.406(c)(2)(iii), Sec. Sec. 97.406(b) and 97.430 through 97.435, the
definitions of ``common designated representative'', ``common
designated representative's assurance level'', and ``common designated
representative's share'' in Sec. 97.402, and the calculation formula
in Sec. 97.406(c)(2)(i).
(B) The Administrator will adjust the calculations to the extent
necessary to ensure that they are in accordance with the provisions
referenced in paragraph (b)(2)(iii)(A) of this section. By October 1
immediately after the promulgation of such notice, the Administrator
will promulgate a notice of data availability of any adjustments that
the Administrator determines to be necessary and the reasons for
accepting or rejecting any objections submitted in accordance with
paragraph (b)(2)(iii)(A) of this section.
(3) For any State (and Indian country within the borders of such
State) referenced in each notice of data availability required in
paragraph (b)(2)(iii)(B) of this section as having TR NOX
Annual units with total NOX emissions exceeding the State
assurance level for a control period in a given year, the Administrator
will establish one assurance account for each set of owners and
operators referenced, in the notice of data availability required under
paragraph (b)(2)(iii)(B) of this section, as all of the owners and
operators of a group of TR NOX Annual sources and units in
the State (and Indian country within the borders of such State) having
a common designated representative for such control period and as being
required to hold TR NOX Annual allowances.
(4)(i) As of midnight of November 1 immediately after the
promulgation of each notice of data availability required in paragraph
(b)(2)(iii)(B) of this section, the owners and operators described in
paragraph (b)(3) of this section shall hold in the assurance account
established for the them and for the appropriate TR NOX
Annual sources, TR NOX Annual units, and State (and Indian
country within the borders of such State) under paragraph (b)(3) of
this section a total amount of TR NOX Annual allowances,
available for deduction under paragraph (a) of this section, equal to
the amount such owners and operators are required to hold with regard
to such sources, units and State (and Indian country within the borders
of such State) as calculated by the Administrator and referenced in
such notice.
(ii) Notwithstanding the allowance-holding deadline specified in
paragraph (b)(4)(i) of this section, if November 1 is not a business
day, then such allowance-holding deadline shall be midnight of the
first business day thereafter.
(5) After November 1 (or the date described in paragraph (b)(4)(ii)
of this section) immediately after the promulgation of each notice of
data availability required in paragraph (b)(2)(iii)(B) of this section
and after the recordation, in accordance with Sec. 97.423, of TR
NOX Annual allowance transfers submitted by midnight of such
date, the Administrator will determine whether the owners and operators
described in paragraph (b)(3) of this section hold, in the assurance
account for the appropriate TR NOX Annual sources, TR
NOX Annual units, and State (and Indian country within the
borders of such State) established under paragraph (b)(3) of this
section, the amount of TR NOX Annual allowances available
under paragraph (a) of this section that the owners and operators are
required to hold with regard to such sources, units, and State (and
Indian country within the borders of such State) as calculated by the
Administrator and referenced in the notice required in paragraph
(b)(2)(iii)(B) of this section.
(6) Notwithstanding any other provision of this subpart and any
revision, made by or submitted to the Administrator after the
promulgation of the notice of data availability required in paragraph
(b)(2)(iii)(B) of this section for a control period in a given year, of
any data used in making the calculations referenced in such notice, the
amounts of TR NOX Annual allowances that the owners and
operators are required to hold in accordance with Sec. 97.406(c)(2)(i)
for such control period shall continue to be such amounts as calculated
by the Administrator and referenced in such notice required in
paragraph (b)(2)(iii)(B) of this section, except as follows:
(i) If any such data are revised by the Administrator as a result
of a decision in or settlement of litigation concerning such data on
appeal under part 78 of this chapter of such notice, or on appeal under
section 307 of the Clean Air Act of a decision rendered under part 78
of this chapter on appeal of such notice, then the Administrator will
use the data as so revised to recalculate the amounts of TR
NOX Annual allowances that owners and operators are required
to hold in accordance with the calculation formula in Sec.
97.406(c)(2)(i) for such control period with regard to the TR
NOX Annual sources, TR NOX Annual units, and
State (and Indian country within the borders of such State) involved,
provided that such litigation under part 78 of this chapter, or the
proceeding under part 78 of this chapter that resulted in the decision
appealed in such litigation under section 307 of the Clean Air Act, was
initiated no later than 30 days after promulgation of such notice
required in paragraph (b)(2)(iii)(B) of this section.
(ii) If any such data are revised by the owners and operators of a
TR NOX Annual source and TR NOX Annual unit whose
designated representative submitted such data under paragraph (b)(2)(i)
of this section, as a result of a decision in or settlement of
litigation concerning such submission, then the Administrator will use
the data as so revised to recalculate the amounts of TR NOX
Annual allowances that owners and operators are required to hold in
accordance with the calculation formula in Sec. 97.406(c)(2)(i) for
such control period with regard to the TR NOX Annual
sources, TR NOX Annual units, and State (and Indian country
within the borders of such State) involved, provided that such
litigation was initiated no later than 30 days after promulgation of
such notice required in paragraph (b)(2)(iii)(B) of this section.
(iii) If the revised data are used to recalculate, in accordance
with paragraphs (b)(6)(i) and (ii) of this section, the amount of TR
NOX Annual allowances that the owners and operators are
required to hold for such control period with regard to the TR
NOX Annual sources, TR NOX Annual units, and
State (and Indian country within the borders of such State) involved--
(A) Where the amount of TR NOX Annual allowances that
the owners and operators are required to hold increases as a result of
the use of all such revised data, the Administrator will establish a
new, reasonable deadline on which the owners and operators shall hold
the additional amount of TR NOX Annual allowances in the
assurance account established by the Administrator for the appropriate
TR NOX Annual sources, TR NOX Annual units, and
State (and Indian country within the borders of such State) under
paragraph (b)(3) of this section. The owners' and operators' failure to
hold such additional amount, as required, before the new deadline shall
not be a violation of the Clean Air Act. The owners' and operators'
failure to hold such additional amount, as required, as of the new
deadline shall be a violation of the Clean Air Act. Each
[[Page 48402]]
TR NOX Annual allowance that the owners and operators fail
to hold as required as of the new deadline, and each day in such
control period, shall be a separate violation of the Clean Air Act.
(B) For the owners and operators for which the amount of TR
NOX Annual allowances required to be held decreases as a
result of the use of all such revised data, the Administrator will
record, in all accounts from which TR NOX Annual allowances
were transferred by such owners and operators for such control period
to the assurance account established by the Administrator for the
appropriate at TR NOX Annual sources, TR NOX
Annual units, and State (and Indian country within the borders of such
State) under paragraph (b)(3) of this section, a total amount of the TR
NOX Annual allowances held in such assurance account equal
to the amount of the decrease. If TR NOX Annual allowances
were transferred to such assurance account from more than one account,
the amount of TR NOX Annual allowances recorded in each such
transferor account will be in proportion to the percentage of the total
amount of TR NOX Annual allowances transferred to such
assurance account for such control period from such transferor account.
(C) Each TR NOX Annual allowance held under paragraph
(b)(6)(iii)(A) of this section as a result of recalculation of
requirements under the TR NOX Annual assurance provisions
for such control period must be a TR NOX Annual allowance
allocated for a control period in a year before or the year immediately
following, or in the same year as, the year of such control period.
Sec. 97.426 Banking.
(a) A TR NOX Annual allowance may be banked for future
use or transfer in a compliance account or a general account in
accordance with paragraph (b) of this section.
(b) Any TR NOX Annual allowance that is held in a
compliance account or a general account will remain in such account
unless and until the TR NOX Annual allowance is deducted or
transferred under Sec. 97.411(c), Sec. 97.423, Sec. 97.424, Sec.
97.425, 97.427, or 97.428.
Sec. 97.427 Account error.
The Administrator may, at his or her sole discretion and on his or
her own motion, correct any error in any Allowance Management System
account. Within 10 business days of making such correction, the
Administrator will notify the authorized account representative for the
account.
Sec. 97.428 Administrator's action on submissions.
(a) The Administrator may review and conduct independent audits
concerning any submission under the TR NOX Annual Trading
Program and make appropriate adjustments of the information in the
submission.
(b) The Administrator may deduct TR NOX Annual
allowances from or transfer TR NOX Annual allowances to a
compliance account or an assurance account, based on the information in
a submission, as adjusted under paragraph (a)(1) of this section, and
record such deductions and transfers.
Sec. 97.429 [Reserved]
Sec. 97.430 General monitoring, recordkeeping, and reporting
requirements.
The owners and operators, and to the extent applicable, the
designated representative, of a TR NOX Annual unit, shall
comply with the monitoring, recordkeeping, and reporting requirements
as provided in this subpart and subpart H of part 75 of this chapter.
For purposes of applying such requirements, the definitions in Sec.
97.402 and in Sec. 72.2 of this chapter shall apply, the terms
``affected unit,'' ``designated representative,'' and ``continuous
emission monitoring system'' (or ``CEMS'') in part 75 of this chapter
shall be deemed to refer to the terms ``TR NOX Annual
unit,'' ``designated representative,'' and ``continuous emission
monitoring system'' (or ``CEMS'') respectively as defined in Sec.
97.402, and the term ``newly affected unit'' shall be deemed to mean
``newly affected TR NOX Annual unit''. The owner or operator
of a unit that is not a TR NOX Annual unit but that is
monitored under Sec. 75.72(b)(2)(ii) of this chapter shall comply with
the same monitoring, recordkeeping, and reporting requirements as a TR
NOX Annual unit.
(a) Requirements for installation, certification, and data
accounting. The owner or operator of each TR NOX Annual unit
shall:
(1) Install all monitoring systems required under this subpart for
monitoring NOX mass emissions and individual unit heat input
(including all systems required to monitor NOX emission
rate, NOX concentration, stack gas moisture content, stack
gas flow rate, CO2 or O2 concentration, and fuel
flow rate, as applicable, in accordance with Sec. Sec. 75.71 and 75.72
of this chapter);
(2) Successfully complete all certification tests required under
Sec. 97.431 and meet all other requirements of this subpart and part
75 of this chapter applicable to the monitoring systems under paragraph
(a)(1) of this section; and
(3) Record, report, and quality-assure the data from the monitoring
systems under paragraph (a)(1) of this section.
(b) Compliance deadlines. Except as provided in paragraph (e) of
this section, the owner or operator shall meet the monitoring system
certification and other requirements of paragraphs (a)(1) and (2) of
this section on or before the following dates and shall record, report,
and quality-assure the data from the monitoring systems under paragraph
(a)(1) of this section on and after the following dates.
(1) For the owner or operator of a TR NOX Annual unit
that commences commercial operation before July 1, 2011, January 1,
2012;
(2) For the owner or operator of a TR NOX Annual unit
that commences commercial operation on or after July 1, 2011, the later
of the following:
(i) January 1, 2012; or
(ii) 180 calendar days after the date on which the unit commences
commercial operation;
(3) The owner or operator of a TR NOX Annual unit for
which construction of a new stack or flue or installation of add-on
NOX emission controls is completed after the applicable
deadline under paragraph (b)(1) or (2) of this section shall meet the
requirements of Sec. Sec. 75.4(e)(1) through (e)(4) of this chapter,
except that:
(i) Such requirements shall apply to the monitoring systems
required under Sec. 97.430 through Sec. 97.435, rather than the
monitoring systems required under part 75 of this chapter;
(ii) NOX emission rate, NOX concentration,
stack gas moisture content, stack gas volumetric flow rate, and
O2 or CO2 concentration data shall be determined
and reported, rather than the data listed in Sec. 75.4(e)(2) of this
chapter; and
(iii) Any petition for another procedure under Sec. 75.4(e)(2) of
this chapter shall be submitted under Sec. 97.435, rather than Sec.
75.66.
(c) Reporting data. The owner or operator of a TR NOX
Annual unit that does not meet the applicable compliance date set forth
in paragraph (b) of this section for any monitoring system under
paragraph (a)(1) of this section shall, for each such monitoring
system, determine, record, and report maximum potential (or, as
appropriate, minimum potential) values for NOX
concentration, NOX emission rate, stack gas flow rate, stack
gas moisture content, fuel flow rate, and any other parameters required
to determine NOX mass emissions and heat input in accordance
with Sec. 75.31(b)(2) or (c)(3) of
[[Page 48403]]
this chapter, section 2.4 of appendix D to part 75 of this chapter, or
section 2.5 of appendix E to part 75 of this chapter, as applicable.
(d) Prohibitions. (1) No owner or operator of a TR NOX
Annual unit shall use any alternative monitoring system, alternative
reference method, or any other alternative to any requirement of this
subpart without having obtained prior written approval in accordance
with Sec. 97.435.
(2) No owner or operator of a TR NOX Annual unit shall
operate the unit so as to discharge, or allow to be discharged,
NOX to the atmosphere without accounting for all such
NOX in accordance with the applicable provisions of this
subpart and part 75 of this chapter.
(3) No owner or operator of a TR NOX Annual unit shall
disrupt the continuous emission monitoring system, any portion thereof,
or any other approved emission monitoring method, and thereby avoid
monitoring and recording NOX mass discharged into the
atmosphere or heat input, except for periods of recertification or
periods when calibration, quality assurance testing, or maintenance is
performed in accordance with the applicable provisions of this subpart
and part 75 of this chapter.
(4) No owner or operator of a TR NOX Annual unit shall
retire or permanently discontinue use of the continuous emission
monitoring system, any component thereof, or any other approved
monitoring system under this subpart, except under any one of the
following circumstances:
(i) During the period that the unit is covered by an exemption
under Sec. 97.405 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 Administrator 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 designated representative submits notification of the
date of certification testing of a replacement monitoring system for
the retired or discontinued monitoring system in accordance with Sec.
97.431(d)(3)(i).
(e) Long-term cold storage. The owner or operator of a TR
NOX Annual unit is subject to the applicable provisions of
Sec. 75.4(d) of this chapter concerning units in long-term cold
storage.
Sec. 97.431 Initial monitoring system certification and
recertification procedures.
(a) The owner or operator of a TR NOX Annual unit shall
be exempt from the initial certification requirements of this section
for a monitoring system under Sec. 97.430(a)(1) if the following
conditions are met:
(1) The monitoring system has been previously certified in
accordance with part 75 of this chapter; and
(2) The applicable quality-assurance and quality-control
requirements of Sec. 75.21 of this chapter and appendices B, D, and E
to part 75 of this chapter are fully met for the certified monitoring
system described in paragraph (a)(1) of this section.
(b) The recertification provisions of this section shall apply to a
monitoring system under Sec. 97.430(a)(1) that is exempt from initial
certification requirements under paragraph (a) of this section.
(c) If the Administrator has previously 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. 75.12 or Sec. 75.17 of this chapter, the designated
representative shall resubmit the petition to the Administrator under
Sec. 97.435 to determine whether the approval applies under the TR
NOX Annual Trading Program.
(d) Except as provided in paragraph (a) of this section, the owner
or operator of a TR NOX Annual unit shall comply with the
following initial certification and recertification procedures for a
continuous monitoring system (i.e., a continuous emission monitoring
system and an excepted monitoring system under appendices D and E to
part 75 of this chapter) under Sec. 97.430(a)(1). The owner or
operator of a unit that qualifies to use the low mass emissions
excepted monitoring methodology under Sec. 75.19 of this chapter or
that qualifies to use an alternative monitoring system under subpart E
of part 75 of this chapter shall comply with the procedures in
paragraph (e) or (f) of this section respectively.
(1) Requirements for initial certification. The owner or operator
shall ensure that each continuous monitoring system under Sec.
97.430(a)(1) (including the automated data acquisition and handling
system) successfully completes all of the initial certification testing
required under Sec. 75.20 of this chapter by the applicable deadline
in Sec. 97.430(b). In addition, whenever the owner or operator
installs a monitoring system to meet the requirements of this subpart
in a location where no such monitoring system was previously installed,
initial certification in accordance with Sec. 75.20 of this chapter is
required.
(2) Requirements for recertification. Whenever the owner or
operator makes a replacement, modification, or change in any certified
continuous emission monitoring system under Sec. 97.430(a)(1) that may
significantly affect the ability of the system to accurately measure or
record NOX mass emissions or heat input rate or to meet the
quality-assurance and quality-control 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 in accordance with 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 may significantly change the stack
flow or concentration profile, the owner or operator shall recertify
each continuous emission monitoring system whose accuracy is
potentially affected by the change, in accordance with Sec. 75.20(b)
of this chapter. Examples of changes to a continuous emission
monitoring system that require recertification include replacement of
the analyzer, complete replacement of an existing continuous emission
monitoring system, or change in location or orientation of the sampling
probe or site. Any fuel flowmeter system, and any excepted
NOX monitoring system under appendix E to part 75 of this
chapter, under Sec. 97.430(a)(1) are subject to the recertification
requirements in Sec. 75.20(g)(6) of this chapter.
(3) Approval process for initial certification and recertification.
For initial certification of a continuous monitoring system under Sec.
97.430(a)(1), paragraphs (d)(3)(i) through (v) of this section apply.
For recertifications of such monitoring systems, paragraphs (d)(3)(i)
through (iv) of this section and the procedures in Sec. Sec.
75.20(b)(5) and (g)(7) of this chapter (in lieu of the procedures in
paragraph (d)(3)(v) of this section) apply, provided that in applying
paragraphs (d)(3)(i) through (iv) of this section, the words
``certification'' and ``initial certification'' are replaced by the
word ``recertification'' and the word ``certified'' is replaced by with
the word ``recertified''.
(i) Notification of certification. The designated representative
shall submit to the appropriate EPA Regional Office and the
Administrator written notice of the dates of certification testing, in
accordance with Sec. 97.433.
[[Page 48404]]
(ii) Certification application. The designated representative shall
submit to the Administrator a certification application for each
monitoring system. A complete certification application shall include
the information specified in Sec. 75.63 of this chapter.
(iii) Provisional certification date. The provisional certification
date for a monitoring system shall be determined in accordance with
Sec. 75.20(a)(3) of this chapter. A provisionally certified monitoring
system may be used under the TR NOX Annual Trading Program
for a period not to exceed 120 days after receipt by the Administrator
of the complete certification application for the monitoring system
under paragraph (d)(3)(ii) of this section. Data measured and recorded
by the provisionally certified monitoring system, in accordance with
the requirements of part 75 of this chapter, will be considered valid
quality-assured data (retroactive to the date and time of provisional
certification), provided that the Administrator does not invalidate the
provisional certification by issuing a notice of disapproval within 120
days of the date of receipt of the complete certification application
by the Administrator.
(iv) Certification application approval process. The Administrator
will issue a written notice of approval or disapproval of the
certification application to the owner or operator within 120 days of
receipt of the complete certification application under paragraph
(d)(3)(ii) of this section. In the event the Administrator does not
issue such a notice within such 120-day period, each monitoring system
that 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 TR NOX Annual Trading Program.
(A) Approval notice. If the certification application is complete
and shows that each monitoring system meets the applicable performance
requirements of part 75 of this chapter, then the Administrator will
issue a written notice of approval of the certification application
within 120 days of receipt.
(B) Incomplete application notice. If the certification application
is not complete, then the Administrator will issue a written notice of
incompleteness that sets a reasonable date by which the designated
representative must submit the additional information required to
complete the certification application. If the designated
representative does not comply with the notice of incompleteness by the
specified date, then the Administrator may issue a notice of
disapproval under paragraph (d)(3)(iv)(C) of this section.
(C) Disapproval notice. If the certification application shows that
any monitoring system does not meet the performance requirements of
part 75 of this chapter or if the certification application is
incomplete and the requirement for disapproval under paragraph
(d)(3)(iv)(B) of this section is met, then the Administrator will issue
a written notice of disapproval of the certification application. Upon
issuance of such notice of disapproval, the provisional certification
is invalidated by the Administrator and the data measured and recorded
by each uncertified monitoring system shall not be considered valid
quality-assured data beginning with the date and hour of provisional
certification (as defined under Sec. 75.20(a)(3) of this chapter).
(D) Audit decertification. The Administrator may issue a notice of
disapproval of the certification status of a monitor in accordance with
Sec. 97.432(b).
(v) Procedures for loss of certification. If the Administrator
issues a notice of disapproval of a certification application under
paragraph (d)(3)(iv)(C) of this section or a notice of disapproval of
certification status under paragraph (d)(3)(iv)(D) of this section,
then:
(A) The owner or operator shall substitute the following values,
for each disapproved monitoring system, for each hour of unit operation
during the period of invalid data specified under Sec.
75.20(a)(4)(iii), Sec. 75.20(g)(7), or Sec. 75.21(e) of this chapter
and continuing until the applicable date and hour specified under Sec.
75.20(a)(5)(i) or (g)(7) of this chapter:
(1) For a disapproved NOX emission rate (i.e.,
NOX-diluent) system, the maximum potential NOX
emission rate, as defined in Sec. 72.2 of this chapter.
(2) For a disapproved NOX pollutant concentration
monitor and disapproved flow monitor, respectively, the maximum
potential concentration of NOX and the maximum potential
flow rate, as defined in sections 2.1.2.1 and 2.1.4.1 of appendix A to
part 75 of this chapter.
(3) For a disapproved moisture monitoring system and disapproved
diluent gas monitoring system, respectively, the minimum potential
moisture percentage and either the maximum potential CO2
concentration or the minimum potential O2 concentration (as
applicable), as defined in sections 2.1.5, 2.1.3.1, and 2.1.3.2 of
appendix A to part 75 of this chapter.
(4) For a disapproved fuel flowmeter system, the maximum potential
fuel flow rate, as defined in section 2.4.2.1 of appendix D to part 75
of this chapter.
(5) For a disapproved excepted NOX monitoring system
under appendix E to part 75 of this chapter, the fuel-specific maximum
potential NOX emission rate, as defined in Sec. 72.2 of
this chapter.
(B) The designated representative shall submit a notification of
certification retest dates and a new certification application in
accordance with paragraphs (d)(3)(i) and (ii) of this section.
(C) The owner or operator shall repeat all certification tests or
other requirements that were failed by the monitoring system, as
indicated in the Administrator's notice of disapproval, no later than
30 unit operating days after the date of issuance of the notice of
disapproval.
(e) The owner or operator of a unit qualified to use the low mass
emissions (LME) excepted methodology under Sec. 75.19 of this chapter
shall meet the applicable certification and recertification
requirements in Sec. Sec. 75.19(a)(2) and 75.20(h) of this chapter. If
the owner or operator of such a unit elects to certify a fuel flowmeter
system for heat input determination, the owner or operator shall also
meet the certification and recertification requirements in Sec.
75.20(g) of this chapter.
(f) The designated representative of each unit for which the owner
or operator intends to use an alternative monitoring system approved by
the Administrator under subpart E of part 75 of this chapter shall
comply with the applicable notification and application procedures of
Sec. 75.20(f) of this chapter.
Sec. 97.432 Monitoring system out-of-control periods.
(a) General provisions. Whenever any monitoring system fails to
meet the quality-assurance and quality-control requirements or data
validation requirements of part 75 of this chapter, data shall be
substituted using the applicable missing data procedures in subpart D
or subpart H of, or appendix D or appendix E to, 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 monitoring system should not have been
certified or recertified because it did not meet a particular
performance specification or other requirement under Sec. 97.431 or
the applicable provisions of part 75 of this chapter, both at the time
of the initial certification or
[[Page 48405]]
recertification application submission and at the time of the audit,
the Administrator will issue a notice of disapproval of the
certification status of such monitoring system. For the purposes of
this paragraph, an audit shall be either a field audit or an audit of
any information submitted to the Administrator or any State or
permitting authority. By issuing the notice of disapproval, the
Administrator revokes prospectively the certification status of the
monitoring system. The data measured and recorded by the monitoring
system 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
for the monitoring system. The owner or operator shall follow the
applicable initial certification or recertification procedures in Sec.
97.431 for each disapproved monitoring system.
Sec. 97.433 Notifications concerning monitoring.
The designated representative of a TR NOX Annual unit
shall submit written notice to the Administrator in accordance with
Sec. 75.61 of this chapter.
Sec. 97.434 Recordkeeping and reporting.
(a) General provisions. The designated representative shall comply
with all recordkeeping and reporting requirements in paragraphs (b)
through (e) of this section, the applicable recordkeeping and reporting
requirements under Sec. 75.73 of this chapter, and the requirements of
Sec. 97.414(a).
(b) Monitoring plans. The owner or operator of a TR NOX
Annual unit shall comply with requirements of Sec. 75.73(c) and (e) of
this chapter.
(c) Certification applications. The designated representative shall
submit an application to the Administrator within 45 days after
completing all initial certification or recertification tests required
under Sec. 97.431, including the information required under Sec.
75.63 of this chapter.
(d) Quarterly reports. The designated representative shall submit
quarterly reports, as follows:
(1) The designated representative shall report the NOX
mass emissions data and heat input data for the TR NOX
Annual unit, in an electronic quarterly report in a format prescribed
by the Administrator, for each calendar quarter beginning with:
(i) For a unit that commences commercial operation before July 1,
2011, the calendar quarter covering January 1, 2012 through March 31,
2012; or
(ii) For a unit that commences commercial operation on or after
July 1, 2011, the calendar quarter corresponding to the earlier of the
date of provisional certification or the applicable deadline for
initial certification under Sec. 97.430(b), unless that quarter is the
third or fourth quarter of 2011, in which case reporting shall commence
in the quarter covering January 1, 2012 through March 31, 2012.
(2) The designated representative shall submit each quarterly
report to the Administrator within 30 days after the end of the
calendar quarter covered by the report. Quarterly reports shall be
submitted in the manner specified in Sec. 75.73(f) of this chapter.
(3) For TR NOX Annual units that are also subject to the
Acid Rain Program, TR NOX Ozone Season Trading Program, TR
SO2 Group 1 Trading Program, or TR SO2 Group 2
Trading Program, quarterly reports shall include the applicable data
and information required by subparts F through H of part 75 of this
chapter as applicable, in addition to the NOX mass emission
data, heat input data, and other information required by this subpart.
(4) The Administrator may review and conduct independent audits of
any quarterly report in order to determine whether the quarterly report
meets the requirements of this subpart and part 75 of this chapter,
including the requirement to use substitute data.
(i) The Administrator will notify the designated representative of
any determination that the quarterly report fails to meet any such
requirements and specify in such notification any corrections that the
Administrator believes are necessary to make through resubmission of
the quarterly report and a reasonable time period within which the
designated representative must respond. Upon request by the designated
representative, the Administrator may specify reasonable extensions of
such time period. Within the time period (including any such
extensions) specified by the Administrator, the designated
representative shall resubmit the quarterly report with the corrections
specified by the Administrator, except to the extent the designated
representative provides information demonstrating that a specified
correction is not necessary because the quarterly report already meets
the requirements of this subpart and part 75 of this chapter that are
relevant to the specified correction.
(ii) Any resubmission of a quarterly report shall meet the
requirements applicable to the submission of a quarterly report under
this subpart and part 75 of this chapter, except for the deadline set
forth in paragraph (d)(2) of this section.
(e) Compliance certification. The designated representative shall
submit to the Administrator a compliance certification (in a format
prescribed by the Administrator) in support of each quarterly report
based on reasonable inquiry of those persons with primary
responsibility for ensuring that all of the unit's emissions are
correctly and fully monitored. The certification shall state that:
(1) 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
(2) For a unit with add-on NOX emission controls and for
all hours where NOX 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 quality
assurance/quality control program under appendix B to part 75 of this
chapter and the substitute data values do not systematically
underestimate NOX emissions.
Sec. 97.435 Petitions for alternatives to monitoring, recordkeeping,
or reporting requirements.
(a) The designated representative of a TR NOX Annual
unit may submit a petition under Sec. 75.66 of this chapter to the
Administrator, requesting approval to apply an alternative to any
requirement of Sec. Sec. 97.430 through 97.434.
(b) A petition submitted under paragraph (a) of this section shall
include sufficient information for the evaluation of the petition,
including, at a minimum, the following information:
(i) Identification of each unit and source covered by the petition;
(ii) A detailed explanation of why the proposed alternative is
being suggested in lieu of the requirement;
(iii) A description and diagram of any equipment and procedures
used in the proposed alternative;
(iv) A demonstration that the proposed alternative is consistent
with the purposes of the requirement for which the alternative is
proposed and with the purposes of this subpart and part 75 of this
chapter and that any adverse effect of approving the alternative will
be de minimis; and
[[Page 48406]]
(v) Any other relevant information that the Administrator may
require.
(c) Use of an alternative to any requirement referenced in
paragraph (a) of this section is in accordance with this subpart only
to the extent that the petition is approved in writing by the
Administrator and that such use is in accordance with such approval.
0
75. Part 97 is amended by adding subpart BBBBB to read as follows:
Subpart BBBBB--TR NOX Ozone Season Trading Program
97.501 Purpose.
97.502 Definitions.
97.503 Measurements, abbreviations, and acronyms.
97.504 Applicability.
97.505 Retired unit exemption.
97.506 Standard requirements.
97.507 Computation of time.
97.508 Administrative appeal procedures.
97.509 [Reserved]
97.510 State NOX Ozone Season trading budgets, new unit
set-asides, Indian country new unit set-asides and variability
limits.
97.511 Timing requirements for TR NOX Ozone Season
allowance allocations.
97.512 TR NOX Ozone Season allowance allocations to new
units.
97.513 Authorization of designated representative and alternate
designated representative.
97.514 Responsibilities of designated representative and alternate
designated representative.
97.515 Changing designated representative and alternate designated
representative; changes in owners and operators.
97.516 Certificate of representation.
97.517 Objections concerning designated representative and alternate
designated representative.
97.518 Delegation by designated representative and alternate
designated representative.
97.519 [Reserved]
97.520 Establishment of compliance accounts and general accounts.
97.521 Recordation of TR NOX Ozone Season allowance
allocations.
97.522 Submission of TR NOX Ozone Season allowance
transfers.
97.523 Recordation of TR NOX Ozone Season allowance
transfers.
97.524 Compliance with TR NOX Ozone Season emissions
limitation.
97.525 Compliance with TR NOX Ozone Season assurance
provisions.
97.526 Banking.
97.527 Account error.
97.528 Administrator's action on submissions.
97.529 [RESERVED]
97.530 General monitoring, recordkeeping, and reporting
requirements.
97.531 Initial monitoring system certification and recertification
procedures.
97.532 Monitoring system out-of-control periods.
97.533 Notifications concerning monitoring.
97.534 Recordkeeping and reporting.
97.535 Petitions for alternatives to monitoring, recordkeeping, or
reporting requirements.
Subpart BBBBB--TR NOX Ozone Season Trading Program
Sec. 97.501 Purpose.
This subpart sets forth the general, designated representative,
allowance, and monitoring provisions for the Transport Rule (TR)
NOX Ozone Season Trading Program, under section 110 of the
Clean Air Act and Sec. 52.38 of this chapter, as a means of mitigating
interstate transport of ozone and nitrogen oxides.
Sec. 97.502 Definitions.
The terms used in this subpart shall have the meanings set forth in
this section as follows:
Acid Rain Program means a multi-state SO2 and
NOX air pollution control and emission reduction program
established by the Administrator under title IV of the Clean Air Act
and parts 72 through 78 of this chapter.
Administrator means the Administrator of the United States
Environmental Protection Agency or the Director of the Clean Air
Markets Division (or its successor determined by the Administrator) of
the United States Environmental Protection Agency, the Administrator's
duly authorized representative under this subpart.
Allocate or allocation means, with regard to TR NOX
Ozone Season allowances, the determination by the Administrator, State,
or permitting authority, in accordance with this subpart and any SIP
revision submitted by the State and approved by the Administrator under
Sec. 52.38(b)(3), (4), or (5) of this chapter, of the amount of such
TR NOX Ozone Season allowances to be initially credited, at
no cost to the recipient, to:
(1) A TR NOX Ozone Season unit;
(2) A new unit set-aside;
(3) An Indian country new unit set-aside; or
(4) An entity not listed in paragraphs (1) through (3) of this
definition;
(5) Provided that, if the Administrator, State, or permitting
authority initially credits, to a TR NOX Ozone Season unit
qualifying for an initial credit, a credit in the amount of zero TR
NOX Ozone Season allowances, the TR NOX Ozone
Season unit will be treated as being allocated an amount (i.e., zero)
of TR NOX Ozone Season allowances.
Allowable NOX emission rate means, for a unit, the most stringent
State or federal NOX emission rate limit (in lb/MWhr or, if
in lb/mmBtu, converted to lb/MWhr by multiplying it by the unit's heat
rate in mmBtu/MWhr) that is applicable to the unit and covers the
longest averaging period not exceeding one year.
Allowance Management System means the system by which the
Administrator records allocations, deductions, and transfers of TR
NOX Ozone Season allowances under the TR NOX
Ozone Season Trading Program. Such allowances are allocated, recorded,
held, deducted, or transferred only as whole allowances.
Allowance Management System account means an account in the
Allowance Management System established by the Administrator for
purposes of recording the allocation, holding, transfer, or deduction
of TR NOX Ozone Season allowances.
Allowance transfer deadline means, for a control period in a given
year, midnight of December 1 (if it is a business day), or midnight of
the first business day thereafter (if December 1 is not a business
day), immediately after such control period and is the deadline by
which a TR NOX Ozone Season allowance transfer must be
submitted for recordation in a TR NOX Ozone Season source's
compliance account in order to be available for use in complying with
the source's TR NOX Ozone Season emissions limitation for
such control period in accordance with Sec. Sec. 97.506 and 97.524.
Alternate designated representative means, for a TR NOX
Ozone Season source and each TR NOX Ozone Season unit at the
source, the natural person who is authorized by the owners and
operators of the source and all such units at the source, in accordance
with this subpart, to act on behalf of the designated representative in
matters pertaining to the TR NOX Ozone Season Trading
Program. If the TR NOX Ozone Season source is also subject
to the Acid Rain Program, TR NOX Annual Trading Program, TR
SO2 Group 1 Trading Program, or TR SO2 Group 2
Trading Program, then this natural person shall be the same natural
person as the alternate designated representative, as defined in the
respective program.
Assurance account means an Allowance Management System account,
established by the Administrator under Sec. 97.525(b)(3) for certain
owners and operators of a group of one or more TR NOX Ozone
Season sources and units in a given State (and Indian country within
the borders of such State), in which are held TR NOX Ozone
Season allowances available for use for a control period in a given
year in complying with the TR NOX Ozone
[[Page 48407]]
Season assurance provisions in accordance with Sec. Sec. 97.506 and
97.525.
Authorized account representative means, for a general account, the
natural person who is authorized, in accordance with this subpart, to
transfer and otherwise dispose of TR NOX Ozone Season
allowances held in the general account and, for a TR NOX
Ozone Season source's compliance account, the designated representative
of the source.
Automated data acquisition and handling system or DAHS means the
component of the continuous emission monitoring system, or other
emissions monitoring system approved for use under this subpart,
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 this subpart.
Biomass means--
(1) Any organic material grown for the purpose of being converted
to energy;
(2) Any organic byproduct of agriculture that can be converted into
energy; or
(3) Any material that can be converted into energy and is
nonmerchantable for other purposes, that is segregated from other
material that is nonmerchantable for other purposes, and that is;
(i) A forest-related organic resource, including mill residues,
precommercial thinnings, slash, brush, or byproduct from conversion of
trees to merchantable material; or
(ii) A wood material, including pallets, crates, dunnage,
manufacturing and construction materials (other than pressure-treated,
chemically-treated, or painted wood products), and landscape or right-
of-way tree trimmings.
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.
Bottoming-cycle unit means a unit in which the energy input to the
unit is first used to produce useful thermal energy, where at least
some of the reject heat from the useful thermal energy application or
process is then used for electricity production.
Business day means a day that does not fall on a weekend or a
federal holiday.
Certifying official means a natural person who is:
(1) For a corporation, a president, secretary, treasurer, or vice-
president of the corporation in charge of a principal business function
or any other person who performs similar policy- or decision-making
functions for the corporation;
(2) For a partnership or sole proprietorship, a general partner or
the proprietor respectively; or
(3) For a local government entity or State, federal, or other
public agency, a principal executive officer or ranking elected
official.
Clean Air Act means the Clean Air Act, 42 U.S.C. 7401, et seq.
Coal means ``coal'' as defined in Sec. 72.2 of this chapter.
Coal-derived fuel means any fuel (whether in a solid, liquid, or
gaseous state) produced by the mechanical, thermal, or chemical
processing of coal.
Cogeneration system means an integrated group, at a source, of
equipment (including a boiler, or combustion turbine, and a steam
turbine generator) designed to produce useful thermal energy for
industrial, commercial, heating, or cooling purposes and electricity
through the sequential use of energy.
Cogeneration unit means a stationary, fossil-fuel-fired boiler or
stationary, fossil-fuel-fired combustion turbine that is a topping-
cycle unit or a bottoming-cycle unit:
(1) Operating as part of a cogeneration system; and
(2) Producing on an annual average basis--
(i) For a topping-cycle unit,
(A) Useful thermal energy not less than 5 percent of total energy
output; and
(B) Useful power that, when added to one-half of useful thermal
energy produced, is not less than 42.5 percent of total energy input,
if useful thermal energy produced is 15 percent or more of total energy
output, or not less than 45 percent of total energy input, if useful
thermal energy produced is less than 15 percent of total energy output.
(ii) For a bottoming-cycle unit, useful power not less than 45
percent of total energy input;
(3) Provided that the requirements in paragraph (2) of this
definition shall not apply to a calendar year referenced in paragraph
(2) of this definition during which the unit did not operate at all;
(4) Provided that the total energy input under paragraphs (2)(i)(B)
and (2)(ii) of this definition shall equal the unit's total energy
input from all fuel, except biomass if the unit is a boiler; and
(5) Provided that, if, throughout its operation during the 12-month
period or a calendar year referenced in paragraph (2) of this
definition, a unit is operated as part of a cogeneration system and the
cogeneration system meets on a system-wide basis the requirement in
paragraph (2)(i)(B) or (2)(ii) of this definition, the unit shall be
deemed to meet such requirement during that 12-month period or calendar
year.
Combustion turbine means an enclosed device comprising:
(1) If the device is simple cycle, 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; and
(2) If the device is combined cycle, the equipment described in
paragraph (1) of this definition and any associated duct burner, heat
recovery steam generator, and steam turbine.
Commence commercial operation means, with regard to a unit:
(1) To have begun to produce steam, gas, or other heated medium
used to generate electricity for sale or use, including test
generation, except as provided in Sec. 97.505.
(i) For a unit that is a TR NOX Ozone Season unit under
Sec. 97.504 on the later of January 1, 2005 or the date the unit
commences commercial operation as defined in the introductory text of
paragraph (1) of this definition and that subsequently undergoes a
physical change or is moved to a new location or source, such date
shall remain the date of commencement of commercial operation of the
unit, which shall continue to be treated as the same unit.
(ii) For a unit that is a TR NOX Ozone Season unit under
Sec. 97.504 on the later of January 1, 2005 or the date the unit
commences commercial operation as defined in the introductory text of
paragraph (1) of this definition and that is subsequently replaced by a
unit at the same or a different source, such date shall remain the
replaced unit's date of commencement of commercial operation, and the
replacement unit shall be treated as a separate unit with a separate
date for commencement of commercial operation as defined in paragraph
(1) or (2) of this definition as appropriate.
(2) Notwithstanding paragraph (1) of this definition and except as
provided in Sec. 97.505, for a unit that is not a TR NOX
Ozone Season unit under Sec. 97.504 on the later of January 1, 2005 or
the date the unit commences commercial operation as defined in
introductory text of paragraph (1) of this definition, the unit's date
for commencement of commercial operation shall be the date on which the
unit becomes a TR NOX Ozone Season unit under Sec. 97.504.
(i) For a unit with a date for commencement of commercial operation
as defined in the introductory text of paragraph (2) of this definition
[[Page 48408]]
and that subsequently undergoes a physical change or is moved to a
different location or source, such date shall remain the date of
commencement of commercial operation of the unit, which shall continue
to be treated as the same unit.
(ii) For a unit with a date for commencement of commercial
operation as defined in the introductory text of paragraph (2) of this
definition and that is subsequently replaced by a unit at the same or a
different source, such date shall remain the replaced unit's date of
commencement of commercial operation, and the replacement unit shall be
treated as a separate unit with a separate date for commencement of
commercial operation as defined in paragraph (1) or (2) of this
definition as appropriate.
Common designated representative means, with regard to a control
period in a given year, a designated representative where, as of April
1 immediately after the allowance transfer deadline for such control
period, the same natural person is authorized under Sec. Sec.
97.513(a) and 97.515(a) as the designated representative for a group of
one or more TR NOX Ozone Season sources and units located in
a State (and Indian country within the borders of such State).
Common designated representative's assurance level means, with
regard to a specific common designated representative and a State (and
Indian country within the borders of such State) and control period in
a given year for which the State assurance level is exceeded as
described in Sec. 97.506(c)(2)(iii), the common designated
representative's share of the State NOX Ozone Season trading
budget with the variability limit for the State for such control
period.
Common designated representative's share means, with regard to a
specific common designated representative for a control period in a
given year:
(1) With regard to a total amount of NOX emissions from
all TR NOX Ozone Season units in a State (and Indian country
within the borders of such State) during such control period, the total
tonnage of NOX emissions during such control period from a
group of one or more TR NOX Ozone Season units located in
such State (and such Indian country) and having the common designated
representative for such control period;
(2) With regard to a State NOX Ozone Season trading
budget with the variability limit for such control period, the amount
(rounded to the nearest allowance) equal to the sum of the total amount
of TR NOX Ozone Season allowances allocated for such control
period to a group of one or more TR NOX Ozone Season units
located in the State (and Indian country within the borders of such
State) and having the common designated representative for such control
period and of the total amount of TR NOX Ozone Season
allowances purchased by an owner or operator of such TR NOX
Ozone Season units in an auction for such control period and submitted
by the State or the permitting authority to the Administrator for
recordation in the compliance accounts for such TR NOX Ozone
Season units in accordance with the TR NOX Ozone Season
allowance auction provisions in a SIP revision approved by the
Administrator under Sec. 52.38(b)(4) or (5) of this chapter,
multiplied by the sum of the State NOX Ozone Season trading
budget under Sec. 97.510(a) and the State's variability limit under
Sec. 97.510(b) for such control period and divided by such State
NOX Ozone Season trading budget;
(3) Provided that, in the case of a unit that operates during, but
has no amount of TR NOX Ozone Season allowances allocated
under Sec. Sec. 97.511 and 97.512 for, such control period, the unit
shall be treated, solely for purposes of this definition, as being
allocated an amount (rounded to the nearest allowance) of TR
NOX Ozone Season allowances for such control period equal to
the unit's allowable NOX emission rate applicable to such
control period, multiplied by a capacity factor of 0.92 (if the unit is
a boiler combusting any amount of coal or coal-derived fuel during such
control period), 0.32 (if the unit is a simple combustion turbine
during such control period), 0.71 (if the unit is a combined cycle
turbine during such control period), 0.73 (if the unit is an integrated
coal gasification combined cycle unit during such control period), or
0.44 (for any other unit), multiplied by the unit's maximum hourly load
as reported in accordance with this subpart and by 3,672 hours/control
period, and divided by 2,000 lb/ton.
Common stack means a single flue through which emissions from 2 or
more units are exhausted.
Compliance account means an Allowance Management System account,
established by the Administrator for a TR NOX Ozone Season
source under this subpart, in which any TR NOX Ozone Season
allowance allocations to the TR NOX Ozone Season units at
the source are recorded and in which are held any TR NOX
Ozone Season allowances available for use for a control period in a
given year in complying with the source's TR NOX Ozone
Season emissions limitation in accordance with Sec. Sec. 97.506 and
97.524.
Continuous emission monitoring system or CEMS means the equipment
required under this subpart to sample, analyze, measure, and provide,
by means of readings recorded at least once every 15 minutes and using
an automated data acquisition and handling system (DAHS), a permanent
record of NOX emissions, stack gas volumetric flow rate,
stack gas moisture content, and O2 or CO2
concentration (as applicable), in a manner consistent with part 75 of
this chapter and Sec. Sec. 97.530 through 97.535. The following
systems are the principal types of continuous emission monitoring
systems:
(1) A flow monitoring system, consisting of a stack flow rate
monitor and an automated data acquisition and handling system and
providing a permanent, continuous record of stack gas volumetric flow
rate, in standard cubic feet per hour (scfh);
(2) A NOX concentration monitoring system, consisting of
a NOX pollutant concentration monitor and an automated data
acquisition and handling system and providing a permanent, continuous
record of NOX emissions, in parts per million (ppm);
(3) A NOX emission rate (or NOX-diluent)
monitoring system, consisting of a NOX pollutant
concentration monitor, a diluent gas (CO2 or O2)
monitor, and an automated data acquisition and handling system and
providing a permanent, continuous record of NOX
concentration, in parts per million (ppm), diluent gas concentration,
in percent CO2 or O2, and NOX emission
rate, in pounds per million British thermal units (lb/mmBtu);
(4) A moisture monitoring system, as defined in Sec. 75.11(b)(2)
of this chapter and providing a permanent, continuous record of the
stack gas moisture content, in percent H2O;
(5) A CO2 monitoring system, consisting of a
CO2 pollutant concentration monitor (or an O2
monitor plus suitable mathematical equations from which the
CO2 concentration is derived) and an automated data
acquisition and handling system and providing a permanent, continuous
record of CO2 emissions, in percent CO2; and
(6) An O2 monitoring system, consisting of an
O2 concentration monitor and an automated data acquisition
and handling system and providing a permanent, continuous record of
O2, in percent O2.
Control period means the period starting May 1 of a calendar year,
except as provided in Sec. 97.506(c)(3), and
[[Page 48409]]
ending on September 30 of the same year, inclusive.
Designated representative means, for a TR NOX Ozone
Season source and each TR NOX Ozone Season unit at the
source, the natural person who is authorized by the owners and
operators of the source and all such units at the source, in accordance
with this subpart, to represent and legally bind each owner and
operator in matters pertaining to the TR NOX Ozone Season
Trading Program. If the TR NOX Ozone Season source is also
subject to the Acid Rain Program, TR NOX Annual Trading
Program, TR SO2 Group 1 Trading Program, or TR
SO2 Group 2 Trading Program, then this natural person shall
be the same natural person as the designated representative, as defined
in the respective program.
Emissions means air pollutants exhausted from a unit or source into
the atmosphere, as measured, recorded, and reported to the
Administrator by the designated representative, and as modified by the
Administrator:
(1) In accordance with this subpart; and
(2) With regard to a period before the unit or source is required
to measure, record, and report such air pollutants in accordance with
this subpart, in accordance with part 75 of this chapter.
Excess emissions means any ton of emissions from the TR
NOX Ozone Season units at a TR NOX Ozone Season
source during a control period in a given year that exceeds the TR
NOX Ozone Season emissions limitation for the source for
such control period.
Fossil fuel means--
(1) Natural gas, petroleum, coal, or any form of solid, liquid, or
gaseous fuel derived from such material; or
(2) For purposes of applying the limitation on ``average annual
fuel consumption of fossil fuel'' in Sec. Sec. 97.504(b)(2)(i)(B) and
(ii), natural gas, petroleum, coal, or any form of solid, liquid, or
gaseous fuel derived from such material for the purpose of creating
useful heat.
Fossil-fuel-fired means, with regard to a unit, combusting any
amount of fossil fuel in 2005 or any calendar year thereafter.
General account means an Allowance Management System account,
established under this subpart, that is not a compliance account or an
assurance account.
Generator means a device that produces electricity.
Gross electrical output means, for a unit, electricity made
available for use, including any such electricity used in the power
production process (which process includes, but is not limited to, any
on-site processing or treatment of fuel combusted at the unit and any
on-site emission controls).
Heat input means, for a unit for a specified period of time, the
product (in mmBtu/time) of the gross calorific value of the fuel (in
mmBtu/lb) fed into the unit multiplied by the fuel feed rate (in lb of
fuel/time), as measured, recorded, and reported to the Administrator by
the designated representative and as modified by the Administrator in
accordance with this subpart and excluding the heat derived from
preheated combustion air, recirculated flue gases, or exhaust.
Heat input rate means, for a unit, the amount of heat input (in
mmBtu) divided by unit operating time (in hr) or, for a unit and a
specific fuel, the amount of heat input attributed to the fuel (in
mmBtu) divided by the unit operating time (in hr) during which the unit
combusts the fuel.
Heat rate means, for a unit, the unit's maximum design heat input
(in Btu/hr), divided by the product of 1,000,000 Btu/mmBtu and the
unit's maximum hourly load.
Indian country means ``Indian country'' as defined in 18 U.S.C.
1151.
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 generated by 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 no less 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, for a unit, the maximum amount of
fuel per hour (in Btu/hr) that the unit is capable of combusting on a
steady state basis as of the initial installation of the unit as
specified by the manufacturer of the unit.
Monitoring system means any monitoring system that meets the
requirements of this subpart, including a continuous emission
monitoring system, an alternative monitoring system, or an excepted
monitoring system under part 75 of this chapter.
Nameplate capacity means, starting from the initial installation of
a generator, the maximum electrical generating output (in MWe, rounded
to the nearest tenth) that the generator is capable of producing on a
steady state basis and during continuous operation (when not restricted
by seasonal or other deratings) as of such installation as specified by
the manufacturer of the generator or, starting from the completion of
any subsequent physical change in the generator resulting in an
increase in the maximum electrical generating output that the generator
is capable of producing on a steady state basis and during continuous
operation (when not restricted by seasonal or other deratings), such
increased maximum amount (in MWe, rounded to the nearest tenth) as of
such completion as specified by the person conducting the physical
change.
Natural gas means ``natural gas'' as defined in Sec. 72.2 of this
chapter.
Newly affected TR NOX Ozone Season unit means a unit that was not a
TR NOX Ozone Season unit when it began operating but that
thereafter becomes a TR NOX Ozone Season unit.
Operate or operation means, with regard to a unit, to combust fuel.
Operator means, for a TR NOX Ozone Season source or a TR
NOX Ozone Season unit at a source respectively, any person
who operates, controls, or supervises a TR NOX Ozone Season
unit at the source or the TR NOX Ozone Season unit and shall
include, but not be limited to, any holding company, utility system, or
plant manager of such source or unit.
Owner means, for a TR NOX Ozone Season source or a TR
NOX Ozone Season unit at a source respectively, any of the
following persons:
(1) Any holder of any portion of the legal or equitable title in a
TR NOX Ozone Season unit at the source or the TR
NOX Ozone Season unit;
(2) Any holder of a leasehold interest in a TR NOX Ozone
Season unit at the source or the TR NOX Ozone Season unit,
provided that, 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) on the revenues or income from
such TR NOX Ozone Season unit; and
(3) Any purchaser of power from a TR NOX Ozone Season
unit at the source or the TR NOX Ozone Season unit under a
life-of-the-unit, firm power contractual arrangement.
Permanently retired means, with regard to a unit, a unit that is
[[Page 48410]]
unavailable for service and that the unit's owners and operators do not
expect to return to service in the future.
Permitting authority means ``permitting authority'' as defined in
Sec. Sec. 70.2 and 71.2 of this chapter.
Potential electrical output capacity means, for a unit, 33 percent
of the unit's maximum design heat input, divided by 3,413 Btu/kWh,
divided by 1,000 kWh/MWh, and multiplied by 8,760 hr/yr.
Receive or receipt of means, when referring to the Administrator,
to come into possession of a document, information, or correspondence
(whether sent in hard copy or by authorized electronic transmission),
as indicated in an official log, or by a notation made on the document,
information, or correspondence, by the Administrator in the regular
course of business.
Recordation, record, or recorded means, with regard to TR
NOX Ozone Season allowances, the moving of TR NOX
Ozone Season allowances by the Administrator into, out of, or between
Allowance Management System accounts, for purposes of allocation,
auction, transfer, or deduction.
Reference method means any direct test method of sampling and
analyzing for an air pollutant as specified in Sec. 75.22 of this
chapter.
Replacement, replace, or replaced means, with regard to a unit, the
demolishing of a unit, or the permanent retirement and permanent
disabling of a unit, and the construction of another unit (the
replacement unit) to be used instead of the demolished or retired unit
(the replaced unit).
Sequential use of energy means:
(1) The use of reject heat from electricity production in a useful
thermal energy application or process; or
(2) The use of reject heat from useful thermal energy application
or process in electricity production.
Serial number means, for a TR NOX Ozone Season
allowance, the unique identification number assigned to each TR
NOX Ozone Season allowance by the Administrator.
Solid waste incineration unit means a stationary, fossil-fuel-fired
boiler or stationary, fossil-fuel-fired combustion turbine that is a
``solid waste incineration unit'' as defined in section 129(g)(1) of
the Clean Air Act.
Source means all buildings, structures, or installations located in
one or more contiguous or adjacent properties under common control of
the same person or persons. This definition does not change or
otherwise affect the definition of ``major source'', ``stationary
source'', or ``source'' as set forth and implemented in a title V
operating permit program or any other program under the Clean Air Act.
State means one of the States that is subject to the TR
NOX Ozone Season Trading Program pursuant to Sec. 52.38(b)
of this chapter.
Submit or serve means to send or transmit a document, information,
or correspondence to the person specified in accordance with the
applicable regulation:
(1) In person;
(2) By United States Postal Service; or
(3) By other means of dispatch or transmission and delivery;
(4) Provided that compliance with any ``submission'' or ``service''
deadline shall be determined by the date of dispatch, transmission, or
mailing and not the date of receipt.
Topping-cycle unit means a unit in which the energy input to the
unit is first used to produce useful power, including electricity,
where at least some of the reject heat from the electricity production
is then used to provide useful thermal energy.
Total energy input means, for a unit, total energy of all forms
supplied to the unit, excluding energy produced by the unit. Each form
of energy supplied shall be measured by the lower heating value of that
form of energy calculated as follows:
LHV = HHV - 10.55 (W + 9H)
Where:
LHV = lower heating value of the form of energy in Btu/lb,
HHV = higher heating value of the form of energy in Btu/lb,
W = weight % of moisture in the form of energy, and
H = weight % of hydrogen in the form of energy.
Total energy output means, for a unit, the sum of useful power and
useful thermal energy produced by the unit.
TR NOX Annual Trading Program means a multi-state NOX
air pollution control and emission reduction program established in
accordance with subpart AAAAA of this part and Sec. 52.38(a) of this
chapter (including such a program that is revised in a SIP revision
approved by the Administrator under Sec. 52.38(a)(3) or (4) of this
chapter or that is established in a SIP revision approved by the
Administrator under Sec. 52.38(a)(5) of this chapter), as a means of
mitigating interstate transport of fine particulates and
NOX.
TR NOX Ozone Season allowance means a limited authorization issued
and allocated or auctioned by the Administrator under this subpart, or
by a State or permitting authority under a SIP revision approved by the
Administrator under Sec. 52.38(b)(3), (4), or (5) of this chapter, to
emit one ton of NOX during a control period of the specified
calendar year for which the authorization is allocated or auctioned or
of any calendar year thereafter under the TR NOX Ozone
Season Trading Program.
TR NOX Ozone Season allowance deduction or deduct TR NOX Ozone
Season allowances means the permanent withdrawal of TR NOX
Ozone Season allowances by the Administrator from a compliance account
(e.g., in order to account for compliance with the TR NOX
Ozone Season emissions limitation) or from an assurance account (e.g.,
in order to account for compliance with the assurance provisions under
Sec. Sec. 97.506 and 97.525).
TR NOX Ozone Season allowances held or hold TR NOX Ozone Season
allowances means the TR NOX Ozone Season allowances treated
as included in an Allowance Management System account as of a specified
point in time because at that time they:
(1) Have been recorded by the Administrator in the account or
transferred into the account by a correctly submitted, but not yet
recorded, TR NOX Ozone Season allowance transfer in
accordance with this subpart; and
(2) Have not been transferred out of the account by a correctly
submitted, but not yet recorded, TR NOX Ozone Season
allowance transfer in accordance with this subpart.
TR NOX Ozone Season emissions limitation means, for a TR
NOX Ozone Season source, the tonnage of NOX
emissions authorized in a control period in a given year by the TR
NOX Ozone Season allowances available for deduction for the
source under Sec. 97.524(a) for such control period.
TR NOX Ozone Season source means a source that includes one or more
TR NOX Ozone Season units.
TR NOX Ozone Season Trading Program means a multi-state
NOX air pollution control and emission reduction program
established in accordance with this subpart and Sec. 52.38(b) of this
chapter (including such a program that is revised in a SIP revision
approved by the Administrator under Sec. 52.38(b)(3) or (4) of this
chapter or that is established in a SIP revision approved by the
Administrator under Sec. 52.38(b)(5) of this chapter), as a means of
mitigating interstate transport of ozone and NOX.
TR NOX Ozone Season unit means a unit that is subject to the TR
NOX Ozone Season Trading Program.
[[Page 48411]]
TR SO2 Group 1 Trading Program means a multi-state SO2
air pollution control and emission reduction program established in
accordance with subpart CCCCC of this part and 52.39(a), (b), (d)
through (f), (j), and (k) of this chapter (including such a program
that is revised in a SIP revision approved by the Administrator under
Sec. 52.39(d) or (e) of this chapter or that is established in a SIP
revision approved by the Administrator under Sec. 52.39(f) of this
chapter), as a means of mitigating interstate transport of fine
particulates and SO2.
TR SO2 Group 2 Trading Program means a multi-state SO2
air pollution control and emission reduction program established in
accordance with subpart DDDDD of this part and 52.39(a), (c), and (g)
through (k) of this chapter (including such a program that is revised
in a SIP revision approved by the Administrator under Sec. 52.39(g) or
(h) of this chapter or that is established in a SIP revision approved
by the Administrator under Sec. 52.39(i) of this chapter), as a means
of mitigating interstate transport of fine particulates and
SO2.
Unit means a stationary, fossil-fuel-fired boiler, stationary,
fossil-fuel-fired combustion turbine, or other stationary, fossil-fuel-
fired combustion device. A unit that undergoes a physical change or is
moved to a different location or source shall continue to be treated as
the same unit. A unit (the replaced unit) that is replaced by another
unit (the replacement unit) at the same or a different source shall
continue to be treated as the same unit, and the replacement unit shall
be treated as a separate unit.
Unit operating day means, with regard to a unit, a calendar day in
which the unit combusts any fuel.
Unit operating hour or hour of unit operation means, with regard to
a unit, an hour in which the unit combusts any fuel.
Useful power means, with regard to a unit, electricity or
mechanical energy that the unit makes available for use, excluding any
such energy used in the power production process (which process
includes, but is not limited to, any on-site processing or treatment of
fuel combusted at the unit and any on-site emission controls).
Useful thermal energy means thermal energy that is:
(1) Made available to an industrial or commercial process (not a
power production process), excluding any heat contained in condensate
return or makeup water;
(2) Used in a heating application (e.g., space heating or domestic
hot water heating); or
(3) Used in a space cooling application (i.e., in an absorption
chiller).
Utility power distribution system means the portion of an
electricity grid owned or operated by a utility and dedicated to
delivering electricity to customers.
Sec. 97.503 Measurements, abbreviations, and acronyms.
Measurements, abbreviations, and acronyms used in this subpart are
defined as follows:
Btu--British thermal unit
CO2--carbon dioxide
H2O--water
hr--hour
kW--kilowatt electrical
kWh--kilowatt hour
lb--pound
mmBtu--million Btu
MWe--megawatt electrical
MWh--megawatt hour
NOX--nitrogen oxides
O2--oxygen
ppm--parts per million
scfh--standard cubic feet per hour
SO2--sulfur dioxide
yr--year
Sec. 97.504 Applicability.
(a) Except as provided in paragraph (b) of this section:
(1) The following units in a State (and Indian country within the
borders of such State) shall be TR NOX Ozone Season units,
and any source that includes one or more such units shall be a TR
NOX Ozone Season source, subject to the requirements of this
subpart: any stationary, fossil-fuel-fired boiler or stationary,
fossil-fuel-fired combustion turbine serving at any time, on or after
January 1, 2005, a generator with nameplate capacity of more than 25
MWe producing electricity for sale.
(2) If a stationary boiler or stationary combustion turbine that,
under paragraph (a)(1) of this section, is not a TR NOX
Ozone Season unit begins to combust fossil fuel or to serve a generator
with nameplate capacity of more than 25 MWe producing electricity for
sale, the unit shall become a TR NOX Ozone Season unit as
provided in paragraph (a)(1) of this section on the first date on which
it both combusts fossil fuel and serves such generator.
(b) Any unit in a State (and Indian country within the borders of
such State) that otherwise is a TR NOX Ozone Season unit
under paragraph (a) of this section and that meets the requirements set
forth in paragraph (b)(1)(i) or (2)(i) of this section shall not be a
TR NOX Ozone Season unit:
(1)(i) Any unit:
(A) Qualifying as a cogeneration unit throughout the later of 2005
or the 12-month period starting on the date the unit first produces
electricity and continuing to qualify as a cogeneration unit throughout
each calendar year ending after the later of 2005 or such 12-month
period; and
(B) Not supplying in 2005 or any calendar year thereafter more than
one-third of the unit's potential electric output capacity or 219,000
MWh, whichever is greater, to any utility power distribution system for
sale.
(ii) If, after qualifying under paragraph (b)(1)(i) of this section
as not being a TR NOX Ozone Season unit, a unit subsequently
no longer meets all the requirements of paragraph (b)(1)(i) of this
section, the unit shall become a TR NOX Ozone Season unit
starting on the earlier of January 1 after the first calendar year
during which the unit first no longer qualifies as a cogeneration unit
or January 1 after the first calendar year during which the unit no
longer meets the requirements of paragraph (b)(1)(i)(B) of this
section. The unit shall thereafter continue to be a TR NOX
Ozone Season unit.
(2)(i) Any unit:
(A) Qualifying as a solid waste incineration unit throughout the
later of 2005 or the 12-month period starting on the date the unit
first produces electricity and continuing to qualify as a solid waste
incineration unit throughout each calendar year ending after the later
of 2005 or such 12-month period; and
(B) With an average annual fuel consumption of fossil fuel for the
first 3 consecutive calendar years of operation starting no earlier
than 2005 of less than 20 percent (on a Btu basis) and an average
annual fuel consumption of fossil fuel for any 3 consecutive calendar
years thereafter of less than 20 percent (on a Btu basis).
(ii) If, after qualifying under paragraph (b)(2)(i) of this section
as not being a TR NOX Ozone Season unit, a unit subsequently
no longer meets all the requirements of paragraph (b)(1)(i) of this
section, the unit shall become a TR NOX Ozone Season unit
starting on the earlier of January 1 after the first calendar year
during which the unit first no longer qualifies as a solid waste
incineration unit or January 1 after the first 3 consecutive calendar
years after 2005 for which the unit has an average annual fuel
consumption of fossil fuel of 20 percent or more. The unit shall
thereafter continue to be a TR NOX Ozone Season unit.
(c) A certifying official of an owner or operator of any unit or
other equipment
[[Page 48412]]
may submit a petition (including any supporting documents) to the
Administrator at any time for a determination concerning the
applicability, under paragraphs (a) and (b) of this section or a SIP
revision approved under Sec. 52.38(b)(4) or (5) of this chapter, of
the TR NOX Ozone Season Trading Program to the unit or other
equipment.
(1) Petition content. The petition shall be in writing and include
the identification of the unit or other equipment and the relevant
facts about the unit or other equipment. The petition and any other
documents provided to the Administrator in connection with the petition
shall include the following certification statement, signed by the
certifying official: ``I am authorized to make this submission on
behalf of the owners and operators of the unit or other equipment 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) Response. The Administrator will issue a written response to
the petition and may request supplemental information determined by the
Administrator to be relevant to such petition. The Administrator's
determination concerning the applicability, under paragraphs (a) and
(b) of this section, of the TR NOX Ozone Season Trading
Program to the unit or other equipment shall be binding on any State or
permitting authority unless the Administrator determines that the
petition or other documents or information provided in connection with
the petition contained significant, relevant errors or omissions.
Sec. 97.505 Retired unit exemption.
(a)(1) Any TR NOX Ozone Season unit that is permanently
retired shall be exempt from Sec. 97.506(b) and (c)(1), Sec. 97.524,
and Sec. Sec. 97.530 through 97.535.
(2) The exemption under paragraph (a)(1) of this section shall
become effective the day on which the TR NOX Ozone Season
unit is permanently retired. Within 30 days of the unit's permanent
retirement, the designated representative shall submit a statement to
the Administrator. The statement shall state, in a format prescribed by
the Administrator, that the unit was permanently retired on a specified
date and will comply with the requirements of paragraph (b) of this
section.
(b) Special provisions. (1) A unit exempt under paragraph (a) of
this section shall not emit any NOX, starting on the date
that the exemption takes effect.
(2) For a period of 5 years from the date the records are created,
the owners and operators of a unit exempt under paragraph (a) of 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 before the
end of the period, in writing by the Administrator. The owners and
operators bear the burden of proof that the unit is permanently
retired.
(3) The owners and operators and, to the extent applicable, the
designated representative of a unit exempt under paragraph (a) of this
section shall comply with the requirements of the TR NOX
Ozone Season 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 exempt under paragraph (a) of this section shall lose
its exemption on the first date on which the unit resumes operation.
Such unit shall be treated, for purposes of applying allocation,
monitoring, reporting, and recordkeeping requirements under this
subpart, as a unit that commences commercial operation on the first
date on which the unit resumes operation.
Sec. 97.506 Standard requirements.
(a) Designated representative requirements. The owners and
operators shall comply with the requirement to have a designated
representative, and may have an alternate designated representative, in
accordance with Sec. Sec. 97.513 through 97.518.
(b) Emissions monitoring, reporting, and recordkeeping
requirements. (1) The owners and operators, and the designated
representative, of each TR NOX Ozone Season source and each
TR NOX Ozone Season unit at the source shall comply with the
monitoring, reporting, and recordkeeping requirements of Sec. Sec.
97.530 through 97.535.
(2) The emissions data determined in accordance with Sec. Sec.
97.530 through 97.535 shall be used to calculate allocations of TR
NOX Ozone Season allowances under Sec. Sec. 97.511(a)(2)
and (b) and 97.512 and to determine compliance with the TR
NOX Ozone Season emissions limitation and assurance
provisions under paragraph (c) of this section, provided that, for each
monitoring location from which mass emissions are reported, the mass
emissions amount used in calculating such allocations and determining
such compliance shall be the mass emissions amount for the monitoring
location determined in accordance with Sec. Sec. 97.530 through 97.535
and rounded to the nearest ton, with any fraction of a ton less than
0.50 being deemed to be zero.
(c) NOX emissions requirements. (1) TR NOX
Ozone Season emissions limitation. (i) As of the allowance transfer
deadline for a control period in a given year, the owners and operators
of each TR NOX Ozone Season source and each TR
NOX Ozone Season unit at the source shall hold, in the
source's compliance account, TR NOX Ozone Season allowances
available for deduction for such control period under Sec. 97.524(a)
in an amount not less than the tons of total NOX emissions
for such control period from all TR NOX Ozone Season units
at the source.
(ii) If total NOX emissions during a control period in a
given year from the TR NOX Ozone Season units at a TR
NOX Ozone Season source are in excess of the TR
NOX Ozone Season emissions limitation set forth in paragraph
(c)(1)(i) of this section, then:
(A) The owners and operators of the source and each TR
NOX Ozone Season unit at the source shall hold the TR
NOX Ozone Season allowances required for deduction under
Sec. 97.524(d); and
(B) The owners and operators of the source and each TR
NOX Ozone Season unit at the source shall pay any fine,
penalty, or assessment or comply with any other remedy imposed, for the
same violations, under the Clean Air Act, and each ton of such excess
emissions and each day of such control period shall constitute a
separate violation of this subpart and the Clean Air Act.
(2) TR NOX Ozone Season assurance provisions. (i) If
total NOX emissions during a control period in a given year
from all TR NOX Ozone Season units at TR NOX
Ozone Season sources in a State (and Indian country within the borders
of such State) exceed the State assurance level, then the owners and
operators of such sources and units in each group of one or more
sources and units having a common designated representative for such
control period, where the common designated representative's share of
such NOX emissions during such control period exceeds the
common designated
[[Page 48413]]
representative's assurance level for the State and such control period,
shall hold (in the assurance account established for the owners and
operators of such group) TR NOX Ozone Season allowances
available for deduction for such control period under Sec. 97.525(a)
in an amount equal to two times the product (rounded to the nearest
whole number), as determined by the Administrator in accordance with
Sec. 97.525(b), of multiplying--
(A) The quotient of the amount by which the common designated
representative's share of such NOX emissions exceeds the
common designated representative's assurance level divided by the sum
of the amounts, determined for all common designated representatives
for such sources and units in the State (and Indian country within the
borders of such State) for such control period, by which each common
designated representative's share of such NOX emissions
exceeds the respective common designated representative's assurance
level; and
(B) The amount by which total NOX emissions from all TR
NOX Ozone Season units at TR NOX Ozone Season
sources in the State (and Indian country within the borders of such
State) for such control period exceed the State assurance level.
(ii) The owners and operators shall hold the TR NOX
Ozone Season allowances required under paragraph (c)(2)(i) of this
section, as of midnight of November 1 (if it is a business day), or
midnight of the first business day thereafter (if November 1 is not a
business day), immediately after such control period.
(iii) Total NOX emissions from all TR NOX
Ozone Season units at TR NOX Ozone Season sources in a State
(and Indian country within the borders of such State) during a control
period in a given year exceed the State assurance level if such total
NOX emissions exceed the sum, for such control period, of
the State NOX Ozone Season trading budget under Sec.
97.510(a) and the State's variability limit under Sec. 97.510(b).
(iv) It shall not be a violation of this subpart or of the Clean
Air Act if total NOX emissions from all TR NOX
Ozone Season units at TR NOX Ozone Season sources in a State
(and Indian country within the borders of such State) during a control
period exceed the State assurance level or if a common designated
representative's share of total NOX emissions from the TR
NOX Ozone Season units at TR NOX Ozone Season
sources in a State (and Indian country within the borders of such
State) during a control period exceeds the common designated
representative's assurance level.
(v) To the extent the owners and operators fail to hold TR
NOX Ozone Season allowances for a control period in a given
year in accordance with paragraphs (c)(2)(i) through (iii) of this
section,
(A) The owners and operators shall pay any fine, penalty, or
assessment or comply with any other remedy imposed under the Clean Air
Act; and
(B) Each TR NOX Ozone Season allowance that the owners
and operators fail to hold for such control period in accordance with
paragraphs (c)(2)(i) through (iii) of this section and each day of such
control period shall constitute a separate violation of this subpart
and the Clean Air Act.
(3) Compliance periods. A TR NOX Ozone Season unit shall
be subject to the requirements under paragraphs (c)(1) and (c)(2) of
this section for the control period starting on the later of May 1,
2012 or the deadline for meeting the unit's monitor certification
requirements under Sec. 97.530(b) and for each control period
thereafter.
(4) Vintage of allowances held for compliance. (i) A TR
NOX Ozone Season allowance held for compliance with the
requirements under paragraph (c)(1)(i) of this section for a control
period in a given year must be a TR NOX Ozone Season
allowance that was allocated for such control period or a control
period in a prior year.
(ii) A TR NOX Ozone Season allowance held for compliance
with the requirements under paragraphs (c)(1)(ii)(A) and (2)(i) through
(iii) of this section for a control period in a given year must be a TR
NOX Ozone Season allowance that was allocated for a control
period in a prior year or the control period in the given year or in
the immediately following year.
(5) Allowance Management System requirements. Each TR
NOX Ozone Season allowance shall be held in, deducted from,
or transferred into, out of, or between Allowance Management System
accounts in accordance with this subpart.
(6) Limited authorization. A TR NOX Ozone Season
allowance is a limited authorization to emit one ton of NOX
during the control period in one year. Such authorization is limited in
its use and duration as follows:
(i) Such authorization shall only be used in accordance with the TR
NOX Ozone Season Trading Program; and
(ii) Notwithstanding any other provision of this subpart, the
Administrator has the authority to terminate or limit the use and
duration of such authorization to the extent the Administrator
determines is necessary or appropriate to implement any provision of
the Clean Air Act.
(7) Property right. A TR NOX Ozone Season allowance does
not constitute a property right.
(d) Title V permit requirements. (1) No title V permit revision
shall be required for any allocation, holding, deduction, or transfer
of TR NOX Ozone Season allowances in accordance with this
subpart.
(2) A description of whether a unit is required to monitor and
report NOX emissions using a continuous emission monitoring
system (under subpart H of part 75 of this chapter), an excepted
monitoring system (under appendices D and E to part 75 of this
chapter), a low mass emissions excepted monitoring methodology (under
Sec. 75.19 of this chapter), or an alternative monitoring system
(under subpart E of part 75 of this chapter) in accordance with
Sec. Sec. 97.530 through 97.535 may be added to, or changed in, a
title V permit using minor permit modification procedures in accordance
with Sec. Sec. 70.7(e)(2) and 71.7(e)(1) of this chapter, provided
that the requirements applicable to the described monitoring and
reporting (as added or changed, respectively) are already incorporated
in such permit. This paragraph explicitly provides that the addition
of, or change to, a unit's description as described in the prior
sentence is eligible for minor permit modification procedures in
accordance with Sec. Sec. 70.7(e)(2)(i)(B) and 71.7(e)(1)(i)(B) of
this chapter.
(e) Additional recordkeeping and reporting requirements. (1) Unless
otherwise provided, the owners and operators of each TR NOX
Ozone Season source and each TR NOX Ozone Season unit at the
source shall keep on site at the source each of the following documents
(in hardcopy or electronic format) for a period of 5 years from the
date the document is created. This period may be extended for cause, at
any time before the end of 5 years, in writing by the Administrator.
(i) The certificate of representation under Sec. 97.516 for the
designated representative for the source and each TR NOX
Ozone Season unit at the source and all documents that demonstrate the
truth of the statements in the certificate of representation; provided
that the certificate and documents shall be retained on site at the
source beyond such 5-year period until such certificate of
representation and documents are superseded because of the submission
of a new certificate of representation under Sec. 97.516 changing the
designated representative.
[[Page 48414]]
(ii) All emissions monitoring information, in accordance with this
subpart.
(iii) Copies of all reports, compliance certifications, and other
submissions and all records made or required under, or to demonstrate
compliance with the requirements of, the TR NOX Ozone Season
Trading Program.
(2) The designated representative of a TR NOX Ozone
Season source and each TR NOX Ozone Season unit at the
source shall make all submissions required under the TR NOX
Ozone Season Trading Program, except as provided in Sec. 97.518. This
requirement does not change, create an exemption from, or otherwise
affect the responsible official submission requirements under a title V
operating permit program in parts 70 and 71 of this chapter.
(f) Liability. (1) Any provision of the TR NOX Ozone
Season Trading Program that applies to a TR NOX Ozone Season
source or the designated representative of a TR NOX Ozone
Season source shall also apply to the owners and operators of such
source and of the TR NOX Ozone Season units at the source.
(2) Any provision of the TR NOX Ozone Season Trading
Program that applies to a TR NOX Ozone Season unit or the
designated representative of a TR NOX Ozone Season unit
shall also apply to the owners and operators of such unit.
(g) Effect on other authorities. No provision of the TR
NOX Ozone Season Trading Program or exemption under Sec.
97.505 shall be construed as exempting or excluding the owners and
operators, and the designated representative, of a TR NOX
Ozone Season source or TR NOX Ozone Season unit from
compliance with any other provision of the applicable, approved State
implementation plan, a federally enforceable permit, or the Clean Air
Act.
Sec. 97.507 Computation of time.
(a) Unless otherwise stated, any time period scheduled, under the
TR NOX Ozone Season 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
TR NOX Ozone Season 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 TR NOX Ozone Season Trading Program, is not a
business day, the time period shall be extended to the next business
day.
Sec. 97.508 Administrative appeal procedures.
The administrative appeal procedures for decisions of the
Administrator under the TR NOX Ozone Season Trading Program
are set forth in part 78 of this chapter.
Sec. 97.509 [Reserved]
Sec. 97.510 State NOX Ozone Season trading budgets, new unit set-
asides, Indian country new unit set-aside, and variability limits.
(a) The State NOX Ozone Season trading budgets, new unit
set-asides, and Indian country new unit set-asides for allocations of
TR NOX Ozone Season allowances for the control periods in
2012 and thereafter are as follows:
----------------------------------------------------------------------------------------------------------------
NOX Ozone Season Indian country new
trading budget New unit set-aside unit set-aside
State (tons) * for 2012 (tons) for 2012 (tons) for 2012
and 2013 and 2013 and 2013
----------------------------------------------------------------------------------------------------------------
Alabama............................................. 31,746 635 ..................
Arkansas............................................ 15,037 301 ..................
Florida............................................. 27,825 529 28
Georgia............................................. 27,944 559 ..................
Illinois............................................ 21,208 1,697 ..................
Indiana............................................. 46,876 1,406 ..................
Kentucky............................................ 36,167 1,447 ..................
Louisiana........................................... 13,432 390 13
Maryland............................................ 7,179 144 ..................
Mississippi......................................... 10,160 193 10
New Jersey.......................................... 3,382 68 ..................
New York............................................ 8,331 242 8
North Carolina...................................... 22,168 1,308 22
Ohio................................................ 40,063 801 ..................
Pennsylvania........................................ 52,201 1,044 ..................
South Carolina...................................... 13,909 264 14
Tennessee........................................... 14,908 298 ..................
Texas............................................... 63,043 1,828 63
Virginia............................................ 14,452 723 ..................
West Virginia....................................... 25,283 1,264 ..................
----------------------------------------------------------------------------------------------------------------
----------------------------------------------------------------------------------------------------------------
NOX Ozone Season Indian country new
trading budget New unit set-aside unit set-aside
State (tons) * for 2014 (tons) for 2014 (tons) for 2014
and thereafter and thereafter and thereafter
----------------------------------------------------------------------------------------------------------------
Alabama............................................. 31,499 630 ..................
Arkansas............................................ 15,037 301 ..................
Florida............................................. 27,825 529 28
Georgia............................................. 18,279 366 ..................
Illinois............................................ 21,208 1,697 ..................
Indiana............................................. 46,175 1,385 ..................
Kentucky............................................ 32,674 1,307 ..................
Louisiana........................................... 13,432 390 13
Maryland............................................ 7,179 144 ..................
Mississippi......................................... 10,160 193 10
New Jersey.......................................... 3,382 68 ..................
[[Page 48415]]
New York............................................ 8,331 242 8
North Carolina...................................... 18,455 1,089 18
Ohio................................................ 37,792 756 ..................
Pennsylvania........................................ 51,912 1,038 ..................
South Carolina...................................... 13,909 264 14
Tennessee........................................... 8,016 160 ..................
Texas............................................... 63,043 1,828 63
Virginia............................................ 14,452 723 ..................
West Virginia....................................... 23,291 1,165 ..................
----------------------------------------------------------------------------------------------------------------
* Each trading budget includes the new unit set-aside and, where applicable, the Indian country new unit set-
aside and does not include the variability limit.
(b) The States' variability limits for the State NOX
Ozone Season trading budgets for the control periods in 2012 and
thereafter are as follows:
------------------------------------------------------------------------
Variability limits
State Variability limits for 2014 and
for 2012 and 2013 thereafter
------------------------------------------------------------------------
Alabama......................... 6,667 6,615
Arkansas........................ 3,158 3,158
Florida......................... 5,843 5,843
Georgia......................... 5,868 3,839
Illinois........................ 4,454 4,454
Indiana......................... 9,844 9,697
Kentucky........................ 7,595 6,862
Louisiana....................... 2,821 2,821
Maryland........................ 1,508 1,508
Mississippi..................... 2,134 2,134
New Jersey...................... 710 710
New York........................ 1,750 1,750
North Carolina.................. 4,655 3,876
Ohio............................ 8,413 7,936
Pennsylvania.................... 10,962 10,902
South Carolina.................. 2,921 2,921
Tennessee....................... 3,131 1,683
Texas........................... 13,239 13,239
Virginia........................ 3,035 3,035
West Virginia................... 5,309 4,891
------------------------------------------------------------------------
Sec. 97.511 Timing requirements for TR NOX Ozone Season allowance
allocations.
(a) Existing units. (1) TR NOX Ozone Season allowances
are allocated, for the control periods in 2012 and each year
thereafter, as provided in a notice of data availability issued by the
Administrator. Providing an allocation to a unit in such notice does
not constitute a determination that the unit is a TR NOX
Ozone Season unit, and not providing an allocation to a unit in such
notice does not constitute a determination that the unit is not a TR
NOX Ozone Season unit.
(2) Notwithstanding paragraph (a)(1) of this section, if a unit
provided an allocation in the notice of data availability issued under
paragraph (a)(1) of this section does not operate, starting after 2011,
during the control period in two consecutive years, such unit will not
be allocated the TR NOX Ozone Season allowances provided in
such notice for the unit for the control periods in the fifth year
after the first such year and in each year after that fifth year. All
TR NOX Ozone Season allowances that would otherwise have
been allocated to such unit will be allocated to the new unit set-aside
for the State where such unit is located and for the respective years
involved. If such unit resumes operation, the Administrator will
allocate TR NOX Ozone Season allowances to the unit in
accordance with paragraph (b) of this section.
(b) New units.--(1) New unit set-asides. (i) By June 1, 2012 and
June 1 of each year thereafter, the Administrator will calculate the TR
NOX Ozone Season allowance allocation to each TR
NOX Ozone Season unit in a State, in accordance with Sec.
97.512(a)(2) through (7) and (12), for the control period in the year
of the applicable calculation deadline under this paragraph and will
promulgate a notice of data availability of the results of the
calculations.
(ii) For each notice of data availability required in paragraph
(b)(1)(i) of this section, the Administrator will provide an
opportunity for submission of objections to the calculations referenced
in such notice.
(A) Objections shall be submitted by the deadline specified in each
notice of data availability required in paragraph (b)(1)(i) of this
section and shall be limited to addressing whether the calculations
(including the identification of the TR NOX Ozone Season
units) are in accordance with Sec. 97.512(a)(2) through (7) and (12)
and Sec. Sec. 97.506(b)(2) and 97.530 through 97.535.
(B) The Administrator will adjust the calculations to the extent
necessary to ensure that they are in accordance with the provisions
referenced in paragraph (b)(1)(ii)(A) of this section. By August 1
immediately after the promulgation of each notice of data availability
required in paragraph (b)(1)(i) of this section, the Administrator will
promulgate a notice
[[Page 48416]]
of data availability of any adjustments that the Administrator
determines to be necessary with regard to allocations under Sec.
97.512(a)(2) through (7) and (12) and the reasons for accepting or
rejecting any objections submitted in accordance with paragraph
(b)(1)(ii)(A) of this section.
(iii) If the new unit set-aside for such control period contains
any TR NOX Ozone Season allowances that have not been
allocated in the applicable notice of data availability required in
paragraph (b)(1)(ii) of this section, the Administrator will
promulgate, by September 15 immediately after such notice, a notice of
data availability that identifies any TR NOX Ozone Season
units that commenced commercial operation during the period starting
May 1 of the year before the year of such control period and ending
August 31 of year of such control period.
(iv) For each notice of data availability required in paragraph
(b)(1)(iii) of this section, the Administrator will provide an
opportunity for submission of objections to the identification of TR
NOX Ozone Season units in such notice.
(A) Objections shall be submitted by the deadline specified in each
notice of data availability required in paragraph (b)(1)(iii) of this
section and shall be limited to addressing whether the identification
of TR NOX Ozone Season units in such notice is in accordance
with paragraph (b)(1)(iii) of this section.
(B) The Administrator will adjust the identification of TR
NOX Ozone Season units in the each notice of data
availability required in paragraph (b)(1)(iii) of this section to the
extent necessary to ensure that it is in accordance with paragraph
(b)(1)(iii) of this section and will calculate the TR NOX
Ozone Season allowance allocation to each TR NOX Ozone
Season unit in accordance with Sec. 97.512(a)(9), (10), and (12) and
Sec. Sec. 97.506(b)(2) and 97.530 through 97.535. By November 15
immediately after the promulgation of each notice of data availability
required in paragraph (b)(1)(iii) of this section, the Administrator
will promulgate a notice of data availability of any adjustments of the
identification of TR NOX Ozone Season units that the
Administrator determines to be necessary, the reasons for accepting or
rejecting any objections submitted in accordance with paragraph
(b)(1)(iv)(A) of this section, and the results of such calculations.
(v) To the extent any TR NOX Ozone Season allowances are
added to the new unit set-aside after promulgation of each notice of
data availability required in paragraph (b)(1)(iv) of this section, the
Administrator will promulgate additional notices of data availability,
as deemed appropriate, of the allocation of such TR NOX
Ozone Season allowances in accordance with Sec. 97.512(a)(10).
(2) Indian country new unit set-asides. (i) By June 1, 2012 and
June 1 of each year thereafter, the Administrator will calculate the TR
NOX Ozone Season allowance allocation to each TR
NOX Ozone Season unit in Indian country within the borders
of a State, in accordance with Sec. 97.512(b)(2) through (7) and (12),
for the control period in the year of the applicable calculation
deadline under this paragraph and will promulgate a notice of data
availability of the results of the calculations.
(ii) For each notice of data availability required in paragraph
(b)(2)(i) of this section, the Administrator will provide an
opportunity for submission of objections to the calculations referenced
in such notice.
(A) Objections shall be submitted by the deadline specified in each
notice of data availability required in paragraph (b)(2)(i) of this
section and shall be limited to addressing whether the calculations
(including the identification of the TR NOX Ozone Season
units) are in accordance with Sec. 97.512(b)(2) through (7) and (12)
and Sec. Sec. 97.506(b)(2) and 97.530 through 97.535.
(B) The Administrator will adjust the calculations to the extent
necessary to ensure that they are in accordance with the provisions
referenced in paragraph (b)(2)(ii)(A) of this section. By August 1
immediately after the promulgation of each notice of data availability
required in paragraph (b)(2)(i) of this section, the Administrator will
promulgate a notice of data availability of any adjustments that the
Administrator determines to be necessary with regard to allocations
under Sec. 97.512(b)(2) through (7) and (12) and the reasons for
accepting or rejecting any objections submitted in accordance with
paragraph (b)(2)(ii)(A) of this section.
(iii) If the Indian country new unit set-aside for such control
period contains any TR NOX Ozone Season allowances that have
not been allocated in the applicable notice of data availability
required in paragraph (b)(2)(ii) of this section, the Administrator
will promulgate, by September 15 immediately after such notice, a
notice of data availability that identifies any TR NOX Ozone
Season units that commenced commercial operation during the period
starting May 1 of the year before the year of such control period and
ending August 31 of year of such control period.
(iv) For each notice of data availability required in paragraph
(b)(2)(iii) of this section, the Administrator will provide an
opportunity for submission of objections to the identification of TR
NOX Ozone Season units in such notice.
(A) Objections shall be submitted by the deadline specified in each
notice of data availability required in paragraph (b)(2)(iii) of this
section and shall be limited to addressing whether the identification
of TR NOX Ozone Season units in such notice is in accordance
with paragraph (b)(2)(iii) of this section.
(B) The Administrator will adjust the identification of TR
NOX Ozone Season units in the each notice of data
availability required in paragraph (b)(2)(iii) of this section to the
extent necessary to ensure that it is in accordance with paragraph
(b)(2)(iii) of this section and will calculate the TR NOX
Ozone Season allowance allocation to each TR NOX Ozone
Season unit in accordance with Sec. 97.512(b)(9), (10), and (12) and
Sec. Sec. 97.506(b)(2) and 97.530 through 97.535. By November 15
immediately after the promulgation of each notice of data availability
required in paragraph (b)(2)(iii) of this section, the Administrator
will promulgate a notice of data availability of any adjustments of the
identification of TR NOX Ozone Season units that the
Administrator determines to be necessary, the reasons for accepting or
rejecting any objections submitted in accordance with paragraph
(b)(2)(iv)(A) of this section, and the results of such calculations.
(v) To the extent any TR NOX Ozone Season allowances are
added to the Indian country new unit set-aside after promulgation of
each notice of data availability required in paragraph (b)(2)(iv) of
this section, the Administrator will promulgate additional notices of
data availability, as deemed appropriate, of the allocation of such TR
NOX Ozone Season allowances in accordance with Sec.
97.512(b)(10).
(c) Units incorrectly allocated TR NOX Ozone Season allowances. (1)
For each control period in 2012 and thereafter, if the Administrator
determines that TR NOX Ozone Season allowances were
allocated under paragraph (a) of this section, or under a provision of
a SIP revision approved under Sec. 52.38(b)(3), (4), or (5) of this
chapter, where such control period and the recipient are covered by the
provisions of paragraph (c)(1)(i) of this section or were allocated
under Sec. 97.512(a)(2) through (7), (9), and (12) and (b)(2) through
(7), (9), and (12), or under a provision of a SIP revision approved
under Sec. 52.38(b)(4) or (5) of this chapter, where such control
period and the recipient are covered by the
[[Page 48417]]
provisions of paragraph (c)(1)(ii) of this section, then the
Administrator will notify the designated representative of the
recipient and will act in accordance with the procedures set forth in
paragraphs (c)(2) through (5) of this section:
(i)(A) The recipient is not actually a TR NOX Ozone
Season unit under Sec. 97.504 as of May 1, 2012 and is allocated TR
NOX Ozone Season allowances for such control period or, in
the case of an allocation under a provision of a SIP revision approved
under Sec. 52.38(b)(3), (4), or (5) of this chapter, the recipient is
not actually a TR NOX Ozone Season unit as of May 1, 2012
and is allocated TR NOX Ozone Season allowances for such
control period that the SIP revision provides should be allocated only
to recipients that are TR NOX Ozone Season units as of May
1, 2012; or
(B) The recipient is not located as of May 1 of the control period
in the State from whose NOX Ozone Season trading budget the
TR NOX Ozone Season allowances allocated under paragraph (a)
of this section, or under a provision of a SIP revision approved under
Sec. 52.38(b)(3), (4), or (5) of this chapter, were allocated for such
control period.
(ii) The recipient is not actually a TR NOX Ozone Season
unit under Sec. 97.504 as of May 1 of such control period and is
allocated TR NOX Ozone Season allowances for such control
period or, in the case of an allocation under a provision of a SIP
revision approved under Sec. 52.38(b)(3), (4), or (5) of this chapter,
the recipient is not actually a TR NOX Ozone Season unit as
of January 1 of such control period and is allocated TR NOX
Ozone Season allowances for such control period that the SIP revision
provides should be allocated only to recipients that are TR
NOX Ozone Season units as of May 1 of such control period.
(2) Except as provided in paragraph (c)(3) or (4) of this section,
the Administrator will not record such TR NOX Ozone Season
allowances under Sec. 97.521.
(3) If the Administrator already recorded such TR NOX
Ozone Season allowances under Sec. 97.521 and if the Administrator
makes the determination under paragraph (c)(1) of this section before
making deductions for the source that includes such recipient under
Sec. 97.524(b) for such control period, then the Administrator will
deduct from the account in which such TR NOX Ozone Season
allowances were recorded an amount of TR NOX Ozone Season
allowances allocated for the same or a prior control period equal to
the amount of such already recorded TR NOX Ozone Season
allowances. The authorized account representative shall ensure that
there are sufficient TR NOX Ozone Season allowances in such
account for completion of the deduction.
(4) If the Administrator already recorded such TR NOX
Ozone Season allowances under Sec. 97.521 and if the Administrator
makes the determination under paragraph (c)(1) of this section after
making deductions for the source that includes such recipient under
Sec. 97.524(b) for such control period, then the Administrator will
not make any deduction to take account of such already recorded TR
NOX Ozone Season allowances.
(5)(i) With regard to the TR NOX Ozone Season allowances
that are not recorded, or that are deducted as an incorrect allocation,
in accordance with paragraphs (c)(2) and (3) of this section for a
recipient under paragraph (c)(1)(i) of this section, the Administrator
will:
(A) Transfer such TR NOX Ozone Season allowances to the
new unit set-aside for such control period for the State from whose
NOX Ozone Season trading budget the TR NOX Ozone
Season allowances were allocated; or
(B) If the State has a SIP revision approved under Sec.
52.38(b)(4) or (5) covering such control period, include such TR
NOX Annual allowances in the portion of the State
NOX Ozone Season trading budget that may be allocated for
such control period in accordance with such SIP revision.
(ii) With regard to the TR NOX Ozone Season allowances
that were not allocated from the Indian country new unit set-aside for
such control period and that are not recorded, or that are deducted as
an incorrect allocation, in accordance with paragraphs (c)(2) and (3)
of this section for a recipient under paragraph (c)(1)(ii) of this
paragraph, the Administrator will:
(A) Transfer such TR NOX Ozone Season allowances to the
new unit set-aside for such control period; or
(B) If the State has a SIP revision approved under Sec.
52.38(b)(4) or (5) covering such control period, include such TR
NOX Ozone Season allowances in the portion of the State
NOX Ozone Season trading budget that may be allocated for
such control period in accordance with such SIP revision.
(iii) With regard to the TR NOX Ozone Season allowances
that were allocated from the Indian country new unit set-aside for such
control period and that are not recorded, or that are deducted as an
incorrect allocation, in accordance with paragraphs (c)(2) and (3) of
this section for a recipient under paragraph (c)(1)(ii) of this
paragraph, the Administrator will transfer such TR NOX Ozone
Season allowances to the Indian country new unit set-aside for such
control period.
Sec. 97.512 TR NOX Ozone Season allowance allocations to new units.
(a) For each control period in 2012 and thereafter and for the TR
NOX Ozone Season units in each State, the Administrator will
allocate TR NOX Ozone Season allowances to the TR
NOX Ozone Season units as follows:
(1) The TR NOX Ozone Season allowances will be allocated
to the following TR NOX Ozone Season units, except as
provided in paragraph (a)(10) of this section:
(i) TR NOX Ozone Season units that are not allocated an
amount of TR NOX Ozone Season allowances in the notice of
data availability issued under Sec. 97.511(a)(1);
(ii) TR NOX Ozone Season units whose allocation of an
amount of TR NOX Ozone Season allowances for such control
period in the notice of data availability issued under Sec.
97.511(a)(1) is covered by Sec. 97.511(c)(2) or (3);
(iii) TR NOX Ozone Season units that are allocated an
amount of TR NOX Ozone Season allowances for such control
period in the notice of data availability issued under Sec.
97.511(a)(1), which allocation is terminated for such control period
pursuant to Sec. 97.511(a)(2), and that operate during the control
period immediately preceding such control period; or
(iv) For purposes of paragraph (a)(9) of this section, TR
NOX Ozone Season units under Sec. 97.511(c)(1)(ii) whose
allocation of an amount of TR NOX Ozone Season allowances
for such control period in the notice of data availability issued under
Sec. 97.511(b)(1)(ii)(B) is covered by Sec. 97.511(c)(2) or (3).
(2) The Administrator will establish a separate new unit set-aside
for the State for each such control period. Each such new unit set-
aside will be allocated TR NOX Ozone Season allowances in an
amount equal to the applicable amount of tons of NOX
emissions as set forth in Sec. 97.510(a) and will be allocated
additional TR NOX Ozone Season allowances (if any) in
accordance with Sec. Sec. 97.511(a)(2) and (c)(5) and paragraph
(b)(10) of this section.
(3) The Administrator will determine, for each TR NOX
Ozone Season unit described in paragraph (a)(1) of this section, an
allocation of TR NOX Ozone Season allowances for the later
of the following control periods and for each subsequent control
period:
(i) The control period in 2012;
(ii) The first control period after the control period in which the
TR NOX
[[Page 48418]]
Ozone Season unit commences commercial operation;
(iii) For a unit described in paragraph (a)(1)(ii) of this section,
the first control period in which the TR NOX Ozone Season
unit operates in the State after operating in another jurisdiction and
for which the unit is not already allocated one or more TR
NOX Ozone Season allowances; and
(iv) For a unit described in paragraph (a)(1)(iii) of this section,
the first control period after the control period in which the unit
resumes operation.
(4)(i) The allocation to each TR NOX Ozone Season unit
described in paragraph (a)(1)(i) through (iii) of this section and for
each control period described in paragraph (a)(3) of this section will
be an amount equal to the unit's total tons of NOX emissions
during the immediately preceding control period.
(ii) The Administrator will adjust the allocation amount in
paragraph (a)(4)(i) in accordance with paragraphs (a)(5) through (7)
and (12) of this section.
(5) The Administrator will calculate the sum of the TR
NOX Ozone Season allowances determined for all such TR
NOX Ozone Season units under paragraph (a)(4)(i) of this
section in the State for such control period.
(6) If the amount of TR NOX Ozone Season allowances in
the new unit set-aside for the State for such control period is greater
than or equal to the sum under paragraph (a)(5) of this section, then
the Administrator will allocate the amount of TR NOX Ozone
Season allowances determined for each such TR NOX Ozone
Season unit under paragraph (a)(4)(i) of this section.
(7) If the amount of TR NOX Ozone Season allowances in
the new unit set-aside for the State for such control period is less
than the sum under paragraph (a)(5) of this section, then the
Administrator will allocate to each such TR NOX Ozone Season
unit the amount of the TR NOX Ozone Season allowances
determined under paragraph (a)(4)(i) of this section for the unit,
multiplied by the amount of TR NOX Ozone Season allowances
in the new unit set-aside for such control period, divided by the sum
under paragraph (a)(5) of this section, and rounded to the nearest
allowance.
(8) The Administrator will notify the public, through the
promulgation of the notices of data availability described in Sec.
97.511(b)(1)(i) and (ii), of the amount of TR NOX Ozone
Season allowances allocated under paragraphs (a)(2) through (7) and
(12) of this section for such control period to each TR NOX
Ozone Season unit eligible for such allocation.
(9) If, after completion of the procedures under paragraphs (a)(5)
through (8) of this section for such control period, any unallocated TR
NOX Ozone Season allowances remain in the new unit set-aside
for the State for such control period, the Administrator will allocate
such TR NOX Ozone Season allowances as follows--
(i) The Administrator will determine, for each unit described in
paragraph (a)(1) of this section that commenced commercial operation
during the period starting May 1 of the year before the year of such
control period and ending August 31 of year of such control period, the
positive difference (if any) between the unit's emissions during such
control period and the amount of TR NOX Ozone Season
allowances referenced in the notice of data availability required under
Sec. 97.511(b)(1)(ii) for the unit for such control period;
(ii) The Administrator will determine the sum of the positive
differences determined under paragraph (a)(9)(i) of this section;
(iii) If the amount of unallocated TR NOX Ozone Season
allowances remaining in the new unit set-aside for the State for such
control period is greater than or equal to the sum determined under
paragraph (a)(9)(ii) of this section, then the Administrator will
allocate the amount of TR NOX Ozone Season allowances
determined for each such TR NOX Ozone Season unit under
paragraph (a)(9)(i) of this section; and
(iv) If the amount of unallocated TR NOX Ozone Season
allowances remaining in the new unit set-aside for the State for such
control period is less than the sum under paragraph (a)(9)(ii) of this
section, then the Administrator will allocate to each such TR
NOX Ozone Season unit the amount of the TR NOX
Ozone Season allowances determined under paragraph (a)(9)(i) of this
section for the unit, multiplied by the amount of unallocated TR
NOX Ozone Season allowances remaining in the new unit set-
aside for such control period, divided by the sum under paragraph
(a)(9)(ii) of this section, and rounded to the nearest allowance.
(10) If, after completion of the procedures under paragraphs (a)(9)
and (12) of this section for such control period, any unallocated TR
NOX Ozone Season allowances remain in the new unit set-aside
for the State for such control period, the Administrator will allocate
to each TR NOX Ozone Season unit that is in the State, is
allocated an amount of TR NOX Ozone Season allowances in the
notice of data availability issued under Sec. 97.511(a)(1), and
continues to be allocated TR NOX Ozone Season allowances for
such control period in accordance with Sec. 97.511(a)(2), an amount of
TR NOX Ozone Season allowances equal to the following: the
total amount of such remaining unallocated TR NOX Ozone
Season allowances in such new unit set-aside, multiplied by the unit's
allocation under Sec. 97.511(a) for such control period, divided by
the remainder of the amount of tons in the applicable State
NOX Ozone Season trading budget minus the sum of the amounts
of tons in such new unit set-aside and the Indian country new unit set-
aside for the State for such control period, and rounded to the nearest
allowance.
(11) The Administrator will notify the public, through the
promulgation of the notices of data availability described in Sec.
97.511(b)(1)(iii), (iv), and (v), of the amount of TR NOX
Ozone Season allowances allocated under paragraphs (a)(9), (10), and
(12) of this section for such control period to each TR NOX
Ozone Season unit eligible for such allocation.
(12)(i) Notwithstanding the requirements of paragraphs (a)(2)
through (11) of this section, if the calculations of allocations of a
new unit set-aside for a control period in a given year under paragraph
(a)(7) of this section, paragraphs (a)(6) and (9)(iv) of this section,
or paragraphs (a)(6), (9)(iii), and (10) of this section would
otherwise result in total allocations of such new unit set-aside
exceeding the total amount of such new unit set-aside, then the
Administrator will adjust the results of the calculations under
paragraph (a)(7), (9)(iv), or (10) of this section, as applicable, as
follows. The Administrator will list the TR NOX Ozone Season
units in descending order based on the amount of such units'
allocations under paragraph (a)(7), (9)(iv), or (10) of this section,
as applicable, and, in cases of equal allocation amounts, in
alphabetical order of the relevant source's name and numerical order of
the relevant unit's identification number, and will reduce each unit's
allocation under paragraph (a)(7), (9)(iv), or (10) of this section, as
applicable, by one TR NOX Ozone Season allowance (but not
below zero) in the order in which the units are listed and will repeat
this reduction process as necessary, until the total allocations of
such new unit set-aside equal the total amount of such new unit set-
aside.
(ii) Notwithstanding the requirements of paragraphs (a)(10) and
(11) of this section, if the calculations of allocations of a new unit
set-aside for a control period in a given year under paragraphs (a)(6),
(9)(iii), and (10) of this section would otherwise result in a total
[[Page 48419]]
allocations of such new unit set-aside less than the total amount of
such new unit set-aside, then the Administrator will adjust the results
of the calculations under paragraph (a)(10) of this section, as
follows. The Administrator will list the TR NOX Ozone Season
units in descending order based on the amount of such units'
allocations under paragraph (a)(10) of this section and, in cases of
equal allocation amounts, in alphabetical order of the relevant
source's name and numerical order of the relevant unit's identification
number, and will increase each unit's allocation under paragraph
(a)(10) of this section by one TR NOX Ozone Season allowance
in the order in which the units are listed and will repeat this
increase process as necessary, until the total allocations of such new
unit set-aside equal the total amount of such new unit set-aside.
(b) For each control period in 2012 and thereafter and for the TR
NOX Ozone Season units located in Indian country within the
borders of each State, the Administrator will allocate TR
NOX Ozone Season allowances to the TR NOX Ozone
Season units as follows:
(1) The TR NOX Ozone Season allowances will be allocated
to the following TR NOX Ozone Season units, except as
provided in paragraph (b)(10) of this section:
(i) TR NOX Ozone Season units that are not allocated an
amount of TR NOX Ozone Season allowances in the notice of
data availability issued under Sec. 97.511(a)(1); or
(ii) For purposes of paragraph (b)(9) of this section, TR
NOX Ozone Season units under Sec. 97.511(c)(1)(ii) whose
allocation of an amount of TR NOX Ozone Season allowances
for such control period in the notice of data availability issued under
Sec. 97.511(b)(2)(ii)(B) is covered by Sec. 97.511(c)(2) or (3).
(2) The Administrator will establish a separate Indian country new
unit set-aside for the State for each such control period. Each such
Indian country new unit set-aside will be allocated TR NOX
Ozone Season allowances in an amount equal to the applicable amount of
tons of NOX emissions as set forth in Sec. 97.510(a) and
will be allocated additional TR NOX Ozone Season allowances
(if any) in accordance with Sec. 97.511(c)(5).
(3) The Administrator will determine, for each TR NOX
Ozone Season unit described in paragraph (b)(1) of this section, an
allocation of TR NOX Ozone Season allowances for the later
of the following control periods and for each subsequent control
period:
(i) The control period in 2012; and
(ii) The first control period after the control period in which the
TR NOX Ozone Season unit commences commercial operation.
(4)(i) The allocation to each TR NOX Ozone Season unit
described in paragraph (b)(1)(i) of this section and for each control
period described in paragraph (b)(3) of this section will be an amount
equal to the unit's total tons of NOX emissions during the
immediately preceding control period.
(ii) The Administrator will adjust the allocation amount in
paragraph (b)(4)(i) in accordance with paragraphs (b)(5) through (7)
and (12) of this section.
(5) The Administrator will calculate the sum of the TR
NOX Ozone Season allowances determined for all such TR
NOX Ozone Season units under paragraph (b)(4)(i) of this
section in Indian country within the borders of the State for such
control period.
(6) If the amount of TR NOX Ozone Season allowances in
the Indian country new unit set-aside for the State for such control
period is greater than or equal to the sum under paragraph (b)(5) of
this section, then the Administrator will allocate the amount of TR
NOX Ozone Season allowances determined for each such TR
NOX Ozone Season unit under paragraph (b)(4)(i) of this
section.
(7) If the amount of TR NOX Ozone Season allowances in
the Indian country new unit set-aside for the State for such control
period is less than the sum under paragraph (b)(5) of this section,
then the Administrator will allocate to each such TR NOX
Ozone Season unit the amount of the TR NOX Ozone Season
allowances determined under paragraph (b)(4)(i) of this section for the
unit, multiplied by the amount of TR NOX Ozone Season
allowances in the Indian country new unit set-aside for such control
period, divided by the sum under paragraph (b)(5) of this section, and
rounded to the nearest allowance.
(8) The Administrator will notify the public, through the
promulgation of the notices of data availability described in Sec.
97.511(b)(2)(i) and (ii), of the amount of TR NOX Ozone
Season allowances allocated under paragraphs (b)(2) through (7) and
(12) of this section for such control period to each TR NOX
Ozone Season unit eligible for such allocation.
(9) If, after completion of the procedures under paragraphs (b)(5)
through (8) of this section for such control period, any unallocated TR
NOX Ozone Season allowances remain in the Indian country new
unit set-aside for the State for such control period, the Administrator
will allocate such TR NOX Ozone Season allowances as
follows--
(i) The Administrator will determine, for each unit described in
paragraph (b)(1) of this section that commenced commercial operation
during the period starting May 1 of the year before the year of such
control period and ending August 31 of year of such control period, the
positive difference (if any) between the unit's emissions during such
control period and the amount of TR NOX Ozone Season
allowances referenced in the notice of data availability required under
Sec. 97.511(b)(2)(ii) for the unit for such control period;
(ii) The Administrator will determine the sum of the positive
differences determined under paragraph (b)(9)(i) of this section;
(iii) If the amount of unallocated TR NOX Ozone Season
allowances remaining in the Indian country new unit set-aside for the
State for such control period is greater than or equal to the sum
determined under paragraph (b)(9)(ii) of this section, then the
Administrator will allocate the amount of TR NOX Ozone
Season allowances determined for each such TR NOX Ozone
Season unit under paragraph (b)(9)(i) of this section; and
(iv) If the amount of unallocated TR NOX Ozone Season
allowances remaining in the Indian country new unit set-aside for the
State for such control period is less than the sum under paragraph
(b)(9)(ii) of this section, then the Administrator will allocate to
each such TR NOX Ozone Season unit the amount of the TR
NOX Ozone Season allowances determined under paragraph
(b)(9)(i) of this section for the unit, multiplied by the amount of
unallocated TR NOX Ozone Season allowances remaining in the
Indian country new unit set-aside for such control period, divided by
the sum under paragraph (b)(9)(ii) of this section, and rounded to the
nearest allowance.
(10) If, after completion of the procedures under paragraphs (b)(9)
and (12) of this section for such control period, any unallocated TR
NOX Ozone Season allowances remain in the Indian country new
unit set-aside for the State for such control period, the Administrator
will:
(i) Transfer such unallocated TR NOX Ozone Season
allowances to the new unit set-aside for the State for such control
period; or
(ii) If the State has a SIP revision approved under Sec.
52.38(b)(4) or (5) covering such control period, include such
unallocated TR NOX Ozone Season allowances in the portion of
the State NOX Ozone Season trading budget that may be
allocated for such control period in accordance with such SIP revision.
[[Page 48420]]
(11) The Administrator will notify the public, through the
promulgation of the notices of data availability described in Sec.
97.511(b)(2)(iii), (iv), and (v), of the amount of TR NOX
Ozone Season allowances allocated under paragraphs (b)(9), (10), and
(12) of this section for such control period to each TR NOX
Ozone Season unit eligible for such allocation.
(12)(i) Notwithstanding the requirements of paragraphs (b)(2)
through (11) of this section, if the calculations of allocations of an
Indian country new unit set-aside for a control period in a given year
under paragraph (b)(7) of this section, paragraphs (b)(6) and (9)(iv)
of this section, or paragraphs (b)(6), (9)(iii), and (10) of this
section would otherwise result in total allocations of such Indian
country new unit set-aside exceeding the total amount of such Indian
country new unit set-aside, then the Administrator will adjust the
results of the calculations under paragraph (b)(7), (9)(iv), or (10) of
this section, as applicable, as follows. The Administrator will list
the TR NOX Ozone Season units in descending order based on
the amount of such units' allocations under paragraph (b)(7), (9)(iv),
or (10) of this section, as applicable, and, in cases of equal
allocation amounts, in alphabetical order of the relevant source's name
and numerical order of the relevant unit's identification number, and
will reduce each unit's allocation under paragraph (b)(7), (9)(iv), or
(10) of this section, as applicable, by one TR NOX Ozone
Season allowance (but not below zero) in the order in which the units
are listed and will repeat this reduction process as necessary, until
the total allocations of such Indian country new unit set-aside equal
the total amount of such Indian country new unit set-aside.
(ii) Notwithstanding the requirements of paragraphs (b)(10) and
(11) of this section, if the calculations of allocations of an Indian
country new unit set-aside for a control period in a given year under
paragraphs (b)(6), (9)(iii), and (10) of this section would otherwise
result in a total allocations of such Indian country new unit set-aside
less than the total amount of such Indian country new unit set-aside,
then the Administrator will adjust the results of the calculations
under paragraph (b)(10) of this section, as follows. The Administrator
will list the TR NOX Ozone Season units in descending order
based on the amount of such units' allocations under paragraph (b)(10)
of this section and, in cases of equal allocation amounts, in
alphabetical order of the relevant source's name and numerical order of
the relevant unit's identification number, and will increase each
unit's allocation under paragraph (b)(10) of this section by one TR
NOX Ozone Season allowance in the order in which the units
are listed and will repeat this increase process as necessary, until
the total allocations of such Indian country new unit set-aside equal
the total amount of such Indian country new unit set-aside.
Sec. 97.513 Authorization of designated representative and alternate
designated representative.
(a) Except as provided under Sec. 97.515, each TR NOX
Ozone Season source, including all TR NOX Ozone Season units
at the source, shall have one and only one designated representative,
with regard to all matters under the TR NOX Ozone Season
Trading Program.
(1) The designated representative shall be selected by an agreement
binding on the owners and operators of the source and all TR
NOX Ozone Season units at the source and shall act in
accordance with the certification statement in Sec. 97.516(a)(4)(iii).
(2) Upon and after receipt by the Administrator of a complete
certificate of representation under Sec. 97.516:
(i) The designated representative shall be authorized and shall
represent and, by his or her representations, actions, inactions, or
submissions, legally bind each owner and operator of the source and
each TR NOX Ozone Season unit at the source in all matters
pertaining to the TR NOX Ozone Season Trading Program,
notwithstanding any agreement between the designated representative and
such owners and operators; and
(ii) The owners and operators of the source and each TR
NOX Ozone Season unit at the source shall be bound by any
decision or order issued to the designated representative by the
Administrator regarding the source or any such unit.
(b) Except as provided under Sec. 97.515, each TR NOX
Ozone Season source may have one and only one alternate designated
representative, who may act on behalf of the designated representative.
The agreement by which the alternate designated representative is
selected shall include a procedure for authorizing the alternate
designated representative to act in lieu of the designated
representative.
(1) The alternate designated representative shall be selected by an
agreement binding on the owners and operators of the source and all TR
NOX Ozone Season units at the source and shall act in
accordance with the certification statement in Sec. 97.516(a)(4)(iii).
(2) Upon and after receipt by the Administrator of a complete
certificate of representation under Sec. 97.516,
(i) The alternate designated representative shall be authorized;
(ii) Any representation, action, inaction, or submission by the
alternate designated representative shall be deemed to be a
representation, action, inaction, or submission by the designated
representative; and
(iii) The owners and operators of the source and each TR
NOX Ozone Season unit at the source shall be bound by any
decision or order issued to the alternate designated representative by
the Administrator regarding the source or any such unit.
(c) Except in this section, Sec. 97.502, and Sec. Sec. 97.514
through 97.518, whenever the term ``designated representative'' (as
distinguished from the term ``common designated representative'') is
used in this subpart, the term shall be construed to include the
designated representative or any alternate designated representative.
Sec. 97.514 Responsibilities of designated representative and
alternate designated representative.
(a) Except as provided under Sec. 97.518 concerning delegation of
authority to make submissions, each submission under the TR
NOX Ozone Season Trading Program shall be made, signed, and
certified by the designated representative or alternate designated
representative for each TR NOX Ozone Season source and TR
NOX Ozone Season unit for which the submission is made. Each
such submission shall include the following certification statement by
the designated representative or alternate designated representative:
``I am authorized to make this submission on behalf of the owners and
operators of the source or 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.''
(b) The Administrator will accept or act on a submission made for a
TR NOX Ozone Season source or a TR NOX Ozone
Season unit only if the
[[Page 48421]]
submission has been made, signed, and certified in accordance with
paragraph (a) of this section and Sec. 97.518.
Sec. 97.515 Changing designated representative and alternate
designated representative; changes in owners and operators; changes in
units at the source.
(a) Changing designated representative. The designated
representative may be changed at any time upon receipt by the
Administrator of a superseding complete certificate of representation
under Sec. 97.516. Notwithstanding any such change, all
representations, actions, inactions, and submissions by the previous
designated representative before the time and date when the
Administrator receives the superseding certificate of representation
shall be binding on the new designated representative and the owners
and operators of the TR NOX Ozone Season source and the TR
NOX Ozone Season units at the source.
(b) Changing alternate designated representative. The alternate
designated representative may be changed at any time upon receipt by
the Administrator of a superseding complete certificate of
representation under Sec. 97.516. Notwithstanding any such change, all
representations, actions, inactions, and submissions by the previous
alternate designated representative before the time and date when the
Administrator receives the superseding certificate of representation
shall be binding on the new alternate designated representative, the
designated representative, and the owners and operators of the TR
NOX Ozone Season source and the TR NOX Ozone
Season units at the source.
(c) Changes in owners and operators. (1) In the event an owner or
operator of a TR NOX Ozone Season source or a TR
NOX Ozone Season unit at the source is not included in the
list of owners and operators in the certificate of representation under
Sec. 97.516, such owner or operator shall be deemed to be subject to
and bound by the certificate of representation, the representations,
actions, inactions, and submissions of the designated representative
and any alternate designated representative of the source or unit, and
the decisions and orders of the Administrator, as if the owner or
operator were included in such list.
(2) Within 30 days after any change in the owners and operators of
a TR NOX Ozone Season source or a TR NOX Ozone
Season unit at the source, including the addition or removal of an
owner or operator, the designated representative or any alternate
designated representative shall submit a revision to the certificate of
representation under Sec. 97.516 amending the list of owners and
operators to reflect the change.
(d) Changes in units at the source. Within 30 days of any change in
which units are located at a TR NOX Ozone Season source
(including the addition or removal of a unit), the designated
representative or any alternate designated representative shall submit
a certificate of representation under Sec. 97.516 amending the list of
units to reflect the change.
(1) If the change is the addition of a unit that operated (other
than for purposes of testing by the manufacturer before initial
installation) before being located at the source, then the certificate
of representation shall identify, in a format prescribed by the
Administrator, the entity from whom the unit was purchased or otherwise
obtained (including name, address, telephone number, and facsimile
number (if any)), the date on which the unit was purchased or otherwise
obtained, and the date on which the unit became located at the source.
(2) If the change is the removal of a unit, then the certificate of
representation shall identify, in a format prescribed by the
Administrator, the entity to which the unit was sold or that otherwise
obtained the unit (including name, address, telephone number, and
facsimile number (if any)), the date on which the unit was sold or
otherwise obtained, and the date on which the unit became no longer
located at the source.
Sec. 97.516 Certificate of representation.
(a) A complete certificate of representation for a designated
representative or an alternate designated representative shall include
the following elements in a format prescribed by the Administrator:
(1) Identification of the TR NOX Ozone Season source,
and each TR NOX Ozone Season unit at the source, for which
the certificate of representation is submitted, including source name,
source category and NAICS code (or, in the absence of a NAICS code, an
equivalent code), State, plant code, county, latitude and longitude,
unit identification number and type, identification number and
nameplate capacity (in MWe, rounded to the nearest tenth) of each
generator served by each such unit, actual or projected date of
commencement of commercial operation, and a statement of whether such
source is located in Indian Country. If a projected date of
commencement of commercial operation is provided, the actual date of
commencement of commercial operation shall be provided when such
information becomes available.
(2) The name, address, e-mail address (if any), telephone number,
and facsimile transmission number (if any) of the designated
representative and any alternate designated representative.
(3) A list of the owners and operators of the TR NOX
Ozone Season source and of each TR NOX Ozone Season unit at
the source.
(4) The following certification statements by the designated
representative and any alternate designated representative--
(i) ``I certify that I was selected as the designated
representative or alternate designated representative, as applicable,
by an agreement binding on the owners and operators of the source and
each TR NOX Ozone Season unit at the source.''
(ii) ``I certify that I have all the necessary authority to carry
out my duties and responsibilities under the TR NOX Ozone
Season Trading Program on behalf of the owners and operators of the
source and of each TR NOX Ozone Season 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 Administrator regarding the source or
unit.''
(iii) ``Where there are multiple holders of a legal or equitable
title to, or a leasehold interest in, a TR NOX Ozone Season
unit, or where a utility or industrial customer purchases power from a
TR NOX Ozone Season unit under a life-of-the-unit, firm
power contractual arrangement, I certify that: I have given a written
notice of my selection as the `designated representative' or `alternate
designated representative', as applicable, and of the agreement by
which I was selected to each owner and operator of the source and of
each TR NOX Ozone Season unit at the source; and TR
NOX Ozone Season allowances and proceeds of transactions
involving TR NOX Ozone Season allowances will be deemed to
be held or distributed in proportion to each holder's legal, equitable,
leasehold, or contractual reservation or entitlement, except that, if
such multiple holders have expressly provided for a different
distribution of TR NOX Ozone Season allowances by contract,
TR NOX Ozone Season allowances and proceeds of transactions
involving TR NOX Ozone Season allowances will be deemed to
be held or distributed in accordance with the contract.''
(5) The signature of the designated representative and any
alternate designated representative and the dates signed.
[[Page 48422]]
(b) Unless otherwise required by the Administrator, documents of
agreement referred to in the certificate of representation shall not be
submitted to the Administrator. The Administrator shall not be under
any obligation to review or evaluate the sufficiency of such documents,
if submitted.
Sec. 97.517 Objections concerning designated representative and
alternate designated representative.
(a) Once a complete certificate of representation under Sec.
97.516 has been submitted and received, the Administrator will rely on
the certificate of representation unless and until a superseding
complete certificate of representation under Sec. 97.516 is received
by the Administrator.
(b) Except as provided in paragraph (a) of this section, no
objection or other communication submitted to the Administrator
concerning the authorization, or any representation, action, inaction,
or submission, of a designated representative or alternate designated
representative shall affect any representation, action, inaction, or
submission of the designated representative or alternate designated
representative or the finality of any decision or order by the
Administrator under the TR NOX Ozone Season Trading Program.
(c) The Administrator will not adjudicate any private legal dispute
concerning the authorization or any representation, action, inaction,
or submission of any designated representative or alternate designated
representative, including private legal disputes concerning the
proceeds of TR NOX Ozone Season allowance transfers.
Sec. 97.518 Delegation by designated representative and alternate
designated representative.
(a) A designated representative may delegate, to one or more
natural persons, his or her authority to make an electronic submission
to the Administrator provided for or required under this subpart.
(b) An alternate designated representative may delegate, to one or
more natural persons, his or her authority to make an electronic
submission to the Administrator provided for or required under this
subpart.
(c) In order to delegate authority to a natural person to make an
electronic submission to the Administrator in accordance with paragraph
(a) or (b) of this section, the designated representative or alternate
designated representative, as appropriate, must submit to the
Administrator a notice of delegation, in a format prescribed by the
Administrator, that includes the following elements:
(1) The name, address, e-mail address, telephone number, and
facsimile transmission number (if any) of such designated
representative or alternate designated representative;
(2) The name, address, e-mail address, telephone number, and
facsimile transmission number (if any) of each such natural person
(referred to in this section as an ``agent'');
(3) For each such natural person, a list of the type or types of
electronic submissions under paragraph (a) or (b) of this section for
which authority is delegated to him or her; and
(4) The following certification statements by such designated
representative or alternate designated representative:
(i) ``I agree that any electronic submission to the Administrator
that is made by an agent identified in this notice of delegation and of
a type listed for such agent in this notice of delegation and that is
made when I am a designated representative or alternate designated
representative, as appropriate, and before this notice of delegation is
superseded by another notice of delegation under 40 CFR 97.518(d) shall
be deemed to be an electronic submission by me.''
(ii) ``Until this notice of delegation is superseded by another
notice of delegation under 40 CFR 97.518(d), I agree to maintain an e-
mail account and to notify the Administrator immediately of any change
in my e-mail address unless all delegation of authority by me under 40
CFR 97.518 is terminated.''.
(d) A notice of delegation submitted under paragraph (c) of this
section shall be effective, with regard to the designated
representative or alternate designated representative identified in
such notice, upon receipt of such notice by the Administrator and until
receipt by the Administrator of a superseding notice of delegation
submitted by such designated representative or alternate designated
representative, as appropriate. The superseding notice of delegation
may replace any previously identified agent, add a new agent, or
eliminate entirely any delegation of authority.
(e) Any electronic submission covered by the certification in
paragraph (c)(4)(i) of this section and made in accordance with a
notice of delegation effective under paragraph (d) of this section
shall be deemed to be an electronic submission by the designated
representative or alternate designated representative submitting such
notice of delegation.
Sec. 97.519 [Reserved]
Sec. 97.520 Establishment of compliance accounts, assurance accounts,
and general accounts.
(a) Compliance accounts. Upon receipt of a complete certificate of
representation under Sec. 97.516, the Administrator will establish a
compliance account for the TR NOX Ozone Season source for
which the certificate of representation was submitted, unless the
source already has a compliance account. The designated representative
and any alternate designated representative of the source shall be the
authorized account representative and the alternate authorized account
representative respectively of the compliance account.
(b) Assurance accounts. The Administrator will establish assurance
accounts for certain owners and operators and States in accordance with
Sec. 97.525(b)(3).
(c) General accounts. (1) Application for general account. (i) Any
person may apply to open a general account, for the purpose of holding
and transferring TR NOX Ozone Season allowances, by
submitting to the Administrator a complete application for a general
account. Such application shall designate one and only one authorized
account representative and may designate one and only one alternate
authorized account representative who may act on behalf of the
authorized account representative.
(A) The authorized account representative and alternate authorized
account representative shall be selected by an agreement binding on the
persons who have an ownership interest with respect to TR
NOX Ozone Season allowances held in the general account.
(B) The agreement by which the alternate authorized account
representative is selected shall include a procedure for authorizing
the alternate authorized account representative to act in lieu of the
authorized account representative.
(ii) A complete application for a general account shall include the
following elements in a format prescribed by the Administrator:
(A) Name, mailing address, e-mail address (if any), telephone
number, and facsimile transmission number (if any) of the authorized
account representative and any alternate authorized account
representative;
(B) An identifying name for the general account;
(C) A list of all persons subject to a binding agreement for the
authorized account representative and any alternate authorized account
representative to
[[Page 48423]]
represent their ownership interest with respect to the TR
NOX Ozone Season allowances held in the general account;
(D) The following certification statement by the authorized account
representative and any alternate authorized account representative: ``I
certify that I was selected as the authorized account representative or
the alternate authorized account representative, as applicable, by an
agreement that is binding on all persons who have an ownership interest
with respect to TR NOX Ozone Season allowances held in the
general account. I certify that I have all the necessary authority to
carry out my duties and responsibilities under the TR NOX
Ozone Season 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 decision or order issued to me by
the Administrator regarding the general account.''
(E) The signature of the authorized account representative and any
alternate authorized account representative and the dates signed.
(iii) Unless otherwise required by the Administrator, documents of
agreement referred to in the application for a general account shall
not be submitted to the Administrator. The Administrator shall not be
under any obligation to review or evaluate the sufficiency of such
documents, if submitted.
(2) Authorization of authorized account representative and
alternate authorized account representative. (i) Upon receipt by the
Administrator of a complete application for a general account under
paragraph (b)(1) of this section, the Administrator will establish a
general account for the person or persons for whom the application is
submitted, and upon and after such receipt by the Administrator:
(A) The authorized account representative of the general account
shall be authorized and shall represent and, by his or her
representations, actions, inactions, or submissions, legally bind each
person who has an ownership interest with respect to TR NOX
Ozone Season allowances held in the general account in all matters
pertaining to the TR NOX Ozone Season Trading Program,
notwithstanding any agreement between the authorized account
representative and such person.
(B) Any alternate authorized account representative shall be
authorized, and any representation, action, inaction, or submission by
any alternate authorized account representative shall be deemed to be a
representation, action, inaction, or submission by the authorized
account representative.
(C) Each person who has an ownership interest with respect to TR
NOX Ozone Season allowances held in the general account
shall be bound by any decision or order issued to the authorized
account representative or alternate authorized account representative
by the Administrator regarding the general account.
(ii) Except as provided in paragraph (c)(5) of this section
concerning delegation of authority to make submissions, each submission
concerning the general account shall be made, signed, and certified by
the authorized account representative or any alternate authorized
account representative for the persons having an ownership interest
with respect to TR NOX Ozone Season allowances held in the
general account. Each such submission shall include the following
certification statement by the authorized account representative or any
alternate authorized account representative: ``I am authorized to make
this submission on behalf of the persons having an ownership interest
with respect to the TR NOX Ozone Season 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.''
(iii) Except in this section, whenever the term ``authorized
account representative'' is used in this subpart, the term shall be
construed to include the authorized account representative or any
alternate authorized account representative.
(3) Changing authorized account representative and alternate
authorized account representative; changes in persons with ownership
interest. (i) The authorized account representative of 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 (c)(1) of this section. Notwithstanding any such change, all
representations, actions, inactions, and submissions by the previous
authorized account representative before the time and date when the
Administrator receives the superseding application for a general
account shall be binding on the new authorized account representative
and the persons with an ownership interest with respect to the TR
NOX Ozone Season allowances in the general account.
(ii) The alternate authorized account representative of 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 (c)(1) of this section. Notwithstanding any such change, all
representations, actions, inactions, and submissions by the previous
alternate authorized account representative before the time and date
when the Administrator receives the superseding application for a
general account shall be binding on the new alternate authorized
account representative, the authorized account representative, and the
persons with an ownership interest with respect to the TR
NOX Ozone Season allowances in the general account.
(iii)(A) In the event a person having an ownership interest with
respect to TR NOX Ozone Season allowances in the general
account is not included in the list of such persons in the application
for a general account, such person shall be deemed to be subject to and
bound by the application for a general account, the representation,
actions, inactions, and submissions of the authorized account
representative and any alternate authorized account representative of
the account, and the decisions and orders of the Administrator, as if
the person were included in such list.
(B) Within 30 days after any change in the persons having an
ownership interest with respect to NOX Ozone Season
allowances in the general account, including the addition or removal of
a person, the authorized account representative or any alternate
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 TR NOX Ozone
Season allowances in the general account to include the change.
(4) Objections concerning authorized account representative and
alternate authorized account representative. (i) Once a complete
application for a general account under paragraph (c)(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.
[[Page 48424]]
(ii) Except as provided in paragraph (c)(4)(i) of this section, no
objection or other communication submitted to the Administrator
concerning the authorization, or any representation, action, inaction,
or submission of the authorized account representative or any alternate
authorized account representative of a general account shall affect any
representation, action, inaction, or submission of the authorized
account representative or any alternate authorized account
representative or the finality of any decision or order by the
Administrator under the TR NOX Ozone Season Trading Program.
(iii) The Administrator will not adjudicate any private legal
dispute concerning the authorization or any representation, action,
inaction, or submission of the authorized account representative or any
alternate authorized account representative of a general account,
including private legal disputes concerning the proceeds of TR
NOX Ozone Season allowance transfers.
(5) Delegation by authorized account representative and alternate
authorized account representative. (i) An authorized account
representative of a general account may delegate, to one or more
natural persons, his or her authority to make an electronic submission
to the Administrator provided for or required under this subpart.
(ii) An alternate authorized account representative of a general
account may delegate, to one or more natural persons, his or her
authority to make an electronic submission to the Administrator
provided for or required under this subpart.
(iii) In order to delegate authority to a natural person to make an
electronic submission to the Administrator in accordance with paragraph
(c)(5)(i) or (ii) of this section, the authorized account
representative or alternate authorized account representative, as
appropriate, must submit to the Administrator a notice of delegation,
in a format prescribed by the Administrator, that includes the
following elements:
(A) The name, address, e-mail address, telephone number, and
facsimile transmission number (if any) of such authorized account
representative or alternate authorized account representative;
(B) The name, address, e-mail address, telephone number, and
facsimile transmission number (if any) of each such natural person
(referred to in this section as an ``agent'');
(C) For each such natural person, a list of the type or types of
electronic submissions under paragraph (c)(5)(i) or (ii) of this
section for which authority is delegated to him or her;
(D) The following certification statement by such authorized
account representative or alternate authorized account representative:
``I agree that any electronic submission to the Administrator that is
made by an agent identified in this notice of delegation and of a type
listed for such agent in this notice of delegation and that is made
when I am an authorized account representative or alternate authorized
representative, as appropriate, and before this notice of delegation is
superseded by another notice of delegation under 40 CFR
97.520(c)(5)(iv) shall be deemed to be an electronic submission by
me.''; and
(E) The following certification statement by such authorized
account representative or alternate authorized account representative:
``Until this notice of delegation is superseded by another notice of
delegation under 40 CFR 97.520(c)(5)(iv), I agree to maintain an e-mail
account and to notify the Administrator immediately of any change in my
e-mail address unless all delegation of authority by me under 40 CFR
97.520(c)(5) is terminated.''.
(iv) A notice of delegation submitted under paragraph (c)(5)(iii)
of this section shall be effective, with regard to the authorized
account representative or alternate authorized account representative
identified in such notice, upon receipt of such notice by the
Administrator and until receipt by the Administrator of a superseding
notice of delegation submitted by such authorized account
representative or alternate authorized account representative, as
appropriate. The superseding notice of delegation may replace any
previously identified agent, add a new agent, or eliminate entirely any
delegation of authority.
(v) Any electronic submission covered by the certification in
paragraph (c)(5)(iii)(D) of this section and made in accordance with a
notice of delegation effective under paragraph (c)(5)(iv) of this
section shall be deemed to be an electronic submission by the
designated representative or alternate designated representative
submitting such notice of delegation.
(6) Closing a general account. (i) The authorized account
representative or alternate authorized account representative of a
general account may submit to the Administrator a request to close the
account. Such request shall include a correctly submitted TR
NOX Ozone Season allowance transfer under Sec. 97.522 for
any TR NOX Ozone Season allowances in the account to one or
more other Allowance Management System accounts.
(ii) If a general account has no TR NOX Ozone Season
allowance transfers to or from the account for a 12-month period or
longer and does not contain any TR NOX Ozone Season
allowances, the Administrator may notify the authorized account
representative for the account that the account will be closed after 30
days after the notice is sent. The account will be closed after the 30-
day period unless, before the end of the 30-day period, the
Administrator receives a correctly submitted TR NOX Ozone
Season allowance transfer under Sec. 97.522 to the account or a
statement submitted by the authorized account representative or
alternate authorized account representative demonstrating to the
satisfaction of the Administrator good cause as to why the account
should not be closed.
(d) Account identification. The Administrator will assign a unique
identifying number to each account established under paragraph (a),
(b), or (c) of this section.
(e) Responsibilities of authorized account representative and
alternate authorized account representative. After the establishment of
a compliance account or general account, the Administrator will accept
or act on a submission pertaining to the account, including, but not
limited to, submissions concerning the deduction or transfer of TR
NOX Ozone Season allowances in the account, only if the
submission has been made, signed, and certified in accordance with
Sec. Sec. 97.514(a) and 97.518 or paragraphs (c)(2)(ii) and (c)(5) of
this section.
Sec. 97.521 Recordation of TR NOX Ozone Season allowance allocations
and auction results.
(a) By November 7, 2011, the Administrator will record in each TR
NOX Ozone Season source's compliance account the TR
NOX Ozone Season allowances allocated to the TR
NOX Ozone Season units at the source in accordance with
Sec. 97.511(a) for the control period in 2012.
(b) By November 7, 2011, the Administrator will record in each TR
NOX Ozone Season source's compliance account the TR
NOX Ozone Season allowances allocated to the TR
NOX Ozone Season units at the source in accordance with
Sec. 97.511(a) for the control period in 2013, unless the State in
which the source is located notifies the Administrator in writing by
October 17, 2011 of the State's intent to submit to the Administrator a
complete SIP revision by April 1, 2012 meeting the
[[Page 48425]]
requirements of Sec. 52.38(b)(3)(i) through (iv) of this chapter.
(1) If, by April 1, 2012, the State does not submit to the
Administrator such complete SIP revision, the Administrator will record
by April 15, 2012 in each TR NOX Ozone Season source's
compliance account the TR NOX Ozone Season allowances
allocated to the TR NOX Ozone Season units at the source in
accordance with Sec. 97.511(a) for the control period in 2013.
(2) If the State submits to the Administrator by April 1, 2012, and
the Administrator approves by October 1, 2012, such complete SIP
revision, the Administrator will record by October 1, 2012 in each TR
NOX Ozone Season source's compliance account the TR
NOX Ozone Season allowances allocated to the TR
NOX Ozone Season units at the source as provided in such
approved, complete SIP revision for the control period in 2013.
(3) If the State submits to the Administrator by April 1, 2012, and
the Administrator does not approve by October 1, 2012, such complete
SIP revision, the Administrator will record by October 1, 2012 in each
TR NOX Ozone Season source's compliance account the TR
NOX Ozone Season allowances allocated to the TR
NOX Ozone Season units at the source in accordance with
Sec. 97.511(a) for the control period in 2013.
(c) By July 1, 2013, the Administrator will record in each TR
NOX Ozone Season source's compliance account the TR
NOX Ozone Season allowances allocated to the TR
NOX Ozone Season units at the source, or in each appropriate
Allowance Management System account the TR NOX Ozone Season
allowances auctioned to TR NOX Ozone Season units, in
accordance with Sec. 97.511(a), or with a SIP revision approved under
Sec. 52.38(b)(4) or (5) of this chapter, for the control period in
2014 and 2015.
(d) By July 1, 2014, the Administrator will record in each TR
NOX Ozone Season source's compliance account the TR
NOX Ozone Season allowances allocated to the TR
NOX Ozone Season units at the source, or in each appropriate
Allowance Management System account the TR NOX Ozone Season
allowances auctioned to TR NOX Ozone Season units, in
accordance with Sec. 97.511(a), or with a SIP revision approved under
Sec. 52.38(b)(4) or (5) of this chapter, for the control period in
2016 and 2017.
(e) By July 1, 2015, the Administrator will record in each TR
NOX Ozone Season source's compliance account the TR
NOX Ozone Season allowances allocated to the TR
NOX Ozone Season units at the source, or in each appropriate
Allowance Management System account the TR NOX Ozone Season
allowances auctioned to TR NOX Ozone Season units, in
accordance with Sec. 97.511(a), or with a SIP revision approved under
Sec. 52.38(b)(4) or (5) of this chapter, for the control period in
2018 and 2019.
(f) By July 1, 2016 and July 1 of each year thereafter, the
Administrator will record in each TR NOX Ozone Season
source's compliance account the TR NOX Ozone Season
allowances allocated to the TR NOX Ozone Season units at the
source, or in each appropriate Allowance Management System account the
TR NOX Ozone Season allowances auctioned to TR
NOX Ozone Season units, in accordance with Sec. 97.511(a),
or with a SIP revision approved under Sec. 52.38(b)(4) or (5) of this
chapter, for the control period in the fourth year after the year of
the applicable recordation deadline under this paragraph.
(g) By August 1, 2012 and August 1 of each year thereafter, the
Administrator will record in each TR NOX Ozone Season
source's compliance account the TR NOX Ozone Season
allowances allocated to the TR NOX Ozone Season units at the
source, or in each appropriate Allowance Management System account the
TR NOX Ozone Season allowances auctioned to TR
NOX Ozone Season units, in accordance with Sec.
97.512(a)(2) through (8) and (12), or with a SIP revision approved
under Sec. 52.38(b)(4) or (5) of this chapter, for the control period
in the year of the applicable recordation deadline under this
paragraph.
(h) By August 1, 2012 and August 1 of each year thereafter, the
Administrator will record in each TR NOX Ozone Season
source's compliance account the TR NOX Ozone Season
allowances allocated to the TR NOX Ozone Season units at the
source in accordance with Sec. 97.512(b)(2) through (8) and (12) for
the control period in the year of the applicable recordation deadline
under this paragraph.
(i) By November 15, 2012 and November 15 of each year thereafter,
the Administrator will record in each TR NOX Ozone Season
source's compliance account the TR NOX Ozone Season
allowances allocated to the TR NOX Ozone Season units at the
source in accordance with Sec. 97.512(a)(9) through (12), for the
control period in the year of the applicable recordation deadline under
this paragraph.
(j) By the date on which any allocation or auction results, other
than an allocation or auction results described in paragraphs (a)
through (i) of this section, of TR NOX Ozone Season
allowances to a recipient is made by or are submitted to the
Administrator in accordance with Sec. 97.511 or Sec. 97.512 or with a
SIP revision approved under Sec. 52.38(b)(4) or (5) of this chapter,
the Administrator will record such allocation or auction results in the
appropriate Allowance Management System account.
(k) When recording the allocation or auction of TR NOX
Ozone Season allowances to a TR NOX Ozone Season unit or
other entity in an Allowance Management System account, the
Administrator will assign each TR NOX Ozone Season allowance
a unique identification number that will include digits identifying the
year of the control period for which the TR NOX Ozone Season
allowance is allocated or auctioned.
Sec. 97.522 Submission of TR NOX Ozone Season allowance transfers.
(a) An authorized account representative seeking recordation of a
TR NOX Ozone Season allowance transfer shall submit the
transfer to the Administrator.
(b) A TR NOX Ozone Season allowance transfer shall be
correctly submitted if:
(1) The transfer includes the following elements, in a format
prescribed by the Administrator:
(i) The account numbers established by the Administrator for both
the transferor and transferee accounts;
(ii) The serial number of each TR NOX Ozone Season
allowance that is in the transferor account and is to be transferred;
and
(iii) The name and signature of the authorized account
representative of the transferor account and the date signed; and
(2) When the Administrator attempts to record the transfer, the
transferor account includes each TR NOX Ozone Season
allowance identified by serial number in the transfer.
Sec. 97.523 Recordation of TR NOX Ozone Season allowance transfers.
(a) Within 5 business days (except as provided in paragraph (b) of
this section) of receiving a TR NOX Ozone Season allowance
transfer that is correctly submitted under Sec. 97.522, the
Administrator will record a TR NOX Ozone Season allowance
transfer by moving each TR NOX Ozone Season allowance from
the transferor account to the transferee account as specified in the
transfer.
(b) A TR NOX Ozone Season allowance transfer to or from
a
[[Page 48426]]
compliance account that is submitted for recordation after the
allowance transfer deadline for a control period and that includes any
TR NOX Ozone Season allowances allocated for any control
period before such allowance transfer deadline will not be recorded
until after the Administrator completes the deductions from such
compliance account under Sec. 97.524 for the control period
immediately before such allowance transfer deadline.
(c) Where a TR NOX Ozone Season allowance transfer is
not correctly submitted under Sec. 97.522, the Administrator will not
record such transfer.
(d) Within 5 business days of recordation of a TR NOX
Ozone Season allowance transfer under paragraphs (a) and (b) of the
section, the Administrator will notify the authorized account
representatives of both the transferor and transferee accounts.
(e) Within 10 business days of receipt of a TR NOX Ozone
Season allowance transfer that is not correctly submitted under Sec.
97.522, the Administrator will notify the 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.
Sec. 97.524 Compliance with TR NOX Ozone Season emissions limitation.
(a) Availability for deduction for compliance. TR NOX
Ozone Season allowances are available to be deducted for compliance
with a source's TR NOX Ozone Season emissions limitation for
a control period in a given year only if the TR NOX Ozone
Season allowances:
(1) Were allocated for such control period or a control period in a
prior year; and
(2) Are held in the source's compliance account as of the allowance
transfer deadline for such control period.
(b) Deductions for compliance. After the recordation, in accordance
with Sec. 97.523, of TR NOX Ozone Season allowance
transfers submitted by the allowance transfer deadline for a control
period in a given year, the Administrator will deduct from each
source's compliance account TR NOX Ozone Season allowances
available under paragraph (a) of this section in order to determine
whether the source meets the TR NOX Ozone Season emissions
limitation for such control period, as follows:
(1) Until the amount of TR NOX Ozone Season allowances
deducted equals the number of tons of total NOX emissions
from all TR NOX Ozone Season units at the source for such
control period; or
(2) If there are insufficient TR NOX Ozone Season
allowances to complete the deductions in paragraph (b)(1) of this
section, until no more TR NOX Ozone Season allowances
available under paragraph (a) of this section remain in the compliance
account.
(c)(1) Identification of TR NOX Ozone Season allowances by serial
number. The authorized account representative for a source's compliance
account may request that specific TR NOX Ozone Season
allowances, identified by serial number, in the compliance account be
deducted for emissions or excess emissions for a control period in a
given year in accordance with paragraph (b) or (d) of this section. In
order to be complete, such request shall be submitted to the
Administrator by the allowance transfer deadline for such control
period and include, in a format prescribed by the Administrator, the
identification of the TR NOX Ozone Season source and the
appropriate serial numbers.
(2) First-in, first-out. The Administrator will deduct TR
NOX Ozone Season allowances under paragraph (b) or (d) of
this section from the source's compliance account in accordance with a
complete request under paragraph (c)(1) of this section or, in the
absence of such request or in the case of identification of an
insufficient amount of TR NOX Ozone Season allowances in
such request, on a first-in, first-out accounting basis in the
following order:
(i) Any TR NOX Ozone Season allowances that were
allocated to the units at the source and not transferred out of the
compliance account, in the order of recordation; and then
(ii) Any TR NOX Ozone Season allowances that were
allocated to any unit and transferred to and recorded in the compliance
account pursuant to this subpart, in the order of recordation.
(d) Deductions for excess emissions. After making the deductions
for compliance under paragraph (b) of this section for a control period
in a year in which the TR NOX Ozone Season source has excess
emissions, the Administrator will deduct from the source's compliance
account an amount of TR NOX Ozone Season allowances,
allocated for a control period in a prior year or the control period in
the year of the excess emissions or in the immediately following year,
equal to two times the number of tons of the source's excess emissions.
(e) Recordation of deductions. The Administrator will record in the
appropriate compliance account all deductions from such an account
under paragraphs (b) and (d) of this section.
Sec. 97.525 Compliance with TR NOX Ozone Season assurance provisions.
(a) Availability for deduction. TR NOX Ozone Season
allowances are available to be deducted for compliance with the TR
NOX Ozone Season assurance provisions for a control period
in a given year by the owners and operators of a group of one or more
TR NOX Ozone Season sources and units in a State (and Indian
country within the borders of such State) only if the TR NOX
Ozone Season allowances:
(1) Were allocated for a control period in a prior year or the
control period in the given year or in the immediately following year;
and
(2) Are held in the assurance account, established by the
Administrator for such owners and operators of such group of TR
NOX Ozone Season sources and units in such State (and Indian
country within the borders of such State) under paragraph (b)(3) of
this section, as of the deadline established in paragraph (b)(4) of
this section.
(b) Deductions for compliance. The Administrator will deduct TR
NOX Ozone Season allowances available under paragraph (a) of
this section for compliance with the TR NOX Ozone Season
assurance provisions for a State for a control period in a given year
in accordance with the following procedures:
(1) By June 1, 2013 and June 1 of each year thereafter, the
Administrator will:
(i) Calculate, for each State (and Indian country within the
borders of such State), the total NOX emissions from all TR
NOX Ozone Season units at TR NOX Ozone Season
sources in the State (and Indian country within the borders of such
State) during the control period in the year before the year of this
calculation deadline and the amount, if any, by which such total
NOX emissions exceed the State assurance level as described
in Sec. 97.506(c)(2)(iii); and
(ii) Promulgate a notice of data availability of the results of the
calculations required in paragraph (b)(1)(i) of this section, including
separate calculations of the NOX emissions from each TR
NOX Ozone Season source.
(2) For each notice of data availability required in paragraph
(b)(1)(ii) of this section and for any State (and Indian country within
the borders of such State) identified in such notice as having TR
NOX Ozone Season units with total NOX emissions
exceeding the State assurance level for a control
[[Page 48427]]
period in a given year, as described in Sec. 97.506(c)(2)(iii):
(i) By July 1 immediately after the promulgation of such notice,
the designated representative of each TR NOX Ozone Season
source in each such State (and Indian country within the borders of
such State) shall submit a statement, in a format prescribed by the
Administrator, providing for each TR NOX Ozone Season unit
(if any) at the source that operates during, but is not allocated an
amount of TR NOX Ozone Season allowances for, such control
period, the unit's allowable NOX emission rate for such
control period and, if such rate is expressed in lb per mmBtu, the
unit's heat rate.
(ii) By August 1 immediately after the promulgation of such notice,
the Administrator will calculate, for each such State (and Indian
country within the borders of such State) and such control period and
each common designated representative for such control period for a
group of one or more TR NOX Ozone Season sources and units
in the State (and Indian country within the borders of such State), the
common designated representative's share of the total NOX
emissions from all TR NOX Ozone Season units at TR
NOX Ozone Season sources in the State (and Indian country
within the borders of such State), the common designated
representative's assurance level, and the amount (if any) of TR
NOX Ozone Season allowances that the owners and operators of
such group of sources and units must hold in accordance with the
calculation formula in Sec. 97.506(c)(2)(i) and will promulgate a
notice of data availability of the results of these calculations.
(iii) The Administrator will provide an opportunity for submission
of objections to the calculations referenced by the notice of data
availability required in paragraph (b)(2)(ii) of this section and the
calculations referenced by the relevant notice of data availability
required in paragraph (b)(1)(i) of this section.
(A) Objections shall be submitted by the deadline specified in such
notice and shall be limited to addressing whether the calculations
referenced in the relevant notice required under paragraph (b)(1)(ii)
of this section and referenced in the notice required under paragraph
(b)(2)(ii) of this section are in accordance with Sec.
97.506(c)(2)(iii), Sec. Sec. 97.506(b) and 97.530 through 97.535, the
definitions of ``common designated representative'', ``common
designated representative's assurance level'', and ``common designated
representative's share'' in Sec. 97.502, and the calculation formula
in Sec. 97.506(c)(2)(i).
(B) The Administrator will adjust the calculations to the extent
necessary to ensure that they are in accordance with the provisions
referenced in paragraph (b)(2)(iii)(A) of this section. By October 1
immediately after the promulgation of such notice, the Administrator
will promulgate a notice of data availability of any adjustments that
the Administrator determines to be necessary and the reasons for
accepting or rejecting any objections submitted in accordance with
paragraph (b)(2)(iii)(A) of this section.
(3) For any State (and Indian country within the borders of such
State) referenced in each notice of data availability required in
paragraph (b)(2)(iii)(B) of this section as having TR NOX
Ozone Season units with total NOX emissions exceeding the
State assurance level for a control period in a given year, the
Administrator will establish one assurance account for each set of
owners and operators referenced, in the notice of data availability
required under paragraph (b)(2)(iii)(B) of this section, as all of the
owners and operators of a group of TR NOX Ozone Season
sources and units in the State (and Indian country within the borders
of such State) having a common designated representative for such
control period and as being required to hold TR NOX Ozone
Season allowances.
(4)(i) As of midnight of November 1 immediately after the
promulgation of each notice of data availability required in paragraph
(b)(2)(iii)(B) of this section, the owners and operators described in
paragraph (b)(3) of this section shall hold in the assurance account
established for the them and for the appropriate TR NOX
Ozone Season sources, TR NOX Ozone Season units, and State
(and Indian country within the borders of such State) under paragraph
(b)(3) of this section a total amount of TR NOX Ozone Season
allowances, available for deduction under paragraph (a) of this
section, equal to the amount such owners and operators are required to
hold with regard to such sources, units and State (and Indian country
within the borders of such State) as calculated by the Administrator
and referenced in such notice.
(ii) Notwithstanding the allowance-holding deadline specified in
paragraph (b)(4)(i) of this section, if November 1 is not a business
day, then such allowance-holding deadline shall be midnight of the
first business day thereafter.
(5) After November 1 (or the date described in paragraph (b)(4)(ii)
of this section) immediately after the promulgation of each notice of
data availability required in paragraph (b)(2)(iii)(B) of this section
and after the recordation, in accordance with Sec. 97.523, of TR
NOX Ozone Season allowance transfers submitted by midnight
of such date, the Administrator will determine whether the owners and
operators described in paragraph (b)(3) of this section hold, in the
assurance account for the appropriate TR NOX Ozone Season
sources, TR NOX Ozone Season units, and State (and Indian
country within the borders of such State) established under paragraph
(b)(3) of this section, the amount of TR NOX Ozone Season
allowances available under paragraph (a) of this section that the
owners and operators are required to hold with regard to such sources,
units, and State (and Indian country within the borders of such State)
as calculated by the Administrator and referenced in the notice
required in paragraph (b)(2)(iii)(B) of this section.
(6) Notwithstanding any other provision of this subpart and any
revision, made by or submitted to the Administrator after the
promulgation of the notice of data availability required in paragraph
(b)(2)(iii)(B) of this section for a control period in a given year, of
any data used in making the calculations referenced in such notice, the
amounts of TR NOX Ozone Season allowances that the owners
and operators are required to hold in accordance with Sec.
97.506(c)(2)(i) for such control period shall continue to be such
amounts as calculated by the Administrator and referenced in such
notice required in paragraph (b)(2)(iii)(B) of this section, except as
follows:
(i) If any such data are revised by the Administrator as a result
of a decision in or settlement of litigation concerning such data on
appeal under part 78 of this chapter of such notice, or on appeal under
section 307 of the Clean Air Act of a decision rendered under part 78
of this chapter on appeal of such notice, then the Administrator will
use the data as so revised to recalculate the amounts of TR
NOX Ozone Season allowances that owners and operators are
required to hold in accordance with the calculation formula in Sec.
97.506(c)(2)(i) for such control period with regard to the TR
NOX Ozone Season sources, TR NOX Ozone Season
units, and State (and Indian country within the borders of such State)
involved, provided that such litigation under part 78 of this chapter,
or the proceeding under part 78 of this chapter that resulted in the
decision appealed in such litigation under section 307 of the Clean Air
Act, was initiated no later than 30 days after
[[Page 48428]]
promulgation of such notice required in paragraph (b)(2)(iii)(B) of
this section.
(ii) If any such data are revised by the owners and operators of a
TR NOX Ozone Season source and TR NOX Ozone
Season unit whose designated representative submitted such data under
paragraph (b)(2)(i) of this section, as a result of a decision in or
settlement of litigation concerning such submission, then the
Administrator will use the data as so revised to recalculate the
amounts of TR NOX Ozone Season allowances that owners and
operators are required to hold in accordance with the calculation
formula in Sec. 97.506(c)(2)(i) for such control period with regard to
the TR NOX Ozone Season sources, TR NOX Ozone
Season units, and State (and Indian country within the borders of such
State) involved, provided that such litigation was initiated no later
than 30 days after promulgation of such notice required in paragraph
(b)(2)(iii)(B) of this section.
(iii) If the revised data are used to recalculate, in accordance
with paragraphs (b)(6)(i) and (ii) of this section, the amount of TR
NOX Ozone Season allowances that the owners and operators
are required to hold for such control period with regard to the TR
NOX Ozone Season sources, TR NOX Ozone Season
units, and State (and Indian country within the borders of such State)
involved--
(A) Where the amount of TR NOX Ozone Season allowances
that the owners and operators are required to hold increases as a
result of the use of all such revised data, the Administrator will
establish a new, reasonable deadline on which the owners and operators
shall hold the additional amount of TR NOX Ozone Season
allowances in the assurance account established by the Administrator
for the appropriate TR NOX Ozone Season sources, TR
NOX Ozone Season units, and State (and Indian country within
the borders of such State) under paragraph (b)(3) of this section. The
owners' and operators' failure to hold such additional amount, as
required, before the new deadline shall not be a violation of the Clean
Air Act. The owners' and operators' failure to hold such additional
amount, as required, as of the new deadline shall be a violation of the
Clean Air Act. Each TR NOX Ozone Season allowance that the
owners and operators fail to hold as required as of the new deadline,
and each day in such control period, shall be a separate violation of
the Clean Air Act.
(B) For the owners and operators for which the amount of TR
NOX Ozone Season allowances required to be held decreases as
a result of the use of all such revised data, the Administrator will
record, in all accounts from which TR NOX Ozone Season
allowances were transferred by such owners and operators for such
control period to the assurance account established by the
Administrator for the appropriate at TR NOX Ozone Season
sources, TR NOX Ozone Season units, and State (and Indian
country within the borders of such State) under paragraph (b)(3) of
this section, a total amount of the TR NOX Ozone Season
allowances held in such assurance account equal to the amount of the
decrease. If TR NOX Ozone Season allowances were transferred
to such assurance account from more than one account, the amount of TR
NOX Ozone Season allowances recorded in each such transferor
account will be in proportion to the percentage of the total amount of
TR NOX Ozone Season allowances transferred to such assurance
account for such control period from such transferor account.
(C) Each TR NOX Ozone Season allowance held under
paragraph (b)(6)(iii)(A) of this section as a result of recalculation
of requirements under the TR NOX Ozone Season assurance
provisions for such control period must be a TR NOX Ozone
Season allowance allocated for a control period in a year before or the
year immediately following, or in the same year as, the year of such
control period.
Sec. 97.526 Banking.
(a) A TR NOX Ozone Season allowance may be banked for
future use or transfer in a compliance account or a general account in
accordance with paragraph (b) of this section.
(b) Any TR NOX Ozone Season allowance that is held in a
compliance account or a general account will remain in such account
unless and until the TR NOX Ozone Season allowance is
deducted or transferred under Sec. 97.511(c), Sec. 97.523, Sec.
97.524, Sec. 97.525, Sec. 97.527, or Sec. 97.528.
Sec. 97.527 Account error.
The Administrator may, at his or her sole discretion and on his or
her own motion, correct any error in any Allowance Management System
account. Within 10 business days of making such correction, the
Administrator will notify the authorized account representative for the
account.
Sec. 97.528 Administrator's action on submissions.
(a) The Administrator may review and conduct independent audits
concerning any submission under the TR NOX Ozone Season
Trading Program and make appropriate adjustments of the information in
the submission.
(b) The Administrator may deduct TR NOX Ozone Season
allowances from or transfer TR NOX Ozone Season allowances
to a compliance account or an assurance account, based on the
information in a submission, as adjusted under paragraph (a)(1) of this
section, and record such deductions and transfers.
Sec. 97.529 [Reserved]
Sec. 97.530 General monitoring, recordkeeping, and reporting
requirements.
The owners and operators, and to the extent applicable, the
designated representative, of a TR NOX Ozone Season unit,
shall comply with the monitoring, recordkeeping, and reporting
requirements as provided in this subpart and subpart H of part 75 of
this chapter. For purposes of applying such requirements, the
definitions in Sec. 97.502 and in Sec. 72.2 of this chapter shall
apply, the terms ``affected unit,'' ``designated representative,'' and
``continuous emission monitoring system'' (or ``CEMS'') in part 75 of
this chapter shall be deemed to refer to the terms ``TR NOX
Ozone Season unit,'' ``designated representative,'' and ``continuous
emission monitoring system'' (or ``CEMS'') respectively as defined in
Sec. 97.502, and the term ``newly affected unit'' shall be deemed to
mean ``newly affected TR NOX Ozone Season unit''. The owner
or operator of a unit that is not a TR NOX Ozone Season unit
but that is monitored under Sec. 75.72(b)(2)(ii) of this chapter shall
comply with the same monitoring, recordkeeping, and reporting
requirements as a TR NOX Ozone Season unit.
(a) Requirements for installation, certification, and data
accounting. The owner or operator of each TR NOX Ozone
Season unit shall:
(1) Install all monitoring systems required under this subpart for
monitoring NOX mass emissions and individual unit heat input
(including all systems required to monitor NOX emission
rate, NOX concentration, stack gas moisture content, stack
gas flow rate, CO2 or O2 concentration, and fuel
flow rate, as applicable, in accordance with Sec. Sec. 75.71 and 75.72
of this chapter);
(2) Successfully complete all certification tests required under
Sec. 97.531 and meet all other requirements of this subpart and part
75 of this chapter applicable to the monitoring systems under paragraph
(a)(1) of this section; and
(3) Record, report, and quality-assure the data from the monitoring
systems under paragraph (a)(1) of this section.
[[Page 48429]]
(b) Compliance deadlines. Except as provided in paragraph (e) of
this section, the owner or operator shall meet the monitoring system
certification and other requirements of paragraphs (a)(1) and (2) of
this section on or before the following dates and shall record, report,
and quality-assure the data from the monitoring systems under paragraph
(a)(1) of this section on and after the following dates.
(1) For the owner or operator of a TR NOX Ozone Season
unit that commences commercial operation before July 1, 2011, May 1,
2012.
(2) For the owner or operator of a TR NOX Ozone Season
unit that commences commercial operation on or after July 1, 2011 and
that reports on an annual basis under Sec. 97.534(d), by the later of
the following:
(i) 180 calendar days after the date on which the unit commences
commercial operation; or
(ii) May 1, 2012.
(3) For the owner or operator of a TR NOX Ozone Season
unit that commences commercial operation on or after July 1, 2011 and
that reports on a control period basis under Sec. 97.534(d)(2)(ii), by
the following date:
(i) 180 calendar days after the date on which the unit commences
commercial operation; or
(ii) If the compliance date under paragraph (b)(3)(i) of this
section is not during a control period, May 1 immediately after the
compliance date under paragraph (b)(3)(i) of this section.
(4) The owner or operator of a TR NOX Ozone Season unit
for which construction of a new stack or flue or installation of add-on
NOX emission controls is completed after the applicable
deadline under paragraph (b)(1), (2), or (3) of this section shall meet
the requirements of Sec. Sec. 75.4(e)(1) through (e)(4) of this
chapter, except that:
(i) Such requirements shall apply to the monitoring systems
required under Sec. 97.530 through Sec. 97.535, rather than the
monitoring systems required under part 75 of this chapter;
(ii) NOX emission rate, NOX concentration,
stack gas moisture content, stack gas volumetric flow rate, and
O2 or CO2 concentration data shall be determined
and reported, rather than the data listed in Sec. 75.4(e)(2) of this
chapter; and
(iii) Any petition for another procedure under Sec. 75.4(e)(2) of
this chapter shall be submitted under Sec. 97.535, rather than Sec.
75.66.
(c) Reporting data. The owner or operator of a TR NOX
Ozone Season unit that does not meet the applicable compliance date set
forth in paragraph (b) of this section for any monitoring system under
paragraph (a)(1) of this section shall, for each such monitoring
system, determine, record, and report maximum potential (or, as
appropriate, minimum potential) values for NOX
concentration, NOX emission rate, stack gas flow rate, stack
gas moisture content, fuel flow rate, and any other parameters required
to determine NOX mass emissions and heat input in accordance
with Sec. 75.31(b)(2) or (c)(3) of this chapter, section 2.4 of
appendix D to part 75 of this chapter, or section 2.5 of appendix E to
part 75 of this chapter, as applicable.
(d) Prohibitions. (1) No owner or operator of a TR NOX
Ozone Season unit shall use any alternative monitoring system,
alternative reference method, or any other alternative to any
requirement of this subpart without having obtained prior written
approval in accordance with Sec. 97.535.
(2) No owner or operator of a TR NOX Ozone Season unit
shall operate the unit so as to discharge, or allow to be discharged,
NOX to the atmosphere without accounting for all such
NOX in accordance with the applicable provisions of this
subpart and part 75 of this chapter.
(3) No owner or operator of a TR NOX Ozone Season unit
shall disrupt the continuous emission monitoring system, any portion
thereof, or any other approved emission monitoring method, and thereby
avoid monitoring and recording NOX mass discharged into the
atmosphere or heat input, except for periods of recertification or
periods when calibration, quality assurance testing, or maintenance is
performed in accordance with the applicable provisions of this subpart
and part 75 of this chapter.
(4) No owner or operator of a TR NOX Ozone Season unit
shall retire or permanently discontinue use of the continuous emission
monitoring system, any component thereof, or any other approved
monitoring system under this subpart, except under any one of the
following circumstances:
(i) During the period that the unit is covered by an exemption
under Sec. 97.505 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 Administrator 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 designated representative submits notification of the
date of certification testing of a replacement monitoring system for
the retired or discontinued monitoring system in accordance with Sec.
97.531(d)(3)(i).
(e) Long-term cold storage. The owner or operator of a TR
NOX Ozone Season unit is subject to the applicable
provisions of Sec. 75.4(d) of this chapter concerning units in long-
term cold storage.
Sec. 97.531 Initial monitoring system certification and
recertification procedures.
(a) The owner or operator of a TR NOX Ozone Season unit
shall be exempt from the initial certification requirements of this
section for a monitoring system under Sec. 97.530(a)(1) if the
following conditions are met:
(1) The monitoring system has been previously certified in
accordance with part 75 of this chapter; and
(2) The applicable quality-assurance and quality-control
requirements of Sec. 75.21 of this chapter and appendices B, D, and E
to part 75 of this chapter are fully met for the certified monitoring
system described in paragraph (a)(1) of this section.
(b) The recertification provisions of this section shall apply to a
monitoring system under Sec. 97.530(a)(1) that is exempt from initial
certification requirements under paragraph (a) of this section.
(c) If the Administrator has previously 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. 75.12 or Sec. 75.17 of this chapter, the designated
representative shall resubmit the petition to the Administrator under
Sec. 97.535 to determine whether the approval applies under the TR
NOX Ozone Season Trading Program.
(d) Except as provided in paragraph (a) of this section, the owner
or operator of a TR NOX Ozone Season unit shall comply with
the following initial certification and recertification procedures for
a continuous monitoring system (i.e., a continuous emission monitoring
system and an excepted monitoring system under appendices D and E to
part 75 of this chapter) under Sec. 97.530(a)(1). The owner or
operator of a unit that qualifies to use the low mass emissions
excepted monitoring methodology under Sec. 75.19 of this chapter or
that qualifies to use an alternative monitoring system under subpart E
of part 75 of this chapter shall comply with the procedures in
paragraph (e) or (f) of this section respectively.
[[Page 48430]]
(1) Requirements for initial certification. The owner or operator
shall ensure that each continuous monitoring system under Sec.
97.530(a)(1) (including the automated data acquisition and handling
system) successfully completes all of the initial certification testing
required under Sec. 75.20 of this chapter by the applicable deadline
in Sec. 97.530(b). In addition, whenever the owner or operator
installs a monitoring system to meet the requirements of this subpart
in a location where no such monitoring system was previously installed,
initial certification in accordance with Sec. 75.20 of this chapter is
required.
(2) Requirements for recertification. Whenever the owner or
operator makes a replacement, modification, or change in any certified
continuous emission monitoring system under Sec. 97.530(a)(1) that may
significantly affect the ability of the system to accurately measure or
record NOX mass emissions or heat input rate or to meet the
quality-assurance and quality-control 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 in accordance with 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 may significantly change the stack
flow or concentration profile, the owner or operator shall recertify
each continuous emission monitoring system whose accuracy is
potentially affected by the change, in accordance with Sec. 75.20(b)
of this chapter. Examples of changes to a continuous emission
monitoring system that require recertification include: replacement of
the analyzer, complete replacement of an existing continuous emission
monitoring system, or change in location or orientation of the sampling
probe or site. Any fuel flowmeter system, and any excepted
NOX monitoring system under appendix E to part 75 of this
chapter, under Sec. 97.530(a)(1) are subject to the recertification
requirements in Sec. 75.20(g)(6) of this chapter.
(3) Approval process for initial certification and recertification.
For initial certification of a continuous monitoring system under Sec.
97.530(a)(1), paragraphs (d)(3)(i) through (v) of this section apply.
For recertifications of such monitoring systems, paragraphs (d)(3)(i)
through (iv) of this section and the procedures in Sec. Sec.
75.20(b)(5) and (g)(7) of this chapter (in lieu of the procedures in
paragraph (d)(3)(v) of this section) apply, provided that in applying
paragraphs (d)(3)(i) through (iv) of this section, the words
``certification'' and ``initial certification'' are replaced by the
word ``recertification'' and the word ``certified'' is replaced by with
the word ``recertified''.
(i) Notification of certification. The designated representative
shall submit to the appropriate EPA Regional Office and the
Administrator written notice of the dates of certification testing, in
accordance with Sec. 97.533.
(ii) Certification application. The designated representative shall
submit to the Administrator a certification application for each
monitoring system. A complete certification application shall include
the information specified in Sec. 75.63 of this chapter.
(iii) Provisional certification date. The provisional certification
date for a monitoring system shall be determined in accordance with
Sec. 75.20(a)(3) of this chapter. A provisionally certified monitoring
system may be used under the TR NOX Ozone Season Trading
Program for a period not to exceed 120 days after receipt by the
Administrator of the complete certification application for the
monitoring system under paragraph (d)(3)(ii) of this section. Data
measured and recorded by the provisionally certified monitoring system,
in accordance with the requirements of part 75 of this chapter, will be
considered valid quality-assured data (retroactive to the date and time
of provisional certification), provided that the Administrator does not
invalidate the provisional certification by issuing a notice of
disapproval within 120 days of the date of receipt of the complete
certification application by the Administrator.
(iv) Certification application approval process. The Administrator
will issue a written notice of approval or disapproval of the
certification application to the owner or operator within 120 days of
receipt of the complete certification application under paragraph
(d)(3)(ii) of this section. In the event the Administrator does not
issue such a notice within such 120-day period, each monitoring system
that 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 TR NOX Ozone Season Trading
Program.
(A) Approval notice. If the certification application is complete
and shows that each monitoring system meets the applicable performance
requirements of part 75 of this chapter, then the Administrator will
issue a written notice of approval of the certification application
within 120 days of receipt.
(B) Incomplete application notice. If the certification application
is not complete, then the Administrator will issue a written notice of
incompleteness that sets a reasonable date by which the designated
representative must submit the additional information required to
complete the certification application. If the designated
representative does not comply with the notice of incompleteness by the
specified date, then the Administrator may issue a notice of
disapproval under paragraph (d)(3)(iv)(C) of this section.
(C) Disapproval notice. If the certification application shows that
any monitoring system does not meet the performance requirements of
part 75 of this chapter or if the certification application is
incomplete and the requirement for disapproval under paragraph
(d)(3)(iv)(B) of this section is met, then the Administrator will issue
a written notice of disapproval of the certification application. Upon
issuance of such notice of disapproval, the provisional certification
is invalidated by the Administrator and the data measured and recorded
by each uncertified monitoring system shall not be considered valid
quality-assured data beginning with the date and hour of provisional
certification (as defined under Sec. 75.20(a)(3) of this chapter).
(D) Audit decertification. The Administrator may issue a notice of
disapproval of the certification status of a monitor in accordance with
Sec. 97.532(b).
(v) Procedures for loss of certification. If the Administrator
issues a notice of disapproval of a certification application under
paragraph (d)(3)(iv)(C) of this section or a notice of disapproval of
certification status under paragraph (d)(3)(iv)(D) of this section,
then:
(A) The owner or operator shall substitute the following values,
for each disapproved monitoring system, for each hour of unit operation
during the period of invalid data specified under Sec.
75.20(a)(4)(iii), Sec. 75.20(g)(7), or Sec. 75.21(e) of this chapter
and continuing until the applicable date and hour specified under Sec.
75.20(a)(5)(i) or (g)(7) of this chapter:
(1) For a disapproved NOX emission rate (i.e.,
NOX-diluent) system, the maximum potential NOX
emission rate, as defined in Sec. 72.2 of this chapter.
(2) For a disapproved NOX pollutant concentration
monitor and disapproved flow monitor, respectively, the maximum
potential concentration of NOX and the maximum potential
flow rate, as defined in sections 2.1.2.1 and
[[Page 48431]]
2.1.4.1 of appendix A to part 75 of this chapter.
(3) For a disapproved moisture monitoring system and disapproved
diluent gas monitoring system, respectively, the minimum potential
moisture percentage and either the maximum potential CO2
concentration or the minimum potential O2 concentration (as
applicable), as defined in sections 2.1.5, 2.1.3.1, and 2.1.3.2 of
appendix A to part 75 of this chapter.
(4) For a disapproved fuel flowmeter system, the maximum potential
fuel flow rate, as defined in section 2.4.2.1 of appendix D to part 75
of this chapter.
(5) For a disapproved excepted NOX monitoring system
under appendix E to part 75 of this chapter, the fuel-specific maximum
potential NOX emission rate, as defined in Sec. 72.2 of
this chapter.
(B) The designated representative shall submit a notification of
certification retest dates and a new certification application in
accordance with paragraphs (d)(3)(i) and (ii) of this section.
(C) The owner or operator shall repeat all certification tests or
other requirements that were failed by the monitoring system, as
indicated in the Administrator's notice of disapproval, no later than
30 unit operating days after the date of issuance of the notice of
disapproval.
(e) The owner or operator of a unit qualified to use the low mass
emissions (LME) excepted methodology under Sec. 75.19 of this chapter
shall meet the applicable certification and recertification
requirements in Sec. Sec. 75.19(a)(2) and 75.20(h) of this chapter. If
the owner or operator of such a unit elects to certify a fuel flowmeter
system for heat input determination, the owner or operator shall also
meet the certification and recertification requirements in Sec.
75.20(g) of this chapter.
(f) The designated representative of each unit for which the owner
or operator intends to use an alternative monitoring system approved by
the Administrator under subpart E of part 75 of this chapter shall
comply with the applicable notification and application procedures of
Sec. 75.20(f) of this chapter.
Sec. 97.532 Monitoring system out-of-control periods.
(a) General provisions. Whenever any monitoring system fails to
meet the quality-assurance and quality-control requirements or data
validation requirements of part 75 of this chapter, data shall be
substituted using the applicable missing data procedures in subpart D
or subpart H of, or appendix D or appendix E to, 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 monitoring system should not have been
certified or recertified because it did not meet a particular
performance specification or other requirement under Sec. 97.531 or
the applicable provisions of part 75 of this chapter, both at the time
of the initial certification or recertification application submission
and at the time of the audit, the Administrator will issue a notice of
disapproval of the certification status of such monitoring system. For
the purposes of this paragraph, an audit shall be either a field audit
or an audit of any information submitted to the Administrator or any
State or permitting authority. By issuing the notice of disapproval,
the Administrator revokes prospectively the certification status of the
monitoring system. The data measured and recorded by the monitoring
system 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
for the monitoring system. The owner or operator shall follow the
applicable initial certification or recertification procedures in Sec.
97.531 for each disapproved monitoring system.
Sec. 97.533 Notifications concerning monitoring.
The designated representative of a TR NOX Ozone Season
unit shall submit written notice to the Administrator in accordance
with Sec. 75.61 of this chapter.
Sec. 97.534 Recordkeeping and reporting.
(a) General provisions. The designated representative shall comply
with all recordkeeping and reporting requirements in paragraphs (b)
through (e) of this section, the applicable recordkeeping and reporting
requirements under Sec. 75.73 of this chapter, and the requirements of
Sec. 97.514(a).
(b) Monitoring plans. The owner or operator of a TR NOX
Ozone Season unit shall comply with requirements of Sec. 75.73(c) and
(e) of this chapter.
(c) Certification applications. The designated representative shall
submit an application to the Administrator within 45 days after
completing all initial certification or recertification tests required
under Sec. 97.531, including the information required under Sec.
75.63 of this chapter.
(d) Quarterly reports. The designated representative shall submit
quarterly reports, as follows:
(1) If the TR NOX Ozone Season unit is subject to the
Acid Rain Program or a TR NOX Annual emissions limitation or
if the owner or operator of such unit chooses to report on an annual
basis under this subpart, the designated representative shall meet the
requirements of subpart H of part 75 of this chapter (concerning
monitoring of NOX mass emissions) for such unit for the
entire year and shall report the NOX mass emissions data and
heat input data for such unit, in an electronic quarterly report in a
format prescribed by the Administrator, for each calendar quarter
beginning with:
(i) For a unit that commences commercial operation before July 1,
2011, the calendar quarter covering May 1, 2012 through June 30, 2012;
or
(ii) For a unit that commences commercial operation on or after
July 1, 2011, the calendar quarter corresponding to the earlier of the
date of provisional certification or the applicable deadline for
initial certification under Sec. 97.530(b), unless that quarter is the
third or fourth quarter of 2011 or the first quarter of 2012, in which
case reporting shall commence in the quarter covering May 1, 2012
through June 30, 2012.
(2) If the TR NOX Ozone Season unit is not subject to
the Acid Rain Program or a TR NOX Annual emissions
limitation, then the designated representative shall either:
(i) Meet the requirements of subpart H of part 75 (concerning
monitoring of NOX mass emissions) for such unit for the
entire year and report the NOX mass emissions data and heat
input data for such unit in accordance with paragraph (d)(1) of this
section; or
(ii) Meet the requirements of subpart H of part 75 for the control
period (including the requirements in Sec. 75.74(c) of this chapter)
and report NOX mass emissions data and heat input data
(including the data described in Sec. 75.74(c)(6) of this chapter) for
such unit only for the control period of each year and report, in an
electronic quarterly report in a format prescribed by the
Administrator, for each calendar quarter beginning with:
(A) For a unit that commences commercial operation before July 1,
2011, the calendar quarter covering May 1, 2012 through June 30, 2012;
or
(B) For a unit that commences commercial operation on or after July
1, 2011, the calendar quarter corresponding to the earlier of the date
[[Page 48432]]
of provisional certification or the applicable deadline for initial
certification under Sec. 97.530(b), unless that date is not during a
control period, in which case reporting shall commence in the quarter
that includes May 1 through June 30 of the first control period after
such date.
(3) The designated representative shall submit each quarterly
report to the Administrator within 30 days after the end of the
calendar quarter covered by the report. Quarterly reports shall be
submitted in the manner specified in Sec. 75.73(f) of this chapter.
(4) For TR NOX Ozone Season units that are also subject
to the Acid Rain Program, TR NOX Annual Trading Program, TR
SO2 Group 1 Trading Program, or TR SO2 Group 2
Trading Program, quarterly reports shall include the applicable data
and information required by subparts F through H of part 75 of this
chapter as applicable, in addition to the NOX mass emission
data, heat input data, and other information required by this subpart.
(5) The Administrator may review and conduct independent audits of
any quarterly report in order to determine whether the quarterly report
meets the requirements of this subpart and part 75 of this chapter,
including the requirement to use substitute data.
(i) The Administrator will notify the designated representative of
any determination that the quarterly report fails to meet any such
requirements and specify in such notification any corrections that the
Administrator believes are necessary to make through resubmission of
the quarterly report and a reasonable time period within which the
designated representative must respond. Upon request by the designated
representative, the Administrator may specify reasonable extensions of
such time period. Within the time period (including any such
extensions) specified by the Administrator, the designated
representative shall resubmit the quarterly report with the corrections
specified by the Administrator, except to the extent the designated
representative provides information demonstrating that a specified
correction is not necessary because the quarterly report already meets
the requirements of this subpart and part 75 of this chapter that are
relevant to the specified correction.
(6) Any resubmission of a quarterly report shall meet the
requirements applicable to the submission of a quarterly report under
this subpart and part 75 of this chapter, except for the deadline set
forth in paragraph (d)(3) of this section.
(e) Compliance certification. The designated representative shall
submit to the Administrator a compliance certification (in a format
prescribed by the Administrator) in support of each quarterly report
based on reasonable inquiry of those persons with primary
responsibility for ensuring that all of the unit's emissions are
correctly and fully monitored. The certification shall state that:
(1) 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;
(2) For a unit with add-on NOX emission controls and for
all hours where NOX 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 quality
assurance/quality control program under appendix B to part 75 of this
chapter and the substitute data values do not systematically
underestimate NOX emissions; and
(3) For a unit that is reporting on a control period basis under
paragraph (d)(2)(ii) of this section, the NOX emission rate
and NOX concentration values substituted for missing data
under subpart D of part 75 of this chapter are calculated using only
values from a control period and do not systematically underestimate
NOX emissions.
Sec. 97.535 Petitions for alternatives to monitoring, recordkeeping,
or reporting requirements.
(a) The designated representative of a TR NOX Ozone
Season unit may submit a petition under Sec. 75.66 of this chapter to
the Administrator, requesting approval to apply an alternative to any
requirement of Sec. Sec. 97.530 through 97.534.
(b) A petition submitted under paragraph (a) of this section shall
include sufficient information for the evaluation of the petition,
including, at a minimum, the following information:
(i) Identification of each unit and source covered by the petition;
(ii) A detailed explanation of why the proposed alternative is
being suggested in lieu of the requirement;
(iii) A description and diagram of any equipment and procedures
used in the proposed alternative;
(iv) A demonstration that the proposed alternative is consistent
with the purposes of the requirement for which the alternative is
proposed and with the purposes of this subpart and part 75 of this
chapter and that any adverse effect of approving the alternative will
be de minimis: and
(v) Any other relevant information that the Administrator may
require.
(c) Use of an alternative to any requirement referenced in
paragraph (a) of this section is in accordance with this subpart only
to the extent that the petition is approved in writing by the
Administrator and that such use is in accordance with such approval.
76. Part 97 is amended by adding subpart CCCCC to read as follows:
Subpart CCCCC--TR SO2 Group 1 Trading Program
Sec.
97.601 Purpose.
97.602 Definitions.
97.603 Measurements, abbreviations, and acronyms.
97.604 Applicability.
97.605 Retired unit exemption.
97.606 Standard requirements.
97.607 Computation of time.
97.608 Administrative appeal procedures.
97.609 [Reserved]
97.610 State SO2 Group 1 trading budgets, new unit set-
asides, Indian country new unit set-asides and variability limits.
97.611 Timing requirements for TR SO2 Group 1 allowance
allocations.
97.612 TR SO2 Group 1 allowance allocations to new units.
97.613 Authorization of designated representative and alternate
designated representative.
97.614 Responsibilities of designated representative and alternate
designated representative.
97.615 Changing designated representative and alternate designated
representative; changes in owners and operators.
97.616 Certificate of representation.
97.617 Objections concerning designated representative and alternate
designated representative.
97.618 Delegation by designated representative and alternate
designated representative.
97.619 [Reserved]
97.620 Establishment of compliance accounts and general accounts.
97.621 Recordation of TR SO2 Group 1 allowance
allocations.
97.622 Submission of TR SO2 Group 1 allowance transfers.
97.623 Recordation of TR SO2 Group 1 allowance transfers.
97.624 Compliance with TR SO2 Group 1 emissions
limitation.
97.625 Compliance with TR SO2 Group 1 assurance
provisions.
97.626 Banking.
97.627 Account error.
97.628 Administrator's action on submissions.
97.629 [Reserved]
97.630 General monitoring, recordkeeping, and reporting
requirements.
97.631 Initial monitoring system certification and recertification
procedures.
97.632 Monitoring system out-of-control periods.
[[Page 48433]]
97.633 Notifications concerning monitoring.
97.634 Recordkeeping and reporting.
97.635 Petitions for alternatives to monitoring, recordkeeping, or
reporting requirements.
Subpart CCCCC--TR SO2 Group 1 Trading Program
Sec. 97.601 Purpose.
This subpart sets forth the general, designated representative,
allowance, and monitoring provisions for the Transport Rule (TR)
SO2 Group 1 Trading Program, under section 110 of the Clean
Air Act and Sec. 52.39 of this chapter, as a means of mitigating
interstate transport of fine particulates and sulfur dioxide.
Sec. 97.602 Definitions.
The terms used in this subpart shall have the meanings set forth in
this section as follows:
Acid Rain Program means a multi-state SO2 and
NOX air pollution control and emission reduction program
established by the Administrator under title IV of the Clean Air Act
and parts 72 through 78 of this chapter.
Administrator means the Administrator of the United States
Environmental Protection Agency or the Director of the Clean Air
Markets Division (or its successor determined by the Administrator) of
the United States Environmental Protection Agency, the Administrator's
duly authorized representative under this subpart.
Allocate or allocation means, with regard to TR SO2
Group 1 allowances, the determination by the Administrator, State, or
permitting authority, in accordance with this subpart and any SIP
revision submitted by the State and approved by the Administrator under
Sec. 52.39(d), (e), or (f) of this chapter, of the amount of such TR
SO2 Group 1 allowances to be initially credited, at no cost
to the recipient, to:
(1) A TR SO2 Group 1 unit;
(2) A new unit set-aside;
(3) An Indian country new unit set-aside; or
(4) An entity not listed in paragraphs (1) through (3) of this
definition;
(5) Provided that, if the Administrator, State, or permitting
authority initially credits, to a TR SO2 Group 1 unit
qualifying for an initial credit, a credit in the amount of zero TR
SO2 Group 1 allowances, the TR SO2 Group 1 unit
will be treated as being allocated an amount (i.e., zero) of TR
SO2 Group 1 allowances.
Allowable SO2 emission rate means, for a unit, the most stringent
State or federal SO2 emission rate limit (in lb/MWhr or, if
in lb/mmBtu, converted to lb/MWhr by multiplying it by the unit's heat
rate in mmBtu/MWhr) that is applicable to the unit and covers the
longest averaging period not exceeding one year.
Allowance Management System means the system by which the
Administrator records allocations, deductions, and transfers of TR
SO2 Group 1 allowances under the TR SO2 Group 1
Trading Program. Such allowances are allocated, recorded, held,
deducted, or transferred only as whole allowances.
Allowance Management System account means an account in the
Allowance Management System established by the Administrator for
purposes of recording the allocation, holding, transfer, or deduction
of TR SO2 Group 1 allowances.
Allowance transfer deadline means, for a control period in a given
year, midnight of March 1 (if it is a business day), or midnight of the
first business day thereafter (if March 1 is not a business day),
immediately after such control period and is the deadline by which a TR
SO2 Group 1 allowance transfer must be submitted for
recordation in a TR SO2 Group 1 source's compliance account
in order to be available for use in complying with the source's TR
SO2 Group 1 emissions limitation for such control period in
accordance with Sec. Sec. 97.606 and 97.624.
Alternate designated representative means, for a TR SO2
Group 1 source and each TR SO2 Group 1 unit at the source,
the natural person who is authorized by the owners and operators of the
source and all such units at the source, in accordance with this
subpart, to act on behalf of the designated representative in matters
pertaining to the TR SO2 Group 1 Trading Program. If the TR
SO2 Group 1 source is also subject to the Acid Rain Program,
TR NOX Annual Trading Program, or TR NOX Ozone
Season Trading Program, then this natural person shall be the same
natural person as the alternate designated representative, as defined
in the respective program.
Assurance account means an Allowance Management System account,
established by the Administrator under Sec. 97.625(b)(3) for certain
owners and operators of a group of one or more TR SO2 Group
1 sources and units in a given State (and Indian country within the
borders of such State), in which are held TR SO2 Group 1
allowances available for use for a control period in a given year in
complying with the TR SO2 Group 1 assurance provisions in
accordance with Sec. Sec. 97.606 and 97.625.
Authorized account representative means, for a general account, the
natural person who is authorized, in accordance with this subpart, to
transfer and otherwise dispose of TR SO2 Group 1 allowances
held in the general account and, for a TR SO2 Group 1
source's compliance account, the designated representative of the
source.
Automated data acquisition and handling system or DAHS means the
component of the continuous emission monitoring system, or other
emissions monitoring system approved for use under this subpart,
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 this subpart.
Biomass means--
(1) Any organic material grown for the purpose of being converted
to energy;
(2) Any organic byproduct of agriculture that can be converted into
energy; or
(3) Any material that can be converted into energy and is
nonmerchantable for other purposes, that is segregated from other
material that is nonmerchantable for other purposes, and that is;
(i) A forest-related organic resource, including mill residues,
precommercial thinnings, slash, brush, or byproduct from conversion of
trees to merchantable material; or
(ii) A wood material, including pallets, crates, dunnage,
manufacturing and construction materials (other than pressure-treated,
chemically-treated, or painted wood products), and landscape or right-
of-way tree trimmings.
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.
Bottoming-cycle unit means a unit in which the energy input to the
unit is first used to produce useful thermal energy, where at least
some of the reject heat from the useful thermal energy application or
process is then used for electricity production.
Business day means a day that does not fall on a weekend or a
federal holiday.
Certifying official means a natural person who is:
(1) For a corporation, a president, secretary, treasurer, or vice-
president of the corporation in charge of a principal business function
or any other person who performs similar policy- or decision-making
functions for the corporation;
[[Page 48434]]
(2) For a partnership or sole proprietorship, a general partner or
the proprietor respectively; or
(3) For a local government entity or State, federal, or other
public agency, a principal executive officer or ranking elected
official.
Clean Air Act means the Clean Air Act, 42 U.S.C. 7401, et seq.
Coal means ``coal'' as defined in Sec. 72.2 of this chapter.
Coal-derived fuel means any fuel (whether in a solid, liquid, or
gaseous state) produced by the mechanical, thermal, or chemical
processing of coal.
Cogeneration system means an integrated group, at a source, of
equipment (including a boiler, or combustion turbine, and a steam
turbine generator) designed to produce useful thermal energy for
industrial, commercial, heating, or cooling purposes and electricity
through the sequential use of energy.
Cogeneration unit means a stationary, fossil-fuel-fired boiler or
stationary, fossil-fuel-fired combustion turbine that is a topping-
cycle unit or a bottoming-cycle unit:
(1) Operating as part of a cogeneration system; and
(2) Producing on an annual average basis--
(i) For a topping-cycle unit,
(A) Useful thermal energy not less than 5 percent of total energy
output; and
(B) Useful power that, when added to one-half of useful thermal
energy produced, is not less than 42.5 percent of total energy input,
if useful thermal energy produced is 15 percent or more of total energy
output, or not less than 45 percent of total energy input, if useful
thermal energy produced is less than 15 percent of total energy output.
(ii) For a bottoming-cycle unit, useful power not less than 45
percent of total energy input;
(3) Provided that the requirements in paragraph (2) of this
definition shall not apply to a calendar year referenced in paragraph
(2) of this definition during which the unit did not operate at all;
(4) Provided that the total energy input under paragraphs (2)(i)(B)
and (2)(ii) of this definition shall equal the unit's total energy
input from all fuel, except biomass if the unit is a boiler; and
(5) Provided that, if, throughout its operation during the 12-month
period or a calendar year referenced in paragraph (2) of this
definition, a unit is operated as part of a cogeneration system and the
cogeneration system meets on a system-wide basis the requirement in
paragraph (2)(i)(B) or (2)(ii) of this definition, the unit shall be
deemed to meet such requirement during that 12-month period or calendar
year.
Combustion turbine means an enclosed device comprising:
(1) If the device is simple cycle, 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; and
(2) If the device is combined cycle, the equipment described in
paragraph (1) of this definition and any associated duct burner, heat
recovery steam generator, and steam turbine.
Commence commercial operation means, with regard to a unit:
(1) To have begun to produce steam, gas, or other heated medium
used to generate electricity for sale or use, including test
generation, except as provided in Sec. 97.605.
(i) For a unit that is a TR SO2 Group 1 unit under Sec.
97.604 on the later of January 1, 2005 or the date the unit commences
commercial operation as defined in the introductory text of paragraph
(1) of this definition and that subsequently undergoes a physical
change or is moved to a new location or source, such date shall remain
the date of commencement of commercial operation of the unit, which
shall continue to be treated as the same unit.
(ii) For a unit that is a TR SO2 Group 1 unit under
Sec. 97.604 on the later of January 1, 2005 or the date the unit
commences commercial operation as defined in the introductory text of
paragraph (1) of this definition and that is subsequently replaced by a
unit at the same or a different source, such date shall remain the
replaced unit's date of commencement of commercial operation, and the
replacement unit shall be treated as a separate unit with a separate
date for commencement of commercial operation as defined in paragraph
(1) or (2) of this definition as appropriate.
(2) Notwithstanding paragraph (1) of this definition and except as
provided in Sec. 97.605, for a unit that is not a TR SO2
Group 1 unit under Sec. 97.604 on the later of January 1, 2005 or the
date the unit commences commercial operation as defined in introductory
text of paragraph (1) of this definition, the unit's date for
commencement of commercial operation shall be the date on which the
unit becomes a TR SO2 Group 1 unit under Sec. 97.604.
(i) For a unit with a date for commencement of commercial operation
as defined in the introductory text of paragraph (2) of this definition
and that subsequently undergoes a physical change or is moved to a
different location or source, such date shall remain the date of
commencement of commercial operation of the unit, which shall continue
to be treated as the same unit.
(ii) For a unit with a date for commencement of commercial
operation as defined in the introductory text of paragraph (2) of this
definition and that is subsequently replaced by a unit at the same or a
different source, such date shall remain the replaced unit's date of
commencement of commercial operation, and the replacement unit shall be
treated as a separate unit with a separate date for commencement of
commercial operation as defined in paragraph (1) or (2) of this
definition as appropriate.
Common designated representative means, with regard to a control
period in a given year, a designated representative where, as of April
1 immediately after the allowance transfer deadline for such control
period, the same natural person is authorized under Sec. Sec.
97.613(a) and 97.615(a) as the designated representative for a group of
one or more TR SO2 Group 1 sources and units located in a
State (and Indian country within the borders of such State).
Common designated representative's assurance level means, with
regard to a specific common designated representative and a State (and
Indian country within the borders of such State) and control period in
a given year for which the State assurance level is exceeded as
described in Sec. 97.606(c)(2)(iii), the common designated
representative's share of the State SO2 Group 1 trading
budget with the variability limit for the State for such control
period.
Common designated representative's share means, with regard to a
specific common designated representative for a control period in a
given year:
(1) With regard to a total amount of SO2 emissions from
all TR SO2 Group 1 units in a State (and Indian country
within the borders of such State) during such control period, the total
tonnage of SO2 emissions during such control period from a
group of one or more TR SO2 Group 1 units located in such
State (and such Indian country) and having the common designated
representative for such control period;
(2) With regard to a State SO2 Group 1 trading budget
with the variability limit for such control period, the amount (rounded
to the nearest allowance) equal to the sum of the total amount of TR
SO2 Group 1 allowances allocated for such control period to
a group of one or more TR SO2 Group 1 units located in the
State (and Indian country within the borders of such
[[Page 48435]]
State) and having the common designated representative for such control
period and of the total amount of TR SO2 Group 1 allowances
purchased by an owner or operator of such TR SO2 Group 1
units in an auction for such control period and submitted by the State
or the permitting authority to the Administrator for recordation in the
compliance accounts for such TR SO2 Group 1 units in
accordance with the TR SO2 Group 1 allowance auction
provisions in a SIP revision approved by the Administrator under Sec.
52.39(e) or (f) of this chapter, multiplied by the sum of the State
SO2 Group 1 trading budget under Sec. 97.610(a) and the
State's variability limit under Sec. 97.610(b) for such control period
and divided by such State SO2 Group 1 trading budget;
(3) Provided that, in the case of a unit that operates during, but
has no amount of TR SO2 Group 1 allowances allocated under
Sec. Sec. 97.611 and 97.612 for, such control period, the unit shall
be treated, solely for purposes of this definition, as being allocated
an amount (rounded to the nearest allowance) of TR SO2 Group
1 allowances for such control period equal to the unit's allowable
SO2 emission rate applicable to such control period,
multiplied by a capacity factor of 0.85 (if the unit is a boiler
combusting any amount of coal or coal-derived fuel during such control
period), 0.24 (if the unit is a simple combustion turbine during such
control period), 0.67 (if the unit is a combined cycle turbine during
such control period), 0.74 (if the unit is an integrated coal
gasification combined cycle unit during such control period), or 0.36
(for any other unit), multiplied by the unit's maximum hourly load as
reported in accordance with this subpart and by 8,760 hours/control
period, and divided by 2,000 lb/ton.
Common stack means a single flue through which emissions from 2 or
more units are exhausted.
Compliance account means an Allowance Management System account,
established by the Administrator for a TR SO2 Group 1 source
under this subpart, in which any TR SO2 Group 1 allowance
allocations to the TR SO2 Group 1 units at the source are
recorded and in which are held any TR SO2 Group 1 allowances
available for use for a control period in a given year in complying
with the source's TR SO2 Group 1 emissions limitation in
accordance with Sec. Sec. 97.606 and 97.624.
Continuous emission monitoring system or CEMS means the equipment
required under this subpart to sample, analyze, measure, and provide,
by means of readings recorded at least once every 15 minutes and using
an automated data acquisition and handling system (DAHS), a permanent
record of SO2 emissions, stack gas volumetric flow rate,
stack gas moisture content, and O2 or CO2
concentration (as applicable), in a manner consistent with part 75 of
this chapter and Sec. Sec. 97.630 through 97.635. The following
systems are the principal types of continuous emission monitoring
systems:
(1) A flow monitoring system, consisting of a stack flow rate
monitor and an automated data acquisition and handling system and
providing a permanent, continuous record of stack gas volumetric flow
rate, in standard cubic feet per hour (scfh);
(2) A SO2 monitoring system, consisting of a
SO2 pollutant concentration monitor and an automated data
acquisition and handling system and providing a permanent, continuous
record of SO2 emissions, in parts per million (ppm);
(3) A moisture monitoring system, as defined in Sec. 75.11(b)(2)
of this chapter and providing a permanent, continuous record of the
stack gas moisture content, in percent H2O;
(4) A CO2 monitoring system, consisting of a
CO2 pollutant concentration monitor (or an O2
monitor plus suitable mathematical equations from which the
CO2 concentration is derived) and an automated data
acquisition and handling system and providing a permanent, continuous
record of CO2 emissions, in percent CO2; and
(5) An O2 monitoring system, consisting of an
O2 concentration monitor and an automated data acquisition
and handling system and providing a permanent, continuous record of
O2, in percent O2.
Control period means the period starting January 1 of a calendar
year, except as provided in Sec. 97.606(c)(3), and ending on December
31 of the same year, inclusive.
Designated representative means, for a TR SO2 Group 1
source and each TR SO2 Group 1 unit at the source, the
natural person who is authorized by the owners and operators of the
source and all such units at the source, in accordance with this
subpart, to represent and legally bind each owner and operator in
matters pertaining to the TR SO2 Group 1 Trading Program. If
the TR SO2 Group 1 source is also subject to the Acid Rain
Program, TR NOX Annual Trading Program, or TR NOX
Ozone Season Trading Program, then this natural person shall be the
same natural person as the designated representative, as defined in the
respective program.
Emissions means air pollutants exhausted from a unit or source into
the atmosphere, as measured, recorded, and reported to the
Administrator by the designated representative, and as modified by the
Administrator:
(1) In accordance with this subpart; and
(2) With regard to a period before the unit or source is required
to measure, record, and report such air pollutants in accordance with
this subpart, in accordance with part 75 of this chapter.
Excess emissions means any ton of emissions from the TR
SO2 Group 1 units at a TR SO2 Group 1 source
during a control period in a given year that exceeds the TR
SO2 Group 1 emissions limitation for the source for such
control period.
Fossil fuel means--
(1) Natural gas, petroleum, coal, or any form of solid, liquid, or
gaseous fuel derived from such material; or
(2) For purposes of applying the limitation on ``average annual
fuel consumption of fossil fuel'' in Sec. Sec. 97.604(b)(2)(i)(B) and
(ii), natural gas, petroleum, coal, or any form of solid, liquid, or
gaseous fuel derived from such material for the purpose of creating
useful heat.
Fossil-fuel-fired means, with regard to a unit, combusting any
amount of fossil fuel in 2005 or any calendar year thereafter.
General account means an Allowance Management System account,
established under this subpart, that is not a compliance account or an
assurance account.
Generator means a device that produces electricity.
Gross electrical output means, for a unit, electricity made
available for use, including any such electricity used in the power
production process (which process includes, but is not limited to, any
on-site processing or treatment of fuel combusted at the unit and any
on-site emission controls).
Heat input means, for a unit for a specified period of time, the
product (in mmBtu/time) of the gross calorific value of the fuel (in
mmBtu/lb) fed into the unit multiplied by the fuel feed rate (in lb of
fuel/time), as measured, recorded, and reported to the Administrator by
the designated representative and as modified by the Administrator in
accordance with this subpart and excluding the heat derived from
preheated combustion air, recirculated flue gases, or exhaust.
Heat input rate means, for a unit, the amount of heat input (in
mmBtu) divided by unit operating time (in hr) or, for a unit and a
specific fuel, the amount of heat input attributed to the
[[Page 48436]]
fuel (in mmBtu) divided by the unit operating time (in hr) during which
the unit combusts the fuel.
Heat rate means, for a unit, the unit's maximum design heat input
(in Btu/hr), divided by the product of 1,000,000 Btu/mmBtu and the
unit's maximum hourly load.
Indian country means ``Indian country'' as defined in 18 U.S.C.
1151.
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 generated by 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 no less 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, for a unit, the maximum amount of
fuel per hour (in Btu/hr) that the unit is capable of combusting on a
steady state basis as of the initial installation of the unit as
specified by the manufacturer of the unit.
Monitoring system means any monitoring system that meets the
requirements of this subpart, including a continuous emission
monitoring system, an alternative monitoring system, or an excepted
monitoring system under part 75 of this chapter.
Nameplate capacity means, starting from the initial installation of
a generator, the maximum electrical generating output (in MWe, rounded
to the nearest tenth) that the generator is capable of producing on a
steady state basis and during continuous operation (when not restricted
by seasonal or other deratings) as of such installation as specified by
the manufacturer of the generator or, starting from the completion of
any subsequent physical change in the generator resulting in an
increase in the maximum electrical generating output that the generator
is capable of producing on a steady state basis and during continuous
operation (when not restricted by seasonal or other deratings), such
increased maximum amount (in MWe, rounded to the nearest tenth) as of
such completion as specified by the person conducting the physical
change.
Natural gas means ``natural gas'' as defined in Sec. 72.2 of this
chapter.
Newly affected TR SO2 Group 1 unit means a unit that was not a TR
SO2 Group 1 unit when it began operating but that thereafter
becomes a TR SO2 Group 1 unit.
Operate or operation means, with regard to a unit, to combust fuel.
Operator means, for a TR SO2 Group 1 source or a TR
SO2 Group 1 unit at a source respectively, any person who
operates, controls, or supervises a TR SO2 Group 1 unit at
the source or the TR SO2 Group 1 unit and shall include, but
not be limited to, any holding company, utility system, or plant
manager of such source or unit.
Owner means, for a TR SO2 Group 1 source or a TR
SO2 Group 1 unit at a source respectively, any of the
following persons:
(1) Any holder of any portion of the legal or equitable title in a
TR SO2 Group 1 unit at the source or the TR SO2
Group 1 unit;
(2) Any holder of a leasehold interest in a TR SO2 Group
1 unit at the source or the TR SO2 Group 1 unit, provided
that, 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) on the revenues or income from such TR
SO2 Group 1 unit; and
(3) Any purchaser of power from a TR SO2 Group 1 unit at
the source or the TR SO2 Group 1 unit under a life-of-the-
unit, firm power contractual arrangement.
Permanently retired means, with regard to a unit, a unit that is
unavailable for service and that the unit's owners and operators do not
expect to return to service in the future.
Permitting authority means ``permitting authority'' as defined in
Sec. Sec. 70.2 and 71.2 of this chapter.
Potential electrical output capacity means, for a unit, 33 percent
of the unit's maximum design heat input, divided by 3,413 Btu/kWh,
divided by 1,000 kWh/MWh, and multiplied by 8,760 hr/yr.
Receive or receipt of means, when referring to the Administrator,
to come into possession of a document, information, or correspondence
(whether sent in hard copy or by authorized electronic transmission),
as indicated in an official log, or by a notation made on the document,
information, or correspondence, by the Administrator in the regular
course of business.
Recordation, record, or recorded means, with regard to TR
SO2 Group 1 allowances, the moving of TR SO2
Group 1 allowances by the Administrator into, out of, or between
Allowance Management System accounts, for purposes of allocation,
auction, transfer, or deduction.
Reference method means any direct test method of sampling and
analyzing for an air pollutant as specified in Sec. 75.22 of this
chapter.
Replacement, replace, or replaced means, with regard to a unit, the
demolishing of a unit, or the permanent retirement and permanent
disabling of a unit, and the construction of another unit (the
replacement unit) to be used instead of the demolished or retired unit
(the replaced unit).
Sequential use of energy means:
(1) The use of reject heat from electricity production in a useful
thermal energy application or process; or
(2) The use of reject heat from useful thermal energy application
or process in electricity production.
Serial number means, for a TR SO2 Group 1 allowance, the
unique identification number assigned to each TR SO2 Group 1
allowance by the Administrator.
Solid waste incineration unit means a stationary, fossil-fuel-fired
boiler or stationary, fossil-fuel-fired combustion turbine that is a
``solid waste incineration unit'' as defined in section 129(g)(1) of
the Clean Air Act.
Source means all buildings, structures, or installations located in
one or more contiguous or adjacent properties under common control of
the same person or persons. This definition does not change or
otherwise affect the definition of ``major source'', ``stationary
source'', or ``source'' as set forth and implemented in a title V
operating permit program or any other program under the Clean Air Act.
State means one of the States that is subject to the TR
SO2 Group 1 Trading Program pursuant to Sec. 52.39(a), (b),
(d), (e), and (f) of this chapter.
Submit or serve means to send or transmit a document, information,
or correspondence to the person specified in accordance with the
applicable regulation:
(1) In person;
(2) By United States Postal Service; or
(3) By other means of dispatch or transmission and delivery;
(4) Provided that compliance with any ``submission'' or ``service''
deadline shall be determined by the date of dispatch, transmission, or
mailing and not the date of receipt.
[[Page 48437]]
Topping-cycle unit means a unit in which the energy input to the
unit is first used to produce useful power, including electricity,
where at least some of the reject heat from the electricity production
is then used to provide useful thermal energy.
Total energy input means, for a unit, total energy of all forms
supplied to the unit, excluding energy produced by the unit. Each form
of energy supplied shall be measured by the lower heating value of that
form of energy calculated as follows:
LHV = HHV - 10.55(W + 9H)
Where:
LHV = lower heating value of the form of energy in Btu/lb,
HHV = higher heating value of the form of energy in Btu/lb,
W = weight % of moisture in the form of energy, and
H = weight % of hydrogen in the form of energy.
Total energy output means, for a unit, the sum of useful power and
useful thermal energy produced by the unit.
TR NOX Annual Trading Program means a multi-state NOX
air pollution control and emission reduction program established in
accordance with subpart AAAAA of this part and Sec. 52.38(a) of this
chapter (including such a program that is revised in a SIP revision
approved by the Administrator under Sec. 52.38(a)(3) or (4) of this
chapter or that is established in a SIP revision approved by the
Administrator under Sec. 52.38(a)(5) of this chapter), as a means of
mitigating interstate transport of fine particulates and
NOX.
TR NOX Ozone Season Trading Program means a multi-state
NOX air pollution control and emission reduction program
established in accordance with subpart BBBBB of this part and Sec.
52.38(b) of this chapter (including such a program that is revised in a
SIP revision approved by the Administrator under Sec. 52.38(b)(3) or
(4) of this chapter or that is established in a SIP revision approved
by the Administrator under Sec. 52.38(b)(5) of this chapter), as a
means of mitigating interstate transport of ozone and NOX.
TR SO2 Group 1 allowance means a limited authorization issued and
allocated or auctioned by the Administrator under this subpart, or by a
State or permitting authority under a SIP revision approved by the
Administrator under Sec. 52.39(d), (e), or (f) of this chapter, to
emit one ton of SO2 during a control period of the specified
calendar year for which the authorization is allocated or auctioned or
of any calendar year thereafter under the TR SO2 Group 1
Trading Program.
TR SO2 Group 1 allowance deduction or deduct TR SO2
Group 1 allowances means the permanent withdrawal of TR SO2
Group 1 allowances by the Administrator from a compliance account
(e.g., in order to account for compliance with the TR SO2
Group 1 emissions limitation) or from an assurance account (e.g., in
order to account for compliance with the assurance provisions under
Sec. Sec. 97.606 and 97.625).
TR SO2 Group 1 allowances held or hold TR SO2 Group 1 allowances
means the TR SO2 Group 1 allowances treated as included in
an Allowance Management System account as of a specified point in time
because at that time they:
(1) Have been recorded by the Administrator in the account or
transferred into the account by a correctly submitted, but not yet
recorded, TR SO2 Group 1 allowance transfer in accordance
with this subpart; and
(2) Have not been transferred out of the account by a correctly
submitted, but not yet recorded, TR SO2 Group 1 allowance
transfer in accordance with this subpart.
TR SO2 Group 1 emissions limitation means, for a TR SO2
Group 1 source, the tonnage of SO2 emissions authorized in a
control period by the TR SO2 Group 1 allowances available
for deduction for the source under Sec. 97.624(a) for such control
period.
TR SO2 Group 1 source means a source that includes one or more TR
SO2 Group 1 units.
TR SO2 Group 1 Trading Program means a multi-state SO2
air pollution control and emission reduction program established in
accordance with this subpart and Sec. 52.39(a), (b), (d) through (f),
(j), and (k) of this chapter (including such a program that is revised
in a SIP revision approved by the Administrator under Sec. 52.39(d) or
(e) of this chapter or that is established in a SIP revision approved
by the Administrator under Sec. 52.39(f) of this chapter), as a means
of mitigating interstate transport of fine particulates and
SO2.
TR SO2 Group 1 unit means a unit that is subject to the TR
SO2 Group 1 Trading Program under Sec. 97.604.
Unit means a stationary, fossil-fuel-fired boiler, stationary,
fossil-fuel-fired combustion turbine, or other stationary, fossil-fuel-
fired combustion device. A unit that undergoes a physical change or is
moved to a different location or source shall continue to be treated as
the same unit. A unit (the replaced unit) that is replaced by another
unit (the replacement unit) at the same or a different source shall
continue to be treated as the same unit, and the replacement unit shall
be treated as a separate unit.
Unit operating day means, with regard to a unit, a calendar day in
which the unit combusts any fuel.
Unit operating hour or hour of unit operation means, with regard to
a unit, an hour in which the unit combusts any fuel.
Useful power means, with regard to a unit, electricity or
mechanical energy that the unit makes available for use, excluding any
such energy used in the power production process (which process
includes, but is not limited to, any on-site processing or treatment of
fuel combusted at the unit and any on-site emission controls).
Useful thermal energy means thermal energy that is:
(1) Made available to an industrial or commercial process (not a
power production process), excluding any heat contained in condensate
return or makeup water;
(2) Used in a heating application (e.g., space heating or domestic
hot water heating); or
(3) Used in a space cooling application (i.e., in an absorption
chiller).
Utility power distribution system means the portion of an
electricity grid owned or operated by a utility and dedicated to
delivering electricity to customers.
Sec. 97.603 Measurements, abbreviations, and acronyms.
Measurements, abbreviations, and acronyms used in this subpart are
defined as follows:
Btu--British thermal unit
CO2--carbon dioxide
H2O--water
hr--hour
kW--kilowatt electrical
kWh--kilowatt hour
lb--pound
mmBtu--million Btu
MWe--megawatt electrical
MWh--megawatt hour
NOX--nitrogen oxides
O2--oxygen
ppm--parts per million
scfh--standard cubic feet per hour
SO2--sulfur dioxide
yr--year
Sec. 97.604 Applicability.
(a) Except as provided in paragraph (b) of this section:
(1) The following units in a State (and Indian country within the
borders of such State) shall be TR SO2 Group 1 units, and
any source that includes one or more such units shall be a TR
SO2 Group 1 source, subject to the requirements of this
subpart: any stationary, fossil-fuel-fired boiler or
[[Page 48438]]
stationary, fossil-fuel-fired combustion turbine serving at any time,
on or after January 1, 2005, a generator with nameplate capacity of
more than 25 MWe producing electricity for sale.
(2) If a stationary boiler or stationary combustion turbine that,
under paragraph (a)(1) of this section, is not a TR SO2
Group 1 unit begins to combust fossil fuel or to serve a generator with
nameplate capacity of more than 25 MWe producing electricity for sale,
the unit shall become a TR SO2 Group 1 unit as provided in
paragraph (a)(1) of this section on the first date on which it both
combusts fossil fuel and serves such generator.
(b) Any unit in a State (and Indian country within the borders of
such State) that otherwise is a TR SO2 Group 1 unit under
paragraph (a) of this section and that meets the requirements set forth
in paragraph (b)(1)(i) or (2)(i) of this section shall not be a TR
SO2 Group 1 unit:
(1)(i) Any unit:
(A) Qualifying as a cogeneration unit throughout the later of 2005
or the 12-month period starting on the date the unit first produces
electricity and continuing to qualify as a cogeneration unit throughout
each calendar year ending after the later of 2005 or such 12-month
period; and
(B) Not supplying in 2005 or any calendar year thereafter more than
one-third of the unit's potential electric output capacity or 219,000
MWh, whichever is greater, to any utility power distribution system for
sale.
(ii) If, after qualifying under paragraph (b)(1)(i) of this section
as not being a TR SO2 Group 1 unit, a unit subsequently no
longer meets all the requirements of paragraph (b)(1)(i) of this
section, the unit shall become a TR SO2 Group 1 unit
starting on the earlier of January 1 after the first calendar year
during which the unit first no longer qualifies as a cogeneration unit
or January 1 after the first calendar year during which the unit no
longer meets the requirements of paragraph (b)(1)(i)(B) of this
section. The unit shall thereafter continue to be a TR SO2
Group 1 unit.
(2)(i) Any unit:
(A) Qualifying as a solid waste incineration unit throughout the
later of 2005 or the 12-month period starting on the date the unit
first produces electricity and continuing to qualify as a solid waste
incineration unit throughout each calendar year ending after the later
of 2005 or such 12-month period; and
(B) With an average annual fuel consumption of fossil fuel for the
first 3 consecutive calendar years of operation starting no earlier
than 2005 of less than 20 percent (on a Btu basis) and an average
annual fuel consumption of fossil fuel for any 3 consecutive calendar
years thereafter of less than 20 percent (on a Btu basis).
(ii) If, after qualifying under paragraph (b)(2)(i) of this section
as not being a TR SO2 Group 1 unit, a unit subsequently no
longer meets all the requirements of paragraph (b)(1)(i) of this
section, the unit shall become a TR SO2 Group 1 unit
starting on the earlier of January 1 after the first calendar year
during which the unit first no longer qualifies as a solid waste
incineration unit or January 1 after the first 3 consecutive calendar
years after 2005 for which the unit has an average annual fuel
consumption of fossil fuel of 20 percent or more. The unit shall
thereafter continue to be a TR SO2 Group 1 unit.
(c) A certifying official of an owner or operator of any unit or
other equipment may submit a petition (including any supporting
documents) to the Administrator at any time for a determination
concerning the applicability, under paragraphs (a) and (b) of this
section or a SIP revision approved under Sec. 52.39(e) or (f) of this
chapter, of the TR SO2 Group 1 Trading Program to the unit
or other equipment.
(1) Petition content. The petition shall be in writing and include
the identification of the unit or other equipment and the relevant
facts about the unit or other equipment. The petition and any other
documents provided to the Administrator in connection with the petition
shall include the following certification statement, signed by the
certifying official: ``I am authorized to make this submission on
behalf of the owners and operators of the unit or other equipment 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) Response. The Administrator will issue a written response to
the petition and may request supplemental information determined by the
Administrator to be relevant to such petition. The Administrator's
determination concerning the applicability, under paragraphs (a) and
(b) of this section, of the TR SO2 Group 1 Trading Program
to the unit or other equipment shall be binding on any State or
permitting authority unless the Administrator determines that the
petition or other documents or information provided in connection with
the petition contained significant, relevant errors or omissions.
Sec. 97.605 Retired unit exemption.
(a)(1) Any TR SO2 Group 1 unit that is permanently
retired shall be exempt from Sec. 97.606(b) and (c)(1), Sec. 97.624,
and Sec. Sec. 97.630 through 97.635.
(2) The exemption under paragraph (a)(1) of this section shall
become effective the day on which the TR SO2 Group 1 unit is
permanently retired. Within 30 days of the unit's permanent retirement,
the designated representative shall submit a statement to the
Administrator. The statement shall state, in a format prescribed by the
Administrator, that the unit was permanently retired on a specified
date and will comply with the requirements of paragraph (b) of this
section.
(b) Special provisions. (1) A unit exempt under paragraph (a) of
this section shall not emit any SO2, starting on the date
that the exemption takes effect.
(2) For a period of 5 years from the date the records are created,
the owners and operators of a unit exempt under paragraph (a) of 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 before the
end of the period, in writing by the Administrator. The owners and
operators bear the burden of proof that the unit is permanently
retired.
(3) The owners and operators and, to the extent applicable, the
designated representative of a unit exempt under paragraph (a) of this
section shall comply with the requirements of the TR SO2
Group 1 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 exempt under paragraph (a) of this section shall lose
its exemption on the first date on which the unit resumes operation.
Such unit shall be treated, for purposes of applying allocation,
monitoring, reporting, and recordkeeping requirements under this
subpart, as a unit that commences commercial operation on the first
date on which the unit resumes operation.
[[Page 48439]]
Sec. 97.606 Standard requirements.
(a) Designated representative requirements. The owners and
operators shall comply with the requirement to have a designated
representative, and may have an alternate designated representative, in
accordance with Sec. Sec. 97.613 through 97.618.
(b) Emissions monitoring, reporting, and recordkeeping
requirements. (1) The owners and operators, and the designated
representative, of each TR SO2 Group 1 source and each TR
SO2 Group 1 unit at the source shall comply with the
monitoring, reporting, and recordkeeping requirements of Sec. Sec.
97.630 through 97.635.
(2) The emissions data determined in accordance with Sec. Sec.
97.630 through 97.635 shall be used to calculate allocations of TR
SO2 Group 1 allowances under Sec. Sec. 97.611(a)(2) and (b)
and 97.612 and to determine compliance with the TR SO2 Group
1 emissions limitation and assurance provisions under paragraph (c) of
this section, provided that, for each monitoring location from which
mass emissions are reported, the mass emissions amount used in
calculating such allocations and determining such compliance shall be
the mass emissions amount for the monitoring location determined in
accordance with Sec. Sec. 97.630 through 97.635 and rounded to the
nearest ton, with any fraction of a ton less than 0.50 being deemed to
be zero.
(c) SO2 emissions requirements. (1) TR SO2 Group 1
emissions limitation. (i) As of the allowance transfer deadline for a
control period in a given year, the owners and operators of each TR
SO2 Group 1 source and each TR SO2 Group 1 unit
at the source shall hold, in the source's compliance account, TR
SO2 Group 1 allowances available for deduction for such
control period under Sec. 97.624(a) in an amount not less than the
tons of total SO2 emissions for such control period from all
TR SO2 Group 1 units at the source.
(ii) If total SO2 emissions during a control period in a
given year from the TR SO2 Group 1 units at a TR
SO2 Group 1 source are in excess of the TR SO2
Group 1 emissions limitation set forth in paragraph (c)(1)(i) of this
section, then:
(A) The owners and operators of the source and each TR
SO2 Group 1 unit at the source shall hold the TR
SO2 Group 1 allowances required for deduction under Sec.
97.624(d); and
(B) The owners and operators of the source and each TR
SO2 Group 1 unit at the source shall pay any fine, penalty,
or assessment or comply with any other remedy imposed, for the same
violations, under the Clean Air Act, and each ton of such excess
emissions and each day of such control period shall constitute a
separate violation of this subpart and the Clean Air Act.
(2) TR SO2 Group 1 assurance provisions. (i) If total
SO2 emissions during a control period in a given year from
all TR SO2 Group 1 units at TR SO2 Group 1
sources in a State (and Indian country within the borders of such
State) exceed the State assurance level, then the owners and operators
of such sources and units in each group of one or more sources and
units having a common designated representative for such control
period, where the common designated representative's share of such
SO2 emissions during such control period exceeds the common
designated representative's assurance level for the State and such
control period, shall hold (in the assurance account established for
the owners and operators of such group) TR SO2 Group 1
allowances available for deduction for such control period under Sec.
97.625(a) in an amount equal to two times the product (rounded to the
nearest whole number), as determined by the Administrator in accordance
with Sec. 97.625(b), of multiplying--
(A) The quotient of the amount by which the common designated
representative's share of such SO2 emissions exceeds the
common designated representative's assurance level divided by the sum
of the amounts, determined for all common designated representatives
for such sources and units in the State (and Indian country within the
borders of such State) for such control period, by which each common
designated representative's share of such SO2 emissions
exceeds the respective common designated representative's assurance
level; and
(B) The amount by which total SO2 emissions from all TR
SO2 Group 1 units at TR SO2 Group 1 sources in
the State (and Indian country within the borders of such State) for
such control period exceed the State assurance level.
(ii) The owners and operators shall hold the TR SO2
Group 1 allowances required under paragraph (c)(2)(i) of this section,
as of midnight of November 1 (if it is a business day), or midnight of
the first business day thereafter (if November 1 is not a business
day), immediately after such control period.
(iii) Total SO2 emissions from all TR SO2
Group 1 units at TR SO2 Group 1 sources in a State (and
Indian country within the borders of such State) during a control
period in a given year exceed the State assurance level if such total
SO2 emissions exceed the sum, for such control period, of
the State SO2 Group 1 trading budget under Sec. 97.610(a)
and the State's variability limit under Sec. 97.610(b).
(iv) It shall not be a violation of this subpart or of the Clean
Air Act if total SO2 emissions from all TR SO2
Group 1 units at TR SO2 Group 1 sources in a State (and
Indian country within the borders of such State) during a control
period exceed the State assurance level or if a common designated
representative's share of total SO2 emissions from the TR
SO2 Group 1 units at TR SO2 Group 1 sources in a
State (and Indian country within the borders of such State) during a
control period exceeds the common designated representative's assurance
level.
(v) To the extent the owners and operators fail to hold TR
SO2 Group 1 allowances for a control period in a given year
in accordance with paragraphs (c)(2)(i) through (iii) of this section,
(A) The owners and operators shall pay any fine, penalty, or
assessment or comply with any other remedy imposed under the Clean Air
Act; and
(B) Each TR SO2 Group 1 allowance that the owners and
operators fail to hold for such control period in accordance with
paragraphs (c)(2)(i) through (iii) of this section and each day of such
control period shall constitute a separate violation of this subpart
and the Clean Air Act.
(3) Compliance periods. A TR SO2 Group 1 unit shall be
subject to the requirements under paragraphs (c)(1) and (c)(2) of this
section for the control period starting on the later of January 1, 2012
or the deadline for meeting the unit's monitor certification
requirements under Sec. 97.630(b) and for each control period
thereafter.
(4) Vintage of allowances held for compliance. (i) A TR
SO2 Group 1 allowance held for compliance with the
requirements under paragraph (c)(1)(i) of this section for a control
period in a given year must be a TR SO2 Group 1 allowance
that was allocated for such control period or a control period in a
prior year.
(ii) A TR SO2 Group 1 allowance held for compliance with
the requirements under paragraphs (c)(1)(ii)(A) and (2)(i) through
(iii) of this section for a control period in a given year must be a TR
SO2 Group 1 allowance that was allocated for a control
period in a prior year or the control period in the given year or in
the immediately following year.
(5) Allowance Management System requirements. Each TR
SO2 Group 1 allowance shall be held in, deducted from, or
transferred into, out of, or between Allowance Management
[[Page 48440]]
System accounts in accordance with this subpart.
(6) Limited authorization. A TR SO2 Group 1 allowance is
a limited authorization to emit one ton of SO2 during the
control period in one year. Such authorization is limited in its use
and duration as follows:
(i) Such authorization shall only be used in accordance with the TR
SO2 Group 1 Trading Program; and
(ii) Notwithstanding any other provision of this subpart, the
Administrator has the authority to terminate or limit the use and
duration of such authorization to the extent the Administrator
determines is necessary or appropriate to implement any provision of
the Clean Air Act.
(7) Property right. A TR SO2 Group 1 allowance does not
constitute a property right.
(d) Title V permit requirements. (1) No title V permit revision
shall be required for any allocation, holding, deduction, or transfer
of TR SO2 Group 1 allowances in accordance with this
subpart.
(2) A description of whether a unit is required to monitor and
report SO2 emissions using a continuous emission monitoring
system (under subpart H of part 75 of this chapter), an excepted
monitoring system (under appendices D and E to part 75 of this
chapter), a low mass emissions excepted monitoring methodology (under
Sec. 75.19 of this chapter), or an alternative monitoring system
(under subpart E of part 75 of this chapter) in accordance with
Sec. Sec. 97.630 through 97.635 may be added to, or changed in, a
title V permit using minor permit modification procedures in accordance
with Sec. Sec. 70.7(e)(2) and 71.7(e)(1) of this chapter, provided
that the requirements applicable to the described monitoring and
reporting (as added or changed, respectively) are already incorporated
in such permit. This paragraph explicitly provides that the addition
of, or change to, a unit's description as described in the prior
sentence is eligible for minor permit modification procedures in
accordance with Sec. Sec. 70.7(e)(2)(i)(B) and 71.7(e)(1)(i)(B) of
this chapter.
(e) Additional recordkeeping and reporting requirements. (1) Unless
otherwise provided, the owners and operators of each TR SO2
Group 1 source and each TR SO2 Group 1 unit at the source
shall keep on site at the source each of the following documents (in
hardcopy or electronic format) for a period of 5 years from the date
the document is created. This period may be extended for cause, at any
time before the end of 5 years, in writing by the Administrator.
(i) The certificate of representation under Sec. 97.616 for the
designated representative for the source and each TR SO2
Group 1 unit at the source and all documents that demonstrate the truth
of the statements in the certificate of representation; provided that
the certificate and documents shall be retained on site at the source
beyond such 5-year period until such certificate of representation and
documents are superseded because of the submission of a new certificate
of representation under Sec. 97.616 changing the designated
representative.
(ii) All emissions monitoring information, in accordance with this
subpart.
(iii) Copies of all reports, compliance certifications, and other
submissions and all records made or required under, or to demonstrate
compliance with the requirements of, the TR SO2 Group 1
Trading Program.
(2) The designated representative of a TR SO2 Group 1
source and each TR SO2 Group 1 unit at the source shall make
all submissions required under the TR SO2 Group 1 Trading
Program, except as provided in Sec. 97.618. This requirement does not
change, create an exemption from, or or otherwise affect the
responsible official submission requirements under a title V operating
permit program in parts 70 and 71 of this chapter.
(f) Liability. (1) Any provision of the TR SO2 Group 1
Trading Program that applies to a TR SO2 Group 1 source or
the designated representative of a TR SO2 Group 1 source
shall also apply to the owners and operators of such source and of the
TR SO2 Group 1 units at the source.
(2) Any provision of the TR SO2 Group 1 Trading Program
that applies to a TR SO2 Group 1 unit or the designated
representative of a TR SO2 Group 1 unit shall also apply to
the owners and operators of such unit.
(g) Effect on other authorities. No provision of the TR
SO2 Group 1 Trading Program or exemption under Sec. 97.605
shall be construed as exempting or excluding the owners and operators,
and the designated representative, of a TR SO2 Group 1
source or TR SO2 Group 1 unit from compliance with any other
provision of the applicable, approved State implementation plan, a
federally enforceable permit, or the Clean Air Act.
Sec. 97.607 Computation of time.
(a) Unless otherwise stated, any time period scheduled, under the
TR SO2 Group 1 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
TR SO2 Group 1 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 TR SO2 Group 1 Trading Program, is not a business
day, the time period shall be extended to the next business day.
Sec. 97.608 Administrative appeal procedures.
The administrative appeal procedures for decisions of the
Administrator under the TR SO2 Group 1 Trading Program are
set forth in part 78 of this chapter.
Sec. 97.609 [Reserved]
Sec. 97.610 State SO2 Group 1 trading budgets, new unit set-asides,
Indian country new unit set-aside, and variability limits.
(a) The State SO2 Group 1 trading budgets, new unit set-
asides, and Indian country new unit set-asides for allocations of TR
SO2 Group 1 allowances for the control periods in 2012 and
thereafter are as follows:
----------------------------------------------------------------------------------------------------------------
SO2 Group 1 Indian country new
trading budget New unit set-aside unit set-aside
State (tons) * for 2012 (tons) for 2012 (tons) for 2012
and 2013 and 2013 and 2013
----------------------------------------------------------------------------------------------------------------
Illinois............................................ 234,889 11,744 ..................
Indiana............................................. 285,424 8,563 ..................
Iowa................................................ 107,085 2,035 107
Kentucky............................................ 232,662 13,960 ..................
Maryland............................................ 30,120 602 ..................
Michigan............................................ 229,303 4,357 229
Missouri............................................ 207,466 4,149 ..................
New Jersey.......................................... 5,574 111 ..................
[[Page 48441]]
New York............................................ 27,325 520 27
North Carolina...................................... 136,881 10,813 137
Ohio................................................ 310,230 6,205 ..................
Pennsylvania........................................ 278,651 5,573 ..................
Tennessee........................................... 148,150 2,963 ..................
Virginia............................................ 70,820 2,833 ..................
West Virginia....................................... 146,174 10,232 ..................
Wisconsin........................................... 79,480 3,894 80
----------------------------------------------------------------------------------------------------------------
----------------------------------------------------------------------------------------------------------------
SO2 Group 1 Indian country new
trading budget New unit set-aside unit set-aside
State (tons) * for 2014 (tons) for 2014 (tons) for 2014
and thereafter and thereafter and thereafter
----------------------------------------------------------------------------------------------------------------
Illinois............................................ 124,123 6,206 ..................
Indiana............................................. 161,111 4,833 ..................
Iowa................................................ 75,184 1,429 75
Kentucky............................................ 106,284 6,377 ..................
Maryland............................................ 28,203 564 ..................
Michigan............................................ 143,995 2,736 144
Missouri............................................ 165,941 3,319 ..................
New Jersey.......................................... 5,574 111 ..................
New York............................................ 18,585 353 19
North Carolina...................................... 57,620 4,552 58
Ohio................................................ 137,077 2,742 ..................
Pennsylvania........................................ 112,021 2,240 ..................
Tennessee........................................... 58,833 1,177 ..................
Virginia............................................ 35,057 1,402 ..................
West Virginia....................................... 75,668 5,297 ..................
Wisconsin........................................... 40,126 1,966 40
----------------------------------------------------------------------------------------------------------------
* Each trading budget includes the new unit set-aside and, where applicable, the Indian country new unit set-
aside and does not include the variability limit.
(b) The States' variability limits for the State SO2
Group 1 trading budgets for the control periods in 2012 and thereafter
are as follows:
------------------------------------------------------------------------
Variability limits
State Variability limits for 2014 and
for 2012 and 2013 thereafter
------------------------------------------------------------------------
Illinois........................ 42,280 22,342
Indiana......................... 51,376 29,000
Iowa............................ 19,275 13,533
Kentucky........................ 41,879 19,131
Maryland........................ 5,422 5,077
Michigan........................ 41,275 25,919
Missouri........................ 37,344 29,869
New Jersey...................... 1,003 1,003
New York........................ 4,919 3,345
North Carolina.................. 24,639 10,372
Ohio............................ 55,841 24,674
Pennsylvania.................... 50,157 20,164
Tennessee....................... 26,667 10,590
Virginia........................ 12,748 6,310
West Virginia................... 26,311 13,620
Wisconsin....................... 14,306 7,223
------------------------------------------------------------------------
Sec. 97.611 Timing requirements for TR SO2 Group 1 allowance
allocations.
(a) Existing units. (1) TR SO2 Group 1 allowances are
allocated, for the control periods in 2012 and each year thereafter, as
provided in a notice of data availability issued by the Administrator.
Providing an allocation to a unit in such notice does not constitute a
determination that the unit is a TR SO2 Group 1 unit, and
not providing an allocation to a unit in such notice does not
constitute a determination that the unit is not a TR SO2
Group 1 unit.
(2) Notwithstanding paragraph (a)(1) of this section, if a unit
provided an allocation in the notice of data availability issued under
paragraph (a)(1) of this section does not operate, starting after 2011,
during the control period in two consecutive years, such unit will not
be allocated the TR SO2 Group 1 allowances provided in such
notice for the unit for the control periods in the fifth year after the
first such year and in each year after that fifth year. All TR
SO2 Group 1 allowances that would otherwise have been
allocated to such unit will be
[[Page 48442]]
allocated to the new unit set-aside for the State where such unit is
located and for the respective years involved. If such unit resumes
operation, the Administrator will allocate TR SO2 Group 1
allowances to the unit in accordance with paragraph (b) of this
section.
(b) New units. (1) New unit set-asides. (i) By June 1, 2012 and
June 1 of each year thereafter, the Administrator will calculate the TR
SO2 Group 1 allowance allocation to each TR SO2
Group 1 unit in a State, in accordance with Sec. 97.612(a)(2) through
(7) and (12), for the control period in the year of the applicable
calculation deadline under this paragraph and will promulgate a notice
of data availability of the results of the calculations.
(ii) For each notice of data availability required in paragraph
(b)(1)(i) of this section, the Administrator will provide an
opportunity for submission of objections to the calculations referenced
in such notice.
(A) Objections shall be submitted by the deadline specified in each
notice of data availability required in paragraph (b)(1)(i) of this
section and shall be limited to addressing whether the calculations
(including the identification of the TR SO2 Group 1 units)
are in accordance with Sec. 97.612(a)(2) through (7) and (12) and
Sec. Sec. 97.606(b)(2) and 97.630 through 97.635.
(B) The Administrator will adjust the calculations to the extent
necessary to ensure that they are in accordance with the provisions
referenced in paragraph (b)(1)(ii)(A) of this section. By August 1
immediately after the promulgation of each notice of data availability
required in paragraph (b)(1)(i) of this section, the Administrator will
promulgate a notice of data availability of any adjustments that the
Administrator determines to be necessary with regard to allocations
under Sec. 97.612(a)(2) through (7) and (12) and the reasons for
accepting or rejecting any objections submitted in accordance with
paragraph (b)(1)(ii)(A) of this section.
(iii) If the new unit set-aside for such control period contains
any TR SO2 Group 1 allowances that have not been allocated
in the applicable notice of data availability required in paragraph
(b)(1)(ii) of this section, the Administrator will promulgate, by
December 15 immediately after such notice, a notice of data
availability that identifies any TR SO2 Group 1 units that
commenced commercial operation during the period starting January 1 of
the year before the year of such control period and ending November 30
of year of such control period.
(iv) For each notice of data availability required in paragraph
(b)(1)(iii) of this section, the Administrator will provide an
opportunity for submission of objections to the identification of TR
SO2 annual units in such notice.
(A) Objections shall be submitted by the deadline specified in each
notice of data availability required in paragraph (b)(1)(iii) of this
section and shall be limited to addressing whether the identification
of TR SO2 annual units in such notice is in accordance with
paragraph (b)(1)(iii) of this section.
(B) The Administrator will adjust the identification of TR
SO2 Group 1 units in each notice of data availability
required in paragraph (b)(1)(iii) of this section to the extent
necessary to ensure that it is in accordance with paragraph (b)(1)(iii)
of this section and will calculate the TR SO2 Group 1
allowance allocation to each TR SO2 Group 1 unit in
accordance with Sec. 97.612(a)(9), (10), and (12) and Sec. Sec.
97.606(b)(2) and 97.630 through 97.635. By February 15 immediately
after the promulgation of each notice of data availability required in
paragraph (b)(1)(iii) of this section, the Administrator will
promulgate a notice of data availability of any adjustments of the
identification of TR SO2 Group 1 units that the
Administrator determines to be necessary, the reasons for accepting or
rejecting any objections submitted in accordance with paragraph
(b)(1)(iv)(A) of this section, and the results of such calculations.
(v) To the extent any TR SO2 Group 1 allowances are
added to the new unit set-aside after promulgation of each notice of
data availability required in paragraph (b)(1)(iv) of this section, the
Administrator will promulgate additional notices of data availability,
as deemed appropriate, of the allocation of such TR SO2
Group 1 allowances in accordance with Sec. 97.612(a)(10).
(2) Indian country new unit set-asides. (i) By June 1, 2012 and
June 1 of each year thereafter, the Administrator will calculate the TR
SO2 Group 1 allowance allocation to each TR SO2
Group 1 unit in Indian country within the borders of a State, in
accordance with Sec. 97.612(b)(2) through (7) and (12), for the
control period in the year of the applicable calculation deadline under
this paragraph and will promulgate a notice of data availability of the
results of the calculations.
(ii) For each notice of data availability required in paragraph
(b)(2)(i) of this section, the Administrator will provide an
opportunity for submission of objections to the calculations referenced
in such notice.
(A) Objections shall be submitted by the deadline specified in each
notice of data availability required in paragraph (b)(2)(i) of this
section and shall be limited to addressing whether the calculations
(including the identification of the TR SO2 Group 1 units)
are in accordance with Sec. 97.612(b)(2) through (7) and (12) and
Sec. Sec. 97.606(b)(2) and 97.630 through 97.635.
(B) The Administrator will adjust the calculations to the extent
necessary to ensure that they are in accordance with the provisions
referenced in paragraph (b)(2)(ii)(A) of this section. By August 1
immediately after the promulgation of each notice of data availability
required in paragraph (b)(2)(i) of this section, the Administrator will
promulgate a notice of data availability of any adjustments that the
Administrator determines to be necessary with regard to allocations
under Sec. 97.612(b)(2) through (7) and (12) and the reasons for
accepting or rejecting any objections submitted in accordance with
paragraph (b)(2)(ii)(A) of this section.
(iii) If the Indian country new unit set-aside for such control
period contains any TR SO2 Group 1 allowances that have not
been allocated in the applicable notice of data availability required
in paragraph (b)(2)(ii) of this section, the Administrator will
promulgate, by December 15 immediately after such notice, a notice of
data availability that identifies any TR SO2 Group 1 units
that commenced commercial operation during the period starting January
1 of the year before the year of such control period and ending
November 30 of year of such control period.
(iv) For each notice of data availability required in paragraph
(b)(2)(iii) of this section, the Administrator will provide an
opportunity for submission of objections to the identification of TR
SO2 annual units in such notice.
(A) Objections shall be submitted by the deadline specified in each
notice of data availability required in paragraph (b)(2)(iii) of this
section and shall be limited to addressing whether the identification
of TR SO2 annual units in such notice is in accordance with
paragraph (b)(2)(iii) of this section.
(B) The Administrator will adjust the identification of TR
SO2 Group 1 units in each notice of data availability
required in paragraph (b)(2)(iii) of this section to the extent
necessary to ensure that it is in accordance with paragraph (b)(2)(iii)
of this section and will calculate the TR SO2 Group 1
allowance allocation to each TR SO2 Group 1 unit in
accordance with Sec. 97.612(b)(9), (10),
[[Page 48443]]
and (12) and Sec. Sec. 97.606(b)(2) and 97.630 through 97.635. By
February 15 immediately after the promulgation of each notice of data
availability required in paragraph (b)(2)(iii) of this section, the
Administrator will promulgate a notice of data availability of any
adjustments of the identification of TR SO2 Group 1 units
that the Administrator determines to be necessary, the reasons for
accepting or rejecting any objections submitted in accordance with
paragraph (b)(2)(iv)(A) of this section, and the results of such
calculations.
(v) To the extent any TR SO2 Group 1 allowances are
added to the Indian country new unit set-aside after promulgation of
each notice of data availability required in paragraph (b)(2)(iv) of
this section, the Administrator will promulgate additional notices of
data availability, as deemed appropriate, of the allocation of such TR
NOX Annual allowances in accordance with Sec.
97.612(b)(10).
(c) Units incorrectly allocated TR SO2 Group 1
allowances. (1) For each control period in 2012 and thereafter, if the
Administrator determines that TR SO2 Group 1 allowances were
allocated under paragraph (a) of this section, or under a provision of
a SIP revision approved under Sec. 52.39(d), (e), or (f) of this
chapter, where such control period and the recipient are covered by the
provisions of paragraph (c)(1)(i) of this section or were allocated
under Sec. 97.612(a)(2) through (7), (9), and (12) and (b)(2) through
(7), (9), and (12), or under a provision of a SIP revision approved
under Sec. 52.39(e) or (f) of this chapter, where such control period
and the recipient are covered by the provisions of paragraph (c)(1)(ii)
of this section, then the Administrator will notify the designated
representative of the recipient and will act in accordance with the
procedures set forth in paragraphs (c)(2) through (5) of this section:
(i)(A) The recipient is not actually a TR SO2 Group 1
unit under Sec. 97.604 as of January 1, 2012 and is allocated TR
SO2 Group 1 allowances for such control period or, in the
case of an allocation under a provision of a SIP revision approved
under Sec. 52.39(d), (e), or (f) of this chapter, the recipient is not
actually a TR SO2 Group 1 unit as of January 1, 2012 and is
allocated TR SO2 Group 1 allowances for such control period
that the SIP revision provides should be allocated only to recipients
that are TR SO2 Group 1 units as of January 1, 2012; or
(B) The recipient is not located as of January 1 of the control
period in the State from whose SO2 Group 1 trading budget
the TR SO2 Group 1 allowances allocated under paragraph (a)
of this section, or under a provision of a SIP revision approved under
Sec. 52.39(d), (e), or (f) of this chapter, were allocated for such
control period.
(ii) The recipient is not actually a TR SO2 Group 1 unit
under Sec. 97.604 as of January 1 of such control period and is
allocated TR SO2 Group 1 allowances for such control period
or, in the case of an allocation under a provision of a SIP revision
approved under Sec. 52.39(d), (e), or (f) of this chapter, the
recipient is not actually a TR SO2 Group 1 unit as of
January 1 of such control period and is allocated TR SO2
Group 1 allowances for such control period that the SIP revision
provides should be allocated only to recipients that are TR
SO2 Group 1 units as of January 1 of such control period.
(2) Except as provided in paragraph (c)(3) or (4) of this section,
the Administrator will not record such TR SO2 Group 1
allowances under Sec. 97.621.
(3) If the Administrator already recorded such TR SO2
Group 1 allowances under Sec. 97.621 and if the Administrator makes
the determination under paragraph (c)(1) of this section before making
deductions for the source that includes such recipient under Sec.
97.624(b) for such control period, then the Administrator will deduct
from the account in which such TR SO2 Group 1 allowances
were recorded an amount of TR SO2 Group 1 allowances
allocated for the same or a prior control period equal to the amount of
such already recorded TR SO2 Group 1 allowances. The
authorized account representative shall ensure that there are
sufficient TR SO2 Group 1 allowances in such account for
completion of the deduction.
(4) If the Administrator already recorded such TR SO2
Group 1 allowances under Sec. 97.621 and if the Administrator makes
the determination under paragraph (c)(1) of this section after making
deductions for the source that includes such recipient under Sec.
97.624(b) for such control period, then the Administrator will not make
any deduction to take account of such already recorded TR
SO2 Group 1 allowances.
(5)(i) With regard to the TR SO2 Group 1 allowances that
are not recorded, or that are deducted as an incorrect allocation, in
accordance with paragraphs (c)(2) and (3) of this section for a
recipient under paragraph (c)(1)(i) of this section, the Administrator
will:
(A) Transfer such TR SO2 Group 1 allowances to the new
unit set-aside for such control period for the State from whose
SO2 Group 1 trading budget the TR SO2 Group 1
allowances were allocated; or
(B) If the State has a SIP revision approved under Sec. 52.39(e)
or (f) covering such control period, include such TR SO2
Group 1 allowances in the portion of the State SO2 Group 1
trading budget that may be allocated for such control period in
accordance with such SIP revision.
(ii) With regard to the TR SO2 Group 1 allowances that
were not allocated from the Indian country new unit set-aside for such
control period and that are not recorded, or that are deducted as an
incorrect allocation, in accordance with paragraphs (c)(2) and (3) of
this section for a recipient under paragraph (c)(1)(ii) of this
paragraph, the Administrator will:
(A) Transfer such TR SO2 Group 1 allowances to the new
unit set-aside for such control period; or
(B) If the State has a SIP revision approved under Sec. 52.39(e)
or (f) covering such control period, include such TR SO2
Group 1 allowances in the portion of the State SO2 Group 1
trading budget that may be allocated for such control period in
accordance with such SIP revision.
(iii) With regard to the TR SO2 Group 1 allowances that
were allocated from the Indian country new unit set-aside for such
control period and that are not recorded, or that are deducted as an
incorrect allocation, in accordance with paragraphs (c)(2) and (3) of
this section for a recipient under paragraph (c)(1)(ii) of this
paragraph, the Administrator will transfer such TR SO2 Group
1 allowances to the Indian country new unit set-aside for such control
period.
Sec. 97.612 TR SO2 Group 1 allowance allocations to new units.
(a) For each control period in 2012 and thereafter and for the TR
SO2 Group 1 units in each State, the Administrator will
allocate TR SO2 Group 1 allowances to the TR SO2
Group 1 units as follows:
(1) The TR SO2 Group 1 allowances will be allocated to
the following TR SO2 Group 1 units, except as provided in
paragraph (a)(10) of this section:
(i) TR SO2 Group 1 units that are not allocated an
amount of TR SO2 Group 1 allowances in the notice of data
availability issued under Sec. 97.611(a)(1);
(ii) TR SO2 Group 1 units whose allocation of an amount
of TR SO2 Group 1 allowances for such control period in the
notice of data availability issued under Sec. 97.611(a)(1) is covered
by Sec. 97.611(c)(2) or (3);
(iii) TR SO2 Group 1 units that are allocated an amount
of TR SO2 Group 1 allowances for such control period in
[[Page 48444]]
the notice of data availability issued under Sec. 97.611(a)(1), which
allocation is terminated for such control period pursuant to Sec.
97.611(a)(2), and that operate during the control period immediately
preceding such control period; or
(iv) For purposes of paragraph (a)(9) of this section, TR
SO2 Group 1 units under Sec. 97.611(c)(1)(ii) whose
allocation of an amount of TR SO2 Group 1 allowances for
such control period in the notice of data availability issued under
Sec. 97.611(b)(1)(ii)(B) is covered by Sec. 97.611(c)(2) or (3).
(2) The Administrator will establish a separate new unit set-aside
for the State for each such control period. Each such new unit set-
aside will be allocated TR SO2 Group 1 allowances in an
amount equal to the applicable amount of tons of SO2
emissions as set forth in Sec. 97.610(a) and will be allocated
additional TR SO2 Group 1 allowances (if any) in accordance
with Sec. Sec. 97.611(a)(2) and (c)(5) and paragraph (b)(10) of this
section.
(3) The Administrator will determine, for each TR SO2
Group 1 unit described in paragraph (a)(1) of this section, an
allocation of TR SO2 Group 1 allowances for the later of the
following control periods and for each subsequent control period:
(i) The control period in 2012;
(ii) The first control period after the control period in which the
TR SO2 Group 1 unit commences commercial operation;
(iii) For a unit described in paragraph (a)(1)(ii) of this section,
the first control period in which the TR SO2 Group 1 unit
operates in the State after operating in another jurisdiction and for
which the unit is not already allocated one or more TR SO2
Group 1 allowances; and
(iv) For a unit described in paragraph (a)(1)(iii) of this section,
the first control period after the control period in which the unit
resumes operation.
(4)(i) The allocation to each TR SO2 annual unit
described in paragraph (a)(1)(i) through (iii) of this section and for
each control period described in paragraph (a)(3) of this section will
be an amount equal to the unit's total tons of SO2 emissions
during the immediately preceding control period.
(ii) The Administrator will adjust the allocation amount in
paragraph (a)(4)(i) in accordance with paragraphs (a)(5) through (7)
and (12) of this section.
(5) The Administrator will calculate the sum of the TR
SO2 Group 1 allowances determined for all such TR
SO2 Group 1 units under paragraph (a)(4)(i) of this section
in the State for such control period.
(6) If the amount of TR SO2 Group 1 allowances in the
new unit set-aside for the State for such control period is greater
than or equal to the sum under paragraph (a)(5) of this section, then
the Administrator will allocate the amount of TR SO2 Group 1
allowances determined for each such TR SO2 Group 1 unit
under paragraph (a)(4)(i) of this section.
(7) If the amount of TR SO2 Group 1 allowances in the
new unit set-aside for the State for such control period is less than
the sum under paragraph (a)(5) of this section, then the Administrator
will allocate to each such TR SO2 Group 1 unit the amount of
the TR SO2 Group 1 allowances determined under paragraph
(a)(4)(i) of this section for the unit, multiplied by the amount of TR
SO2 Group 1 allowances in the new unit set-aside for such
control period, divided by the sum under paragraph (a)(5) of this
section, and rounded to the nearest allowance.
(8) The Administrator will notify the public, through the
promulgation of the notices of data availability described in Sec.
97.611(b)(1)(i) and (ii), of the amount of TR SO2 Group 1
allowances allocated under paragraphs (a)(2) through (7) and (12) of
this section for such control period to each TR SO2 Group 1
unit eligible for such allocation.
(9) If, after completion of the procedures under paragraphs (a)(5)
through (8) of this section for such control period, any unallocated TR
SO2 Group 1 allowances remain in the new unit set-aside for
the State for such control period, the Administrator will allocate such
TR SO2 Group 1 allowances as follows--
(i) The Administrator will determine, for each unit described in
paragraph (a)(1) of this section that commenced commercial operation
during the period starting January 1 of the year before the year of
such control period and ending November 30 of year of such control
period, the positive difference (if any) between the unit's emissions
during such control period and the amount of TR SO2 Group 1
allowances referenced in the notice of data availability required under
Sec. 97.611(b)(1)(ii) for the unit for such control period;
(ii) The Administrator will determine the sum of the positive
differences determined under paragraph (a)(9)(i) of this section;
(iii) If the amount of unallocated TR SO2 Group 1
allowances remaining in the new unit set-aside for the State for such
control period is greater than or equal to the sum determined under
paragraph (a)(9)(ii) of this section, then the Administrator will
allocate the amount of TR SO2 Group 1 allowances determined
for each such TR SO2 Group 1 unit under paragraph (a)(9)(i)
of this section; and
(iv) If the amount of unallocated TR SO2 Group 1
allowances remaining in the new unit set-aside for the State for such
control period is less than the sum under paragraph (a)(9)(ii) of this
section, then the Administrator will allocate to each such TR
SO2 Group 1 unit the amount of the TR SO2 Group 1
allowances determined under paragraph (a)(9)(i) of this section for the
unit, multiplied by the amount of unallocated TR SO2 Group 1
allowances remaining in the new unit set-aside for such control period,
divided by the sum under paragraph (a)(9)(ii) of this section, and
rounded to the nearest allowance.
(10) If, after completion of the procedures under paragraphs (a)(9)
and (12) of this section for such control period, any unallocated TR
SO2 Group 1 allowances remain in the new unit set-aside for
the State for such control period, the Administrator will allocate to
each TR SO2 Group 1 unit that is in the State, is allocated
an amount of TR SO2 Group 1 allowances in the notice of data
availability issued under Sec. 97.611(a)(1), and continues to be
allocated TR SO2 Group 1 allowances for such control period
in accordance with Sec. 97.611(a)(2), an amount of TR SO2
Group 1 allowances equal to the following: The total amount of such
remaining unallocated TR SO2 Group 1 allowances in such new
unit set-aside, multiplied by the unit's allocation under Sec.
97.611(a) for such control period, divided by the remainder of the
amount of tons in the applicable State SO2 Group 1 trading
budget minus the sum of the amounts of tons in such new unit set-aside
and the Indian country new unit set-aside for the State for such
control period, and rounded to the nearest allowance.
(11) The Administrator will notify the public, through the
promulgation of the notices of data availability described in Sec.
97.611(b)(1)(iii), (iv), and (v), of the amount of TR SO2
Group 1 allowances allocated under paragraphs (a)(9), (10), and (12) of
this section for such control period to each TR SO2 Group 1
unit eligible for such allocation.
(12)(i) Notwithstanding the requirements of paragraphs (a)(2)
through (11) of this section, if the calculations of allocations of a
new unit set-aside for a control period in a given year under paragraph
(a)(7) of this section, paragraphs (a)(6) and (9)(iv) of this section,
or paragraphs (a)(6), (9)(iii), and (10) of this section would
otherwise result in total allocations of such new unit set-aside
exceeding the total amount of such new unit set-aside, then
[[Page 48445]]
the Administrator will adjust the results of the calculations under
paragraph (a)(7), (9)(iv), or (10) of this section, as applicable, as
follows. The Administrator will list the TR SO2 Group 1
units in descending order based on the amount of such units'
allocations under paragraph (a)(7), (9)(iv), or (10) of this section,
as applicable, and, in cases of equal allocation amounts, in
alphabetical order of the relevant source's name and numerical order of
the relevant unit's identification number, and will reduce each unit's
allocation under paragraph (a)(7), (9)(iv), or (10) of this section, as
applicable, by one TR SO2 Group 1 allowance (but not below
zero) in the order in which the units are listed and will repeat this
reduction process as necessary, until the total allocations of such new
unit set-aside equal the total amount of such new unit set-aside.
(ii) Notwithstanding the requirements of paragraphs (a)(10) and
(11) of this section, if the calculations of allocations of a new unit
set-aside for a control period in a given year under paragraphs (a)(6),
(9)(iii), and (10) of this section would otherwise result in a total
allocations of such new unit set-aside less than the total amount of
such new unit set-aside, then the Administrator will adjust the results
of the calculations under paragraph (a)(10) of this section, as
follows. The Administrator will list the TR SO2 Group 1
units in descending order based on the amount of such units'
allocations under paragraph (a)(10) of this section and, in cases of
equal allocation amounts, in alphabetical order of the relevant
source's name and numerical order of the relevant unit's identification
number, and will increase each unit's allocation under paragraph
(a)(10) of this section by one TR SO2 Group 1 allowance in
the order in which the units are listed and will repeat this increase
process as necessary, until the total allocations of such new unit set-
aside equal the total amount of such new unit set-aside.
(b) For each control period in 2012 and thereafter and for the TR
SO2 Group 1 units located in Indian country within the
borders of each State, the Administrator will allocate TR
SO2 Group 1 allowances to the TR SO2 Group 1
units as follows:
(1) The TR SO2 Group 1 allowances will be allocated to
the following TR SO2 Group 1 units, except as provided in
paragraph (b)(10) of this section:
(i) TR SO2 Group 1 units that are not allocated an
amount of TR SO2 Group 1 allowances in the notice of data
availability issued under Sec. 97.611(a)(1); or
(ii) For purposes of paragraph (b)(9) of this section, TR
SO2 Group 1 units under Sec. 97.611(c)(1)(ii) whose
allocation of an amount of TR SO2 Group 1 allowances for
such control period in the notice of data availability issued under
Sec. 97.611(b)(2)(ii)(B) is covered by Sec. 97.611(c)(2) or (3).
(2) The Administrator will establish a separate Indian country new
unit set-aside for the State for each such control period. Each such
Indian country new unit set-aside will be allocated TR SO2
Group 1 allowances in an amount equal to the applicable amount of tons
of SO2 emissions as set forth in Sec. 97.610(a) and will be
allocated additional TR SO2 Group 1 allowances (if any) in
accordance with Sec. 97.611(c)(5).
(3) The Administrator will determine, for each TR SO2
Group 1 unit described in paragraph (b)(1) of this section, an
allocation of TR SO2 Group 1 allowances for the later of the
following control periods and for each subsequent control period:
(i) The control period in 2012; and
(ii) The first control period after the control period in which the
TR SO2 Group 1 unit commences commercial operation.
(4)(i) The allocation to each TR SO2 annual unit
described in paragraph (b)(1)(i) of this section and for each control
period described in paragraph (b)(3) of this section will be an amount
equal to the unit's total tons of SO2 emissions during the
immediately preceding control period.
(ii) The Administrator will adjust the allocation amount in
paragraph (b)(4)(i) in accordance with paragraphs (b)(5) through (7)
and (12) of this section.
(5) The Administrator will calculate the sum of the TR
SO2 Group 1 allowances determined for all such TR
SO2 Group 1 units under paragraph (b)(4)(i) of this section
in Indian country within the borders of the State for such control
period.
(6) If the amount of TR SO2 Group 1 allowances in the
Indian country new unit set-aside for the State for such control period
is greater than or equal to the sum under paragraph (b)(5) of this
section, then the Administrator will allocate the amount of TR
SO2 Group 1 allowances determined for each such TR
SO2 Group 1 unit under paragraph (b)(4)(i) of this section.
(7) If the amount of TR SO2 Group 1 allowances in the
Indian country new unit set-aside for the State for such control period
is less than the sum under paragraph (b)(5) of this section, then the
Administrator will allocate to each such TR SO2 Group 1 unit
the amount of the TR SO2 Group 1 allowances determined under
paragraph (b)(4)(i) of this section for the unit, multiplied by the
amount of TR SO2 Group 1 allowances in the Indian country
new unit set-aside for such control period, divided by the sum under
paragraph (b)(5) of this section, and rounded to the nearest allowance.
(8) The Administrator will notify the public, through the
promulgation of the notices of data availability described in Sec.
97.611(b)(2)(i) and (ii), of the amount of TR SO2 Group 1
allowances allocated under paragraphs (b)(2) through (7) and (12) of
this section for such control period to each TR SO2 Group 1
unit eligible for such allocation.
(9) If, after completion of the procedures under paragraphs (b)(5)
through (8) of this section for such control period, any unallocated TR
SO2 Group 1 allowances remain in the Indian country new unit
set-aside for the State for such control period, the Administrator will
allocate such TR SO2 Group 1 allowances as follows--
(i) The Administrator will determine, for each unit described in
paragraph (b)(1) of this section that commenced commercial operation
during the period starting January 1 of the year before the year of
such control period and ending November 30 of year of such control
period, the positive difference (if any) between the unit's emissions
during such control period and the amount of TR SO2 Group 1
allowances referenced in the notice of data availability required under
Sec. 97.611(b)(2)(ii) for the unit for such control period;
(ii) The Administrator will determine the sum of the positive
differences determined under paragraph (b)(9)(i) of this section;
(iii) If the amount of unallocated TR SO2 Group 1
allowances remaining in the Indian country new unit set-aside for the
State for such control period is greater than or equal to the sum
determined under paragraph (b)(9)(ii) of this section, then the
Administrator will allocate the amount of TR SO2 Group 1
allowances determined for each such TR SO2 Group 1 unit
under paragraph (b)(9)(i) of this section; and
(iv) If the amount of unallocated TR SO2 Group 1
allowances remaining in the Indian country new unit set-aside for the
State for such control period is less than the sum under paragraph
(b)(9)(ii) of this section, then the Administrator will allocate to
each such TR SO2 Group 1 unit the amount of the TR
SO2 Group 1 allowances determined under paragraph (b)(9)(i)
of this section for the unit, multiplied by the amount of unallocated
TR SO2 Group 1 allowances remaining in the Indian country
new unit set-aside for such control period, divided by the sum
[[Page 48446]]
under paragraph (b)(9)(ii) of this section, and rounded to the nearest
allowance.
(10) If, after completion of the procedures under paragraphs (b)(9)
and (12) of this section for such control period, any unallocated TR
SO2 Group 1 allowances remain in the Indian country new unit
set-aside for the State for such control period, the Administrator
will:
(i) Transfer such unallocated TR SO2 Group 1 allowances
to the new unit set-aside for the State for such control period; or
(ii) If the State has a SIP revision approved under Sec. 52.39(d),
(e), or (f) of this chapter covering such control period, include such
unallocated TR SO2 Group 1 allowances in the portion of the
State SO2 Group 1 trading budget that may be allocated for
such control period in accordance with such SIP revision.
(11) The Administrator will notify the public, through the
promulgation of the notices of data availability described in Sec.
97.611(b)(2)(iii), (iv), and (v), of the amount of TR SO2
Group 1 allowances allocated under paragraphs (b)(9), (10), and (12)
for such control period to each TR SO2 Group 1 unit eligible
for such allocation.
(12)(i) Notwithstanding the requirements of paragraphs (b)(2)
through (11) of this section, if the calculations of allocations of an
Indian country new unit set-aside for a control period in a given year
under paragraph (b)(7) of this section, paragraphs (b)(6) and (9)(iv)
of this section, or paragraphs (b)(6), (9)(iii), and (10) of this
section would otherwise result in total allocations of such Indian
country new unit set-aside exceeding the total amount of such Indian
country new unit set-aside, then the Administrator will adjust the
results of the calculations under paragraph (b)(7), (9)(iv), or (10) of
this section, as applicable, as follows. The Administrator will list
the TR SO2 Group 1 units in descending order based on the
amount of such units' allocations under paragraph (b)(7), (9)(iv), or
(10) of this section, as applicable, and, in cases of equal allocation
amounts, in alphabetical order of the relevant source's name and
numerical order of the relevant unit's identification number, and will
reduce each unit's allocation under paragraph (b)(7), (9)(iv), or (10)
of this section, as applicable, by one TR SO2 Group 1
allowance (but not below zero) in the order in which the units are
listed and will repeat this reduction process as necessary, until the
total allocations of such Indian country new unit set-aside equal the
total amount of such Indian country new unit set-aside.
(ii) Notwithstanding the requirements of paragraphs (b)(10) and
(11) of this section, if the calculations of allocations of an Indian
country new unit set-aside for a control period in a given year under
paragraphs (b)(6), (9)(iii), and (10) of this section would otherwise
result in a total allocations of such Indian country new unit set-aside
less than the total amount of such Indian country new unit set-aside,
then the Administrator will adjust the results of the calculations
under paragraph (b)(10) of this section, as follows. The Administrator
will list the TR SO2 Group 1 units in descending order based
on the amount of such units' allocations under paragraph (b)(10) of
this section and, in cases of equal allocation amounts, in alphabetical
order of the relevant source's name and numerical order of the relevant
unit's identification number, and will increase each unit's allocation
under paragraph (b)(10) of this section by one TR SO2 Group
1 allowance in the order in which the units are listed and will repeat
this increase process as necessary, until the total allocations of such
Indian country new unit set-aside equal the total amount of such Indian
country new unit set-aside.
Sec. 97.613 Authorization of designated representative and alternate
designated representative.
(a) Except as provided under Sec. 97.615, each TR SO2
Group 1 source, including all TR SO2 Group 1 units at the
source, shall have one and only one designated representative, with
regard to all matters under the TR SO2 Group 1 Trading
Program.
(1) The designated representative shall be selected by an agreement
binding on the owners and operators of the source and all TR
SO2 Group 1 units at the source and shall act in accordance
with the certification statement in Sec. 97.616(a)(4)(iii).
(2) Upon and after receipt by the Administrator of a complete
certificate of representation under Sec. 97.616:
(i) The designated representative shall be authorized and shall
represent and, by his or her representations, actions, inactions, or
submissions, legally bind each owner and operator of the source and
each TR SO2 Group 1 unit at the source in all matters
pertaining to the TR SO2 Group 1 Trading Program,
notwithstanding any agreement between the designated representative and
such owners and operators; and
(ii) The owners and operators of the source and each TR
SO2 Group 1 unit at the source shall be bound by any
decision or order issued to the designated representative by the
Administrator regarding the source or any such unit.
(b) Except as provided under Sec. 97.615, each TR SO2
Group 1 source may have one and only one alternate designated
representative, who may act on behalf of the designated representative.
The agreement by which the alternate designated representative is
selected shall include a procedure for authorizing the alternate
designated representative to act in lieu of the designated
representative.
(1) The alternate designated representative shall be selected by an
agreement binding on the owners and operators of the source and all TR
SO2 Group 1 units at the source and shall act in accordance
with the certification statement in Sec. 97.616(a)(4)(iii).
(2) Upon and after receipt by the Administrator of a complete
certificate of representation under Sec. 97.616,
(i) The alternate designated representative shall be authorized;
(ii) Any representation, action, inaction, or submission by the
alternate designated representative shall be deemed to be a
representation, action, inaction, or submission by the designated
representative; and
(iii) The owners and operators of the source and each TR
SO2 Group 1 unit at the source shall be bound by any
decision or order issued to the alternate designated representative by
the Administrator regarding the source or any such unit.
(c) Except in this section, Sec. 97.602, and Sec. Sec. 97.614
through 97.618, whenever the term ``designated representative'' (as
distinguished from the term ``common designated representative'') is
used in this subpart, the term shall be construed to include the
designated representative or any alternate designated representative.
Sec. 97.614 Responsibilities of designated representative and
alternate designated representative.
(a) Except as provided under Sec. 97.618 concerning delegation of
authority to make submissions, each submission under the TR
SO2 Group 1 Trading Program shall be made, signed, and
certified by the designated representative or alternate designated
representative for each TR SO2 Group 1 source and TR
SO2 Group 1 unit for which the submission is made. Each such
submission shall include the following certification statement by the
designated representative or alternate designated representative: ``I
am authorized to make this submission on behalf of the owners and
operators of the source or units for which the submission is made. I
certify under
[[Page 48447]]
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.''
(b) The Administrator will accept or act on a submission made for a
TR SO2 Group 1 source or a TR SO2 Group 1 unit
only if the submission has been made, signed, and certified in
accordance with paragraph (a) of this section and Sec. 97.618.
Sec. 97.615 Changing designated representative and alternate
designated representative; changes in owners and operators; changes in
units at the source.
(a) Changing designated representative. The designated
representative may be changed at any time upon receipt by the
Administrator of a superseding complete certificate of representation
under Sec. 97.616. Notwithstanding any such change, all
representations, actions, inactions, and submissions by the previous
designated representative before the time and date when the
Administrator receives the superseding certificate of representation
shall be binding on the new designated representative and the owners
and operators of the TR SO2 Group 1 source and the TR
SO2 Group 1 units at the source.
(b) Changing alternate designated representative. The alternate
designated representative may be changed at any time upon receipt by
the Administrator of a superseding complete certificate of
representation under Sec. 97.616. Notwithstanding any such change, all
representations, actions, inactions, and submissions by the previous
alternate designated representative before the time and date when the
Administrator receives the superseding certificate of representation
shall be binding on the new alternate designated representative, the
designated representative, and the owners and operators of the TR
SO2 Group 1 source and the TR SO2 Group 1 units
at the source.
(c) Changes in owners and operators. (1) In the event an owner or
operator of a TR SO2 Group 1 source or a TR SO2
Group 1 unit at the source is not included in the list of owners and
operators in the certificate of representation under Sec. 97.616, such
owner or operator shall be deemed to be subject to and bound by the
certificate of representation, the representations, actions, inactions,
and submissions of the designated representative and any alternate
designated representative of the source or unit, and the decisions and
orders of the Administrator, as if the owner or operator were included
in such list.
(2) Within 30 days after any change in the owners and operators of
a TR SO2 Group 1 source or a TR SO2 Group 1 unit
at the source, including the addition or removal of an owner or
operator, the designated representative or any alternate designated
representative shall submit a revision to the certificate of
representation under Sec. 97.616 amending the list of owners and
operators to reflect the change.
(d) Changes in units at the source. Within 30 days of any change in
which units are located at a TR SO2 Group 1 source
(including the addition or removal of a unit), the designated
representative or any alternate designated representative shall submit
a certificate of representation under Sec. 97.616 amending the list of
units to reflect the change.
(1) If the change is the addition of a unit that operated (other
than for purposes of testing by the manufacturer before initial
installation) before being located at the source, then the certificate
of representation shall identify, in a format prescribed by the
Administrator, the entity from whom the unit was purchased or otherwise
obtained (including name, address, telephone number, and facsimile
number (if any)), the date on which the unit was purchased or otherwise
obtained, and the date on which the unit became located at the source.
(2) If the change is the removal of a unit, then the certificate of
representation shall identify, in a format prescribed by the
Administrator, the entity to which the unit was sold or that otherwise
obtained the unit (including name, address, telephone number, and
facsimile number (if any)), the date on which the unit was sold or
otherwise obtained, and the date on which the unit became no longer
located at the source.
Sec. 97.616 Certificate of representation.
(a) A complete certificate of representation for a designated
representative or an alternate designated representative shall include
the following elements in a format prescribed by the Administrator:
(1) Identification of the TR SO2 Group 1 source, and
each TR SO2 Group 1 unit at the source, for which the
certificate of representation is submitted, including source name,
source category and NAICS code (or, in the absence of a NAICS code, an
equivalent code), State, plant code, county, latitude and longitude,
unit identification number and type, identification number and
nameplate capacity (in MWe, rounded to the nearest tenth) of each
generator served by each such unit, actual or projected date of
commencement of commercial operation, and a statement of whether such
source is located in Indian Country. If a projected date of
commencement of commercial operation is provided, the actual date of
commencement of commercial operation shall be provided when such
information becomes available.
(2) The name, address, e-mail address (if any), telephone number,
and facsimile transmission number (if any) of the designated
representative and any alternate designated representative.
(3) A list of the owners and operators of the TR SO2
Group 1 source and of each TR SO2 Group 1 unit at the
source.
(4) The following certification statements by the designated
representative and any alternate designated representative--
(i) ``I certify that I was selected as the designated
representative or alternate designated representative, as applicable,
by an agreement binding on the owners and operators of the source and
each TR SO2 Group 1 unit at the source.''
(ii) ``I certify that I have all the necessary authority to carry
out my duties and responsibilities under the TR SO2 Group 1
Trading Program on behalf of the owners and operators of the source and
of each TR SO2 Group 1 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 Administrator regarding the source or unit.''
(iii) ``Where there are multiple holders of a legal or equitable
title to, or a leasehold interest in, a TR SO2 Group 1 unit,
or where a utility or industrial customer purchases power from a TR
SO2 Group 1 unit under a life-of-the-unit, firm power
contractual arrangement, I certify that: I have given a written notice
of my selection as the `designated representative' or `alternate
designated representative', as applicable, and of the agreement by
which I was selected to each owner and operator of the source and of
each TR SO2 Group 1 unit at the source; and TR
SO2 Group 1 allowances and proceeds of transactions
involving TR SO2 Group 1 allowances will be deemed to be
held or distributed in proportion to each
[[Page 48448]]
holder's legal, equitable, leasehold, or contractual reservation or
entitlement, except that, if such multiple holders have expressly
provided for a different distribution of TR SO2 Group 1
allowances by contract, TR SO2 Group 1 allowances and
proceeds of transactions involving TR SO2 Group 1 allowances
will be deemed to be held or distributed in accordance with the
contract.''
(5) The signature of the designated representative and any
alternate designated representative and the dates signed.
(b) Unless otherwise required by the Administrator, documents of
agreement referred to in the certificate of representation shall not be
submitted to the Administrator. The Administrator shall not be under
any obligation to review or evaluate the sufficiency of such documents,
if submitted.
Sec. 97.617 Objections concerning designated representative and
alternate designated representative.
(a) Once a complete certificate of representation under Sec.
97.616 has been submitted and received, the Administrator will rely on
the certificate of representation unless and until a superseding
complete certificate of representation under Sec. 97.616 is received
by the Administrator.
(b) Except as provided in paragraph (a) of this section, no
objection or other communication submitted to the Administrator
concerning the authorization, or any representation, action, inaction,
or submission, of a designated representative or alternate designated
representative shall affect any representation, action, inaction, or
submission of the designated representative or alternate designated
representative or the finality of any decision or order by the
Administrator under the TR SO2 Group 1 Trading Program.
(c) The Administrator will not adjudicate any private legal dispute
concerning the authorization or any representation, action, inaction,
or submission of any designated representative or alternate designated
representative, including private legal disputes concerning the
proceeds of TR SO2 Group 1 allowance transfers.
Sec. 97.618 Delegation by designated representative and alternate
designated representative.
(a) A designated representative may delegate, to one or more
natural persons, his or her authority to make an electronic submission
to the Administrator provided for or required under this subpart.
(b) An alternate designated representative may delegate, to one or
more natural persons, his or her authority to make an electronic
submission to the Administrator provided for or required under this
subpart.
(c) In order to delegate authority to a natural person to make an
electronic submission to the Administrator in accordance with paragraph
(a) or (b) of this section, the designated representative or alternate
designated representative, as appropriate, must submit to the
Administrator a notice of delegation, in a format prescribed by the
Administrator, that includes the following elements:
(1) The name, address, e-mail address, telephone number, and
facsimile transmission number (if any) of such designated
representative or alternate designated representative;
(2) The name, address, e-mail address, telephone number, and
facsimile transmission number (if any) of each such natural person
(referred to in this section as an ``agent'');
(3) For each such natural person, a list of the type or types of
electronic submissions under paragraph (a) or (b) of this section for
which authority is delegated to him or her; and
(4) The following certification statements by such designated
representative or alternate designated representative:
(i) ``I agree that any electronic submission to the Administrator
that is made by an agent identified in this notice of delegation and of
a type listed for such agent in this notice of delegation and that is
made when I am a designated representative or alternate designated
representative, as appropriate, and before this notice of delegation is
superseded by another notice of delegation under 40 CFR 97.618(d) shall
be deemed to be an electronic submission by me.''
(ii) ``Until this notice of delegation is superseded by another
notice of delegation under 40 CFR 97.618(d), I agree to maintain an e-
mail account and to notify the Administrator immediately of any change
in my e-mail address unless all delegation of authority by me under 40
CFR 97.618 is terminated.''.
(d) A notice of delegation submitted under paragraph (c) of this
section shall be effective, with regard to the designated
representative or alternate designated representative identified in
such notice, upon receipt of such notice by the Administrator and until
receipt by the Administrator of a superseding notice of delegation
submitted by such designated representative or alternate designated
representative, as appropriate. The superseding notice of delegation
may replace any previously identified agent, add a new agent, or
eliminate entirely any delegation of authority.
(e) Any electronic submission covered by the certification in
paragraph (c)(4)(i) of this section and made in accordance with a
notice of delegation effective under paragraph (d) of this section
shall be deemed to be an electronic submission by the designated
representative or alternate designated representative submitting such
notice of delegation.
Sec. 97.619 [Reserved]
Sec. 97.620 Establishment of compliance accounts, assurance accounts,
and general accounts.
(a) Compliance accounts. Upon receipt of a complete certificate of
representation under Sec. 97.616, the Administrator will establish a
compliance account for the TR SO2 Group 1 source for which
the certificate of representation was submitted, unless the source
already has a compliance account. The designated representative and any
alternate designated representative of the source shall be the
authorized account representative and the alternate authorized account
representative respectively of the compliance account.
(b) Assurance accounts. The Administrator will establish assurance
accounts for certain owners and operators and States in accordance with
Sec. 97.625(b)(3).
(c) General accounts. (1) Application for general account. (i) Any
person may apply to open a general account, for the purpose of holding
and transferring TR SO2 Group 1 allowances, by submitting to
the Administrator a complete application for a general account. Such
application shall designate one and only one authorized account
representative and may designate one and only one alternate authorized
account representative who may act on behalf of the authorized account
representative.
(A) The authorized account representative and alternate authorized
account representative shall be selected by an agreement binding on the
persons who have an ownership interest with respect to TR
SO2 Group 1 allowances held in the general account.
(B) The agreement by which the alternate authorized account
representative is selected shall include a procedure for authorizing
the alternate authorized account representative to act in lieu of the
authorized account representative.
(ii) A complete application for a general account shall include the
[[Page 48449]]
following elements in a format prescribed by the Administrator:
(A) Name, mailing address, e-mail address (if any), telephone
number, and facsimile transmission number (if any) of the authorized
account representative and any alternate authorized account
representative;
(B) An identifying name for the general account;
(C) A list of all persons subject to a binding agreement for the
authorized account representative and any alternate authorized account
representative to represent their ownership interest with respect to
the TR SO2 Group 1 allowances held in the general account;
(D) The following certification statement by the authorized account
representative and any alternate authorized account representative: ``I
certify that I was selected as the authorized account representative or
the alternate authorized account representative, as applicable, by an
agreement that is binding on all persons who have an ownership interest
with respect to TR SO2 Group 1 allowances held in the
general account. I certify that I have all the necessary authority to
carry out my duties and responsibilities under the TR SO2
Group 1 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 decision or order issued to me by the
Administrator regarding the general account.''
(E) The signature of the authorized account representative and any
alternate authorized account representative and the dates signed.
(iii) Unless otherwise required by the Administrator, documents of
agreement referred to in the application for a general account shall
not be submitted to the Administrator. The Administrator shall not be
under any obligation to review or evaluate the sufficiency of such
documents, if submitted.
(2) Authorization of authorized account representative and
alternate authorized account representative. (i) Upon receipt by the
Administrator of a complete application for a general account under
paragraph (b)(1) of this section, the Administrator will establish a
general account for the person or persons for whom the application is
submitted, and upon and after such receipt by the Administrator:
(A) The authorized account representative of the general account
shall be authorized and shall represent and, by his or her
representations, actions, inactions, or submissions, legally bind each
person who has an ownership interest with respect to TR SO2
Group 1 allowances held in the general account in all matters
pertaining to the TR SO2 Group 1 Trading Program,
notwithstanding any agreement between the authorized account
representative and such person.
(B) Any alternate authorized account representative shall be
authorized, and any representation, action, inaction, or submission by
any alternate authorized account representative shall be deemed to be a
representation, action, inaction, or submission by the authorized
account representative.
(C) Each person who has an ownership interest with respect to TR
SO2 Group 1 allowances held in the general account shall be
bound by any decision or order issued to the authorized account
representative or alternate authorized account representative by the
Administrator regarding the general account.
(ii) Except as provided in paragraph (c)(5) of this section
concerning delegation of authority to make submissions, each submission
concerning the general account shall be made, signed, and certified by
the authorized account representative or any alternate authorized
account representative for the persons having an ownership interest
with respect to TR SO2 Group 1 allowances held in the
general account. Each such submission shall include the following
certification statement by the authorized account representative or any
alternate authorized account representative: ``I am authorized to make
this submission on behalf of the persons having an ownership interest
with respect to the TR SO2 Group 1 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.''
(iii) Except in this section, whenever the term ``authorized
account representative'' is used in this subpart, the term shall be
construed to include the authorized account representative or any
alternate authorized account representative.
(3) Changing authorized account representative and alternate
authorized account representative; changes in persons with ownership
interest. (i) The authorized account representative of 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 (c)(1) of this section. Notwithstanding any such change, all
representations, actions, inactions, and submissions by the previous
authorized account representative before the time and date when the
Administrator receives the superseding application for a general
account shall be binding on the new authorized account representative
and the persons with an ownership interest with respect to the TR
SO2 Group 1 allowances in the general account.
(ii) The alternate authorized account representative of 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 (c)(1) of this section. Notwithstanding any such change, all
representations, actions, inactions, and submissions by the previous
alternate authorized account representative before the time and date
when the Administrator receives the superseding application for a
general account shall be binding on the new alternate authorized
account representative, the authorized account representative, and the
persons with an ownership interest with respect to the TR
SO2 Group 1 allowances in the general account.
(iii)(A) In the event a person having an ownership interest with
respect to TR SO2 Group 1 allowances in the general account
is not included in the list of such persons in the application for a
general account, such person shall be deemed to be subject to and bound
by the application for a general account, the representation, actions,
inactions, and submissions of the authorized account representative and
any alternate authorized account representative of the account, and the
decisions and orders of the Administrator, as if the person were
included in such list.
(B) Within 30 days after any change in the persons having an
ownership interest with respect to SO2 Group 1 allowances in
the general account, including the addition or removal of a person, the
authorized account representative or any alternate 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 TR SO2 Group 1 allowances in the general
account to include the change.
(4) Objections concerning authorized account representative and
alternate
[[Page 48450]]
authorized account representative. (i) Once a complete application for
a general account under paragraph (c)(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 (c)(4)(i) of this section, no
objection or other communication submitted to the Administrator
concerning the authorization, or any representation, action, inaction,
or submission of the authorized account representative or any alternate
authorized account representative of a general account shall affect any
representation, action, inaction, or submission of the authorized
account representative or any alternate authorized account
representative or the finality of any decision or order by the
Administrator under the TR SO2 Group 1 Trading Program.
(iii) The Administrator will not adjudicate any private legal
dispute concerning the authorization or any representation, action,
inaction, or submission of the authorized account representative or any
alternate authorized account representative of a general account,
including private legal disputes concerning the proceeds of TR
SO2 Group 1 allowance transfers.
(5) Delegation by authorized account representative and alternate
authorized account representative. (i) An authorized account
representative of a general account may delegate, to one or more
natural persons, his or her authority to make an electronic submission
to the Administrator provided for or required under this subpart.
(ii) An alternate authorized account representative of a general
account may delegate, to one or more natural persons, his or her
authority to make an electronic submission to the Administrator
provided for or required under this subpart.
(iii) In order to delegate authority to a natural person to make an
electronic submission to the Administrator in accordance with paragraph
(c)(5)(i) or (ii) of this section, the authorized account
representative or alternate authorized account representative, as
appropriate, must submit to the Administrator a notice of delegation,
in a format prescribed by the Administrator, that includes the
following elements:
(A) The name, address, e-mail address, telephone number, and
facsimile transmission number (if any) of such authorized account
representative or alternate authorized account representative;
(B) The name, address, e-mail address, telephone number, and
facsimile transmission number (if any) of each such natural person
(referred to in this section as an ``agent'');
(C) For each such natural person, a list of the type or types of
electronic submissions under paragraph (c)(5)(i) or (ii) of this
section for which authority is delegated to him or her;
(D) The following certification statement by such authorized
account representative or alternate authorized account representative:
``I agree that any electronic submission to the Administrator that is
made by an agent identified in this notice of delegation and of a type
listed for such agent in this notice of delegation and that is made
when I am an authorized account representative or alternate authorized
representative, as appropriate, and before this notice of delegation is
superseded by another notice of delegation under 40 CFR
97.620(c)(5)(iv) shall be deemed to be an electronic submission by
me.''; and
(E) The following certification statement by such authorized
account representative or alternate authorized account representative:
``Until this notice of delegation is superseded by another notice of
delegation under 40 CFR 97.620(c)(5)(iv), I agree to maintain an e-mail
account and to notify the Administrator immediately of any change in my
e-mail address unless all delegation of authority by me under 40 CFR
97.620(c)(5) is terminated.''.
(iv) A notice of delegation submitted under paragraph (c)(5)(iii)
of this section shall be effective, with regard to the authorized
account representative or alternate authorized account representative
identified in such notice, upon receipt of such notice by the
Administrator and until receipt by the Administrator of a superseding
notice of delegation submitted by such authorized account
representative or alternate authorized account representative, as
appropriate. The superseding notice of delegation may replace any
previously identified agent, add a new agent, or eliminate entirely any
delegation of authority.
(v) Any electronic submission covered by the certification in
paragraph (c)(5)(iii)(D) of this section and made in accordance with a
notice of delegation effective under paragraph (c)(5)(iv) of this
section shall be deemed to be an electronic submission by the
designated representative or alternate designated representative
submitting such notice of delegation.
(6) Closing a general account. (i) The authorized account
representative or alternate authorized account representative of a
general account may submit to the Administrator a request to close the
account. Such request shall include a correctly submitted TR
SO2 Group 1 allowance transfer under Sec. 97.622 for any TR
SO2 Group 1 allowances in the account to one or more other
Allowance Management System accounts.
(ii) If a general account has no TR SO2 Group 1
allowance transfers to or from the account for a 12-month period or
longer and does not contain any TR SO2 Group 1 allowances,
the Administrator may notify the authorized account representative for
the account that the account will be closed after 30 days after the
notice is sent. The account will be closed after the 30-day period
unless, before the end of the 30-day period, the Administrator receives
a correctly submitted TR SO2 Group 1 allowance transfer
under Sec. 97.622 to the account or a statement submitted by the
authorized account representative or alternate authorized account
representative demonstrating to the satisfaction of the Administrator
good cause as to why the account should not be closed.
(d) Account identification. The Administrator will assign a unique
identifying number to each account established under paragraph (a),
(b), or (c) of this section.
(e) Responsibilities of authorized account representative and
alternate authorized account representative. After the establishment of
a compliance account or general account, the Administrator will accept
or act on a submission pertaining to the account, including, but not
limited to, submissions concerning the deduction or transfer of TR
SO2 Group 1 allowances in the account, only if the
submission has been made, signed, and certified in accordance with
Sec. Sec. 97.614(a) and 97.618 or paragraphs (c)(2)(ii) and (c)(5) of
this section.
Sec. 97.621 Recordation of TR SO2 Group 1 allowance allocations and
auction results.
(a) By November 7, 2011, the Administrator will record in each TR
SO2 Group 1 source's compliance account the TR
SO2 Group 1 allowances allocated to the TR SO2
Group 1 units at the source in accordance with Sec. 97.611(a) for the
control period in 2012.
(b) By November 7, 2011, the Administrator will record in each TR
SO2 Group 1 source's compliance account the TR
SO2 Group 1 allowances allocated to the TR SO2
Group 1 units at the source in accordance with
[[Page 48451]]
Sec. 97.611(a) for the control period in 2013, unless the State in
which the source is located notifies the Administrator in writing by
October 17, 2011 of the State's intent to submit to the Administrator a
complete SIP revision by April 1, 2012 meeting the requirements of
Sec. 52.39(d)(1) through (4) of this chapter.
(1) If, by April 1, 2012, the State does not submit to the
Administrator such complete SIP revision, the Administrator will record
by April 15, 2012 in each TR SO2 Group 1 source's compliance
account the TR SO2 Group 1 allowances allocated to the TR
SO2 Group 1 units at the source in accordance with Sec.
97.611(a) for the control period in 2013.
(2) If the State submits to the Administrator by April 1, 2012, and
the Administrator approves by October 1, 2012, such complete SIP
revision, the Administrator will record by October 1, 2012 in each TR
SO2 Group 1 source's compliance account the TR
SO2 Group 1 allowances allocated to the TR SO2
Group 1 units at the source as provided in such approved, complete SIP
revision for the control period in 2013.
(3) If the State submits to the Administrator by April 1, 2012, and
the Administrator does not approve by October 1, 2012, such complete
SIP revision, the Administrator will record by October 1, 2012 in each
TR SO2 Group 1 source's compliance account the TR
SO2 Group 1 allowances allocated to the TR SO2
Group 1 units at the source in accordance with Sec. 97.611(a) for the
control period in 2013.
(c) By July 1, 2013, the Administrator will record in each TR
SO2 Group 1 source's compliance account the TR
SO2 Group 1 allowances allocated to the TR SO2
Group 1 units at the source, or in each appropriate Allowance
Management System account the TR SO2 Group 1 allowances
auctioned to TR SO2 Group 1 units, in accordance with Sec.
97.611(a), or with a SIP revision approved under Sec. 52.39(e) or (f)
of this chapter, for the control period in 2014 and 2015.
(d) By July 1, 2014, the Administrator will record in each TR
SO2 Group 1 source's compliance account the TR
SO2 Group 1 allowances allocated to the TR SO2
Group 1 units at the source, or in each appropriate Allowance
Management System account the TR SO2 Group 1 allowances
auctioned to TR SO2 Group 1 units, in accordance with Sec.
97.611(a), or with a SIP revision approved under Sec. 52.39(e) or (f)
of this chapter, for the control period in 2016 and 2017.
(e) By July 1, 2015, the Administrator will record in each TR
SO2 Group 1 source's compliance account the TR
SO2 Group 1 allowances allocated to the TR SO2
Group 1 units at the source, or in each appropriate Allowance
Management System account the TR SO2 Group 1 allowances
auctioned to TR SO2 Group 1 units, in accordance with Sec.
97.611(a), or with a SIP revision approved under Sec. 52.39(e) or (f)
of this chapter, for the control period in 2018 and 2019.
(f) By July 1, 2016 and July 1 of each year thereafter, the
Administrator will record in each TR SO2 Group 1 source's
compliance account the TR SO2 Group 1 allowances allocated
to the TR SO2 Group 1 units at the source, or in each
appropriate Allowance Management System account the TR SO2
Group 1 allowances auctioned to TR SO2 Group 1 units, in
accordance with Sec. 97.611(a), or with a SIP revision approved under
Sec. 52.39(e) and (f) of this chapter, for the control period in the
fourth year after the year of the applicable recordation deadline under
this paragraph.
(g) By August 1, 2012 and August 1 of each year thereafter, the
Administrator will record in each TR SO2 Group 1 source's
compliance account the TR SO2 Group 1 allowances allocated
to the TR SO2 Group 1 units at the source, or in each
appropriate Allowance Management System account the TR SO2
Group 1 allowances auctioned to TR SO2 Group 1 units, in
accordance with Sec. 97.612(a)(2) through (8) and (12), or with a SIP
revision approved under Sec. 52.39(e) and (f) of this chapter, for the
control period in the year of the applicable recordation deadline under
this paragraph.
(h) By August 1, 2012 and August 1 of each year thereafter, the
Administrator will record in each TR SO2 Group 1 source's
compliance account the TR SO2 Group 1 allowances allocated
to the TR SO2 Group 1 units at the source in accordance with
Sec. 97.612(b)(2) through (8) and (12) for the control period in the
year of the applicable recordation deadline under this paragraph.
(i) By February 15, 2013 and February 15 of each year thereafter,
the Administrator will record in each TR SO2 Group 1
source's compliance account the TR SO2 Group 1 allowances
allocated to the TR SO2 Group 1 units at the source in
accordance with Sec. 97.612(a)(9) through (12), for the control period
in the year before the year of the applicable recordation deadline
under this paragraph.
(j) By the date on which any allocation or auction results, other
than an allocation or auction results described in paragraphs (a)
through (i) of this section, of TR SO2 Group 1 allowances to
a recipient is made by or are submitted to the Administrator in
accordance with Sec. 97.611 or Sec. 97.612 or with a SIP revision
approved under Sec. 52.39(e) or (f) of this chapter, the Administrator
will record such allocation or auction results in the appropriate
Allowance Management System account.
(k) When recording the allocation or auction of TR SO2
Group 1 allowances to a TR SO2 Group 1 unit or other entity
in an Allowance Management System account, the Administrator will
assign each TR SO2 Group 1 allowance a unique identification
number that will include digits identifying the year of the control
period for which the TR SO2 Group 1 allowance is allocated
or auctioned.
Sec. 97.622 Submission of TR SO2 Group 1 allowance transfers.
(a) An authorized account representative seeking recordation of a
TR SO2 Group 1 allowance transfer shall submit the transfer
to the Administrator.
(b) A TR SO2 Group 1 allowance transfer shall be
correctly submitted if:
(1) The transfer includes the following elements, in a format
prescribed by the Administrator:
(i) The account numbers established by the Administrator for both
the transferor and transferee accounts;
(ii) The serial number of each TR SO2 Group 1 allowance
that is in the transferor account and is to be transferred; and
(iii) The name and signature of the authorized account
representative of the transferor account and the date signed; and
(2) When the Administrator attempts to record the transfer, the
transferor account includes each TR SO2 Group 1 allowance
identified by serial number in the transfer.
Sec. 97.623 Recordation of TR SO2 Group 1 allowance transfers.
(a) Within 5 business days (except as provided in paragraph (b) of
this section) of receiving a TR SO2 Group 1 allowance
transfer that is correctly submitted under Sec. 97.622, the
Administrator will record a TR SO2 Group 1 allowance
transfer by moving each TR SO2 Group 1 allowance from the
transferor account to the transferee account as specified in the
transfer.
(b) A TR SO2 Group 1 allowance transfer to or from a
compliance account that is submitted for recordation after the
allowance transfer deadline for a control period and that includes any
TR SO2 Group 1 allowances allocated for
[[Page 48452]]
any control period before such allowance transfer deadline will not be
recorded until after the Administrator completes the deductions from
such compliance account under Sec. 97.624 for the control period
immediately before such allowance transfer deadline.
(c) Where a TR SO2 Group 1 allowance transfer is not
correctly submitted under Sec. 97.622, the Administrator will not
record such transfer.
(d) Within 5 business days of recordation of a TR SO2
Group 1 allowance transfer under paragraphs (a) and (b) of the section,
the Administrator will notify the authorized account representatives of
both the transferor and transferee accounts.
(e) Within 10 business days of receipt of a TR SO2 Group
1 allowance transfer that is not correctly submitted under Sec.
97.622, the Administrator will notify the 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.
Sec. 97.624 Compliance with TR SO2 Group 1 emissions limitation.
(a) Availability for deduction for compliance. TR SO2
Group 1 allowances are available to be deducted for compliance with a
source's TR SO2 Group 1 emissions limitation for a control
period in a given year only if the TR SO2 Group 1
allowances:
(1) Were allocated for such control period or a control period in a
prior year; and
(2) Are held in the source's compliance account as of the allowance
transfer deadline for such control period.
(b) Deductions for compliance. After the recordation, in accordance
with Sec. 97.623, of TR SO2 Group 1 allowance transfers
submitted by the allowance transfer deadline for a control period in a
given year, the Administrator will deduct from each source's compliance
account TR SO2 Group 1 allowances available under paragraph
(a) of this section in order to determine whether the source meets the
TR SO2 Group 1 emissions limitation for such control period,
as follows:
(1) Until the amount of TR SO2 Group 1 allowances
deducted equals the number of tons of total SO2 emissions
from all TR SO2 Group 1 units at the source for such control
period; or
(2) If there are insufficient TR SO2 Group 1 allowances
to complete the deductions in paragraph (b)(1) of this section, until
no more TR SO2 Group 1 allowances available under paragraph
(a) of this section remain in the compliance account.
(c)(1) Identification of TR SO2 Group 1 allowances by serial
number. The authorized account representative for a source's compliance
account may request that specific TR SO2 Group 1 allowances,
identified by serial number, in the compliance account be deducted for
emissions or excess emissions for a control period in a given year in
accordance with paragraph (b) or (d) of this section. In order to be
complete, such request shall be submitted to the Administrator by the
allowance transfer deadline for such control period and include, in a
format prescribed by the Administrator, the identification of the TR
SO2 Group 1 source and the appropriate serial numbers.
(2) First-in, first-out. The Administrator will deduct TR
SO2 Group 1 allowances under paragraph (b) or (d) of this
section from the source's compliance account in accordance with a
complete request under paragraph (c)(1) of this section or, in the
absence of such request or in the case of identification of an
insufficient amount of TR SO2 Group 1 allowances in such
request, on a first-in, first-out accounting basis in the following
order:
(i) Any TR SO2 Group 1 allowances that were allocated to
the units at the source and not transferred out of the compliance
account, in the order of recordation; and then
(ii) Any TR SO2 Group 1 allowances that were allocated
to any unit and transferred to and recorded in the compliance account
pursuant to this subpart, in the order of recordation.
(d) Deductions for excess emissions. After making the deductions
for compliance under paragraph (b) of this section for a control period
in a year in which the TR SO2 Group 1 source has excess
emissions, the Administrator will deduct from the source's compliance
account an amount of TR SO2 Group 1 allowances, allocated
for a control period in a prior year or the control period in the year
of the excess emissions or in the immediately following year, equal to
two times the number of tons of the source's excess emissions.
(e) Recordation of deductions. The Administrator will record in the
appropriate compliance account all deductions from such an account
under paragraphs (b) and (d) of this section.
Sec. 97.625 Compliance with TR SO2 Group 1 assurance provisions.
(a) Availability for deduction. TR SO2 Group 1
allowances are available to be deducted for compliance with the TR
SO2 Group 1 assurance provisions for a control period in a
given year by the owners and operators of a group of one or more TR
SO2 Group 1 sources and units in a State (and Indian country
within the borders of such State) only if the TR SO2 Group 1
allowances:
(1) Were allocated for a control period in a prior year or the
control period in the given year or in the immediately following year;
and
(2) Are held in the assurance account, established by the
Administrator for such owners and operators of such group of TR
SO2 Group 1 sources and units in such State (and Indian
country within the borders of such State) under paragraph (b)(3) of
this section, as of the deadline established in paragraph (b)(4) of
this section.
(b) Deductions for compliance. The Administrator will deduct TR
SO2 Group 1 allowances available under paragraph (a) of this
section for compliance with the TR SO2 Group 1 assurance
provisions for a State for a control period in a given year in
accordance with the following procedures:
(1) By June 1, 2013 and June 1 of each year thereafter, the
Administrator will:
(i) Calculate, for each State (and Indian country within the
borders of such State), the total SO2 emissions from all TR
SO2 Group 1 units at TR SO2 Group 1 sources in
the State (and Indian country within the borders of such State) during
the control period in the year before the year of this calculation
deadline and the amount, if any, by which such total SO2
emissions exceed the State assurance level as described in Sec.
97.606(c)(2)(iii); and
(ii) Promulgate a notice of data availability of the results of the
calculations required in paragraph (b)(1)(i) of this section, including
separate calculations of the SO2 emissions from each TR
SO2 Group 1 source.
(2) For each notice of data availability required in paragraph
(b)(1)(ii) of this section and for any State (and Indian country within
the borders of such State) identified in such notice as having TR
SO2 Group 1 units with total SO2 emissions
exceeding the State assurance level for a control period in a given
year, as described in Sec. 97.606(c)(2)(iii):
(i) By July 1 immediately after the promulgation of such notice,
the designated representative of each TR SO2 Group 1 source
in each such State (and Indian country within the borders of such
State) shall submit a statement, in a format prescribed by the
Administrator, providing for each TR SO2 Group 1 unit (if
any) at the source
[[Page 48453]]
that operates during, but is not allocated an amount of TR
SO2 Group 1 allowances for, such control period, the unit's
allowable SO2 emission rate for such control period and, if
such rate is expressed in lb per mmBtu, the unit's heat rate.
(ii) By August 1 immediately after the promulgation of such notice,
the Administrator will calculate, for each such State (and Indian
country within the borders of such State) and such control period and
each common designated representative for such control period for a
group of one or more TR SO2 Group 1 sources and units in the
State (and Indian country within the borders of such State), the common
designated representative's share of the total SO2 emissions
from all TR SO2 Group 1 units at TR SO2 Group 1
sources in the State (and Indian country within the borders of such
State), the common designated representative's assurance level, and the
amount (if any) of TR SO2 Group 1 allowances that the owners
and operators of such group of sources and units must hold in
accordance with the calculation formula in Sec. 97.606(c)(2)(i) and
will promulgate a notice of data availability of the results of these
calculations.
(iii) The Administrator will provide an opportunity for submission
of objections to the calculations referenced by the notice of data
availability required in paragraph (b)(2)(ii) of this section and the
calculations referenced by the relevant notice of data availability
required in paragraph (b)(1)(i) of this section.
(A) Objections shall be submitted by the deadline specified in such
notice and shall be limited to addressing whether the calculations
referenced in the relevant notice required under paragraph (b)(1)(ii)
of this section and referenced in the notice required under paragraph
(b)(2)(ii) of this section are in accordance with Sec.
97.606(c)(2)(iii), Sec. Sec. 97.606(b) and 97.630 through 97.635, the
definitions of ``common designated representative'', ``common
designated representative's assurance level'', and ``common designated
representative's share'' in Sec. 97.602, and the calculation formula
in Sec. 97.606(c)(2)(i).
(B) The Administrator will adjust the calculations to the extent
necessary to ensure that they are in accordance with the provisions
referenced in paragraph (b)(2)(iii)(A) of this section. By October 1
immediately after the promulgation of such notice, the Administrator
will promulgate a notice of data availability of any adjustments that
the Administrator determines to be necessary and the reasons for
accepting or rejecting any objections submitted in accordance with
paragraph (b)(2)(iii)(A) of this section.
(3) For any State (and Indian country within the borders of such
State) referenced in each notice of data availability required in
paragraph (b)(2)(iii)(B) of this section as having TR SO2
Group 1 units with total SO2 emissions exceeding the State
assurance level for a control period in a given year, the Administrator
will establish one assurance account for each set of owners and
operators referenced, in the notice of data availability required under
paragraph (b)(2)(iii)(B) of this section, as all of the owners and
operators of a group of TR SO2 Group 1 sources and units in
the State (and Indian country within the borders of such State) having
a common designated representative for such control period and as being
required to hold TR SO2 Group 1 allowances.
(4)(i) As of midnight of November 1 immediately after the
promulgation of each notice of data availability required in paragraph
(b)(2)(iii)(B) of this section, the owners and operators described in
paragraph (b)(3) of this section shall hold in the assurance account
established for them and for the appropriate TR SO2 Group 1
sources, TR SO2 Group 1 units, and State (and Indian country
within the borders of such State) under paragraph (b)(3) of this
section a total amount of TR SO2 Group 1 allowances,
available for deduction under paragraph (a) of this section, equal to
the amount such owners and operators are required to hold with regard
to such sources, units and State (and Indian country within the borders
of such State) as calculated by the Administrator and referenced in
such notice.
(ii) Notwithstanding the allowance-holding deadline specified in
paragraph (b)(4)(i) of this section, if November 1 is not a business
day, then such allowance-holding deadline shall be midnight of the
first business day thereafter.
(5) After November 1 (or the date described in paragraph (b)(4)(ii)
of this section) immediately after the promulgation of each notice of
data availability required in paragraph (b)(2)(iii)(B) of this section
and after the recordation, in accordance with Sec. 97.623, of TR
SO2 Group 1 allowance transfers submitted by midnight of
such date, the Administrator will determine whether the owners and
operators described in paragraph (b)(3) of this section hold, in the
assurance account for the appropriate TR SO2 Group 1
sources, TR SO2 Group 1 units, and State (and Indian country
within the borders of such State) established under paragraph (b)(3) of
this section, the amount of TR SO2 Group 1 allowances
available under paragraph (a) of this section that the owners and
operators are required to hold with regard to such sources, units, and
State (and Indian country within the borders of such State) as
calculated by the Administrator and referenced in the notice required
in paragraph (b)(2)(iii)(B) of this section.
(6) Notwithstanding any other provision of this subpart and any
revision, made by or submitted to the Administrator after the
promulgation of the notice of data availability required in paragraph
(b)(2)(iii)(B) of this section for a control period in a given year, of
any data used in making the calculations referenced in such notice, the
amounts of TR SO2 Group 1 allowances that the owners and
operators are required to hold in accordance with Sec. 97.606(c)(2)(i)
for such control period shall continue to be such amounts as calculated
by the Administrator and referenced in such notice required in
paragraph (b)(2)(iii)(B) of this section, except as follows:
(i) If any such data are revised by the Administrator as a result
of a decision in or settlement of litigation concerning such data on
appeal under part 78 of this chapter of such notice, or on appeal under
section 307 of the Clean Air Act of a decision rendered under part 78
of this chapter on appeal of such notice, then the Administrator will
use the data as so revised to recalculate the amounts of TR
SO2 Group 1 allowances that owners and operators are
required to hold in accordance with the calculation formula in Sec.
97.606(c)(2)(i) for such control period with regard to the TR
SO2 Group 1 sources, TR SO2 Group 1 units, and
State (and Indian country within the borders of such State) involved,
provided that such litigation under part 78 of this chapter, or the
proceeding under part 78 of this chapter that resulted in the decision
appealed in such litigation under section 307 of the Clean Air Act, was
initiated no later than 30 days after promulgation of such notice
required in paragraph (b)(2)(iii)(B) of this section.
(ii) If any such data are revised by the owners and operators of a
TR SO2 Group 1 source and TR SO2 Group 1 unit
whose designated representative submitted such data under paragraph
(b)(2)(i) of this section, as a result of a decision in or settlement
of litigation concerning such submission, then the Administrator will
use the data as so revised to recalculate the amounts of TR
SO2 Group 1 allowances that owners and operators are
required to hold in
[[Page 48454]]
accordance with the calculation formula in Sec. 97.606(c)(2)(i) for
such control period with regard to the TR SO2 Group 1
sources, TR SO2 Group 1 units, and State (and Indian country
within the borders of such State) involved, provided that such
litigation was initiated no later than 30 days after promulgation of
such notice required in paragraph (b)(2)(iii)(B) of this section.
(iii) If the revised data are used to recalculate, in accordance
with paragraphs (b)(6)(i) and (ii) of this section, the amount of TR
SO2 Group 1 allowances that the owners and operators are
required to hold for such control period with regard to the TR
SO2 Group 1 sources, TR SO2 Group 1 units, and
State (and Indian country within the borders of such State) involved--
(A) Where the amount of TR SO2 Group 1 allowances that
the owners and operators are required to hold increases as a result of
the use of all such revised data, the Administrator will establish a
new, reasonable deadline on which the owners and operators shall hold
the additional amount of TR SO2 Group 1 allowances in the
assurance account established by the Administrator for the appropriate
TR SO2 Group 1 sources, TR SO2 Group 1 units, and
State (and Indian country within the borders of such State) under
paragraph (b)(3) of this section. The owners' and operators' failure to
hold such additional amount, as required, before the new deadline shall
not be a violation of the Clean Air Act. The owners' and operators'
failure to hold such additional amount, as required, as of the new
deadline shall be a violation of the Clean Air Act. Each TR
SO2 Group 1 allowance that the owners and operators fail to
hold as required as of the new deadline, and each day in such control
period, shall be a separate violation of the Clean Air Act.
(B) For the owners and operators for which the amount of TR
SO2 Group 1 allowances required to be held decreases as a
result of the use of all such revised data, the Administrator will
record, in all accounts from which TR SO2 Group 1 allowances
were transferred by such owners and operators for such control period
to the assurance account established by the Administrator for the
appropriate TR SO2 Group 1 sources, TR SO2 Group
1 units, and State (and Indian country within the borders of such
State) under paragraph (b)(3) of this section, a total amount of the TR
SO2 Group 1 allowances held in such assurance account equal
to the amount of the decrease. If TR SO2 Group 1 allowances
were transferred to such assurance account from more than one account,
the amount of TR SO2 Group 1 allowances recorded in each
such transferor account will be in proportion to the percentage of the
total amount of TR SO2 Group 1 allowances transferred to
such assurance account for such control period from such transferor
account.
(C) Each TR SO2 Group 1 allowance held under paragraph
(b)(6)(iii)(A) of this section as a result of recalculation of
requirements under the TR SO2 Group 1 assurance provisions
for such control period must be a TR SO2 Group 1 allowance
allocated for a control period in a year before or the year immediately
following, or in the same year as, the year of such control period.
Sec. 97.626 Banking.
(a) A TR SO2 Group 1 allowance may be banked for future
use or transfer in a compliance account or a general account in
accordance with paragraph (b) of this section.
(b) Any TR SO2 Group 1 allowance that is held in a
compliance account or a general account will remain in such account
unless and until the TR SO2 Group 1 allowance is deducted or
transferred under Sec. 97.611(c), Sec. 97.623, Sec. 97.624, Sec.
97.625, Sec. 97.627, or Sec. 97.628.
Sec. 97.627 Account error.
The Administrator may, at his or her sole discretion and on his or
her own motion, correct any error in any Allowance Management System
account. Within 10 business days of making such correction, the
Administrator will notify the authorized account representative for the
account.
Sec. 97.628 Administrator's action on submissions.
(a) The Administrator may review and conduct independent audits
concerning any submission under the TR SO2 Group 1 Trading
Program and make appropriate adjustments of the information in the
submission.
(b) The Administrator may deduct TR SO2 Group 1
allowances from or transfer TR SO2 Group 1 allowances to a
compliance account or an assurance account, based on the information in
a submission, as adjusted under paragraph (a)(1) of this section, and
record such deductions and transfers.
Sec. 97.629 [Reserved]
Sec. 97.630 General monitoring, recordkeeping, and reporting
requirements.
The owners and operators, and to the extent applicable, the
designated representative, of a TR SO2 Group 1 unit, shall
comply with the monitoring, recordkeeping, and reporting requirements
as provided in this subpart and subparts F and G of part 75 of this
chapter. For purposes of applying such requirements, the definitions in
Sec. 97.602 and in Sec. 72.2 of this chapter shall apply, the terms
``affected unit,'' ``designated representative,'' and ``continuous
emission monitoring system'' (or ``CEMS'') in part 75 of this chapter
shall be deemed to refer to the terms ``TR SO2 Group 1
unit,'' ``designated representative,'' and ``continuous emission
monitoring system'' (or ``CEMS'') respectively as defined in Sec.
97.602, and the term ``newly affected unit'' shall be deemed to mean
``newly affected TR SO2 Group 1 unit''. The owner or
operator of a unit that is not a TR SO2 Group 1 unit but
that is monitored under Sec. 75.16(b)(2) of this chapter shall comply
with the same monitoring, recordkeeping, and reporting requirements as
a TR SO2 Group 1 unit.
(a) Requirements for installation, certification, and data
accounting. The owner or operator of each TR SO2 Group 1
unit shall:
(1) Install all monitoring systems required under this subpart for
monitoring SO2 mass emissions and individual unit heat input
(including all systems required to monitor SO2
concentration, stack gas moisture content, stack gas flow rate,
CO2 or O2 concentration, and fuel flow rate, as
applicable, in accordance with Sec. Sec. 75.11 and 75.16 of this
chapter);
(2) Successfully complete all certification tests required under
Sec. 97.631 and meet all other requirements of this subpart and part
75 of this chapter applicable to the monitoring systems under paragraph
(a)(1) of this section; and
(3) Record, report, and quality-assure the data from the monitoring
systems under paragraph (a)(1) of this section.
(b) Compliance deadlines. Except as provided in paragraph (e) of
this section, the owner or operator shall meet the monitoring system
certification and other requirements of paragraphs (a)(1) and (2) of
this section on or before the following dates and shall record, report,
and quality-assure the data from the monitoring systems under paragraph
(a)(1) of this section on and after the following dates.
(1) For the owner or operator of a TR SO2 Group 1 unit
that commences commercial operation before July 1, 2011, January 1,
2012.
(2) For the owner or operator of a TR SO2 Group 1 unit
that commences commercial operation on or after July 1, 2011, by the
later of the following:
(i) January 1, 2012; or
(ii) 180 calendar days after the date on which the unit commences
commercial operation.
[[Page 48455]]
(3) The owner or operator of a TR SO2 Group 1 unit for
which construction of a new stack or flue or installation of add-on
SO2 emission controls is completed after the applicable
deadline under paragraph (b)(1) or (2) of this section shall meet the
requirements of Sec. Sec. 75.4(e)(1) through (e)(4) of this chapter,
except that:
(i) Such requirements shall apply to the monitoring systems
required under Sec. 97.630 through Sec. 97.635, rather than the
monitoring systems required under part 75 of this chapter;
(ii) SO2 concentration, stack gas moisture content,
stack gas volumetric flow rate, and O2 or CO2
concentration data shall be determined and reported, rather than the
data listed in Sec. 75.4(e)(2) of this chapter; and
(iii) Any petition for another procedure under Sec. 75.4(e)(2) of
this chapter shall be submitted under Sec. 97.635, rather than Sec.
75.66.
(c) Reporting data. The owner or operator of a TR SO2
Group 1 unit that does not meet the applicable compliance date set
forth in paragraph (b) of this section for any monitoring system under
paragraph (a)(1) of this section shall, for each such monitoring
system, determine, record, and report maximum potential (or, as
appropriate, minimum potential) values for SO2
concentration, stack gas flow rate, stack gas moisture content, fuel
flow rate, and any other parameters required to determine
SO2 mass emissions and heat input in accordance with Sec.
75.31(b)(2) or (c)(3) of this chapter or section 2.4 of appendix D to
part 75 of this chapter, as applicable.
(d) Prohibitions. (1) No owner or operator of a TR SO2
Group 1 unit shall use any alternative monitoring system, alternative
reference method, or any other alternative to any requirement of this
subpart without having obtained prior written approval in accordance
with Sec. 97.635.
(2) No owner or operator of a TR SO2 Group 1 unit shall
operate the unit so as to discharge, or allow to be discharged,
SO2 to the atmosphere without accounting for all such
SO2 in accordance with the applicable provisions of this
subpart and part 75 of this chapter.
(3) No owner or operator of a TR SO2 Group 1 unit shall
disrupt the continuous emission monitoring system, any portion thereof,
or any other approved emission monitoring method, and thereby avoid
monitoring and recording SO2 mass discharged into the
atmosphere or heat input, except for periods of recertification or
periods when calibration, quality assurance testing, or maintenance is
performed in accordance with the applicable provisions of this subpart
and part 75 of this chapter.
(4) No owner or operator of a TR SO2 Group 1 unit shall
retire or permanently discontinue use of the continuous emission
monitoring system, any component thereof, or any other approved
monitoring system under this subpart, except under any one of the
following circumstances:
(i) During the period that the unit is covered by an exemption
under Sec. 97.605 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 Administrator 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 designated representative submits notification of the
date of certification testing of a replacement monitoring system for
the retired or discontinued monitoring system in accordance with Sec.
97.631(d)(3)(i).
(e) Long-term cold storage. The owner or operator of a TR
SO2 Group 1 unit is subject to the applicable provisions of
Sec. 75.4(d) of this chapter concerning units in long-term cold
storage.
Sec. 97.631 Initial monitoring system certification and
recertification procedures.
(a) The owner or operator of a TR SO2 Group 1 unit shall
be exempt from the initial certification requirements of this section
for a monitoring system under Sec. 97.630(a)(1) if the following
conditions are met:
(1) The monitoring system has been previously certified in
accordance with part 75 of this chapter; and
(2) The applicable quality-assurance and quality-control
requirements of Sec. 75.21 of this chapter and appendices B and D to
part 75 of this chapter are fully met for the certified monitoring
system described in paragraph (a)(1) of this section.
(b) The recertification provisions of this section shall apply to a
monitoring system under Sec. 97.630(a)(1) that is exempt from initial
certification requirements under paragraph (a) of this section.
(c) [Reserved]
(d) Except as provided in paragraph (a) of this section, the owner
or operator of a TR SO2 Group 1 unit shall comply with the
following initial certification and recertification procedures, for a
continuous monitoring system (i.e., a continuous emission monitoring
system and an excepted monitoring system under appendix D to part 75 of
this chapter) under Sec. 97.630(a)(1). The owner or operator of a unit
that qualifies to use the low mass emissions excepted monitoring
methodology under Sec. 75.19 of this chapter or that qualifies to use
an alternative monitoring system under subpart E of part 75 of this
chapter shall comply with the procedures in paragraph (e) or (f) of
this section respectively.
(1) Requirements for initial certification. The owner or operator
shall ensure that each continuous monitoring system under Sec.
97.630(a)(1) (including the automated data acquisition and handling
system) successfully completes all of the initial certification testing
required under Sec. 75.20 of this chapter by the applicable deadline
in Sec. 97.630(b). In addition, whenever the owner or operator
installs a monitoring system to meet the requirements of this subpart
in a location where no such monitoring system was previously installed,
initial certification in accordance with Sec. 75.20 of this chapter is
required.
(2) Requirements for recertification. Whenever the owner or
operator makes a replacement, modification, or change in any certified
continuous emission monitoring system under Sec. 97.630(a)(1) that may
significantly affect the ability of the system to accurately measure or
record SO2 mass emissions or heat input rate or to meet the
quality-assurance and quality-control 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 in accordance with 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 may significantly change the stack
flow or concentration profile, the owner or operator shall recertify
each continuous emission monitoring system whose accuracy is
potentially affected by the change, in accordance with Sec. 75.20(b)
of this chapter. Examples of changes to a continuous emission
monitoring system that require recertification include: Replacement of
the analyzer, complete replacement of an existing continuous emission
monitoring system, or change in location or orientation of the sampling
probe or site. Any fuel flowmeter system under Sec. 97.630(a)(1) is
subject to the recertification requirements in Sec. 75.20(g)(6) of
this chapter.
(3) Approval process for initial certification and recertification.
For initial certification of a continuous monitoring system under Sec.
97.630(a)(1), paragraphs (d)(3)(i) through (v) of this
[[Page 48456]]
section apply. For recertifications of such monitoring systems,
paragraphs (d)(3)(i) through (iv) of this section and the procedures in
Sec. Sec. 75.20(b)(5) and (g)(7) of this chapter (in lieu of the
procedures in paragraph (d)(3)(v) of this section) apply, provided that
in applying paragraphs (d)(3)(i) through (iv) of this section, the
words ``certification'' and ``initial certification'' are replaced by
the word ``recertification'' and the word ``certified'' is replaced by
the word ``recertified''.
(i) Notification of certification. The designated representative
shall submit to the appropriate EPA Regional Office and the
Administrator written notice of the dates of certification testing, in
accordance with Sec. 97.633.
(ii) Certification application. The designated representative shall
submit to the Administrator a certification application for each
monitoring system. A complete certification application shall include
the information specified in Sec. 75.63 of this chapter.
(iii) Provisional certification date. The provisional certification
date for a monitoring system shall be determined in accordance with
Sec. 75.20(a)(3) of this chapter. A provisionally certified monitoring
system may be used under the TR SO2 Group 1 Trading Program
for a period not to exceed 120 days after receipt by the Administrator
of the complete certification application for the monitoring system
under paragraph (d)(3)(ii) of this section. Data measured and recorded
by the provisionally certified monitoring system, in accordance with
the requirements of part 75 of this chapter, will be considered valid
quality-assured data (retroactive to the date and time of provisional
certification), provided that the Administrator does not invalidate the
provisional certification by issuing a notice of disapproval within 120
days of the date of receipt of the complete certification application
by the Administrator.
(iv) Certification application approval process. The Administrator
will issue a written notice of approval or disapproval of the
certification application to the owner or operator within 120 days of
receipt of the complete certification application under paragraph
(d)(3)(ii) of this section. In the event the Administrator does not
issue such a notice within such 120-day period, each monitoring system
that 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 TR SO2 Group 1 Trading Program.
(A) Approval notice. If the certification application is complete
and shows that each monitoring system meets the applicable performance
requirements of part 75 of this chapter, then the Administrator will
issue a written notice of approval of the certification application
within 120 days of receipt.
(B) Incomplete application notice. If the certification application
is not complete, then the Administrator will issue a written notice of
incompleteness that sets a reasonable date by which the designated
representative must submit the additional information required to
complete the certification application. If the designated
representative does not comply with the notice of incompleteness by the
specified date, then the Administrator may issue a notice of
disapproval under paragraph (d)(3)(iv)(C) of this section.
(C) Disapproval notice. If the certification application shows that
any monitoring system does not meet the performance requirements of
part 75 of this chapter or if the certification application is
incomplete and the requirement for disapproval under paragraph
(d)(3)(iv)(B) of this section is met, then the Administrator will issue
a written notice of disapproval of the certification application. Upon
issuance of such notice of disapproval, the provisional certification
is invalidated by the Administrator and the data measured and recorded
by each uncertified monitoring system shall not be considered valid
quality-assured data beginning with the date and hour of provisional
certification (as defined under Sec. 75.20(a)(3) of this chapter).
(D) Audit decertification. The Administrator may issue a notice of
disapproval of the certification status of a monitor in accordance with
Sec. 97.632(b).
(v) Procedures for loss of certification. If the Administrator
issues a notice of disapproval of a certification application under
paragraph (d)(3)(iv)(C) of this section or a notice of disapproval of
certification status under paragraph (d)(3)(iv)(D) of this section,
then:
(A) The owner or operator shall substitute the following values,
for each disapproved monitoring system, for each hour of unit operation
during the period of invalid data specified under Sec.
75.20(a)(4)(iii), Sec. 75.20(g)(7), or Sec. 75.21(e) of this chapter
and continuing until the applicable date and hour specified under Sec.
75.20(a)(5)(i) or (g)(7) of this chapter:
(1) For a disapproved SO2 pollutant concentration
monitor and disapproved flow monitor, respectively, the maximum
potential concentration of SO2 and the maximum potential
flow rate, as defined in sections 2.1.1.1 and 2.1.4.1 of appendix A to
part 75 of this chapter.
(2) For a disapproved moisture monitoring system and disapproved
diluent gas monitoring system, respectively, the minimum potential
moisture percentage and either the maximum potential CO2
concentration or the minimum potential O2 concentration (as
applicable), as defined in sections 2.1.5, 2.1.3.1, and 2.1.3.2 of
appendix A to part 75 of this chapter.
(3) For a disapproved fuel flowmeter system, the maximum potential
fuel flow rate, as defined in section 2.4.2.1 of appendix D to part 75
of this chapter.
(B) The designated representative shall submit a notification of
certification retest dates and a new certification application in
accordance with paragraphs (d)(3)(i) and (ii) of this section.
(C) The owner or operator shall repeat all certification tests or
other requirements that were failed by the monitoring system, as
indicated in the Administrator's notice of disapproval, no later than
30 unit operating days after the date of issuance of the notice of
disapproval.
(e) The owner or operator of a unit qualified to use the low mass
emissions (LME) excepted methodology under Sec. 75.19 of this chapter
shall meet the applicable certification and recertification
requirements in Sec. Sec. 75.19(a)(2) and 75.20(h) of this chapter. If
the owner or operator of such a unit elects to certify a fuel flowmeter
system for heat input determination, the owner or operator shall also
meet the certification and recertification requirements in Sec.
75.20(g) of this chapter.
(f) The designated representative of each unit for which the owner
or operator intends to use an alternative monitoring system approved by
the Administrator under subpart E of part 75 of this chapter shall
comply with the applicable notification and application procedures of
Sec. 75.20(f) of this chapter.
Sec. 97.632 Monitoring system out-of-control periods.
(a) General provisions. Whenever any monitoring system fails to
meet the quality-assurance and quality-control requirements or data
validation requirements of part 75 of this chapter, data shall be
substituted using the applicable missing data procedures in subpart D
or appendix D to part 75 of this chapter.
(b) Audit decertification. Whenever both an audit of a monitoring
system
[[Page 48457]]
and a review of the initial certification or recertification
application reveal that any monitoring system should not have been
certified or recertified because it did not meet a particular
performance specification or other requirement under Sec. 97.631 or
the applicable provisions of part 75 of this chapter, both at the time
of the initial certification or recertification application submission
and at the time of the audit, the Administrator will issue a notice of
disapproval of the certification status of such monitoring system. For
the purposes of this paragraph, an audit shall be either a field audit
or an audit of any information submitted to the Administrator or any
State or permitting authority. By issuing the notice of disapproval,
the Administrator revokes prospectively the certification status of the
monitoring system. The data measured and recorded by the monitoring
system 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
for the monitoring system. The owner or operator shall follow the
applicable initial certification or recertification procedures in Sec.
97.631 for each disapproved monitoring system.
Sec. 97.633 Notifications concerning monitoring.
The designated representative of a TR SO2 Group 1 unit
shall submit written notice to the Administrator in accordance with
Sec. 75.61 of this chapter.
Sec. 97.634 Recordkeeping and reporting.
(a) General provisions. The designated representative shall comply
with all recordkeeping and reporting requirements in paragraphs (b)
through (e) of this section, the applicable recordkeeping and reporting
requirements in subparts F and G of part 75 of this chapter, and the
requirements of Sec. 97.614(a).
(b) Monitoring plans. The owner or operator of a TR SO2
Group 1 unit shall comply with requirements of Sec. 75.62 of this
chapter.
(c) Certification applications. The designated representative shall
submit an application to the Administrator within 45 days after
completing all initial certification or recertification tests required
under Sec. 97.631, including the information required under Sec.
75.63 of this chapter.
(d) Quarterly reports. The designated representative shall submit
quarterly reports, as follows:
(1) The designated representative shall report the SO2
mass emissions data and heat input data for the TR SO2 Group
1 unit, in an electronic quarterly report in a format prescribed by the
Administrator, for each calendar quarter beginning with:
(i) For a unit that commences commercial operation before July 1,
2011, the calendar quarter covering January 1, 2012 through March 31,
2012; or
(ii) For a unit that commences commercial operation on or after
July 1, 2011, the calendar quarter corresponding to the earlier of the
date of provisional certification or the applicable deadline for
initial certification under Sec. 97.630(b), unless that quarter is the
third or fourth quarter of 2011, in which case reporting shall commence
in the quarter covering January 1, 2012 through March 31, 2012.
(2) The designated representative shall submit each quarterly
report to the Administrator within 30 days after the end of the
calendar quarter covered by the report. Quarterly reports shall be
submitted in the manner specified in Sec. 75.64 of this chapter.
(3) For TR SO2 Group 1 units that are also subject to
the Acid Rain Program, TR NOX Annual Trading Program, or TR
NOX Ozone Season Trading Program, quarterly reports shall
include the applicable data and information required by subparts F
through H of part 75 of this chapter as applicable, in addition to the
SO2 mass emission data, heat input data, and other
information required by this subpart.
(4) The Administrator may review and conduct independent audits of
any quarterly report in order to determine whether the quarterly report
meets the requirements of this subpart and part 75 of this chapter,
including the requirement to use substitute data.
(i) The Administrator will notify the designated representative of
any determination that the quarterly report fails to meet any such
requirements and specify in such notification any corrections that the
Administrator believes are necessary to make through resubmission of
the quarterly report and a reasonable time period within which the
designated representative must respond. Upon request by the designated
representative, the Administrator may specify reasonable extensions of
such time period. Within the time period (including any such
extensions) specified by the Administrator, the designated
representative shall resubmit the quarterly report with the corrections
specified by the Administrator, except to the extent the designated
representative provides information demonstrating that a specified
correction is not necessary because the quarterly report already meets
the requirements of this subpart and part 75 of this chapter that are
relevant to the specified correction.
(ii) Any resubmission of a quarterly report shall meet the
requirements applicable to the submission of a quarterly report under
this subpart and part 75 of this chapter, except for the deadline set
forth in paragraph (d)(2) of this section.
(e) Compliance certification. The designated representative shall
submit to the Administrator a compliance certification (in a format
prescribed by the Administrator) in support of each quarterly report
based on reasonable inquiry of those persons with primary
responsibility for ensuring that all of the unit's emissions are
correctly and fully monitored. The certification shall state that:
(1) 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
(2) For a unit with add-on SO2 emission controls and for
all hours where SO2 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 quality
assurance/quality control program under appendix B to part 75 of this
chapter and the substitute data values do not systematically
underestimate SO2 emissions.
Sec. 97.635 Petitions for alternatives to monitoring, recordkeeping,
or reporting requirements.
(a) The designated representative of a TR SO2 Group 1
unit may submit a petition under Sec. 75.66 of this chapter to the
Administrator, requesting approval to apply an alternative to any
requirement of Sec. Sec. 97.630 through 97.634.
(b) A petition submitted under paragraph (a) of this section shall
include sufficient information for the evaluation of the petition,
including, at a minimum, the following information:
(i) Identification of each unit and source covered by the petition;
(ii) A detailed explanation of why the proposed alternative is
being suggested in lieu of the requirement;
(iii) A description and diagram of any equipment and procedures
used in the proposed alternative;
(iv) A demonstration that the proposed alternative is consistent
with
[[Page 48458]]
the purposes of the requirement for which the alternative is proposed
and with the purposes of this subpart and part 75 of this chapter and
that any adverse effect of approving the alternative will be de
minimis; and
(v) Any other relevant information that the Administrator may
require.
(c) Use of an alternative to any requirement referenced in
paragraph (a) of this section is in accordance with this subpart only
to the extent that the petition is approved in writing by the
Administrator and that such use is in accordance with such approval.
77. Part 97 is amended by adding subpart DDDDD to read as follows:
Subpart DDDDD--TR SO2 Group 2 Trading Program
Sec.
97.701 Purpose.
97.702 Definitions.
97.703 Measurements, abbreviations, and acronyms.
97.704 Applicability.
97.705 Retired unit exemption.
97.706 Standard requirements.
97.707 Computation of time.
97.708 Administrative appeal procedures.
97.709 [Reserved]
97.710 State SO2 Group 2 trading budgets, new unit set-
asides, Indian country new unit set-asides and variability limits.
97.711 Timing requirements for TR SO2 Group 2 allowance
allocations.
97.712 TR SO2 Group 2 allowance allocations to new units.
97.713 Authorization of designated representative and alternate
designated representative.
97.714 Responsibilities of designated representative and alternate
designated representative.
97.715 Changing designated representative and alternate designated
representative; changes in owners and operators.
97.716 Certificate of representation.
97.717 Objections concerning designated representative and alternate
designated representative.
97.718 Delegation by designated representative and alternate
designated representative.
97.719 [Reserved]
97.720 Establishment of compliance accounts and general accounts.
97.721 Recordation of TR SO2 Group 2 allowance
allocations.
97.722 Submission of TR SO2 Group 2 allowance transfers.
97.723 Recordation of TR SO2 Group 2 allowance transfers.
97.724 Compliance with TR SO2 Group 2 emissions
limitation.
97.725 Compliance with TR SO2 Group 2 assurance
provisions.
97.726 Banking.
97.727 Account error.
97.728 Administrator's action on submissions.
97.729 [Reserved]
97.730 General monitoring, recordkeeping, and reporting
requirements.
97.731 Initial monitoring system certification and recertification
procedures.
97.732 Monitoring system out-of-control periods.
97.733 Notifications concerning monitoring.
97.734 Recordkeeping and reporting.
97.735 Petitions for alternatives to monitoring, recordkeeping, or
reporting requirements.
Subpart DDDDD--TR SO2 Group 2 Trading Program
Sec. 97.701 Purpose.
This subpart sets forth the general, designated representative,
allowance, and monitoring provisions for the Transport Rule (TR)
SO2 Group 2 Trading Program, under section 110 of the Clean
Air Act and Sec. 52.39 of this chapter, as a means of mitigating
interstate transport of fine particulates and sulfur dioxide.
Sec. 97.702 Definitions.
The terms used in this subpart shall have the meanings set forth in
this section as follows:
Acid Rain Program means a multi-state SO2 and
NOX air pollution control and emission reduction program
established by the Administrator under title IV of the Clean Air Act
and parts 72 through 78 of this chapter.
Administrator means the Administrator of the United States
Environmental Protection Agency or the Director of the Clean Air
Markets Division (or its successor determined by the Administrator) of
the United States Environmental Protection Agency, the Administrator's
duly authorized representative under this subpart.
Allocate or allocation means, with regard to TR SO2
Group 2 allowances, the determination by the Administrator, State, or
permitting authority, in accordance with this subpart and any SIP
revision submitted by the State and approved by the Administrator under
Sec. 52.39(g), (h), or (i) of this chapter, of the amount of such TR
SO2 Group 2 allowances to be initially credited, at no cost
to the recipient, to:
(1) A TR SO2 Group 2 unit;
(2) A new unit set-aside;
(3) An Indian country new unit set-aside; or
(4) An entity not listed in paragraphs (1) through (3) of this
definition;
(5) Provided that, if the Administrator, State, or permitting
authority initially credits, to a TR SO2 Group 2 unit
qualifying for an initial credit, a credit in the amount of zero TR
SO2 Group 2 allowances, the TR SO2 Group 2 unit
will be treated as being allocated an amount (i.e., zero) of TR
SO2 Group 2 allowances.
Allowable SO2 emission rate means, for a unit, the most stringent
State or federal SO2 emission rate limit (in lb/MWhr or, if
in lb/mmBtu, converted to lb/MWhr by multiplying it by the unit's heat
rate in mmBtu/MWhr) that is applicable to the unit and covers the
longest averaging period not exceeding one year.
Allowance Management System means the system by which the
Administrator records allocations, deductions, and transfers of TR
SO2 Group 2 allowances under the TR SO2 Group 2
Trading Program. Such allowances are allocated, recorded, held,
deducted, or transferred only as whole allowances.
Allowance Management System account means an account in the
Allowance Management System established by the Administrator for
purposes of recording the allocation, holding, transfer, or deduction
of TR SO2 Group 2 allowances.
Allowance transfer deadline means, for a control period in a given
year, midnight of March 1 (if it is a business day), or midnight of the
first business day thereafter (if March 1 is not a business day),
immediately after such control period and is the deadline by which a TR
SO2 Group 2 allowance transfer must be submitted for
recordation in a TR SO2 Group 2 source's compliance account
in order to be available for use in complying with the source's TR
SO2 Group 2 emissions limitation for such control period in
accordance with Sec. Sec. 97.706 and 97.724.
Alternate designated representative means, for a TR SO2
Group 2 source and each TR SO2 Group 2 unit at the source,
the natural person who is authorized by the owners and operators of the
source and all such units at the source, in accordance with this
subpart, to act on behalf of the designated representative in matters
pertaining to the TR SO2 Group 2 Trading Program. If the TR
SO2 Group 2 source is also subject to the Acid Rain Program,
TR NOX Annual Trading Program, or TR NOX Ozone
Season Trading Program, then this natural person shall be the same
natural person as the alternate designated representative, as defined
in the respective program.
Assurance account means an Allowance Management System account,
established by the Administrator under Sec. 97.725(b)(3) for certain
owners and operators of a group of one or more TR SO2 Group
2 sources and units in a given State (and Indian country within the
borders of such State), in which are held TR SO2 Group 2
allowances available for use for a control period in a given year in
[[Page 48459]]
complying with the TR SO2 Group 2 assurance provisions in
accordance with Sec. Sec. 97.706 and 97.725.
Authorized account representative means, for a general account, the
natural person who is authorized, in accordance with this subpart, to
transfer and otherwise dispose of TR SO2 Group 2 allowances
held in the general account and, for a TR SO2 Group 2
source's compliance account, the designated representative of the
source.
Automated data acquisition and handling system or DAHS means the
component of the continuous emission monitoring system, or other
emissions monitoring system approved for use under this subpart,
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 this subpart.
Biomass means--
(1) Any organic material grown for the purpose of being converted
to energy;
(2) Any organic byproduct of agriculture that can be converted into
energy; or
(3) Any material that can be converted into energy and is
nonmerchantable for other purposes, that is segregated from other
material that is nonmerchantable for other purposes, and that is;
(i) A forest-related organic resource, including mill residues,
precommercial thinnings, slash, brush, or byproduct from conversion of
trees to merchantable material; or
(ii) A wood material, including pallets, crates, dunnage,
manufacturing and construction materials (other than pressure-treated,
chemically-treated, or painted wood products), and landscape or right-
of-way tree trimmings.
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.
Bottoming-cycle unit means a unit in which the energy input to the
unit is first used to produce useful thermal energy, where at least
some of the reject heat from the useful thermal energy application or
process is then used for electricity production.
Business day means a day that does not fall on a weekend or a
federal holiday.
Certifying official means a natural person who is:
(1) For a corporation, a president, secretary, treasurer, or vice-
president of the corporation in charge of a principal business function
or any other person who performs similar policy- or decision-making
functions for the corporation;
(2) For a partnership or sole proprietorship, a general partner or
the proprietor respectively; or
(3) For a local government entity or State, federal, or other
public agency, a principal executive officer or ranking elected
official.
Clean Air Act means the Clean Air Act, 42 U.S.C. 7401, et seq.
Coal means ``coal'' as defined in Sec. 72.2 of this chapter.
Coal-derived fuel means any fuel (whether in a solid, liquid, or
gaseous state) produced by the mechanical, thermal, or chemical
processing of coal.
Cogeneration system means an integrated group, at a source, of
equipment (including a boiler, or combustion turbine, and a steam
turbine generator) designed to produce useful thermal energy for
industrial, commercial, heating, or cooling purposes and electricity
through the sequential use of energy.
Cogeneration unit means a stationary, fossil-fuel-fired boiler or
stationary, fossil-fuel-fired combustion turbine that is a topping-
cycle unit or a bottoming-cycle unit:
(1) Operating as part of a cogeneration system; and
(2) Producing on an annual average basis--
(i) For a topping-cycle unit,
(A) Useful thermal energy not less than 5 percent of total energy
output; and
(B) Useful power that, when added to one-half of useful thermal
energy produced, is not less than 42.5 percent of total energy input,
if useful thermal energy produced is 15 percent or more of total energy
output, or not less than 45 percent of total energy input, if useful
thermal energy produced is less than 15 percent of total energy output.
(ii) For a bottoming-cycle unit, useful power not less than 45
percent of total energy input;
(3) Provided that the requirements in paragraph (2) of this
definition shall not apply to a calendar year referenced in paragraph
(2) of this definition during which the unit did not operate at all;
(4) Provided that the total energy input under paragraphs (2)(i)(B)
and (2)(ii) of this definition shall equal the unit's total energy
input from all fuel, except biomass if the unit is a boiler; and
(5) Provided that, if, throughout its operation during the 12-month
period or a calendar year referenced in paragraph (2) of this
definition, a unit is operated as part of a cogeneration system and the
cogeneration system meets on a system-wide basis the requirement in
paragraph (2)(i)(B) or (2)(ii) of this definition, the unit shall be
deemed to meet such requirement during that 12-month period or calendar
year.
Combustion turbine means an enclosed device comprising:
(1) If the device is simple cycle, 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; and
(2) If the device is combined cycle, the equipment described in
paragraph (1) of this definition and any associated duct burner, heat
recovery steam generator, and steam turbine.
Commence commercial operation means, with regard to a unit:
(1) To have begun to produce steam, gas, or other heated medium
used to generate electricity for sale or use, including test
generation, except as provided in Sec. 97.705.
(i) For a unit that is a TR SO2 Group 2 unit under Sec.
97.704 on the later of January 1, 2005 or the date the unit commences
commercial operation as defined in the introductory text of paragraph
(1) of this definition and that subsequently undergoes a physical
change or is moved to a new location or source, such date shall remain
the date of commencement of commercial operation of the unit, which
shall continue to be treated as the same unit.
(ii) For a unit that is a TR SO2 Group 2 unit under
Sec. 97.704 on the later of January 1, 2005 or the date the unit
commences commercial operation as defined in the introductory text of
paragraph (1) of this definition and that is subsequently replaced by a
unit at the same or a different source, such date shall remain the
replaced unit's date of commencement of commercial operation, and the
replacement unit shall be treated as a separate unit with a separate
date for commencement of commercial operation as defined in paragraph
(1) or (2) of this definition as appropriate.
(2) Notwithstanding paragraph (1) of this definition and except as
provided in Sec. 97.705, for a unit that is not a TR SO2
Group 2 unit under Sec. 97.704 on the later of January 1, 2005 or the
date the unit commences commercial operation as defined in introductory
text of paragraph (1) of this definition, the unit's date for
commencement of commercial operation shall be the date on which the
unit becomes a TR SO2 Group 2 unit under Sec. 97.704.
(i) For a unit with a date for commencement of commercial operation
as defined in the introductory text of paragraph (2) of this definition
[[Page 48460]]
and that subsequently undergoes a physical change or is moved to a
different location or source, such date shall remain the date of
commencement of commercial operation of the unit, which shall continue
to be treated as the same unit.
(ii) For a unit with a date for commencement of commercial
operation as defined in the introductory text of paragraph (2) of this
definition and that is subsequently replaced by a unit at the same or a
different source, such date shall remain the replaced unit's date of
commencement of commercial operation, and the replacement unit shall be
treated as a separate unit with a separate date for commencement of
commercial operation as defined in paragraph (1) or (2) of this
definition as appropriate.
Common designated representative means, with regard to a control
period in a given year, a designated representative where, as of April
1 immediately after the allowance transfer deadline for such control
period, the same natural person is authorized under Sec. Sec.
97.713(a) and 97.715(a) as the designated representative for a group of
one or more TR SO2 Group 2 sources and units located in a
State (and Indian country within the borders of such State).
Common designated representative's assurance level means, with
regard to a specific common designated representative and a State (and
Indian country within the borders of such State) and control period in
a given year for which the State assurance level is exceeded as
described in Sec. 97.706(c)(2)(iii), the common designated
representative's share of the State SO2 Group 2 trading
budget with the variability limit for the State for such control
period.
Common designated representative's share means, with regard to a
specific common designated representative for a control period in a
given year:
(1) With regard to a total amount of SO2 emissions from
all TR SO2 Group 2 units in a State (and Indian country
within the borders of such State) during such control period, the total
tonnage of SO2 emissions during such control period from a
group of one or more TR SO2 Group 2 units located in such
State (and such Indian country) and having the common designated
representative for such control period;
(2) With regard to a State SO2 Group 2 trading budget
with the variability limit for such control period, the amount (rounded
to the nearest allowance) equal to the sum of the total amount of TR
SO2 Group 2 allowances allocated for such control period to
a group of one or more TR SO2 Group 2 units located in the
State (and Indian country within the borders of such State) and having
the common designated representative for such control period and of the
total amount of TR SO2 Group 2 allowances purchased by an
owner or operator of such TR SO2 Group 2 units in an auction
for such control period and submitted by the State or the permitting
authority to the Administrator for recordation in the compliance
accounts for such TR SO2 Group 2 units in accordance with
the TR SO2 Group 2 allowance auction provisions in a SIP
revision approved by the Administrator under Sec. 52.39(h) or (i) of
this chapter, multiplied by the sum of the State SO2 Group 2
trading budget under Sec. 97.710(a) and the State's variability limit
under Sec. 97.710(b) for such control period and divided by such State
SO2 Group 2 trading budget;
(3) Provided that, in the case of a unit that operates during, but
has no amount of TR SO2 Group 2 allowances allocated under
Sec. Sec. 97.711 and 97.712 for, such control period, the unit shall
be treated, solely for purposes of this definition, as being allocated
an amount (rounded to the nearest allowance) of TR SO2 Group
2 allowances for such control period equal to the unit's allowable
SO2 emission rate applicable to such control period,
multiplied by a capacity factor of 0.85 (if the unit is a boiler
combusting any amount of coal or coal-derived fuel during such control
period), 0.24 (if the unit is a simple combustion turbine during such
control period), 0.67 (if the unit is a combined cycle turbine during
such control period), 0.74 (if the unit is an integrated coal
gasification combined cycle unit during such control period), or 0.36
(for any other unit), multiplied by the unit's maximum hourly load as
reported in accordance with this subpart and by 8,760 hours/control
period, and divided by 2,000 lb/ton.
Common stack means a single flue through which emissions from 2 or
more units are exhausted.
Compliance account means an Allowance Management System account,
established by the Administrator for a TR SO2 Group 2 source
under this subpart, in which any TR SO2 Group 2 allowance
allocations to the TR SO2 Group 2 units at the source are
recorded and in which are held any TR SO2 Group 2 allowances
available for use for a control period in a given year in complying
with the source's TR SO2 Group 2 emissions limitation in
accordance with Sec. Sec. 97.706 and 97.724.
Continuous emission monitoring system or CEMS means the equipment
required under this subpart to sample, analyze, measure, and provide,
by means of readings recorded at least once every 15 minutes and using
an automated data acquisition and handling system (DAHS), a permanent
record of SO2 emissions, stack gas volumetric flow rate,
stack gas moisture content, and O2 or CO2
concentration (as applicable), in a manner consistent with part 75 of
this chapter and Sec. Sec. 97.730 through 97.735. The following
systems are the principal types of continuous emission monitoring
systems:
(1) A flow monitoring system, consisting of a stack flow rate
monitor and an automated data acquisition and handling system and
providing a permanent, continuous record of stack gas volumetric flow
rate, in standard cubic feet per hour (scfh);
(2) A SO2 monitoring system, consisting of a
SO2 pollutant concentration monitor and an automated data
acquisition and handling system and providing a permanent, continuous
record of SO2 emissions, in parts per million (ppm);
(3) A moisture monitoring system, as defined in Sec. 75.11(b)(2)
of this chapter and providing a permanent, continuous record of the
stack gas moisture content, in percent H2O;
(4) A CO2 monitoring system, consisting of a
CO2 pollutant concentration monitor (or an O2
monitor plus suitable mathematical equations from which the
CO2 concentration is derived) and an automated data
acquisition and handling system and providing a permanent, continuous
record of CO2 emissions, in percent CO2; and
(5) An O2 monitoring system, consisting of an
O2 concentration monitor and an automated data acquisition
and handling system and providing a permanent, continuous record of
O2, in percent O2.
Control period means the period starting January 1 of a calendar
year, except as provided in Sec. 97.706(c)(3), and ending on December
31 of the same year, inclusive.
Designated representative means, for a TR SO2 Group 2
source and each TR SO2 Group 2 unit at the source, the
natural person who is authorized by the owners and operators of the
source and all such units at the source, in accordance with this
subpart, to represent and legally bind each owner and operator in
matters pertaining to the TR SO2 Group 2 Trading Program. If
the TR SO2 Group 2 source is also subject to the Acid Rain
Program, TR NOX Annual Trading Program, or TR NOX
Ozone Season Trading Program, then this natural person shall be the
same
[[Page 48461]]
natural person as the designated representative, as defined in the
respective program.
Emissions means air pollutants exhausted from a unit or source into
the atmosphere, as measured, recorded, and reported to the
Administrator by the designated representative, and as modified by the
Administrator:
(1) In accordance with this subpart; and
(2) With regard to a period before the unit or source is required
to measure, record, and report such air pollutants in accordance with
this subpart, in accordance with part 75 of this chapter.
Excess emissions means any ton of emissions from the TR
SO2 Group 2 units at a TR SO2 Group 2 source
during a control period in a given year that exceeds the TR
SO2 Group 2 emissions limitation for the source for such
control period.
Fossil fuel means--
(1) Natural gas, petroleum, coal, or any form of solid, liquid, or
gaseous fuel derived from such material; or
(2) For purposes of applying the limitation on ``average annual
fuel consumption of fossil fuel'' in Sec. Sec. 97.704(b)(2)(i)(B) and
(ii), natural gas, petroleum, coal, or any form of solid, liquid, or
gaseous fuel derived from such material for the purpose of creating
useful heat.
Fossil-fuel-fired means, with regard to a unit, combusting any
amount of fossil fuel in 2005 or any calendar year thereafter.
General account means an Allowance Management System account,
established under this subpart, that is not a compliance account or an
assurance account.
Generator means a device that produces electricity.
Gross electrical output means, for a unit, electricity made
available for use, including any such electricity used in the power
production process (which process includes, but is not limited to, any
on-site processing or treatment of fuel combusted at the unit and any
on-site emission controls).
Heat input means, for a unit for a specified period of time, the
product (in mmBtu/time) of the gross calorific value of the fuel (in
mmBtu/lb) fed into the unit multiplied by the fuel feed rate (in lb of
fuel/time), as measured, recorded, and reported to the Administrator by
the designated representative and as modified by the Administrator in
accordance with this subpart and excluding the heat derived from
preheated combustion air, recirculated flue gases, or exhaust.
Heat input rate means, for a unit, the amount of heat input (in
mmBtu) divided by unit operating time (in hr) or, for a unit and a
specific fuel, the amount of heat input attributed to the fuel (in
mmBtu) divided by the unit operating time (in hr) during which the unit
combusts the fuel.
Heat rate means, for a unit, the unit's maximum design heat input
(in Btu/hr), divided by the product of 1,000,000 Btu/mmBtu and the
unit's maximum hourly load.
Indian country means ``Indian country'' as defined in 18 U.S.C.
1151.
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 generated by 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 no less 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, for a unit, the maximum amount of
fuel per hour (in Btu/hr) that the unit is capable of combusting on a
steady state basis as of the initial installation of the unit as
specified by the manufacturer of the unit.
Monitoring system means any monitoring system that meets the
requirements of this subpart, including a continuous emission
monitoring system, an alternative monitoring system, or an excepted
monitoring system under part 75 of this chapter.
Nameplate capacity means, starting from the initial installation of
a generator, the maximum electrical generating output (in MWe, rounded
to the nearest tenth) that the generator is capable of producing on a
steady state basis and during continuous operation (when not restricted
by seasonal or other deratings) as of such installation as specified by
the manufacturer of the generator or, starting from the completion of
any subsequent physical change in the generator resulting in an
increase in the maximum electrical generating output that the generator
is capable of producing on a steady state basis and during continuous
operation (when not restricted by seasonal or other deratings), such
increased maximum amount (in MWe, rounded to the nearest tenth) as of
such completion as specified by the person conducting the physical
change.
Natural gas means ``natural gas'' as defined in Sec. 72.2 of this
chapter.
Newly affected TR SO2 Group 2 unit means a unit that was
not a TR SO2 Group 2 unit when it began operating but that
thereafter becomes a TR SO2 Group 2 unit.
Operate or operation means, with regard to a unit, to combust fuel.
Operator means, for a TR SO2 Group 2 source or a TR
SO2 Group 2 unit at a source respectively, any person who
operates, controls, or supervises a TR SO2 Group 2 unit at
the source or the TR SO2 Group 2 unit and shall include, but
not be limited to, any holding company, utility system, or plant
manager of such source or unit.
Owner means, for a TR SO2 Group 2 source or a TR
SO2 Group 2 unit at a source respectively, any of the
following persons:
(1) Any holder of any portion of the legal or equitable title in a
TR SO2 Group 2 unit at the source or the TR SO2
Group 2 unit;
(2) Any holder of a leasehold interest in a TR SO2 Group
2 unit at the source or the TR SO2 Group 2 unit, provided
that, 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) on the revenues or income from such TR
SO2 Group 2 unit; and
(3) Any purchaser of power from a TR SO2 Group 2 unit at
the source or the TR SO2 Group 2 unit under a life-of-the-
unit, firm power contractual arrangement.
Permanently retired means, with regard to a unit, a unit that is
unavailable for service and that the unit's owners and operators do not
expect to return to service in the future.
Permitting authority means ``permitting authority'' as defined in
Sec. Sec. 70.2 and 71.2 of this chapter.
Potential electrical output capacity means, for a unit, 33 percent
of the unit's maximum design heat input, divided by 3,413 Btu/kWh,
divided by 1,000 kWh/MWh, and multiplied by 8,760 hr/yr.
Receive or receipt of means, when referring to the Administrator,
to come into possession of a document, information, or correspondence
(whether sent in hard copy or by authorized electronic transmission),
as indicated in an official log, or by a notation made on the document,
[[Page 48462]]
information, or correspondence, by the Administrator in the regular
course of business.
Recordation, record, or recorded means, with regard to TR
SO2 Group 2 allowances, the moving of TR SO2
Group 2 allowances by the Administrator into, out of, or between
Allowance Management System accounts, for purposes of allocation,
auction, transfer, or deduction.
Reference method means any direct test method of sampling and
analyzing for an air pollutant as specified in Sec. 75.22 of this
chapter.
Replacement, replace, or replaced means, with regard to a unit, the
demolishing of a unit, or the permanent retirement and permanent
disabling of a unit, and the construction of another unit (the
replacement unit) to be used instead of the demolished or retired unit
(the replaced unit).
Sequential use of energy means:
(1) The use of reject heat from electricity production in a useful
thermal energy application or process; or
(2) The use of reject heat from useful thermal energy application
or process in electricity production.
Serial number means, for a TR SO2 Group 2 allowance, the
unique identification number assigned to each TR SO2 Group 2
allowance by the Administrator.
Solid waste incineration unit means a stationary, fossil-fuel-fired
boiler or stationary, fossil-fuel-fired combustion turbine that is a
``solid waste incineration unit'' as defined in section 129(g)(1) of
the Clean Air Act.
Source means all buildings, structures, or installations located in
one or more contiguous or adjacent properties under common control of
the same person or persons. This definition does not change or
otherwise affect the definition of ``major source'', ``stationary
source'', or ``source'' as set forth and implemented in a title V
operating permit program or any other program under the Clean Air Act.
State means one of the States that is subject to the TR
SO2 Group 2 Trading Program pursuant to Sec. 52.39(a), (c),
(g), (h), and (i) of this chapter.
Submit or serve means to send or transmit a document, information,
or correspondence to the person specified in accordance with the
applicable regulation:
(1) In person;
(2) By United States Postal Service; or
(3) By other means of dispatch or transmission and delivery;
(4) Provided that compliance with any ``submission'' or ``service''
deadline shall be determined by the date of dispatch, transmission, or
mailing and not the date of receipt.
Topping-cycle unit means a unit in which the energy input to the
unit is first used to produce useful power, including electricity,
where at least some of the reject heat from the electricity production
is then used to provide useful thermal energy.
Total energy input means, for a unit, total energy of all forms
supplied to the unit, excluding energy produced by the unit. Each form
of energy supplied shall be measured by the lower heating value of that
form of energy calculated as follows:
LHV = HHV - 10.55(W + 9H)
Where:
LHV = lower heating value of the form of energy in Btu/lb,
HHV = higher heating value of the form of energy in Btu/lb,
W = weight % of moisture in the form of energy, and
H = weight % of hydrogen in the form of energy.
Total energy output means, for a unit, the sum of useful power and
useful thermal energy produced by the unit.
TR NOX Annual Trading Program means a multi-state NOX
air pollution control and emission reduction program established in
accordance with subpart AAAAA of this part and Sec. 52.38(a) of this
chapter (including such a program that is revised in a SIP revision
approved by the Administrator under Sec. 52.38(a)(3) or (4) of this
chapter or that is established in a SIP revision approved by the
Administrator under Sec. 52.38(a)(5) of this chapter), as a means of
mitigating interstate transport of fine particulates and
NOX.
TR NOX Ozone Season Trading Program means a multi-state
NOX air pollution control and emission reduction program
established in accordance with subpart BBBBB of this part and Sec.
52.38(b) of this chapter (including such a program that is revised in a
SIP revision approved by the Administrator under Sec. 52.38(b)(3) or
(4) of this chapter or that is established in a SIP revision approved
by the Administrator under Sec. 52.38(b)(5) of this chapter), as a
means of mitigating interstate transport of ozone and NOX.
TR SO2 Group 2 allowance means a limited authorization issued and
allocated or auctioned by the Administrator under this subpart, or by a
State or permitting authority under a SIP revision approved by the
Administrator under Sec. 52.39(g), (h), or (i) of this chapter, to
emit one ton of SO2 during a control period of the specified
calendar year for which the authorization is allocated or auctioned or
of any calendar year thereafter under the TR SO2 Group 2
Trading Program.
TR SO2 Group 2 allowance deduction or deduct TR SO2 Group 2
allowances means the permanent withdrawal of TR SO2 Group 2
allowances by the Administrator from a compliance account (e.g., in
order to account for compliance with the TR SO2 Group 2
emissions limitation) or from an assurance account (e.g., in order to
account for compliance with the assurance provisions under Sec. Sec.
97.706 and 97.725).
TR SO2 Group 2 allowances held or hold TR SO2 Group 2 allowances
means the TR SO2 Group 2 allowances treated as included in
an Allowance Management System account as of a specified point in time
because at that time they:
(1) Have been recorded by the Administrator in the account or
transferred into the account by a correctly submitted, but not yet
recorded, TR SO2 Group 2 allowance transfer in accordance
with this subpart; and
(2) Have not been transferred out of the account by a correctly
submitted, but not yet recorded, TR SO2 Group 2 allowance
transfer in accordance with this subpart.
TR SO2 Group 2 emissions limitation means, for a TR SO2
Group 2 source, the tonnage of SO2 emissions authorized in a
control period by the TR SO2 Group 2 allowances available for deduction
for the source under Sec. 97.724(a) for such control period.
TR SO2 Group 2 source means a source that includes one or more TR
SO2 Group 2 units.
TR SO2 Group 2 Trading Program means a multi-state SO2
air pollution control and emission reduction program established in
accordance with this subpart and Sec. 52.39(a), (c), and (g) through
(k) of this chapter (including such a program that is revised in a SIP
revision approved by the Administrator under Sec. 52.39(g) or (h) of
this chapter or that is established in a SIP revision approved by the
Administrator under Sec. 52.39(i) of this chapter), as a means of
mitigating interstate transport of fine particulates and
SO2.
TR SO2 Group 2 unit means a unit that is subject to the TR
SO2 Group 2 Trading Program under Sec. 97.704.
Unit means a stationary, fossil-fuel-fired boiler, stationary,
fossil-fuel-fired combustion turbine, or other stationary, fossil-fuel-
fired combustion device. A unit that undergoes a physical change or is
moved to a different location or source shall continue to be treated as
the same unit. A unit (the replaced unit) that is replaced by another
unit (the
[[Page 48463]]
replacement unit) at the same or a different source shall continue to
be treated as the same unit, and the replacement unit shall be treated
as a separate unit.
Unit operating day means, with regard to a unit, a calendar day in
which the unit combusts any fuel.
Unit operating hour or hour of unit operation means, with regard to
a unit, an hour in which the unit combusts any fuel.
Useful power means, with regard to a unit, electricity or
mechanical energy that the unit makes available for use, excluding any
such energy used in the power production process (which process
includes, but is not limited to, any on-site processing or treatment of
fuel combusted at the unit and any on-site emission controls).
Useful thermal energy means thermal energy that is:
(1) Made available to an industrial or commercial process (not a
power production process), excluding any heat contained in condensate
return or makeup water;
(2) Used in a heating application (e.g., space heating or domestic
hot water heating); or
(3) Used in a space cooling application (i.e., in an absorption
chiller).
Utility power distribution system means the portion of an
electricity grid owned or operated by a utility and dedicated to
delivering electricity to customers.
Sec. 97.703 Measurements, abbreviations, and acronyms.
Measurements, abbreviations, and acronyms used in this subpart are
defined as follows:
Btu--British thermal unit
CO2--carbon dioxide
H2O--water
hr--hour
kW--kilowatt electrical
kWh--kilowatt hour
lb--pound
mmBtu--million Btu
MWe--megawatt electrical
MWh--megawatt hour
NOX--nitrogen oxides
O2--oxygen
ppm--parts per million
scfh--standard cubic feet per hour
SO2--sulfur dioxide
yr--year
Sec. 97.704 Applicability.
(a) Except as provided in paragraph (b) of this section:
(1) The following units in a State (and Indian country within the
borders of such State) shall be TR SO2 Group 2 units, and
any source that includes one or more such units shall be a TR
SO2 Group 2 source, subject to the requirements of this
subpart: Any stationary, fossil-fuel-fired boiler or stationary,
fossil-fuel-fired combustion turbine serving at any time, on or after
January 1, 2005, a generator with nameplate capacity of more than 25
MWe producing electricity for sale.
(2) If a stationary boiler or stationary combustion turbine that,
under paragraph (a)(1) of this section, is not a TR SO2
Group 2 unit begins to combust fossil fuel or to serve a generator with
nameplate capacity of more than 25 MWe producing electricity for sale,
the unit shall become a TR SO2 Group 2 unit as provided in
paragraph (a)(1) of this section on the first date on which it both
combusts fossil fuel and serves such generator.
(b) Any unit in a State (and Indian country within the borders of
such State) that otherwise is a TR SO2 Group 2 unit under
paragraph (a) of this section and that meets the requirements set forth
in paragraph (b)(1)(i) or (2)(i) of this section shall not be a TR
SO2 Group 2 unit:
(1)(i) Any unit:
(A) Qualifying as a cogeneration unit throughout the later of 2005
or the 12-month period starting on the date the unit first produces
electricity and continuing to qualify as a cogeneration unit throughout
each calendar year ending after the later of 2005 or such 12-month
period; and
(B) Not supplying in 2005 or any calendar year thereafter more than
one-third of the unit's potential electric output capacity or 219,000
MWh, whichever is greater, to any utility power distribution system for
sale.
(ii) If, after qualifying under paragraph (b)(1)(i) of this section
as not being a TR SO2 Group 2 unit, a unit subsequently no
longer meets all the requirements of paragraph (b)(1)(i) of this
section, the unit shall become a TR SO2 Group 2 unit
starting on the earlier of January 1 after the first calendar year
during which the unit first no longer qualifies as a cogeneration unit
or January 1 after the first calendar year during which the unit no
longer meets the requirements of paragraph (b)(1)(i)(B) of this
section. The unit shall thereafter continue to be a TR SO2
Group 2 unit.
(2)(i) Any unit:
(A) Qualifying as a solid waste incineration unit throughout the
later of 2005 or the 12-month period starting on the date the unit
first produces electricity and continuing to qualify as a solid waste
incineration unit throughout each calendar year ending after the later
of 2005 or such 12-month period; and
(B) With an average annual fuel consumption of fossil fuel for the
first 3 consecutive calendar years of operation starting no earlier
than 2005 of less than 20 percent (on a Btu basis) and an average
annual fuel consumption of fossil fuel for any 3 consecutive calendar
years thereafter of less than 20 percent (on a Btu basis).
(ii) If, after qualifying under paragraph (b)(2)(i) of this section
as not being a TR SO2 Group 2 unit, a unit subsequently no
longer meets all the requirements of paragraph (b)(1)(i) of this
section, the unit shall become a TR SO2 Group 2 unit
starting on the earlier of January 1 after the first calendar year
during which the unit first no longer qualifies as a solid waste
incineration unit or January 1 after the first 3 consecutive calendar
years after 2005 for which the unit has an average annual fuel
consumption of fossil fuel of 20 percent or more. The unit shall
thereafter continue to be a TR SO2 Group 2 unit.
(c) A certifying official of an owner or operator of any unit or
other equipment may submit a petition (including any supporting
documents) to the Administrator at any time for a determination
concerning the applicability, under paragraphs (a) and (b) of this
section or a SIP revision approved under Sec. 52.39(h) or (i) of this
chapter, of the TR SO2 Group 2 Trading Program to the unit
or other equipment.
(1) Petition content. The petition shall be in writing and include
the identification of the unit or other equipment and the relevant
facts about the unit or other equipment. The petition and any other
documents provided to the Administrator in connection with the petition
shall include the following certification statement, signed by the
certifying official: ``I am authorized to make this submission on
behalf of the owners and operators of the unit or other equipment 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) Response. The Administrator will issue a written response to
the petition
[[Page 48464]]
and may request supplemental information determined by the
Administrator to be relevant to such petition. The Administrator's
determination concerning the applicability, under paragraphs (a) and
(b) of this section, of the TR SO2 Group 2 Trading Program
to the unit or other equipment shall be binding on any State or
permitting authority unless the Administrator determines that the
petition or other documents or information provided in connection with
the petition contained significant, relevant errors or omissions.
Sec. 97.705 Retired unit exemption.
(a)(1) Any TR SO2 Group 2 unit that is permanently
retired shall be exempt from Sec. 97.706(b) and (c)(1), Sec. 97.724,
and Sec. Sec. 97.730 through 97.735.
(2) The exemption under paragraph (a)(1) of this section shall
become effective the day on which the TR SO2 Group 2 unit is
permanently retired. Within 30 days of the unit's permanent retirement,
the designated representative shall submit a statement to the
Administrator. The statement shall state, in a format prescribed by the
Administrator, that the unit was permanently retired on a specified
date and will comply with the requirements of paragraph (b) of this
section.
(b) Special provisions. (1) A unit exempt under paragraph (a) of
this section shall not emit any SO2, starting on the date
that the exemption takes effect.
(2) For a period of 5 years from the date the records are created,
the owners and operators of a unit exempt under paragraph (a) of 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 before the
end of the period, in writing by the Administrator. The owners and
operators bear the burden of proof that the unit is permanently
retired.
(3) The owners and operators and, to the extent applicable, the
designated representative of a unit exempt under paragraph (a) of this
section shall comply with the requirements of the TR SO2
Group 2 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 exempt under paragraph (a) of this section shall lose
its exemption on the first date on which the unit resumes operation.
Such unit shall be treated, for purposes of applying allocation,
monitoring, reporting, and recordkeeping requirements under this
subpart, as a unit that commences commercial operation on the first
date on which the unit resumes operation.
Sec. 97.706 Standard requirements.
(a) Designated representative requirements. The owners and
operators shall comply with the requirement to have a designated
representative, and may have an alternate designated representative, in
accordance with Sec. Sec. 97.713 through 97.718.
(b) Emissions monitoring, reporting, and recordkeeping
requirements. (1) The owners and operators, and the designated
representative, of each TR SO2 Group 2 source and each TR
SO2 Group 2 unit at the source shall comply with the
monitoring, reporting, and recordkeeping requirements of Sec. Sec.
97.730 through 97.735.
(2) The emissions data determined in accordance with Sec. Sec.
97.730 through 97.735 shall be used to calculate allocations of TR
SO2 Group 2 allowances under Sec. Sec. 97.711(a)(2) and (b)
and 97.712 and to determine compliance with the TR SO2 Group
2 emissions limitation and assurance provisions under paragraph (c) of
this section, provided that, for each monitoring location from which
mass emissions are reported, the mass emissions amount used in
calculating such allocations and determining such compliance shall be
the mass emissions amount for the monitoring location determined in
accordance with Sec. Sec. 97.730 through 97.735 and rounded to the
nearest ton, with any fraction of a ton less than 0.50 being deemed to
be zero.
(c) SO2 emissions requirements. (1) TR SO2 Group 2
emissions limitation. (i) As of the allowance transfer deadline for a
control period in a given year, the owners and operators of each TR
SO2 Group 2 source and each TR SO2 Group 2 unit
at the source shall hold, in the source's compliance account, TR
SO2 Group 2 allowances available for deduction for such
control period under Sec. 97.724(a) in an amount not less than the
tons of total SO2 emissions for such control period from all
TR SO2 Group 2 units at the source.
(ii) If total SO2 emissions during a control period in a
given year from the TR SO2 Group 2 units at a TR
SO2 Group 2 source are in excess of the TR SO2
Group 2 emissions limitation set forth in paragraph (c)(1)(i) of this
section, then:
(A) The owners and operators of the source and each TR
SO2 Group 2 unit at the source shall hold the TR
SO2 Group 2 allowances required for deduction under Sec.
97.724(d); and
(B) The owners and operators of the source and each TR
SO2 Group 2 unit at the source shall pay any fine, penalty,
or assessment or comply with any other remedy imposed, for the same
violations, under the Clean Air Act, and each ton of such excess
emissions and each day of such control period shall constitute a
separate violation of this subpart and the Clean Air Act.
(2) TR SO2 Group 2 assurance provisions. (i) If total
SO2 emissions during a control period in a given year from
all TR SO2 Group 2 units at TR SO2 Group 2
sources in a State (and Indian country within the borders of such
State) exceed the State assurance level, then the owners and operators
of such sources and units in each group of one or more sources and
units having a common designated representative for such control
period, where the common designated representative's share of such
SO2 emissions during such control period exceeds the common
designated representative's assurance level for the State and such
control period, shall hold (in the assurance account established for
the owners and operators of such group) TR SO2 Group 2
allowances available for deduction for such control period under Sec.
97.725(a) in an amount equal to two times the product (rounded to the
nearest whole number), as determined by the Administrator in accordance
with Sec. 97.725(b), of multiplying--
(A) The quotient of the amount by which the common designated
representative's share of such SO2 emissions exceeds the
common designated representative's assurance level divided by the sum
of the amounts, determined for all common designated representatives
for such sources and units in the State (and Indian country within the
borders of such State) for such control period, by which each common
designated representative's share of such SO2 emissions
exceeds the respective common designated representative's assurance
level; and
(B) The amount by which total SO2 emissions from all TR
SO2 Group 2 units at TR SO2 Group 2 sources in
the State (and Indian country within the borders of such State) for
such control period exceed the State assurance level.
(ii) The owners and operators shall hold the TR SO2
Group 2 allowances required under paragraph (c)(2)(i) of this section,
as of midnight of November 1 (if it is a business day), or midnight of
the first business day thereafter (if November 1 is not a business
day), immediately after such control period.
(iii) Total SO2 emissions from all TR SO2
Group 2 units at TR SO2 Group 2
[[Page 48465]]
sources in a State (and Indian country within the borders of such
State) during a control period in a given year exceed the State
assurance level if such total SO2 emissions exceed the sum,
for such control period, of the State SO2 Group 2 trading
budget under Sec. 97.710(a) and the State's variability limit under
Sec. 97.710(b).
(iv) It shall not be a violation of this subpart or of the Clean
Air Act if total SO2 emissions from all TR SO2
Group 2 units at TR SO2 Group 2 sources in a State (and
Indian country within the borders of such State) during a control
period exceed the State assurance level or if a common designated
representative's share of total SO2 emissions from the TR
SO2 Group 2 units at TR SO2 Group 2 sources in a
State (and Indian country within the borders of such State) during a
control period exceeds the common designated representative's assurance
level.
(v) To the extent the owners and operators fail to hold TR
SO2 Group 2 allowances for a control period in a given year
in accordance with paragraphs (c)(2)(i) through (iii) of this section,
(A) The owners and operators shall pay any fine, penalty, or
assessment or comply with any other remedy imposed under the Clean Air
Act; and
(B) Each TR SO2 Group 2 allowance that the owners and
operators fail to hold for such control period in accordance with
paragraphs (c)(2)(i) through (iii) of this section and each day of such
control period shall constitute a separate violation of this subpart
and the Clean Air Act.
(3) Compliance periods. A TR SO2 Group 2 unit shall be
subject to the requirements under paragraphs (c)(1) and (c)(2) of this
section for the control period starting on the later of January 1, 2012
or the deadline for meeting the unit's monitor certification
requirements under Sec. 97.730(b) and for each control period
thereafter.
(4) Vintage of allowances held for compliance. (i) A TR
SO2 Group 2 allowance held for compliance with the
requirements under paragraph (c)(1)(i) of this section for a control
period in a given year must be a TR SO2 Group 2 allowance
that was allocated for such control period or a control period in a
prior year.
(ii) A TR SO2 Group 2 allowance held for compliance with
the requirements under paragraphs (c)(1)(ii)(A) and (2)(i) through
(iii) of this section for a control period in a given year must be a TR
SO2 Group 2 allowance that was allocated for a control
period in a prior year or the control period in the given year or in
the immediately following year.
(5) Allowance Management System requirements. Each TR
SO2 Group 2 allowance shall be held in, deducted from, or
transferred into, out of, or between Allowance Management System
accounts in accordance with this subpart.
(6) Limited authorization. A TR SO2 Group 2 allowance is
a limited authorization to emit one ton of SO2 during the
control period in one year. Such authorization is limited in its use
and duration as follows:
(i) Such authorization shall only be used in accordance with the TR
SO2 Group 2 Trading Program; and
(ii) Notwithstanding any other provision of this subpart, the
Administrator has the authority to terminate or limit the use and
duration of such authorization to the extent the Administrator
determines is necessary or appropriate to implement any provision of
the Clean Air Act.
(7) Property right. A TR SO2 Group 2 allowance does not
constitute a property right.
(d) Title V permit requirements. (1) No title V permit revision
shall be required for any allocation, holding, deduction, or transfer
of TR SO2 Group 2 allowances in accordance with this
subpart.
(2) A description of whether a unit is required to monitor and
report SO2 emissions using a continuous emission monitoring
system (under subpart H of part 75 of this chapter), an excepted
monitoring system (under appendices D and E to part 75 of this
chapter), a low mass emissions excepted monitoring methodology (under
Sec. 75.19 of this chapter), or an alternative monitoring system
(under subpart E of part 75 of this chapter) in accordance with
Sec. Sec. 97.730 through 97.735 may be added to, or changed in, a
title V permit using minor permit modification procedures in accordance
with Sec. Sec. 70.7(e)(2) and 71.7(e)(1) of this chapter, provided
that the requirements applicable to the described monitoring and
reporting (as added or changed, respectively) are already incorporated
in such permit. This paragraph explicitly provides that the addition
of, or change to, a unit's description as described in the prior
sentence is eligible for minor permit modification procedures in
accordance with Sec. Sec. 70.7(e)(2)(i)(B) and 71.7(e)(1)(i)(B) of
this chapter.
(e) Additional recordkeeping and reporting requirements. (1) Unless
otherwise provided, the owners and operators of each TR SO2
Group 2 source and each TR SO2 Group 2 unit at the source
shall keep on site at the source each of the following documents (in
hardcopy or electronic format) for a period of 5 years from the date
the document is created. This period may be extended for cause, at any
time before the end of 5 years, in writing by the Administrator.
(i) The certificate of representation under Sec. 97.716 for the
designated representative for the source and each TR SO2
Group 2 unit at the source and all documents that demonstrate the truth
of the statements in the certificate of representation; provided that
the certificate and documents shall be retained on site at the source
beyond such 5-year period until such certificate of representation and
documents are superseded because of the submission of a new certificate
of representation under Sec. 97.716 changing the designated
representative.
(ii) All emissions monitoring information, in accordance with this
subpart.
(iii) Copies of all reports, compliance certifications, and other
submissions and all records made or required under, or to demonstrate
compliance with the requirements of, the TR SO2 Group 2
Trading Program.
(2) The designated representative of a TR SO2 Group 2
source and each TR SO2 Group 2 unit at the source shall make
all submissions required under the TR SO2 Group 2 Trading
Program, except as provided in Sec. 97.718. This requirement does not
change, create an exemption from, or or otherwise affect the
responsible official submission requirements under a title V operating
permit program in parts 70 and 71 of this chapter.
(f) Liability. (1) Any provision of the TR SO2 Group 2
Trading Program that applies to a TR SO2 Group 2 source or
the designated representative of a TR SO2 Group 2 source
shall also apply to the owners and operators of such source and of the
TR SO2 Group 2 units at the source.
(2) Any provision of the TR SO2 Group 2 Trading Program
that applies to a TR SO2 Group 2 unit or the designated
representative of a TR SO2 Group 2 unit shall also apply to
the owners and operators of such unit.
(g) Effect on other authorities. No provision of the TR
SO2 Group 2 Trading Program or exemption under Sec. 97.705
shall be construed as exempting or excluding the owners and operators,
and the designated representative, of a TR SO2 Group 2
source or TR SO2 Group 2 unit from compliance with any other
provision of the applicable, approved State implementation plan, a
federally enforceable permit, or the Clean Air Act.
[[Page 48466]]
Sec. 97.707 Computation of time.
(a) Unless otherwise stated, any time period scheduled, under the
TR SO2 Group 2 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
TR SO2 Group 2 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 TR SO2 Group 2 Trading Program, is not a business
day, the time period shall be extended to the next business day.
Sec. 97.708 Administrative appeal procedures.
The administrative appeal procedures for decisions of the
Administrator under the TR SO2 Group 2 Trading Program are
set forth in part 78 of this chapter.
Sec. 97.709 [Reserved]
Sec. 97.710 State SO2 Group 2 trading budgets, new unit set-asides,
Indian country new unit set-aside, and variability limits.
(a) The State SO2 Group 2 trading budgets, new unit set-
asides, and Indian country new unit set-asides for allocations of TR
SO2 Group 2 allowances for the control periods in 2012 and
thereafter are as follows:
----------------------------------------------------------------------------------------------------------------
SO2 Group 2 Indian country new
trading budget New unit set-aside unit set-aside
State (tons) * for 2012 (tons) for 2012 (tons) for 2012
and 2013 and 2013 and 2013
----------------------------------------------------------------------------------------------------------------
Alabama............................................. 216,033 4,321 ..................
Georgia............................................. 158,527 3,171 ..................
Kansas.............................................. 41,528 789 42
Minnesota........................................... 41,981 798 42
Nebraska............................................ 65,052 2,537 65
South Carolina...................................... 88,620 1,683 89
Texas............................................... 243,954 11,954 244
----------------------------------------------------------------------------------------------------------------
----------------------------------------------------------------------------------------------------------------
SO2 Group 2 Indian country new
trading budget New unit set-aside unit set-aside
State (tons) * for 2014 (tons) for 2014 (tons) for 2014
and thereafter and thereafter and thereafter
----------------------------------------------------------------------------------------------------------------
Alabama............................................. 213,258 4,265 ..................
Georgia............................................. 95,231 1,905 ..................
Kansas.............................................. 41,528 789 42
Minnesota........................................... 41,981 798 42
Nebraska............................................ 65,052 2,537 65
South Carolina...................................... 88,620 1,683 89
Texas............................................... 243,954 11,954 244
----------------------------------------------------------------------------------------------------------------
* Each trading budget includes the new unit set-aside and, where applicable, the Indian country new unit set-
aside and does not include the variability limit.
(b) The States' variability limits for the State SO2
Group 2 trading budgets for the control periods in 2012 and thereafter
are as follows:
------------------------------------------------------------------------
Variability limits
State Variability limits for 2014 and
for 2012 and 2013 thereafter
------------------------------------------------------------------------
Alabama..................... 38,886 38,386
Georgia..................... 28,535 17,142
Kansas...................... 7,475 7,475
Minnesota................... 7,557 7,557
Nebraska.................... 11,709 11,709
South Carolina.............. 15,952 15,952
Texas....................... 43,912 43,912
------------------------------------------------------------------------
Sec. 97.711 Timing requirements for TR SO2 Group 2 allowance
allocations.
(a) Existing units. (1) TR SO2 Group 2 allowances are
allocated, for the control periods in 2012 and each year thereafter, as
provided in a notice of data availability issued by the Administrator.
Providing an allocation to a unit in such notice does not constitute a
determination that the unit is a TR SO2 Group 2 unit, and
not providing an allocation to a unit in such notice does not
constitute a determination that the unit is not a TR SO2
Group 2 unit.
(2) Notwithstanding paragraph (a)(1) of this section, if a unit
provided an allocation in the notice of data availability issued under
paragraph (a)(1) of this section does not operate, starting after 2011,
during the control period in two consecutive years, such unit will not
be allocated the TR SO2 Group 2 allowances provided in such
notice for the unit for the control periods in the fifth year after the
first such year and in each year after that fifth year. All TR
SO2 Group 2 allowances that would otherwise have been
allocated to such unit will be allocated to the new unit set-aside for
the State where such unit is located and for the respective years
involved. If such unit resumes operation, the Administrator will
allocate TR SO2 Group 2 allowances to the unit in accordance
with paragraph (b) of this section.
[[Page 48467]]
(b) New units. (1) New unit set-asides. (i) By June 1, 2012 and
June 1 of each year thereafter, the Administrator will calculate the TR
SO2 Group 2 allowance allocation to each TR SO2
Group 2 unit in a State, in accordance with Sec. 97.712(a)(2) through
(7) and (12), for the control period in the year of the applicable
calculation deadline under this paragraph and will promulgate a notice
of data availability of the results of the calculations.
(ii) For each notice of data availability required in paragraph
(b)(1)(i) of this section, the Administrator will provide an
opportunity for submission of objections to the calculations referenced
in such notice.
(A) Objections shall be submitted by the deadline specified in each
notice of data availability required in paragraph (b)(1)(i) of this
section and shall be limited to addressing whether the calculations
(including the identification of the TR SO2 Group 2 units)
are in accordance with Sec. 97.712(a)(2) through (7) and (12) and
Sec. Sec. 97.706(b)(2) and 97.730 through 97.735.
(B) The Administrator will adjust the calculations to the extent
necessary to ensure that they are in accordance with the provisions
referenced in paragraph (b)(1)(ii)(A) of this section. By August 1
immediately after the promulgation of each notice of data availability
required in paragraph (b)(1)(i) of this section, the Administrator will
promulgate a notice of data availability of any adjustments that the
Administrator determines to be necessary with regard to allocations
under Sec. 97.712(a)(2) through (7) and (12) and the reasons for
accepting or rejecting any objections submitted in accordance with
paragraph (b)(1)(ii)(A) of this section.
(iii) If the new unit set-aside for such control period contains
any TR SO2 Group 2 allowances that have not been allocated
in the applicable notice of data availability required in paragraph
(b)(1)(ii) of this section, the Administrator will promulgate, by
December 15 immediately after such notice, a notice of data
availability that identifies any TR SO2 Group 2 units that
commenced commercial operation during the period starting January 1 of
the year before the year of such control period and ending November 30
of year of such control period.
(iv) For each notice of data availability required in paragraph
(b)(1)(iii) of this section, the Administrator will provide an
opportunity for submission of objections to the identification of TR
SO2 annual units in such notice.
(A) Objections shall be submitted by the deadline specified in each
notice of data availability required in paragraph (b)(1)(iii) of this
section and shall be limited to addressing whether the identification
of TR SO2 annual units in such notice is in accordance with
paragraph (b)(1)(iii) of this section.
(B) The Administrator will adjust the identification of TR
SO2 Group 2 units in the each notice of data availability
required in paragraph (b)(1)(iii) of this section to the extent
necessary to ensure that it is in accordance with paragraph (b)(1)(iii)
of this section and will calculate the TR SO2 Group 2
allowance allocation to each TR SO2 Group 2 unit in
accordance with Sec. 97.712(a)(9), (10), and (12) and Sec. Sec.
97.706(b)(2) and 97.730 through 97.735. By February 15 immediately
after the promulgation of each notice of data availability required in
paragraph (b)(1)(iii) of this section, the Administrator will
promulgate a notice of data availability of any adjustments of the
identification of TR SO2 Group 2 units that the
Administrator determines to be necessary, the reasons for accepting or
rejecting any objections submitted in accordance with paragraph
(b)(1)(iv)(A) of this section, and the results of such calculations.
(v) To the extent any TR SO2 Group 2 allowances are
added to the new unit set-aside after promulgation of each notice of
data availability required in paragraph (b)(1)(iv) of this section, the
Administrator will promulgate additional notices of data availability,
as deemed appropriate, of the allocation of such TR SO2
Group 2 allowances in accordance with Sec. 97.712(a)(10).
(2) Indian country new unit set-asides. (i) By June 1, 2012 and
June 1 of each year thereafter, the Administrator will calculate the TR
SO2 Group 2 allowance allocation to each TR SO2
Group 2 unit in Indian country within the borders of a State, in
accordance with Sec. 97.712(b)(2) through (7) and (12), for the
control period in the year of the applicable calculation deadline under
this paragraph and will promulgate a notice of data availability of the
results of the calculations.
(ii) For each notice of data availability required in paragraph
(b)(2)(i) of this section, the Administrator will provide an
opportunity for submission of objections to the calculations referenced
in such notice.
(A) Objections shall be submitted by the deadline specified in each
notice of data availability required in paragraph (b)(2)(i) of this
section and shall be limited to addressing whether the calculations
(including the identification of the TR SO2 Group 2 units)
are in accordance with Sec. 97.712(b)(2) through (7) and (12) and
Sec. Sec. 97.706(b)(2) and 97.730 through 97.735.
(B) The Administrator will adjust the calculations to the extent
necessary to ensure that they are in accordance with the provisions
referenced in paragraph (b)(2)(ii)(A) of this section. By August 1
immediately after the promulgation of each notice of data availability
required in paragraph (b)(2)(i) of this section, the Administrator will
promulgate a notice of data availability of any adjustments that the
Administrator determines to be necessary with regard to allocations
under Sec. 97.712(b)(2) through (7) and (12) and the reasons for
accepting or rejecting any objections submitted in accordance with
paragraph (b)(2)(ii)(A) of this section.
(iii) If the Indian country new unit set-aside for such control
period contains any TR SO2 Group 2 allowances that have not
been allocated in the applicable notice of data availability required
in paragraph (b)(2)(ii) of this section, the Administrator will
promulgate, by December 15 immediately after such notice, a notice of
data availability that identifies any TR SO2 Group 2 units
that commenced commercial operation during the period starting January
1 of the year before the year of such control period and ending
November 30 of year of such control period.
(iv) For each notice of data availability required in paragraph
(b)(2)(iii) of this section, the Administrator will provide an
opportunity for submission of objections to the identification of TR
SO2 annual units in such notice.
(A) Objections shall be submitted by the deadline specified in each
notice of data availability required in paragraph (b)(2)(iii) of this
section and shall be limited to addressing whether the identification
of TR SO2 annual units in such notice is in accordance with
paragraph (b)(2)(iii) of this section.
(B) The Administrator will adjust the identification of TR
SO2 Group 2 units in the each notice of data availability
required in paragraph (b)(2)(iii) of this section to the extent
necessary to ensure that it is in accordance with paragraph (b)(2)(iii)
of this section and will calculate the TR SO2 Group 2
allowance allocation to each TR SO2 Group 2 unit in
accordance with Sec. 97.712(b)(9), (10), and (12) and Sec. Sec.
97.706(b)(2) and 97.730 through 97.735. By February 15 immediately
after the promulgation of each notice of data availability required in
paragraph (b)(2)(iii) of this section, the Administrator will
promulgate a notice of data availability of any
[[Page 48468]]
adjustments of the identification of TR SO2 Group 2 units
that the Administrator determines to be necessary, the reasons for
accepting or rejecting any objections submitted in accordance with
paragraph (b)(2)(iv)(A) of this section, and the results of such
calculations.
(v) To the extent any TR SO2 Group 2 allowances are
added to the Indian country new unit set-aside after promulgation of
each notice of data availability required in paragraph (b)(2)(iv) of
this section, the Administrator will promulgate additional notices of
data availability, as deemed appropriate, of the allocation of such TR
SO2 Group 2 allowances in accordance with Sec.
97.712(b)(10).
(c) Units incorrectly allocated TR SO2 Group 2 allowances. (1) For
each control period in 2012 and thereafter, if the Administrator
determines that TR SO2 Group 2 allowances were allocated
under paragraph (a) of this section, or under a provision of a SIP
revision approved Sec. 52.39(g), (h), or (i) of this chapter, where
such control period and the recipient are covered by the provisions of
paragraph (c)(1)(i) of this section or were allocated under Sec.
97.712(a)(2) through (7), (9), and (12) and (b)(2) through (7), (9),
and (12), or under a provision of a SIP revision approved Sec.
52.39(h) or (i) of this chapter, where such control period and the
recipient are covered by the provisions of paragraph (c)(1)(ii) of this
section, then the Administrator will notify the designated
representative of the recipient and will act in accordance with the
procedures set forth in paragraphs (c)(2) through (5) of this section:
(i)(A) The recipient is not actually a TR SO2 Group 2
unit under Sec. 97.704 as of January 1, 2012 and is allocated TR
SO2 Group 2 allowances for such control period or, in the
case of an allocation under a provision of a SIP revision approved
under Sec. 52.39(g), (h), or (i) of this chapter, the recipient is not
actually a TR SO2 Group 2 unit as of January 1, 2012 and is
allocated TR SO2 Group 2 allowances for such control period
that the SIP revision provides should be allocated only to recipients
that are TR SO2 Group 2 units as of January 1, 2012; or
(B) The recipient is not located as of January 1 of the control
period in the State from whose SO2 Group 2 trading budget
the TR SO2 Group 2 allowances allocated under paragraph (a)
of this section, or under a provision of a SIP revision approved under
Sec. 52.39(g), (h), or (i) of this chapter, were allocated for such
control period.
(ii) The recipient is not actually a TR SO2 Group 2 unit
under Sec. 97.704 as of January 1 of such control period and is
allocated TR SO2 Group 2 allowances for such control period
or, in the case of an allocation under a provision of a SIP revision
approved under Sec. 52.39(g), (h), or (i) of this chapter, the
recipient is not actually a TR SO2 Group 2 unit as of
January 1 of such control period and is allocated TR SO2
Group 2 allowances for such control period that the SIP revision
provides should be allocated only to recipients that are TR
SO2 Group 2 units as of January 1 of such control period.
(2) Except as provided in paragraph (c)(3) or (4) of this section,
the Administrator will not record such TR SO2 Group 2
allowances under Sec. 97.721.
(3) If the Administrator already recorded such TR SO2
Group 2 allowances under Sec. 97.721 and if the Administrator makes
the determination under paragraph (c)(1) of this section before making
deductions for the source that includes such recipient under Sec.
97.724(b) for such control period, then the Administrator will deduct
from the account in which such TR SO2 Group 2 allowances
were recorded an amount of TR SO2 Group 2 allowances
allocated for the same or a prior control period equal to the amount of
such already recorded TR SO2 Group 2 allowances. The
authorized account representative shall ensure that there are
sufficient TR SO2 Group 2 allowances in such account for
completion of the deduction.
(4) If the Administrator already recorded such TR SO2
Group 2 allowances under Sec. 97.721 and if the Administrator makes
the determination under paragraph (c)(1) of this section after making
deductions for the source that includes such recipient under Sec.
97.724(b) for such control period, then the Administrator will not make
any deduction to take account of such already recorded TR
SO2 Group 2 allowances.
(5)(i) With regard to the TR SO2 Group 2 allowances that
are not recorded, or that are deducted as an incorrect allocation, in
accordance with paragraphs (c)(2) and (3) of this section for a
recipient under paragraph (c)(1)(i) of this section, the Administrator
will:
(A) Transfer such TR SO2 Group 2 allowances to the new
unit set-aside for such control period for the State from whose
SO2 Group 2 trading budget the TR SO2 Group 2
allowances were allocated; or
(B) If the State has a SIP revision approved under Sec. 52.39(h)
or (i) covering such control period, include such TR SO2
Group 2 allowances in the portion of the State SO2 Group 2
trading budget that may be allocated for such control period in
accordance with such SIP revision.
(ii) With regard to the TR SO2 Group 2 allowances that
were not allocated from the Indian country new unit set-aside for such
control period and that are not recorded, or that are deducted as an
incorrect allocation, in accordance with paragraphs (c)(2) and (3) of
this section for a recipient under paragraph (c)(1)(ii) of this
paragraph, the Administrator will:
(A) Transfer such TR SO2 Group 2 allowances to the new
unit set-aside for such control period; or
(B) If the State has a SIP revision approved under Sec. 52.39(h)
or (i) covering such control period, include such TR SO2
Group 2 allowances in the portion of the State SO2 Group 2
trading budget that may be allocated for such control period in
accordance with such SIP revision.
(iii) With regard to the TR SO2 Group 2 allowances that
were allocated from the Indian country new unit set-aside for such
control period and that are not recorded, or that are deducted as an
incorrect allocation, in accordance with paragraphs (c)(2) and (3) of
this section for a recipient under paragraph (c)(1)(ii) of this
paragraph, the Administrator will transfer such TR SO2 Group
2 allowances to the Indian country new unit set-aside for such control
period.
Sec. 97.712 TR SO2 Group 2 allowance allocations to new units.
(a) For each control period in 2012 and thereafter and for the TR
SO2 Group 2 units in each State, the Administrator will
allocate TR SO2 Group 2 allowances to the TR SO2
Group 2 units as follows:
(1) The TR SO2 Group 2 allowances will be allocated to
the following TR SO2 Group 2 units, except as provided in
paragraph (a)(10) of this section:
(i) TR SO2 Group 2 units that are not allocated an
amount of TR SO2 Group 2 allowances in the notice of data
availability issued under Sec. 97.711(a)(1);
(ii) TR SO2 Group 2 units whose allocation of an amount
of TR SO2 Group 2 allowances for such control period in the
notice of data availability issued under Sec. 97.711(a)(1) is covered
by Sec. 97.711(c)(2) or (3);
(iii) TR SO2 Group 2 units that are allocated an amount
of TR SO2 Group 2 allowances for such control period in the
notice of data availability issued under Sec. 97.711(a)(1), which
allocation is terminated for such control period pursuant to Sec.
97.711(a)(2), and that operate during the control period
[[Page 48469]]
immediately preceding such control period; or
(iv) For purposes of paragraph (a)(9) of this section, TR
SO2 Group 2 units under Sec. 97.711(c)(1)(ii) whose
allocation of an amount of TR SO2 Group 2 allowances for
such control period in the notice of data availability issued under
Sec. 97.711(b)(1)(ii)(B) is covered by Sec. 97.711(c)(2) or (3).
(2) The Administrator will establish a separate new unit set-aside
for the State for each such control period. Each such new unit set-
aside will be allocated TR SO2 Group 2 allowances in an
amount equal to the applicable amount of tons of SO2
emissions as set forth in Sec. 97.710(a) and will be allocated
additional TR SO2 Group 2 allowances (if any) in accordance
with Sec. Sec. 97.711(a)(2) and (c)(5) and paragraph (b)(10) of this
section.
(3) The Administrator will determine, for each TR SO2
Group 2 unit described in paragraph (a)(1) of this section, an
allocation of TR SO2 Group 2 allowances for the later of the
following control periods and for each subsequent control period:
(i) The control period in 2012;
(ii) The first control period after the control period in which the
TR SO2 Group 2 unit commences commercial operation;
(iii) For a unit described in paragraph (a)(1)(ii) of this section,
the first control period in which the TR SO2 Group 2 unit
operates in the State after operating in another jurisdiction and for
which the unit is not already allocated one or more TR SO2
Group 2 allowances; and
(iv) For a unit described in paragraph (a)(1)(iii) of this section,
the first control period after the control period in which the unit
resumes operation.
(4)(i) The allocation to each TR SO2 annual unit
described in paragraph (a)(1)(i) through (iii) of this section and for
each control period described in paragraph (a)(3) of this section will
be an amount equal to the unit's total tons of SO2 emissions
during the immediately preceding control period.
(ii) The Administrator will adjust the allocation amount in
paragraph (a)(4)(i) in accordance with paragraphs (a)(5) through (7)
and (12) of this section.
(5) The Administrator will calculate the sum of the TR
SO2 Group 2 allowances determined for all such TR
SO2 Group 2 units under paragraph (a)(4)(i) of this section
in the State for such control period.
(6) If the amount of TR SO2 Group 2 allowances in the
new unit set-aside for the State for such control period is greater
than or equal to the sum under paragraph (a)(5) of this section, then
the Administrator will allocate the amount of TR SO2 Group 2
allowances determined for each such TR SO2 Group 2 unit
under paragraph (a)(4)(i) of this section.
(7) If the amount of TR SO2 Group 2 allowances in the
new unit set-aside for the State for such control period is less than
the sum under paragraph (a)(5) of this section, then the Administrator
will allocate to each such TR SO2 Group 2 unit the amount of
the TR SO2 Group 2 allowances determined under paragraph
(a)(4)(i) of this section for the unit, multiplied by the amount of TR
SO2 Group 2 allowances in the new unit set-aside for such
control period, divided by the sum under paragraph (a)(5) of this
section, and rounded to the nearest allowance.
(8) The Administrator will notify the public, through the
promulgation of the notices of data availability described in Sec.
97.711(b)(1)(i) and (ii), of the amount of TR SO2 Group 2
allowances allocated under paragraphs (a)(2) through (7) and (12) of
this section for such control period to each TR SO2 Group 2
unit eligible for such allocation.
(9) If, after completion of the procedures under paragraphs (a)(5)
through (8) of this section for such control period, any unallocated TR
SO2 Group 2 allowances remain in the new unit set-aside for
the State for such control period, the Administrator will allocate such
TR SO2 Group 2 allowances as follows--
(i) The Administrator will determine, for each unit described in
paragraph (a)(1) of this section that commenced commercial operation
during the period starting January 1 of the year before the year of
such control period and ending November 30 of year of such control
period, the positive difference (if any) between the unit's emissions
during such control period and the amount of TR SO2 Group 2
allowances referenced in the notice of data availability required under
Sec. 97.711(b)(1)(ii) for the unit for such control period;
(ii) The Administrator will determine the sum of the positive
differences determined under paragraph (a)(9)(i) of this section;
(iii) If the amount of unallocated TR SO2 Group 2
allowances remaining in the new unit set-aside for the State for such
control period is greater than or equal to the sum determined under
paragraph (a)(9)(ii) of this section, then the Administrator will
allocate the amount of TR SO2 Group 2 allowances determined
for each such TR SO2 Group 2 unit under paragraph (a)(9)(i)
of this section; and
(iv) If the amount of unallocated TR SO2 Group 2
allowances remaining in the new unit set-aside for the State for such
control period is less than the sum under paragraph (a)(9)(ii) of this
section, then the Administrator will allocate to each such TR
SO2 Group 2 unit the amount of the TR SO2 Group 2
allowances determined under paragraph (a)(9)(i) of this section for the
unit, multiplied by the amount of unallocated TR SO2 Group 2
allowances remaining in the new unit set-aside for such control period,
divided by the sum under paragraph (a)(9)(ii) of this section, and
rounded to the nearest allowance.
(10) If, after completion of the procedures under paragraphs (a)(9)
and (12) of this section for such control period, any unallocated TR
SO2 Group 2 allowances remain in the new unit set-aside for
the State for such control period, the Administrator will allocate to
each TR SO2 Group 2 unit that is in the State, is allocated
an amount of TR SO2 Group 2 allowances in the notice of data
availability issued under Sec. 97.711(a)(1), and continues to be
allocated TR SO2 Group 2 allowances for such control period
in accordance with Sec. 97.711(a)(2), an amount of TR SO2
Group 2 allowances equal to the following: The total amount of such
remaining unallocated TR SO2 Group 2 allowances in such new
unit set-aside, multiplied by the unit's allocation under Sec.
97.711(a) for such control period, divided by the remainder of the
amount of tons in the applicable State SO2 Group 2 trading
budget minus the sum of the amounts of tons in such new unit set-aside
and the Indian country new unit set-aside for the State for such
control period, and rounded to the nearest allowance.
(11) The Administrator will notify the public, through the
promulgation of the notices of data availability described in Sec.
97.711(b)(1)(iii), (iv), and (v), of the amount of TR SO2
Group 2 allowances allocated under paragraphs (a)(9), (10), and (12) of
this section for such control period to each TR SO2 Group 2
unit eligible for such allocation.
(12)(i) Notwithstanding the requirements of paragraphs (a)(2)
through (11) of this section, if the calculations of allocations of a
new unit set-aside for a control period in a given year under paragraph
(a)(7) of this section, paragraphs (a)(6) and (9)(iv) of this section,
or paragraphs (a)(6), (9)(iii), and (10) of this section would
otherwise result in total allocations of such new unit set-aside
exceeding the total amount of such new unit set-aside, then the
Administrator will adjust the results of the calculations under
paragraph (a)(7), (9)(iv), or (10) of this section, as applicable, as
follows. The Administrator will list the TR SO2 Group 2
units in descending order based
[[Page 48470]]
on the amount of such units' allocations under paragraph (a)(7),
(9)(iv), or (10) of this section, as applicable, and, in cases of equal
allocation amounts, in alphabetical order of the relevant source's name
and numerical order of the relevant unit's identification number, and
will reduce each unit's allocation under paragraph (a)(7), (9)(iv), or
(10) of this section, as applicable, by one TR SO2 Group 2
allowance (but not below zero) in the order in which the units are
listed and will repeat this reduction process as necessary, until the
total allocations of such new unit set-aside equal the total amount of
such new unit set-aside.
(ii) Notwithstanding the requirements of paragraphs (a)(10) and
(11) of this section, if the calculations of allocations of a new unit
set-aside for a control period in a given year under paragraphs (a)(6),
(9)(iii), and (10) of this section would otherwise result in a total
allocations of such new unit set-aside less than the total amount of
such new unit set-aside, then the Administrator will adjust the results
of the calculations under paragraph (a)(10) of this section, as
follows. The Administrator will list the TR SO2 Group 2
units in descending order based on the amount of such units'
allocations under paragraph (a)(10) of this section and, in cases of
equal allocation amounts, in alphabetical order of the relevant
source's name and numerical order of the relevant unit's identification
number, and will increase each unit's allocation under paragraph
(a)(10) of this section by one TR SO2 Group 2 allowance in
the order in which the units are listed and will repeat this increase
process as necessary, until the total allocations of such new unit set-
aside equal the total amount of such new unit set-aside.
(b) For each control period in 2012 and thereafter and for the TR
SO2 Group 2 units located in Indian country within the
borders of each State, the Administrator will allocate TR
SO2 Group 2 allowances to the TR SO2 Group 2
units as follows:
(1) The TR SO2 Group 2 allowances will be allocated to
the following TR SO2 Group 2 units, except as provided in
paragraph (b)(10) of this section:
(i) TR SO2 Group 2 units that are not allocated an
amount of TR SO2 Group 2 allowances in the notice of data
availability issued under Sec. 97.711(a)(1); or
(ii) For purposes of paragraph (b)(9) of this section, TR
SO2 Group 2 units under Sec. 97.711(c)(1)(ii) whose
allocation of an amount of TR SO2 Group 2 allowances for
such control period in the notice of data availability issued under
Sec. 97.711(b)(2)(ii)(B) is covered by Sec. 97.711(c)(2) or (3).
(2) The Administrator will establish a separate Indian country new
unit set-aside for the State for each such control period. Each such
Indian country new unit set-aside will be allocated TR SO2
Group 2 allowances in an amount equal to the applicable amount of tons
of SO2 emissions as set forth in Sec. 97.710(a) and will be
allocated additional TR SO2 Group 2 allowances (if any) in
accordance with Sec. 97.711(c)(5).
(3) The Administrator will determine, for each TR SO2
Group 2 unit described in paragraph (b)(1) of this section, an
allocation of TR SO2 Group 2 allowances for the later of the
following control periods and for each subsequent control period:
(i) The control period in 2012; and
(ii) The first control period after the control period in which the
TR SO2 Group 2 unit commences commercial operation.
(4)(i) The allocation to each TR SO2 annual unit
described in paragraph (b)(1)(i) of this section and for each control
period described in paragraph (b)(3) of this section will be an amount
equal to the unit's total tons of SO2 emissions during the
immediately preceding control period.
(ii) The Administrator will adjust the allocation amount in
paragraph (b)(4)(i) in accordance with paragraphs (b)(5) through (7)
and (12) of this section.
(5) The Administrator will calculate the sum of the TR
SO2 Group 2 allowances determined for all such TR
SO2 Group 2 units under paragraph (b)(4)(i) of this section
in Indian country within the borders of the State for such control
period.
(6) If the amount of TR SO2 Group 2 allowances in the
Indian country new unit set-aside for the State for such control period
is greater than or equal to the sum under paragraph (b)(5) of this
section, then the Administrator will allocate the amount of TR
SO2 Group 2 allowances determined for each such TR
SO2 Group 2 unit under paragraph (b)(4)(i) of this section.
(7) If the amount of TR SO2 Group 2 allowances in the
Indian country new unit set-aside for the State for such control period
is less than the sum under paragraph (b)(5) of this section, then the
Administrator will allocate to each such TR SO2 Group 2 unit
the amount of the TR SO2 Group 2 allowances determined under
paragraph (b)(4)(i) of this section for the unit, multiplied by the
amount of TR SO2 Group 2 allowances in the Indian country
new unit set-aside for such control period, divided by the sum under
paragraph (b)(5) of this section, and rounded to the nearest allowance.
(8) The Administrator will notify the public, through the
promulgation of the notices of data availability described in Sec.
97.711(b)(2)(i) and (ii), of the amount of TR SO2 Group 2
allowances allocated under paragraphs (b)(2) through (7) and (12) of
this section for such control period to each TR SO2 Group 2
unit eligible for such allocation.
(9) If, after completion of the procedures under paragraphs (b)(5)
through (8) of this section for such control period, any unallocated TR
SO2 Group 2 allowances remain in the Indian country new unit
set-aside for the State for such control period, the Administrator will
allocate such TR SO2 Group 2 allowances as follows--
(i) The Administrator will determine, for each unit described in
paragraph (b)(1) of this section that commenced commercial operation
during the period starting January 1 of the year before the year of
such control period and ending November 30 of year of such control
period, the positive difference (if any) between the unit's emissions
during such control period and the amount of TR SO2 Group 2
allowances referenced in the notice of data availability required under
Sec. 97.711(b)(2)(ii) for the unit for such control period;
(ii) The Administrator will determine the sum of the positive
differences determined under paragraph (b)(9)(i) of this section;
(iii) If the amount of unallocated TR SO2 Group 2
allowances remaining in the Indian country new unit set-aside for the
State for such control period is greater than or equal to the sum
determined under paragraph (b)(9)(ii) of this section, then the
Administrator will allocate the amount of TR SO2 Group 2
allowances determined for each such TR SO2 Group 2 unit
under paragraph (b)(9)(i) of this section; and
(iv) If the amount of unallocated TR SO2 Group 2
allowances remaining in the Indian country new unit set-aside for the
State for such control period is less than the sum under paragraph
(b)(9)(ii) of this section, then the Administrator will allocate to
each such TR SO2 Group 2 unit the amount of the TR
SO2 Group 2 allowances determined under paragraph (b)(9)(i)
of this section for the unit, multiplied by the amount of unallocated
TR SO2 Group 2 allowances remaining in the Indian country
new unit set-aside for such control period, divided by the sum under
paragraph (b)(9)(ii) of this section, and rounded to the nearest
allowance.
(10) If, after completion of the procedures under paragraphs (b)(9)
and (12) of this section for such control
[[Page 48471]]
period, any unallocated TR SO2 Group 2 allowances remain in
the Indian country new unit set-aside for the State for such control
period, the Administrator will:
(i) Transfer such unallocated TR SO2 Group 2 allowances
to the new unit set-aside for the State for such control period; or
(ii) If the State has a SIP revision approved under Sec. 52.39(g),
(h), or (i) of this chapter covering such control period, include such
unallocated TR SO2 Group 2 allowances in the portion of the
State SO2 Group 2 trading budget that may be allocated for
such control period in accordance with such SIP revision.
(11) The Administrator will notify the public, through the
promulgation of the notices of data availability described in Sec.
97.711(b)(2)(iii), (iv), and (v), of the amount of TR SO2
Group 2 allowances allocated under paragraphs (b)(9), (10), and (12) of
this section for such control period to each TR SO2 Group 2
unit eligible for such allocation.
(12)(i) Notwithstanding the requirements of paragraphs (b)(2)
through (11) of this section, if the calculations of allocations of an
Indian country new unit set-aside for a control period in a given year
under paragraph (b)(7) of this section, paragraphs (b)(6) and (9)(iv)
of this section, or paragraphs (b)(6), (9)(iii), and (10) of this
section would otherwise result in total allocations of such Indian
country new unit set-aside exceeding the total amount of such Indian
country new unit set-aside, then the Administrator will adjust the
results of the calculations under paragraph (b)(7), (9)(iv), or (10) of
this section, as applicable, as follows. The Administrator will list
the TR SO2 Group 2 units in descending order based on the
amount of such units' allocations under paragraph (b)(7), (9)(iv), or
(10) of this section, as applicable, and, in cases of equal allocation
amounts, in alphabetical order of the relevant source's name and
numerical order of the relevant unit's identification number, and will
reduce each unit's allocation under paragraph (b)(7), (9)(iv), or (10)
of this section, as applicable, by one TR SO2 Group 2
allowance (but not below zero) in the order in which the units are
listed and will repeat this reduction process as necessary, until the
total allocations of such Indian country new unit set-aside equal the
total amount of such Indian country new unit set-aside.
(ii) Notwithstanding the requirements of paragraphs (b)(10) and
(11) of this section, if the calculations of allocations of an Indian
country new unit set-aside for a control period in a given year under
paragraphs (b)(6), (9)(iii), and (10) of this section would otherwise
result in a total allocations of such Indian country new unit set-aside
less than the total amount of such Indian country new unit set-aside,
then the Administrator will adjust the results of the calculations
under paragraph (b)(10) of this section, as follows. The Administrator
will list the TR SO2 Group 2 units in descending order based
on the amount of such units' allocations under paragraph (b)(10) of
this section and, in cases of equal allocation amounts, in alphabetical
order of the relevant source's name and numerical order of the relevant
unit's identification number, and will increase each unit's allocation
under paragraph (b)(10) of this section by one TR SO2 Group
2 allowance in the order in which the units are listed and will repeat
this increase process as necessary, until the total allocations of such
Indian country new unit set-aside equal the total amount of such Indian
country new unit set-aside.
Sec. 97.713 Authorization of designated representative and alternate
designated representative.
(a) Except as provided under Sec. 97.715, each TR SO2
Group 2 source, including all TR SO2 Group 2 units at the
source, shall have one and only one designated representative, with
regard to all matters under the TR SO2 Group 2 Trading
Program.
(1) The designated representative shall be selected by an agreement
binding on the owners and operators of the source and all TR
SO2 Group 2 units at the source and shall act in accordance
with the certification statement in Sec. 97.716(a)(4)(iii).
(2) Upon and after receipt by the Administrator of a complete
certificate of representation under Sec. 97.716:
(i) The designated representative shall be authorized and shall
represent and, by his or her representations, actions, inactions, or
submissions, legally bind each owner and operator of the source and
each TR SO2 Group 2 unit at the source in all matters
pertaining to the TR SO2 Group 2 Trading Program,
notwithstanding any agreement between the designated representative and
such owners and operators; and
(ii) The owners and operators of the source and each TR
SO2 Group 2 unit at the source shall be bound by any
decision or order issued to the designated representative by the
Administrator regarding the source or any such unit.
(b) Except as provided under Sec. 97.715, each TR SO2
Group 2 source may have one and only one alternate designated
representative, who may act on behalf of the designated representative.
The agreement by which the alternate designated representative is
selected shall include a procedure for authorizing the alternate
designated representative to act in lieu of the designated
representative.
(1) The alternate designated representative shall be selected by an
agreement binding on the owners and operators of the source and all TR
SO2 Group 2 units at the source and shall act in accordance
with the certification statement in Sec. 97.716(a)(4)(iii).
(2) Upon and after receipt by the Administrator of a complete
certificate of representation under Sec. 97.716,
(i) The alternate designated representative shall be authorized;
(ii) Any representation, action, inaction, or submission by the
alternate designated representative shall be deemed to be a
representation, action, inaction, or submission by the designated
representative; and
(iii) The owners and operators of the source and each TR
SO2 Group 2 unit at the source shall be bound by any
decision or order issued to the alternate designated representative by
the Administrator regarding the source or any such unit.
(c) Except in this section, Sec. 97.702, and Sec. Sec. 97.714
through 97.718, whenever the term ``designated representative'' (as
distinguished from the term ``common designated representative'') is
used in this subpart, the term shall be construed to include the
designated representative or any alternate designated representative.
Sec. 97.714 Responsibilities of designated representative and
alternate designated representative.
(a) Except as provided under Sec. 97.718 concerning delegation of
authority to make submissions, each submission under the TR
SO2 Group 2 Trading Program shall be made, signed, and
certified by the designated representative or alternate designated
representative for each TR SO2 Group 2 source and TR
SO2 Group 2 unit for which the submission is made. Each such
submission shall include the following certification statement by the
designated representative or alternate designated representative: ``I
am authorized to make this submission on behalf of the owners and
operators of the source or 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
[[Page 48472]]
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.''
(b) The Administrator will accept or act on a submission made for a
TR SO2 Group 2 source or a TR SO2 Group 2 unit
only if the submission has been made, signed, and certified in
accordance with paragraph (a) of this section and Sec. 97.718.
Sec. 97.715 Changing designated representative and alternate
designated representative; changes in owners and operators; changes in
units at the source.
(a) Changing designated representative. The designated
representative may be changed at any time upon receipt by the
Administrator of a superseding complete certificate of representation
under Sec. 97.716. Notwithstanding any such change, all
representations, actions, inactions, and submissions by the previous
designated representative before the time and date when the
Administrator receives the superseding certificate of representation
shall be binding on the new designated representative and the owners
and operators of the TR SO2 Group 2 source and the TR
SO2 Group 2 units at the source.
(b) Changing alternate designated representative. The alternate
designated representative may be changed at any time upon receipt by
the Administrator of a superseding complete certificate of
representation under Sec. 97.716. Notwithstanding any such change, all
representations, actions, inactions, and submissions by the previous
alternate designated representative before the time and date when the
Administrator receives the superseding certificate of representation
shall be binding on the new alternate designated representative, the
designated representative, and the owners and operators of the TR
SO2 Group 2 source and the TR SO2 Group 2 units
at the source.
(c) Changes in owners and operators. (1) In the event an owner or
operator of a TR SO2 Group 2 source or a TR SO2
Group 2 unit at the source is not included in the list of owners and
operators in the certificate of representation under Sec. 97.716, such
owner or operator shall be deemed to be subject to and bound by the
certificate of representation, the representations, actions, inactions,
and submissions of the designated representative and any alternate
designated representative of the source or unit, and the decisions and
orders of the Administrator, as if the owner or operator were included
in such list.
(2) Within 30 days after any change in the owners and operators of
a TR SO2 Group 2 source or a TR SO2 Group 2 unit
at the source, including the addition or removal of an owner or
operator, the designated representative or any alternate designated
representative shall submit a revision to the certificate of
representation under Sec. 97.716 amending the list of owners and
operators to reflect the change.
(d) Changes in units at the source. Within 30 days of any change in
which units are located at a TR SO2 Group 2 source
(including the addition or removal of a unit), the designated
representative or any alternate designated representative shall submit
a certificate of representation under Sec. 97.716 amending the list of
units to reflect the change.
(1) If the change is the addition of a unit that operated (other
than for purposes of testing by the manufacturer before initial
installation) before being located at the source, then the certificate
of representation shall identify, in a format prescribed by the
Administrator, the entity from whom the unit was purchased or otherwise
obtained (including name, address, telephone number, and facsimile
number (if any)), the date on which the unit was purchased or otherwise
obtained, and the date on which the unit became located at the source.
(2) If the change is the removal of a unit, then the certificate of
representation shall identify, in a format prescribed by the
Administrator, the entity to which the unit was sold or that otherwise
obtained the unit (including name, address, telephone number, and
facsimile number (if any)), the date on which the unit was sold or
otherwise obtained, and the date on which the unit became no longer
located at the source.
Sec. 97.716 Certificate of representation.
(a) A complete certificate of representation for a designated
representative or an alternate designated representative shall include
the following elements in a format prescribed by the Administrator:
(1) Identification of the TR SO2 Group 2 source, and
each TR SO2 Group 2 unit at the source, for which the
certificate of representation is submitted, including source name,
source category and NAICS code (or, in the absence of a NAICS code, an
equivalent code), State, plant code, county, latitude and longitude,
unit identification number and type, identification number and
nameplate capacity (in MWe, rounded to the nearest tenth) of each
generator served by each such unit, actual or projected date of
commencement of commercial operation, and a statement of whether such
source is located in Indian Country. If a projected date of
commencement of commercial operation is provided, the actual date of
commencement of commercial operation shall be provided when such
information becomes available.
(2) The name, address, e-mail address (if any), telephone number,
and facsimile transmission number (if any) of the designated
representative and any alternate designated representative.
(3) A list of the owners and operators of the TR SO2
Group 2 source and of each TR SO2 Group 2 unit at the
source.
(4) The following certification statements by the designated
representative and any alternate designated representative--
(i) ``I certify that I was selected as the designated
representative or alternate designated representative, as applicable,
by an agreement binding on the owners and operators of the source and
each TR SO2 Group 2 unit at the source.''
(ii) ``I certify that I have all the necessary authority to carry
out my duties and responsibilities under the TR SO2 Group 2
Trading Program on behalf of the owners and operators of the source and
of each TR SO2 Group 2 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 Administrator regarding the source or unit.''
(iii) ``Where there are multiple holders of a legal or equitable
title to, or a leasehold interest in, a TR SO2 Group 2 unit,
or where a utility or industrial customer purchases power from a TR
SO2 Group 2 unit under a life-of-the-unit, firm power
contractual arrangement, I certify that: I have given a written notice
of my selection as the `designated representative' or `alternate
designated representative', as applicable, and of the agreement by
which I was selected to each owner and operator of the source and of
each TR SO2 Group 2 unit at the source; and TR
SO2 Group 2 allowances and proceeds of transactions
involving TR SO2 Group 2 allowances will be deemed to be
held or distributed in proportion to each holder's legal, equitable,
leasehold, or contractual reservation or entitlement, except that, if
such multiple holders have expressly provided for a different
distribution of TR SO2 Group 2
[[Page 48473]]
allowances by contract, TR SO2 Group 2 allowances and
proceeds of transactions involving TR SO2 Group 2 allowances
will be deemed to be held or distributed in accordance with the
contract.''
(5) The signature of the designated representative and any
alternate designated representative and the dates signed.
(b) Unless otherwise required by the Administrator, documents of
agreement referred to in the certificate of representation shall not be
submitted to the Administrator. The Administrator shall not be under
any obligation to review or evaluate the sufficiency of such documents,
if submitted.
Sec. 97.717 Objections concerning designated representative and
alternate designated representative.
(a) Once a complete certificate of representation under Sec.
97.716 has been submitted and received, the Administrator will rely on
the certificate of representation unless and until a superseding
complete certificate of representation under Sec. 97.716 is received
by the Administrator.
(b) Except as provided in paragraph (a) of this section, no
objection or other communication submitted to the Administrator
concerning the authorization, or any representation, action, inaction,
or submission, of a designated representative or alternate designated
representative shall affect any representation, action, inaction, or
submission of the designated representative or alternate designated
representative or the finality of any decision or order by the
Administrator under the TR SO2 Group 2 Trading Program.
(c) The Administrator will not adjudicate any private legal dispute
concerning the authorization or any representation, action, inaction,
or submission of any designated representative or alternate designated
representative, including private legal disputes concerning the
proceeds of TR SO2 Group 2 allowance transfers.
Sec. 97.718 Delegation by designated representative and alternate
designated representative.
(a) A designated representative may delegate, to one or more
natural persons, his or her authority to make an electronic submission
to the Administrator provided for or required under this subpart.
(b) An alternate designated representative may delegate, to one or
more natural persons, his or her authority to make an electronic
submission to the Administrator provided for or required under this
subpart.
(c) In order to delegate authority to a natural person to make an
electronic submission to the Administrator in accordance with paragraph
(a) or (b) of this section, the designated representative or alternate
designated representative, as appropriate, must submit to the
Administrator a notice of delegation, in a format prescribed by the
Administrator, that includes the following elements:
(1) The name, address, e-mail address, telephone number, and
facsimile transmission number (if any) of such designated
representative or alternate designated representative;
(2) The name, address, e-mail address, telephone number, and
facsimile transmission number (if any) of each such natural person
(referred to in this section as an ``agent'');
(3) For each such natural person, a list of the type or types of
electronic submissions under paragraph (a) or (b) of this section for
which authority is delegated to him or her; and
(4) The following certification statements by such designated
representative or alternate designated representative:
(i) ``I agree that any electronic submission to the Administrator
that is made by an agent identified in this notice of delegation and of
a type listed for such agent in this notice of delegation and that is
made when I am a designated representative or alternate designated
representative, as appropriate, and before this notice of delegation is
superseded by another notice of delegation under 40 CFR 97.718(d) shall
be deemed to be an electronic submission by me.''
(ii) ``Until this notice of delegation is superseded by another
notice of delegation under 40 CFR 97.718(d), I agree to maintain an e-
mail account and to notify the Administrator immediately of any change
in my e-mail address unless all delegation of authority by me under 40
CFR 97.718 is terminated.''.
(d) A notice of delegation submitted under paragraph (c) of this
section shall be effective, with regard to the designated
representative or alternate designated representative identified in
such notice, upon receipt of such notice by the Administrator and until
receipt by the Administrator of a superseding notice of delegation
submitted by such designated representative or alternate designated
representative, as appropriate. The superseding notice of delegation
may replace any previously identified agent, add a new agent, or
eliminate entirely any delegation of authority.
(e) Any electronic submission covered by the certification in
paragraph (c)(4)(i) of this section and made in accordance with a
notice of delegation effective under paragraph (d) of this section
shall be deemed to be an electronic submission by the designated
representative or alternate designated representative submitting such
notice of delegation.
Sec. 97.719 [Reserved]
Sec. 97.720 Establishment of compliance accounts, assurance accounts,
and general accounts.
(a) Compliance accounts. Upon receipt of a complete certificate of
representation under Sec. 97.716, the Administrator will establish a
compliance account for the TR SO2 Group 2 source for which
the certificate of representation was submitted, unless the source
already has a compliance account. The designated representative and any
alternate designated representative of the source shall be the
authorized account representative and the alternate authorized account
representative respectively of the compliance account.
(b) Assurance accounts. The Administrator will establish assurance
accounts for certain owners and operators and States in accordance with
Sec. 97.725(b)(3).
(c) General accounts. (1) Application for general account. (i) Any
person may apply to open a general account, for the purpose of holding
and transferring TR SO2 Group 2 allowances, by submitting to
the Administrator a complete application for a general account. Such
application shall designate one and only one authorized account
representative and may designate one and only one alternate authorized
account representative who may act on behalf of the authorized account
representative.
(A) The authorized account representative and alternate authorized
account representative shall be selected by an agreement binding on the
persons who have an ownership interest with respect to TR
SO2 Group 2 allowances held in the general account.
(B) The agreement by which the alternate authorized account
representative is selected shall include a procedure for authorizing
the alternate authorized account representative to act in lieu of the
authorized account representative.
(ii) A complete application for a general account shall include the
following elements in a format prescribed by the Administrator:
(A) Name, mailing address, e-mail address (if any), telephone
number, and
[[Page 48474]]
facsimile transmission number (if any) of the authorized account
representative and any alternate authorized account representative;
(B) An identifying name for the general account;
(C) A list of all persons subject to a binding agreement for the
authorized account representative and any alternate authorized account
representative to represent their ownership interest with respect to
the TR SO2 Group 2 allowances held in the general account;
(D) The following certification statement by the authorized account
representative and any alternate authorized account representative: ``I
certify that I was selected as the authorized account representative or
the alternate authorized account representative, as applicable, by an
agreement that is binding on all persons who have an ownership interest
with respect to TR SO2 Group 2 allowances held in the
general account. I certify that I have all the necessary authority to
carry out my duties and responsibilities under the TR SO2
Group 2 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 decision or order issued to me by the
Administrator regarding the general account.''
(E) The signature of the authorized account representative and any
alternate authorized account representative and the dates signed.
(iii) Unless otherwise required by the Administrator, documents of
agreement referred to in the application for a general account shall
not be submitted to the Administrator. The Administrator shall not be
under any obligation to review or evaluate the sufficiency of such
documents, if submitted.
(2) Authorization of authorized account representative and
alternate authorized account representative. (i) Upon receipt by the
Administrator of a complete application for a general account under
paragraph (b)(1) of this section, the Administrator will establish a
general account for the person or persons for whom the application is
submitted, and upon and after such receipt by the Administrator:
(A) The authorized account representative of the general account
shall be authorized and shall represent and, by his or her
representations, actions, inactions, or submissions, legally bind each
person who has an ownership interest with respect to TR SO2
Group 2 allowances held in the general account in all matters
pertaining to the TR SO2 Group 2 Trading Program,
notwithstanding any agreement between the authorized account
representative and such person.
(B) Any alternate authorized account representative shall be
authorized, and any representation, action, inaction, or submission by
any alternate authorized account representative shall be deemed to be a
representation, action, inaction, or submission by the authorized
account representative.
(C) Each person who has an ownership interest with respect to TR
SO2 Group 2 allowances held in the general account shall be
bound by any decision or order issued to the authorized account
representative or alternate authorized account representative by the
Administrator regarding the general account.
(ii) Except as provided in paragraph (c)(5) of this section
concerning delegation of authority to make submissions, each submission
concerning the general account shall be made, signed, and certified by
the authorized account representative or any alternate authorized
account representative for the persons having an ownership interest
with respect to TR SO2 Group 2 allowances held in the
general account. Each such submission shall include the following
certification statement by the authorized account representative or any
alternate authorized account representative: ``I am authorized to make
this submission on behalf of the persons having an ownership interest
with respect to the TR SO2 Group 2 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.''
(iii) Except in this section, whenever the term ``authorized
account representative'' is used in this subpart, the term shall be
construed to include the authorized account representative or any
alternate authorized account representative.
(3) Changing authorized account representative and alternate
authorized account representative; changes in persons with ownership
interest. (i) The authorized account representative of 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 (c)(1) of this section. Notwithstanding any such change, all
representations, actions, inactions, and submissions by the previous
authorized account representative before the time and date when the
Administrator receives the superseding application for a general
account shall be binding on the new authorized account representative
and the persons with an ownership interest with respect to the TR
SO2 Group 2 allowances in the general account.
(ii) The alternate authorized account representative of 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 (c)(1) of this section. Notwithstanding any such change, all
representations, actions, inactions, and submissions by the previous
alternate authorized account representative before the time and date
when the Administrator receives the superseding application for a
general account shall be binding on the new alternate authorized
account representative, the authorized account representative, and the
persons with an ownership interest with respect to the TR
SO2 Group 2 allowances in the general account.
(iii)(A) In the event a person having an ownership interest with
respect to TR SO2 Group 2 allowances in the general account
is not included in the list of such persons in the application for a
general account, such person shall be deemed to be subject to and bound
by the application for a general account, the representation, actions,
inactions, and submissions of the authorized account representative and
any alternate authorized account representative of the account, and the
decisions and orders of the Administrator, as if the person were
included in such list.
(B) Within 30 days after any change in the persons having an
ownership interest with respect to SO2 Group 2 allowances in
the general account, including the addition or removal of a person, the
authorized account representative or any alternate 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 TR SO2 Group 2 allowances in the general
account to include the change.
(4) Objections concerning authorized account representative and
alternate authorized account representative. (i) Once a complete
application for a general account under paragraph (c)(1) of this
section has been submitted and
[[Page 48475]]
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 (c)(4)(i) of this section, no
objection or other communication submitted to the Administrator
concerning the authorization, or any representation, action, inaction,
or submission of the authorized account representative or any alternate
authorized account representative of a general account shall affect any
representation, action, inaction, or submission of the authorized
account representative or any alternate authorized account
representative or the finality of any decision or order by the
Administrator under the TR SO2 Group 2 Trading Program.
(iii) The Administrator will not adjudicate any private legal
dispute concerning the authorization or any representation, action,
inaction, or submission of the authorized account representative or any
alternate authorized account representative of a general account,
including private legal disputes concerning the proceeds of TR
SO2 Group 2 allowance transfers.
(5) Delegation by authorized account representative and alternate
authorized account representative. (i) An authorized account
representative of a general account may delegate, to one or more
natural persons, his or her authority to make an electronic submission
to the Administrator provided for or required under this subpart.
(ii) An alternate authorized account representative of a general
account may delegate, to one or more natural persons, his or her
authority to make an electronic submission to the Administrator
provided for or required under this subpart.
(iii) In order to delegate authority to a natural person to make an
electronic submission to the Administrator in accordance with paragraph
(c)(5)(i) or (ii) of this section, the authorized account
representative or alternate authorized account representative, as
appropriate, must submit to the Administrator a notice of delegation,
in a format prescribed by the Administrator, that includes the
following elements:
(A) The name, address, e-mail address, telephone number, and
facsimile transmission number (if any) of such authorized account
representative or alternate authorized account representative;
(B) The name, address, e-mail address, telephone number, and
facsimile transmission number (if any) of each such natural person
(referred to in this section as an ``agent'');
(C) For each such natural person, a list of the type or types of
electronic submissions under paragraph (c)(5)(i) or (ii) of this
section for which authority is delegated to him or her;
(D) The following certification statement by such authorized
account representative or alternate authorized account representative:
``I agree that any electronic submission to the Administrator that is
made by an agent identified in this notice of delegation and of a type
listed for such agent in this notice of delegation and that is made
when I am an authorized account representative or alternate authorized
representative, as appropriate, and before this notice of delegation is
superseded by another notice of delegation under 40 CFR
97.720(c)(5)(iv) shall be deemed to be an electronic submission by
me.''; and
(E) The following certification statement by such authorized
account representative or alternate authorized account representative:
``Until this notice of delegation is superseded by another notice of
delegation under 40 CFR 97.720(c)(5)(iv), I agree to maintain an e-mail
account and to notify the Administrator immediately of any change in my
e-mail address unless all delegation of authority by me under 40 CFR
97.720(c)(5) is terminated.''.
(iv) A notice of delegation submitted under paragraph (c)(5)(iii)
of this section shall be effective, with regard to the authorized
account representative or alternate authorized account representative
identified in such notice, upon receipt of such notice by the
Administrator and until receipt by the Administrator of a superseding
notice of delegation submitted by such authorized account
representative or alternate authorized account representative, as
appropriate. The superseding notice of delegation may replace any
previously identified agent, add a new agent, or eliminate entirely any
delegation of authority.
(v) Any electronic submission covered by the certification in
paragraph (c)(5)(iii)(D) of this section and made in accordance with a
notice of delegation effective under paragraph (c)(5)(iv) of this
section shall be deemed to be an electronic submission by the
designated representative or alternate designated representative
submitting such notice of delegation.
(6) Closing a general account. (i) The authorized account
representative or alternate authorized account representative of a
general account may submit to the Administrator a request to close the
account. Such request shall include a correctly submitted TR
SO2 Group 2 allowance transfer under Sec. 97.722 for any TR
SO2 Group 2 allowances in the account to one or more other
Allowance Management System accounts.
(ii) If a general account has no TR SO2 Group 2
allowance transfers to or from the account for a 12-month period or
longer and does not contain any TR SO2 Group 2 allowances,
the Administrator may notify the authorized account representative for
the account that the account will be closed after 30 days after the
notice is sent. The account will be closed after the 30-day period
unless, before the end of the 30-day period, the Administrator receives
a correctly submitted TR SO2 Group 2 allowance transfer
under Sec. 97.722 to the account or a statement submitted by the
authorized account representative or alternate authorized account
representative demonstrating to the satisfaction of the Administrator
good cause as to why the account should not be closed.
(d) Account identification. The Administrator will assign a unique
identifying number to each account established under paragraph (a),
(b), or (c) of this section.
(e) Responsibilities of authorized account representative and
alternate authorized account representative. After the establishment of
a compliance account or general account, the Administrator will accept
or act on a submission pertaining to the account, including, but not
limited to, submissions concerning the deduction or transfer of TR
SO2 Group 2 allowances in the account, only if the
submission has been made, signed, and certified in accordance with
Sec. Sec. 97.714(a) and 97.718 or paragraphs (c)(2)(ii) and (c)(5) of
this section.
Sec. 97.721 Recordation of TR SO2 Group 2 allowance allocations and
auction results.
(a) By November 7, 2011, the Administrator will record in each TR
SO2 Group 2 source's compliance account the TR
SO2 Group 2 allowances allocated to the TR SO2
Group 2 units at the source in accordance with Sec. 97.711(a) for the
control period in 2012.
(b) By November 7, 2011, the Administrator will record in each TR
SO2 Group 2 source's compliance account the TR
SO2 Group 2 allowances allocated to the TR SO2
Group 2 units at the source in accordance with Sec. 97.711(a) for the
control period in 2013, unless the State in which the source is located
notifies the
[[Page 48476]]
Administrator in writing by October 17, 2011 of the State's intent to
submit to the Administrator a complete SIP revision by April 1, 2012
meeting the requirements of Sec. 52.39(g)(1) through (4) of this
chapter.
(1) If, by April 1, 2012, the State does not submit to the
Administrator such complete SIP revision, the Administrator will record
by April 15, 2012 in each TR SO2 Group 2 source's compliance
account the TR SO2 Group 2 allowances allocated to the TR
SO2 Group 2 units at the source in accordance with Sec.
97.711(a) for the control period in 2013.
(2) If the State submits to the Administrator by April 1, 2012, and
the Administrator approves by October 1, 2012, such complete SIP
revision, the Administrator will record by October 1, 2012 in each TR
SO2 Group 2 source's compliance account the TR
SO2 Group 2 allowances allocated to the TR SO2
Group 2 units at the source as provided in such approved, complete SIP
revision for the control period in 2013.
(3) If the State submits to the Administrator by April 1, 2012, and
the Administrator does not approve by October 1, 2012, such complete
SIP revision, the Administrator will record by October 1, 2012 in each
TR SO2 Group 2 source's compliance account the TR
SO2 Group 2 allowances allocated to the TR SO2
Group 2 units at the source in accordance with Sec. 97.711(a) for the
control period in 2013.
(c) By July 1, 2013, the Administrator will record in each TR
SO2 Group 2 source's compliance account the TR
SO2 Group 2 allowances allocated to the TR SO2
Group 2 units at the source, or in each appropriate Allowance
Management System account the TR SO2 Group 2 allowances
auctioned to TR SO2 Group 2 units, in accordance with Sec.
97.711(a), or with a SIP revision approved under Sec. 52.39(h) or (i)
of this chapter, for the control period in 2014 and 2015.
(d) By July 1, 2014, the Administrator will record in each TR
SO2 Group 2 source's compliance account the TR
SO2 Group 2 allowances allocated to the TR SO2
Group 2 units at the source, or in each appropriate Allowance
Management System account the TR SO2 Group 2 allowances
auctioned to TR SO2 Group 2 units, in accordance with Sec.
97.711(a), or with a SIP revision approved under Sec. 52.39(h) or (i)
of this chapter, for the control period in 2016 and 2017.
(e) By July 1, 2015, the Administrator will record in each TR
SO2 Group 2 source's compliance account the TR
SO2 Group 2 allowances allocated to the TR SO2
Group 2 units at the source, or in each appropriate Allowance
Management System account the TR SO2 Group 2 allowances
auctioned to TR SO2 Group 2 units, in accordance with Sec.
97.711(a), or with a SIP revision approved under Sec. 52.39(h) or (i)
of this chapter, for the control period in 2018 and 2019.
(f) By July 1, 2016 and July 1 of each year thereafter, the
Administrator will record in each TR SO2 Group 2 source's
compliance account the TR SO2 Group 2 allowances allocated
to the TR SO2 Group 2 units at the source, or in each
appropriate Allowance Management System account the TR SO2
Group 2 allowances auctioned to TR SO2 Group 2 units, in
accordance with Sec. 97.711(a), or with a SIP revision approved under
Sec. 52.39(h) and (i) of this chapter, for the control period in the
fourth year after the year of the applicable recordation deadline under
this paragraph.
(g) By August 1, 2012 and August 1 of each year thereafter, the
Administrator will record in each TR SO2 Group 2 source's
compliance account the TR SO2 Group 2 allowances allocated
to the TR SO2 Group 2 units at the source, or in each
appropriate Allowance Management System account the TR SO2
Group 2 allowances auctioned to TR SO2 Group 2 units, in
accordance with Sec. 97.712(a)(2) through (8) and (12), or with a SIP
revision approved under Sec. 52.39(h) and (i) of this chapter, for the
control period in the year of the applicable recordation deadline under
this paragraph.
(h) By August 1, 2012 and August 1 of each year thereafter, the
Administrator will record in each TR SO2 Group 2 source's
compliance account the TR SO2 Group 2 allowances allocated
to the TR SO2 Group 2 units at the source in accordance with
Sec. 97.712(b)(2) through (8) and (12) for the control period in the
year of the applicable recordation deadline under this paragraph.
(i) By February 15, 2013 and February 15 of each year thereafter,
the Administrator will record in each TR SO2 Group 2
source's compliance account the TR SO2 Group 2 allowances
allocated to the TR SO2 Group 2 units at the source in
accordance with Sec. 97.712(a)(9) through (12), for the control period
in the year before the year of the applicable recordation deadline
under this paragraph.
(j) By the date on which any allocation or auction results, other
than an allocation or auction results, described in paragraphs (a)
through (i) of this section, of TR SO2 Group 2 allowances to
a recipient is made by or are submitted to the Administrator in
accordance with Sec. 97.711 or Sec. 97.712 or with a SIP revision
approved under Sec. 52.39(h) or (i) of this chapter, the Administrator
will record such allocation or auction results in the appropriate
Allowance Management System account.
(k) When recording the allocation or auction of TR SO2
Group 2 allowances to a TR SO2 Group 2 unit or other entity
in an Allowance Management System account, the Administrator will
assign each TR SO2 Group 2 allowance a unique identification
number that will include digits identifying the year of the control
period for which the TR SO2 Group 2 allowance is allocated
or auctioned.
Sec. 97.722 Submission of TR SO2 Group 2 allowance transfers.
(a) An authorized account representative seeking recordation of a
TR SO2 Group 2 allowance transfer shall submit the transfer
to the Administrator.
(b) A TR SO2 Group 2 allowance transfer shall be
correctly submitted if:
(1) The transfer includes the following elements, in a format
prescribed by the Administrator:
(i) The account numbers established by the Administrator for both
the transferor and transferee accounts;
(ii) The serial number of each TR SO2 Group 2 allowance
that is in the transferor account and is to be transferred; and
(iii) The name and signature of the authorized account
representative of the transferor account and the date signed; and
(2) When the Administrator attempts to record the transfer, the
transferor account includes each TR SO2 Group 2 allowance
identified by serial number in the transfer.
Sec. 97.723 Recordation of TR SO2 Group 2 allowance transfers.
(a) Within 5 business days (except as provided in paragraph (b) of
this section) of receiving a TR SO2 Group 2 allowance
transfer that is correctly submitted under Sec. 97.722, the
Administrator will record a TR SO2 Group 2 allowance
transfer by moving each TR SO2 Group 2 allowance from the
transferor account to the transferee account as specified in the
transfer.
(b) A TR SO2 Group 2 allowance transfer to or from a
compliance account that is submitted for recordation after the
allowance transfer deadline for a control period and that includes any
TR SO2 Group 2 allowances allocated for any control period
before such allowance transfer deadline will not be recorded until
after the Administrator completes the deductions from such
[[Page 48477]]
compliance account under Sec. 97.724 for the control period
immediately before such allowance transfer deadline.
(c) Where a TR SO2 Group 2 allowance transfer is not
correctly submitted under Sec. 97.722, the Administrator will not
record such transfer.
(d) Within 5 business days of recordation of a TR SO2
Group 2 allowance transfer under paragraphs (a) and (b) of the section,
the Administrator will notify the authorized account representatives of
both the transferor and transferee accounts.
(e) Within 10 business days of receipt of a TR SO2 Group
2 allowance transfer that is not correctly submitted under Sec.
97.722, the Administrator will notify the 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.
Sec. 97.724 Compliance with TR SO2 Group 2 emissions limitation.
(a) Availability for deduction for compliance. TR SO2
Group 2 allowances are available to be deducted for compliance with a
source's TR SO2 Group 2 emissions limitation for a control
period in a given year only if the TR SO2 Group 2
allowances:
(1) Were allocated for such control period or a control period in a
prior year; and
(2) Are held in the source's compliance account as of the allowance
transfer deadline for such control period.
(b) Deductions for compliance. After the recordation, in accordance
with Sec. 97.723, of TR SO2 Group 2 allowance transfers
submitted by the allowance transfer deadline for a control period in a
given year, the Administrator will deduct from each source's compliance
account TR SO2 Group 2 allowances available under paragraph
(a) of this section in order to determine whether the source meets the
TR SO2 Group 2 emissions limitation for such control period,
as follows:
(1) Until the amount of TR SO2 Group 2 allowances
deducted equals the number of tons of total SO2 emissions
from all TR SO2 Group 2 units at the source for such control
period; or
(2) If there are insufficient TR SO2 Group 2 allowances
to complete the deductions in paragraph (b)(1) of this section, until
no more TR SO2 Group 2 allowances available under paragraph
(a) of this section remain in the compliance account.
(c)(1) Identification of TR SO2 Group 2 allowances by serial
number. The authorized account representative for a source's compliance
account may request that specific TR SO2 Group 2 allowances,
identified by serial number, in the compliance account be deducted for
emissions or excess emissions for a control period in a given year in
accordance with paragraph (b) or (d) of this section. In order to be
complete, such request shall be submitted to the Administrator by the
allowance transfer deadline for such control period and include, in a
format prescribed by the Administrator, the identification of the TR
SO2 Group 2 source and the appropriate serial numbers.
(2) First-in, first-out. The Administrator will deduct TR
SO2 Group 2 allowances under paragraph (b) or (d) of this
section from the source's compliance account in accordance with a
complete request under paragraph (c)(1) of this section or, in the
absence of such request or in the case of identification of an
insufficient amount of TR SO2 Group 2 allowances in such
request, on a first-in, first-out accounting basis in the following
order:
(i) Any TR SO2 Group 2 allowances that were allocated to
the units at the source and not transferred out of the compliance
account, in the order of recordation; and then
(ii) Any TR SO2 Group 2 allowances that were allocated
to any unit and transferred to and recorded in the compliance account
pursuant to this subpart, in the order of recordation.
(d) Deductions for excess emissions. After making the deductions
for compliance under paragraph (b) of this section for a control period
in a year in which the TR SO2 Group 2 source has excess
emissions, the Administrator will deduct from the source's compliance
account an amount of TR SO2 Group 2 allowances, allocated
for a control period in a prior year or the control period in the year
of the excess emissions or in the immediately following year, equal to
two times the number of tons of the source's excess emissions.
(e) Recordation of deductions. The Administrator will record in the
appropriate compliance account all deductions from such an account
under paragraphs (b) and (d) of this section.
Sec. 97.725 Compliance with TR SO2 Group 2 assurance provisions.
(a) Availability for deduction. TR SO2 Group 2
allowances are available to be deducted for compliance with the TR
SO2 Group 2 assurance provisions for a control period in a
given year by the owners and operators of a group of one or more TR
SO2 Group 2 sources and units in a State (and Indian country
within the borders of such State) only if the TR SO2 Group 2
allowances:
(1) Were allocated for a control period in a prior year or the
control period in the given year or in the immediately following year;
and
(2) Are held in the assurance account, established by the
Administrator for such owners and operators of such group of TR
SO2 Group 2 sources and units in such State (and Indian
country within the borders of such State) under paragraph (b)(3) of
this section, as of the deadline established in paragraph (b)(4) of
this section.
(b) Deductions for compliance. The Administrator will deduct TR
SO2 Group 2 allowances available under paragraph (a) of this
section for compliance with the TR SO2 Group 2 assurance
provisions for a State for a control period in a given year in
accordance with the following procedures:
(1) By June 1, 2013 and June 1 of each year thereafter, the
Administrator will:
(i) Calculate, for each State (and Indian country within the
borders of such State), the total SO2 emissions from all TR
SO2 Group 2 units at TR SO2 Group 2 sources in
the State (and Indian country within the borders of such State) during
the control period in the year before the year of this calculation
deadline and the amount, if any, by which such total SO2
emissions exceed the State assurance level as described in Sec.
97.706(c)(2)(iii); and
(ii) Promulgate a notice of data availability of the results of the
calculations required in paragraph (b)(1)(i) of this section, including
separate calculations of the SO2 emissions from each TR
SO2 Group 2 source.
(2) For each notice of data availability required in paragraph
(b)(1)(ii) of this section and for any State (and Indian country within
the borders of such State) identified in such notice as having TR
SO2 Group 2 units with total SO2 emissions
exceeding the State assurance level for a control period in a given
year, as described in Sec. 97.706(c)(2)(iii):
(i) By July 1 immediately after the promulgation of such notice,
the designated representative of each TR SO2 Group 2 source
in each such State (and Indian country within the borders of such
State) shall submit a statement, in a format prescribed by the
Administrator, providing for each TR SO2 Group 2 unit (if
any) at the source that operates during, but is not allocated an amount
of TR SO2 Group 2 allowances for, such control period, the
unit's allowable SO2 emission rate for such control period
and, if such rate is
[[Page 48478]]
expressed in lb per mmBtu, the unit's heat rate.
(ii) By August 1 immediately after the promulgation of such notice,
the Administrator will calculate, for each such State (and Indian
country within the borders of such State) and such control period and
each common designated representative for such control period for a
group of one or more TR SO2 Group 2 sources and units in the
State (and Indian country within the borders of such State), the common
designated representative's share of the total SO2 emissions
from all TR SO2 Group 2 units at TR SO2 Group 2
sources in the State (and Indian country within the borders of such
State), the common designated representative's assurance level, and the
amount (if any) of TR SO2 Group 2 allowances that the owners
and operators of such group of sources and units must hold in
accordance with the calculation formula in Sec. 97.706(c)(2)(i) and
will promulgate a notice of data availability of the results of these
calculations.
(iii) The Administrator will provide an opportunity for submission
of objections to the calculations referenced by the notice of data
availability required in paragraph (b)(2)(ii) of this section and the
calculations referenced by the relevant notice of data availability
required in paragraph (b)(1)(i) of this section.
(A) Objections shall be submitted by the deadline specified in such
notice and shall be limited to addressing whether the calculations
referenced in the relevant notice required under paragraph (b)(1)(ii)
of this section and referenced in the notice required under paragraph
(b)(2)(ii) of this section are in accordance with Sec.
97.706(c)(2)(iii), Sec. Sec. 97.706(b) and 97.730 through 97.735, the
definitions of ``common designated representative'', ``common
designated representative's assurance level'', and ``common designated
representative's share'' in Sec. 97.702, and the calculation formula
in Sec. 97.706(c)(2)(i).
(B) The Administrator will adjust the calculations to the extent
necessary to ensure that they are in accordance with the provisions
referenced in paragraph (b)(2)(iii)(A) of this section. By October 1
immediately after the promulgation of such notice, the Administrator
will promulgate a notice of data availability of any adjustments that
the Administrator determines to be necessary and the reasons for
accepting or rejecting any objections submitted in accordance with
paragraph (b)(2)(iii)(A) of this section.
(3) For any State (and Indian country within the borders of such
State) referenced in each notice of data availability required in
paragraph (b)(2)(iii)(B) of this section as having TR SO2
Group 2 units with total SO2 emissions exceeding the State
assurance level for a control period in a given year, the Administrator
will establish one assurance account for each set of owners and
operators referenced, in the notice of data availability required under
paragraph (b)(2)(iii)(B) of this section, as all of the owners and
operators of a group of TR SO2 Group 2 sources and units in
the State (and Indian country within the borders of such State) having
a common designated representative for such control period and as being
required to hold TR SO2 Group 2 allowances.
(4)(i) As of midnight of November 1 immediately after the
promulgation of each notice of data availability required in paragraph
(b)(2)(iii)(B) of this section, the owners and operators described in
paragraph (b)(3) of this section shall hold in the assurance account
established for them and for the appropriate TR SO2 Group 2
sources, TR SO2 Group 2 units, and State (and Indian country
within the borders of such State) under paragraph (b)(3) of this
section a total amount of TR SO2 Group 2 allowances,
available for deduction under paragraph (a) of this section, equal to
the amount such owners and operators are required to hold with regard
to such sources, units and State (and Indian country within the borders
of such State) as calculated by the Administrator and referenced in
such notice.
(ii) Notwithstanding the allowance-holding deadline specified in
paragraph (b)(4)(i) of this section, if November 1 is not a business
day, then such allowance-holding deadline shall be midnight of the
first business day thereafter.
(5) After November 1 (or the date described in paragraph (b)(4)(ii)
of this section) immediately after the promulgation of each notice of
data availability required in paragraph (b)(2)(iii)(B) of this section
and after the recordation, in accordance with Sec. 97.723, of TR
SO2 Group 2 allowance transfers submitted by midnight of
such date, the Administrator will determine whether the owners and
operators described in paragraph (b)(3) of this section hold, in the
assurance account for the appropriate TR SO2 Group 2
sources, TR SO2 Group 2 units, and State (and Indian country
within the borders of such State) established under paragraph (b)(3) of
this section, the amount of TR SO2 Group 2 allowances
available under paragraph (a) of this section that the owners and
operators are required to hold with regard to such sources, units, and
State (and Indian country within the borders of such State) as
calculated by the Administrator and referenced in the notice required
in paragraph (b)(2)(iii)(B) of this section.
(6) Notwithstanding any other provision of this subpart and any
revision, made by or submitted to the Administrator after the
promulgation of the notice of data availability required in paragraph
(b)(2)(iii)(B) of this section for a control period in a given year, of
any data used in making the calculations referenced in such notice, the
amounts of TR SO2 Group 2 allowances that the owners and
operators are required to hold in accordance with Sec. 97.706(c)(2)(i)
for such control period shall continue to be such amounts as calculated
by the Administrator and referenced in such notice required in
paragraph (b)(2)(iii)(B) of this section, except as follows:
(i) If any such data are revised by the Administrator as a result
of a decision in or settlement of litigation concerning such data on
appeal under part 78 of this chapter of such notice, or on appeal under
section 307 of the Clean Air Act of a decision rendered under part 78
of this chapter on appeal of such notice, then the Administrator will
use the data as so revised to recalculate the amounts of TR
SO2 Group 2 allowances that owners and operators are
required to hold in accordance with the calculation formula in Sec.
97.706(c)(2)(i) for such control period with regard to the TR
SO2 Group 2 sources, TR SO2 Group 2 units, and
State (and Indian country within the borders of such State) involved,
provided that such litigation under part 78 of this chapter, or the
proceeding under part 78 of this chapter that resulted in the decision
appealed in such litigation under section 307 of the Clean Air Act, was
initiated no later than 30 days after promulgation of such notice
required in paragraph (b)(2)(iii)(B) of this section.
(ii) If any such data are revised by the owners and operators of a
TR SO2 Group 2 source and TR SO2 Group 2 unit
whose designated representative submitted such data under paragraph
(b)(2)(i) of this section, as a result of a decision in or settlement
of litigation concerning such submission, then the Administrator will
use the data as so revised to recalculate the amounts of TR
SO2 Group 2 allowances that owners and operators are
required to hold in accordance with the calculation formula in Sec.
97.706(c)(2)(i) for such control period with regard to the TR
SO2 Group 2 sources, TR SO2 Group 2 units, and
State (and Indian country within the
[[Page 48479]]
borders of such State) involved, provided that such litigation was
initiated no later than 30 days after promulgation of such notice
required in paragraph (b)(2)(iii)(B) of this section.
(iii) If the revised data are used to recalculate, in accordance
with paragraphs (b)(6)(i) and (ii) of this section, the amount of TR
SO2 Group 2 allowances that the owners and operators are
required to hold for such control period with regard to the TR
SO2 Group 2 sources, TR SO2 Group 2 units, and
State (and Indian country within the borders of such State) involved--
(A) Where the amount of TR SO2 Group 2 allowances that
the owners and operators are required to hold increases as a result of
the use of all such revised data, the Administrator will establish a
new, reasonable deadline on which the owners and operators shall hold
the additional amount of TR SO2 Group 2 allowances in the
assurance account established by the Administrator for the appropriate
TR SO2 Group 2 sources, TR SO2 Group 2 units, and
State (and Indian country within the borders of such State) under
paragraph (b)(3) of this section. The owners' and operators' failure to
hold such additional amount, as required, before the new deadline shall
not be a violation of the Clean Air Act. The owners' and operators'
failure to hold such additional amount, as required, as of the new
deadline shall be a violation of the Clean Air Act. Each TR
SO2 Group 2 allowance that the owners and operators fail to
hold as required as of the new deadline, and each day in such control
period, shall be a separate violation of the Clean Air Act.
(B) For the owners and operators for which the amount of TR
SO2 Group 2 allowances required to be held decreases as a
result of the use of all such revised data, the Administrator will
record, in all accounts from which TR SO2 Group 2 allowances
were transferred by such owners and operators for such control period
to the assurance account established by the Administrator for the
appropriate at TR SO2 Group 2 sources, TR SO2
Group 2 units, and State (and Indian country within the borders of such
State) under paragraph (b)(3) of this section, a total amount of the TR
SO2 Group 2 allowances held in such assurance account equal
to the amount of the decrease. If TR SO2 Group 2 allowances
were transferred to such assurance account from more than one account,
the amount of TR SO2 Group 2 allowances recorded in each
such transferor account will be in proportion to the percentage of the
total amount of TR SO2 Group 2 allowances transferred to
such assurance account for such control period from such transferor
account.
(C) Each TR SO2 Group 2 allowance held under paragraph
(b)(6)(iii)(A) of this section as a result of recalculation of
requirements under the TR SO2 Group 2 assurance provisions
for such control period must be a TR SO2 Group 2 allowance
allocated for a control period in a year before or the year immediately
following, or in the same year as, the year of such control period.
Sec. 97.726 Banking.
(a) A TR SO2 Group 2 allowance may be banked for future
use or transfer in a compliance account or a general account in
accordance with paragraph (b) of this section.
(b) Any TR SO2 Group 2 allowance that is held in a
compliance account or a general account will remain in such account
unless and until the TR SO2 Group 2 allowance is deducted or
transferred under Sec. 97.711(c), Sec. 97.723, Sec. 97.724, Sec.
97.725, Sec. 97.727, or Sec. 97.728.
Sec. 97.727 Account error.
The Administrator may, at his or her sole discretion and on his or
her own motion, correct any error in any Allowance Management System
account. Within 10 business days of making such correction, the
Administrator will notify the authorized account representative for the
account.
Sec. 97.728 Administrator's action on submissions.
(a) The Administrator may review and conduct independent audits
concerning any submission under the TR SO2 Group 2 Trading
Program and make appropriate adjustments of the information in the
submission.
(b) The Administrator may deduct TR SO2 Group 2
allowances from or transfer TR SO2 Group 2 allowances to a
compliance account or an assurance account, based on the information in
a submission, as adjusted under paragraph (a)(1) of this section, and
record such deductions and transfers.
Sec. 97.729 [Reserved]
Sec. 97.730 General monitoring, recordkeeping, and reporting
requirements.
The owners and operators, and to the extent applicable, the
designated representative, of a TR SO2 Group 2 unit, shall
comply with the monitoring, recordkeeping, and reporting requirements
as provided in this subpart and subparts F and G of part 75 of this
chapter. For purposes of applying such requirements, the definitions in
Sec. 97.702 and in Sec. 72.2 of this chapter shall apply, the terms
``affected unit,'' ``designated representative,'' and ``continuous
emission monitoring system'' (or ``CEMS'') in part 75 of this chapter
shall be deemed to refer to the terms ``TR SO2 Group 2
unit,'' ``designated representative,'' and ``continuous emission
monitoring system'' (or ``CEMS'') respectively as defined in Sec.
97.702, and the term ``newly affected unit'' shall be deemed to mean
``newly affected TR SO2 Group 2 unit''. The owner or
operator of a unit that is not a TR SO2 Group 2 unit but
that is monitored under Sec. 75.16(b)(2) of this chapter shall comply
with the same monitoring, recordkeeping, and reporting requirements as
a TR SO2 Group 2 unit.
(a) Requirements for installation, certification, and data
accounting. The owner or operator of each TR SO2 Group 2
unit shall:
(1) Install all monitoring systems required under this subpart for
monitoring SO2 mass emissions and individual unit heat input
(including all systems required to monitor SO2
concentration, stack gas moisture content, stack gas flow rate,
CO2 or O2 concentration, and fuel flow rate, as
applicable, in accordance with Sec. Sec. 75.11 and 75.16 of this
chapter);
(2) Successfully complete all certification tests required under
Sec. 97.731 and meet all other requirements of this subpart and part
75 of this chapter applicable to the monitoring systems under paragraph
(a)(1) of this section; and
(3) Record, report, and quality-assure the data from the monitoring
systems under paragraph (a)(1) of this section.
(b) Compliance deadlines. Except as provided in paragraph (e) of
this section, the owner or operator shall meet the monitoring system
certification and other requirements of paragraphs (a)(1) and (2) of
this section on or before the following dates and shall record, report,
and quality-assure the data from the monitoring systems under paragraph
(a)(1) of this section on and after the following dates.
(1) For the owner or operator of a TR SO2 Group 2 unit
that commences commercial operation before July 1, 2011, January 1,
2012.
(2) For the owner or operator of a TR SO2 Group 2 unit
that commences commercial operation on or after July 1, 2011, by the
later of the following:
(i) January 1, 2012; or
(ii) 180 calendar days after the date on which the unit commences
commercial operation.
(3) The owner or operator of a TR SO2 Group 2 unit for
which construction of a new stack or flue or installation of add-on
SO2 emission controls is completed after the applicable
deadline
[[Page 48480]]
under paragraph (b)(1) or (2) of this section shall meet the
requirements of Sec. Sec. 75.4(e)(1) through (e)(4) of this chapter,
except that:
(i) Such requirements shall apply to the monitoring systems
required under Sec. 97.730 through Sec. 97.735, rather than the
monitoring systems required under part 75 of this chapter;
(ii) SO2 concentration, stack gas moisture content,
stack gas volumetric flow rate, and O2 or CO2
concentration data shall be determined and reported, rather than the
data listed in Sec. 75.4(e)(2) of this chapter; and
(iii) Any petition for another procedure under Sec. 75.4(e)(2) of
this chapter shall be submitted under Sec. 97.735, rather than Sec.
75.66.
(c) Reporting data. The owner or operator of a TR SO2
Group 2 unit that does not meet the applicable compliance date set
forth in paragraph (b) of this section for any monitoring system under
paragraph (a)(1) of this section shall, for each such monitoring
system, determine, record, and report maximum potential (or, as
appropriate, minimum potential) values for SO2
concentration, stack gas flow rate, stack gas moisture content, fuel
flow rate, and any other parameters required to determine
SO2 mass emissions and heat input in accordance with Sec.
75.31(b)(2) or (c)(3) of this chapter or section 2.4 of appendix D to
part 75 of this chapter, as applicable.
(d) Prohibitions. (1) No owner or operator of a TR SO2
Group 2 unit shall use any alternative monitoring system, alternative
reference method, or any other alternative to any requirement of this
subpart without having obtained prior written approval in accordance
with Sec. 97.735.
(2) No owner or operator of a TR SO2 Group 2 unit shall
operate the unit so as to discharge, or allow to be discharged,
SO2 to the atmosphere without accounting for all such
SO2 in accordance with the applicable provisions of this
subpart and part 75 of this chapter.
(3) No owner or operator of a TR SO2 Group 2 unit shall
disrupt the continuous emission monitoring system, any portion thereof,
or any other approved emission monitoring method, and thereby avoid
monitoring and recording SO2 mass discharged into the
atmosphere or heat input, except for periods of recertification or
periods when calibration, quality assurance testing, or maintenance is
performed in accordance with the applicable provisions of this subpart
and part 75 of this chapter.
(4) No owner or operator of a TR SO2 Group 2 unit shall
retire or permanently discontinue use of the continuous emission
monitoring system, any component thereof, or any other approved
monitoring system under this subpart, except under any one of the
following circumstances:
(i) During the period that the unit is covered by an exemption
under Sec. 97.705 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 Administrator 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 designated representative submits notification of the
date of certification testing of a replacement monitoring system for
the retired or discontinued monitoring system in accordance with Sec.
97.731(d)(3)(i).
(e) Long-term cold storage. The owner or operator of a TR
SO2 Group 2 unit is subject to the applicable provisions of
Sec. 75.4(d) of this chapter concerning units in long-term cold
storage.
Sec. 97.731 Initial monitoring system certification and
recertification procedures.
(a) The owner or operator of a TR SO2 Group 2 unit shall
be exempt from the initial certification requirements of this section
for a monitoring system under Sec. 97.730(a)(1) if the following
conditions are met:
(1) The monitoring system has been previously certified in
accordance with part 75 of this chapter; and
(2) The applicable quality-assurance and quality-control
requirements of Sec. 75.21 of this chapter and appendices B and D to
part 75 of this chapter are fully met for the certified monitoring
system described in paragraph (a)(1) of this section.
(b) The recertification provisions of this section shall apply to a
monitoring system under Sec. 97.730(a)(1) that is exempt from initial
certification requirements under paragraph (a) of this section.
(c) [Reserved]
(d) Except as provided in paragraph (a) of this section, the owner
or operator of a TR SO2 Group 2 unit shall comply with the
following initial certification and recertification procedures, for a
continuous monitoring system (i.e., a continuous emission monitoring
system and an excepted monitoring system under appendix D to part 75 of
this chapter) under Sec. 97.730(a)(1). The owner or operator of a unit
that qualifies to use the low mass emissions excepted monitoring
methodology under Sec. 75.19 of this chapter or that qualifies to use
an alternative monitoring system under subpart E of part 75 of this
chapter shall comply with the procedures in paragraph (e) or (f) of
this section respectively.
(1) Requirements for initial certification. The owner or operator
shall ensure that each continuous monitoring system under Sec.
97.730(a)(1) (including the automated data acquisition and handling
system) successfully completes all of the initial certification testing
required under Sec. 75.20 of this chapter by the applicable deadline
in Sec. 97.730(b). In addition, whenever the owner or operator
installs a monitoring system to meet the requirements of this subpart
in a location where no such monitoring system was previously installed,
initial certification in accordance with Sec. 75.20 of this chapter is
required.
(2) Requirements for recertification. Whenever the owner or
operator makes a replacement, modification, or change in any certified
continuous emission monitoring system under Sec. 97.730(a)(1) that may
significantly affect the ability of the system to accurately measure or
record SO2 mass emissions or heat input rate or to meet the
quality-assurance and quality-control 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 in accordance with 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 may significantly change the stack
flow or concentration profile, the owner or operator shall recertify
each continuous emission monitoring system whose accuracy is
potentially affected by the change, in accordance with Sec. 75.20(b)
of this chapter. Examples of changes to a continuous emission
monitoring system that require recertification include: Replacement of
the analyzer, complete replacement of an existing continuous emission
monitoring system, or change in location or orientation of the sampling
probe or site. Any fuel flowmeter system under Sec. 97.730(a)(1) is
subject to the recertification requirements in Sec. 75.20(g)(6) of
this chapter.
(3) Approval process for initial certification and recertification.
For initial certification of a continuous monitoring system under Sec.
97.730(a)(1), paragraphs (d)(3)(i) through (v) of this section apply.
For recertifications of such monitoring systems, paragraphs (d)(3)(i)
through (iv) of this section and the procedures in Sec. Sec.
75.20(b)(5) and (g)(7) of this chapter (in lieu of the
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procedures in paragraph (d)(3)(v) of this section) apply, provided that
in applying paragraphs (d)(3)(i) through (iv) of this section, the
words ``certification'' and ``initial certification'' are replaced by
the word ``recertification'' and the word ``certified'' is replaced by
with the word ``recertified''.
(i) Notification of certification. The designated representative
shall submit to the appropriate EPA Regional Office and the
Administrator written notice of the dates of certification testing, in
accordance with Sec. 97.733.
(ii) Certification application. The designated representative shall
submit to the Administrator a certification application for each
monitoring system. A complete certification application shall include
the information specified in Sec. 75.63 of this chapter.
(iii) Provisional certification date. The provisional certification
date for a monitoring system shall be determined in accordance with
Sec. 75.20(a)(3) of this chapter. A provisionally certified monitoring
system may be used under the TR SO2 Group 2 Trading Program
for a period not to exceed 120 days after receipt by the Administrator
of the complete certification application for the monitoring system
under paragraph (d)(3)(ii) of this section. Data measured and recorded
by the provisionally certified monitoring system, in accordance with
the requirements of part 75 of this chapter, will be considered valid
quality-assured data (retroactive to the date and time of provisional
certification), provided that the Administrator does not invalidate the
provisional certification by issuing a notice of disapproval within 120
days of the date of receipt of the complete certification application
by the Administrator.
(iv) Certification application approval process. The Administrator
will issue a written notice of approval or disapproval of the
certification application to the owner or operator within 120 days of
receipt of the complete certification application under paragraph
(d)(3)(ii) of this section. In the event the Administrator does not
issue such a notice within such 120-day period, each monitoring system
that 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 TR SO2 Group 2 Trading Program.
(A) Approval notice. If the certification application is complete
and shows that each monitoring system meets the applicable performance
requirements of part 75 of this chapter, then the Administrator will
issue a written notice of approval of the certification application
within 120 days of receipt.
(B) Incomplete application notice. If the certification application
is not complete, then the Administrator will issue a written notice of
incompleteness that sets a reasonable date by which the designated
representative must submit the additional information required to
complete the certification application. If the designated
representative does not comply with the notice of incompleteness by the
specified date, then the Administrator may issue a notice of
disapproval under paragraph (d)(3)(iv)(C) of this section.
(C) Disapproval notice. If the certification application shows that
any monitoring system does not meet the performance requirements of
part 75 of this chapter or if the certification application is
incomplete and the requirement for disapproval under paragraph
(d)(3)(iv)(B) of this section is met, then the Administrator will issue
a written notice of disapproval of the certification application. Upon
issuance of such notice of disapproval, the provisional certification
is invalidated by the Administrator and the data measured and recorded
by each uncertified monitoring system shall not be considered valid
quality-assured data beginning with the date and hour of provisional
certification (as defined under Sec. 75.20(a)(3) of this chapter).
(D) Audit decertification. The Administrator may issue a notice of
disapproval of the certification status of a monitor in accordance with
Sec. 97.732(b).
(v) Procedures for loss of certification. If the Administrator
issues a notice of disapproval of a certification application under
paragraph (d)(3)(iv)(C) of this section or a notice of disapproval of
certification status under paragraph (d)(3)(iv)(D) of this section,
then:
(A) The owner or operator shall substitute the following values,
for each disapproved monitoring system, for each hour of unit operation
during the period of invalid data specified under Sec.
75.20(a)(4)(iii), Sec. 75.20(g)(7), or Sec. 75.21(e) of this chapter
and continuing until the applicable date and hour specified under Sec.
75.20(a)(5)(i) or (g)(7) of this chapter:
(1) For a disapproved SO2 pollutant concentration
monitor and disapproved flow monitor, respectively, the maximum
potential concentration of SO2 and the maximum potential
flow rate, as defined in sections 2.1.1.1 and 2.1.4.1 of appendix A to
part 75 of this chapter.
(2) For a disapproved moisture monitoring system and disapproved
diluent gas monitoring system, respectively, the minimum potential
moisture percentage and either the maximum potential CO2
concentration or the minimum potential O2 concentration (as
applicable), as defined in sections 2.1.5, 2.1.3.1, and 2.1.3.2 of
appendix A to part 75 of this chapter.
(3) For a disapproved fuel flowmeter system, the maximum potential
fuel flow rate, as defined in section 2.4.2.1 of appendix D to part 75
of this chapter.
(B) The designated representative shall submit a notification of
certification retest dates and a new certification application in
accordance with paragraphs (d)(3)(i) and (ii) of this section.
(C) The owner or operator shall repeat all certification tests or
other requirements that were failed by the monitoring system, as
indicated in the Administrator's notice of disapproval, no later than
30 unit operating days after the date of issuance of the notice of
disapproval.
(e) The owner or operator of a unit qualified to use the low mass
emissions (LME) excepted methodology under Sec. 75.19 of this chapter
shall meet the applicable certification and recertification
requirements in Sec. Sec. 75.19(a)(2) and 75.20(h) of this chapter. If
the owner or operator of such a unit elects to certify a fuel flowmeter
system for heat input determination, the owner or operator shall also
meet the certification and recertification requirements in Sec.
75.20(g) of this chapter.
(f) The designated representative of each unit for which the owner
or operator intends to use an alternative monitoring system approved by
the Administrator under subpart E of part 75 of this chapter shall
comply with the applicable notification and application procedures of
Sec. 75.20(f) of this chapter.
Sec. 97.732 Monitoring system out-of-control periods.
(a) General provisions. Whenever any monitoring system fails to
meet the quality-assurance and quality-control requirements or data
validation requirements of part 75 of this chapter, data shall be
substituted using the applicable missing data procedures in subpart D
or appendix D to 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 monitoring system should not have been
certified or recertified because it did not meet a particular
performance
[[Page 48482]]
specification or other requirement under Sec. 97.731 or the applicable
provisions of part 75 of this chapter, both at the time of the initial
certification or recertification application submission and at the time
of the audit, the Administrator will issue a notice of disapproval of
the certification status of such monitoring system. For the purposes of
this paragraph, an audit shall be either a field audit or an audit of
any information submitted to the Administrator or any State or
permitting authority. By issuing the notice of disapproval, the
Administrator revokes prospectively the certification status of the
monitoring system. The data measured and recorded by the monitoring
system 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
for the monitoring system. The owner or operator shall follow the
applicable initial certification or recertification procedures in Sec.
97.731 for each disapproved monitoring system.
Sec. 97.733 Notifications concerning monitoring.
The designated representative of a TR SO2 Group 2 unit
shall submit written notice to the Administrator in accordance with
Sec. 75.61 of this chapter.
Sec. 97.734 Recordkeeping and reporting.
(a) General provisions. The designated representative shall comply
with all recordkeeping and reporting requirements in paragraphs (b)
through (e) of this section, the applicable recordkeeping and reporting
requirements in subparts F and G of part 75 of this chapter, and the
requirements of Sec. 97.714(a).
(b) Monitoring plans. The owner or operator of a TR SO2
Group 2 unit shall comply with requirements of Sec. 75.62 of this
chapter.
(c) Certification applications. The designated representative shall
submit an application to the Administrator within 45 days after
completing all initial certification or recertification tests required
under Sec. 97.731, including the information required under Sec.
75.63 of this chapter.
(d) Quarterly reports. The designated representative shall submit
quarterly reports, as follows:
(1) The designated representative shall report the SO2
mass emissions data and heat input data for the TR SO2 Group
2 unit, in an electronic quarterly report in a format prescribed by the
Administrator, for each calendar quarter beginning with:
(i) For a unit that commences commercial operation before July 1,
2011, the calendar quarter covering January 1, 2012 through March 31,
2012; or
(ii) For a unit that commences commercial operation on or after
July 1, 2011, the calendar quarter corresponding to the earlier of the
date of provisional certification or the applicable deadline for
initial certification under Sec. 97.730(b), unless that quarter is the
third or fourth quarter of 2011, in which case reporting shall commence
in the quarter covering January 1, 2012 through March 31, 2012.
(2) The designated representative shall submit each quarterly
report to the Administrator within 30 days after the end of the
calendar quarter covered by the report. Quarterly reports shall be
submitted in the manner specified in Sec. 75.64 of this chapter.
(3) For TR SO2 Group 2 units that are also subject to
the Acid Rain Program, TR NOX Annual Trading Program, or TR
NOX Ozone Season Trading Program, quarterly reports shall
include the applicable data and information required by subparts F
through H of part 75 of this chapter as applicable, in addition to the
SO2 mass emission data, heat input data, and other
information required by this subpart.
(4) The Administrator may review and conduct independent audits of
any quarterly report in order to determine whether the quarterly report
meets the requirements of this subpart and part 75 of this chapter,
including the requirement to use substitute data.
(i) The Administrator will notify the designated representative of
any determination that the quarterly report fails to meet any such
requirements and specify in such notification any corrections that the
Administrator believes are necessary to make through resubmission of
the quarterly report and a reasonable time period within which the
designated representative must respond. Upon request by the designated
representative, the Administrator may specify reasonable extensions of
such time period. Within the time period (including any such
extensions) specified by the Administrator, the designated
representative shall resubmit the quarterly report with the corrections
specified by the Administrator, except to the extent the designated
representative provides information demonstrating that a specified
correction is not necessary because the quarterly report already meets
the requirements of this subpart and part 75 of this chapter that are
relevant to the specified correction.
(ii) Any resubmission of a quarterly report shall meet the
requirements applicable to the submission of a quarterly report under
this subpart and part 75 of this chapter, except for the deadline set
forth in paragraph (d)(2) of this section.
(e) Compliance certification. The designated representative shall
submit to the Administrator a compliance certification (in a format
prescribed by the Administrator) in support of each quarterly report
based on reasonable inquiry of those persons with primary
responsibility for ensuring that all of the unit's emissions are
correctly and fully monitored. The certification shall state that:
(1) 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
(2) For a unit with add-on SO2 emission controls and for
all hours where SO2 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 quality
assurance/quality control program under appendix B to part 75 of this
chapter and the substitute data values do not systematically
underestimate SO2 emissions.
Sec. 97.735 Petitions for alternatives to monitoring, recordkeeping,
or reporting requirements.
(a) The designated representative of a TR SO2 Group 2
unit may submit a petition under Sec. 75.66 of this chapter to the
Administrator, requesting approval to apply an alternative to any
requirement of Sec. Sec. 97.730 through 97.734.
(b) A petition submitted under paragraph (a) of this section shall
include sufficient information for the evaluation of the petition,
including, at a minimum, the following information:
(i) Identification of each unit and source covered by the petition;
(ii) A detailed explanation of why the proposed alternative is
being suggested in lieu of the requirement;
(iii) A description and diagram of any equipment and procedures
used in the proposed alternative;
(iv) A demonstration that the proposed alternative is consistent
with the purposes of the requirement for which the alternative is
proposed and with the purposes of this subpart and part 75 of this
chapter and that any
[[Page 48483]]
adverse effect of approving the alternative will be de minimis; and
(v) Any other relevant information that the Administrator may
require.
(c) Use of an alternative to any requirement referenced in
paragraph (a) of this section is in accordance with this subpart only
to the extent that the petition is approved in writing by the
Administrator and that such use is in accordance with such approval.
[FR Doc. 2011-17600 Filed 8-5-11; 8:45 am]
BILLING CODE 6560-50-P