Federal Implementation Plans To Reduce Interstate Transport of Fine Particulate Matter and Ozone, 45210-45465 [2010-17007]
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Federal Register / Vol. 75, No. 147 / Monday, August 2, 2010 / Proposed Rules
ENVIRONMENTAL PROTECTION
AGENCY
40 CFR Parts 51, 52, 72, 78, and 97
[EPA–HQ–OAR–2009–0491; FRL–9174–9]
RIN 2060–AP50
Federal Implementation Plans To
Reduce Interstate Transport of Fine
Particulate Matter and Ozone
Environmental Protection
Agency (EPA).
ACTION: Proposed rule.
AGENCY:
EPA is proposing to limit the
interstate transport of emissions of
nitrogen oxides (NOX) and sulfur
dioxide (SO2). In this action, EPA is
proposing to both identify and limit
emissions within 32 states in the eastern
United States that affect the ability of
downwind states to attain and maintain
compliance with the 1997 and 2006 fine
particulate matter (PM2.5) national
ambient air quality standards (NAAQS)
and the 1997 ozone NAAQS. EPA is
proposing to limit these emissions
through Federal Implementation Plans
(FIPs) that regulate electric generating
units (EGUs) in the 32 states. This
action will substantially reduce the
impact of transported emissions on
downwind states. In conjunction with
other federal and state actions, it helps
assure that all but a handful of areas in
the eastern part of the country will be
in compliance with the current ozone
and PM2.5 NAAQS by 2014 or earlier. To
the extent the proposed FIPs do not
fully address all significant transport,
EPA is committed to assuring that any
additional reductions needed are
addressed quickly. EPA takes comments
on ways this proposal could achieve
additional NOX reductions and
additional actions including other
rulemakings that EPA could undertake
to achieve any additional reductions
needed.
DATES: Comments. Comments must be
received on or before October 1, 2010.
Public Hearing: Three public hearings
will be held before the end of the
comment period. The dates, times and
locations will be announced separately.
Please refer to SUPPLEMENTARY
INFORMATION for additional information
on the comment period and the public
hearings.
ADDRESSES: Submit your comments,
identified by Docket ID No. EPA–HQ–
OAR–2009–0491 by one of the following
methods:
• https://www.regulations.gov. Follow
the online instructions for submitting
comments. Attention Docket ID No.
EPA–HQ–OAR–2009–0491.
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• E-mail: a-and-r-docket@epa.gov.
Attention Docket ID No. EPA–HQ–
OAR–2009–0491.
• Fax: (202) 566–9744. Attention
Docket ID No. EPA–HQ–OAR–2009–
0491.
• Mail: EPA Docket Center, EPA West
(Air Docket), Attention Docket ID No.
EPA–HQ–OAR–2009–0491, U.S.
Environmental Protection Agency,
Mailcode: 2822T, 1200 Pennsylvania
Avenue, NW., Washington, DC 20460.
Please include 2 copies. In addition,
please mail a copy of your comments on
the information collection provisions to
the Office of Information and Regulatory
Affairs, Office of Management and
Budget (OMB), Attn: Desk Officer for
EPA, 725 17th Street, NW., Washington,
DC 20503.
• Hand Delivery: U.S. Environmental
Protection Agency, EPA West (Air
Docket), 1301 Constitution Avenue,
Northwest, Room 3334, Washington, DC
20004, Attention Docket ID No. EPA–
HQ–OAR–2009–0491. Such deliveries
are only accepted during the Docket’s
normal hours of operation, and special
arrangements should be made for
deliveries of boxed information.
Instructions. Direct your comments to
Docket ID No. EPA–HQ–OAR–2009–
0491. EPA’s policy is that all comments
received will be included in the public
docket without change and may be
made available online at https://
www.regulations.gov, including any
personal information provided, unless
the comment includes information
claimed to be Confidential Business
Information (CBI) or other information
whose disclosure is restricted by statute.
Do not submit information that you
consider to be CBI or otherwise
protected through https://
www.regulations.gov or e-mail. The
https://www.regulations.gov Web site is
an ‘‘anonymous access’’ system, which
means EPA will not know your identity
or contact information unless you
provide it in the body of your comment.
If you send an e-mail comment directly
to EPA without going through https://
www.regulations.gov, your e-mail
address will be automatically captured
and included as part of the comment
that is placed in the public docket and
made available on the Internet. If you
submit an electronic comment, EPA
recommends that you include your
name and other contact information in
the body of your comment and with any
disk or CD–ROM you submit. If EPA
cannot read your comment due to
technical difficulties and cannot contact
you for clarification, EPA may not be
able to consider your comment.
Electronic files should avoid the use of
special characters, avoid any form of
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encryption, and be free of any defects or
viruses. For additional information
about EPA’s public docket, visit the EPA
Docket Center homepage at https://
www.epa.gov/epahome/dockets.htm.
Docket. All documents in the docket
are listed in the https://
www.regulations.gov index. 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,
will be publicly available only in hard
copy. Publicly available docket
materials are available either
electronically in https://
www.regulations.gov or in hard copy at
the Air and Radiation Docket and
Information Center, EPA/DC, EPA West
Building, Room 3334, 1301 Constitution
Ave., 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: Mr.
Tim Smith, Air Quality Policy Division,
Office of Air Quality Planning and
Standards (C539–04), Environmental
Protection Agency, Research Triangle
Park, NC 27711; telephone number:
(919) 541–4718; fax number: (919) 541–
0824; e-mail address:
smith.tim@epa.gov. 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 rodman.sonja@epa.gov.
SUPPLEMENTARY INFORMATION:
I. Preamble Glossary of Terms and
Abbreviations
The following are abbreviations of terms
used in the preamble.
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
CBI Confidential Business Information
CFR Code of Federal Regulations
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
Hg Mercury
IPM Integrated Planning Model
lb/mmbtu Pounds Per Million British
Thermal Unit
μg/m3 Micrograms Per Cubic Meter
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NAAQS National Ambient Air Quality
Standards
NOX Nitrogen Oxides
NSPS New Source Performance Standard
OTAG Ozone Transport Assessment Group
PUC Public Utility Commission
SNCR Selective Non-catalytic Reduction
SCR Selective Catalytic Reduction
SIP State Implementation Plan
PM2.5 Fine Particulate Matter, Less Than 2.5
Micrometers
PM10 Fine and Coarse Particulate Matter,
Less Than 10 Micrometers
PM Particulate Matter
RIA Regulatory Impact Analysis
SO2 Sulfur Dioxide
SOX Sulfur Oxides, Including Sulfur
Dioxide (SO2) and Sulfur Trioxide (SO3)
TIP Tribal Implementation Plan tpy Tons
Per Year
TSD Technical Support Document
CD–ROM the specific information that
is claimed as CBI. In addition to one
complete version of the comment that
includes information claimed as CBI, a
copy of the comment that does not
contain the information claimed as CBI
must be submitted for inclusion in the
public docket. Information so marked
will not be disclosed except in
accordance with procedures set forth in
40 CFR part 2. Send or deliver
information identified as CBI only to the
following address: Roberto Morales,
OAQPS Document Control Officer
(C404–02), U.S. EPA, Research Triangle
Park, NC 27711, Attention Docket ID
No. EPA–HQ–OAR–2009–0491.
2. Tips for preparing your comments.
When submitting comments, remember
to:
II. General Information
• Identify the rulemaking by docket
number and other identifying
A. Does this action apply to me?
information (subject heading, Federal
This rule affects EGUs, and regulates
Register date and page number).
the following groups:
• Follow directions—The agency may
ask you to respond to specific questions
Industry group
NAICS a
or organize comments by referencing a
Utilities (electric, natural
2211, 2212, 2213 Code of Federal Regulations (CFR) part
gas, other systems).
or section number.
• Explain why you agree or disagree;
a North
American Industry Classification
suggest alternatives and substitute
System.
language for your requested changes.
This table is not intended to be
• Describe any assumptions and
exhaustive, but rather provides a guide
provide any technical information and/
for readers regarding entities likely to be or data that you used.
regulated by this action. This table lists
• If you estimate potential costs or
the types of entities that EPA is aware
burdens, explain how you arrived at
of that could potentially be regulated.
your estimate in sufficient detail to
Other types of entities not listed in the
allow for it to be reproduced.
table could also be regulated. To
• Provide specific examples to
determine whether your facility would
illustrate your concerns, and suggest
be regulated by the proposed rule, you
alternatives.
should carefully examine the
• Explain your views as clearly as
applicability criteria in proposed
possible, avoiding the use of profanity
§§ 97.404, 97.504, 97,604, and 97.704.
or personal threats.
• Make sure to submit your
B. Where can I get a copy of this
comments by the comment period
document and other related
deadline identified.
information?
D. How can I find information about the
In addition to being available in the
public hearings?
docket, an electronic copy of this
The EPA will hold three public
proposal will also be available on the
hearings on this proposal. The dates,
World Wide Web. Following signature
by the EPA Administrator, a copy of this times and locations of the pubic
hearings will be announced separately.
action will be posted on the transport
Oral testimony will be limited to 5
rule Web site https://www.epa.gov/
minutes per commenter. The EPA
airtransport.
encourages commenters to provide
C. What should I consider as I prepare
written versions of their oral testimonies
my comments for EPA?
either electronically or in paper copy.
1. Submitting CBI. Do not submit this
Verbatim transcripts and written
information to EPA through https://
statements will be included in the
www.regulations.gov or e-mail. Clearly
rulemaking docket. If you would like to
mark the part or all of the information
present oral testimony at one of the
that you claim to be CBI. For CBI
hearings, please notify Ms. Pamela S.
information in a disk or CD–ROM that
Long, Air Quality Policy Division
you mail to EPA, mark the outside of the (C504–03), U.S. EPA, Research Triangle
disk or CD–ROM as CBI and then
Park, NC 27711, telephone number (919)
identify electronically within the disk or 541–0641; e-mail: long.pam@epa.gov.
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Persons interested in presenting oral
testimony should notify Ms. Long at
least 2 days in advance of the public
hearings. For updates and additional
information on the public hearings,
please check EPA’s website for this
rulemaking, https://www.epa.gov/
airtransport. The public hearings will
provide interested parties the
opportunity to present data, views, or
arguments concerning the proposed
rule. The EPA officials may ask
clarifying questions during the oral
presentations, but will not respond to
the presentations or comments at that
time. Written statements and supporting
information submitted during the
comment period will be considered
with the same weight as any oral
comments and supporting information
presented at the public hearings.
E. How is this Preamble Organized?
I. Preamble Glossary of Terms and
Abbreviations
II. General Information
A. Does this action apply to me?
B. Where can I get a copy of this document
and other related information?
C. What should I consider as I prepare my
comments for EPA?
D. How can I find information about the
hearings?
E. How is the preamble organized?
III. Summary of Proposed Rule and
Background
A. Summary of Proposed Rule
B. Background
1. What is the source of EPA’s authority for
this action?
2. What air quality problems does this
proposal address?
3. Which NAAQS does this proposal
address?
4. EPA Transport Rulemaking History
C. What are the goals of this proposed rule?
1. Primary Goals
2. Key Guiding Principles
D. Why does this proposed rule focus on
the eastern half of the United States?
E. Anticipated Rules Affecting Power
Sector
IV. Defining ‘‘Significant Contribution’’ and
‘‘Interference With Maintenance’’
A. Background
1. Approach Used in NOX SIP Call and
CAIR
2. Judicial Opinions
3. Overview of Proposed Approach
B. Overview of Approach To Identify
Contributing Upwind States
1. Background
2. Approach for Proposed Rule
C. Air Quality Modeling Approach and
Results
1. What air quality modeling platform did
EPA use?
2. How did EPA project future
nonattainment and maintenance for
annual PM2.5, 24-Hour PM2.5, and 8-hour
ozone?
3. How did EPA assess interstate
contributions to nonattainment and
maintenance?
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4. What are the estimated interstate
contributions to annual PM2.5, 24-hour
PM2.5, and 8-hour ozone nonattainment
and maintenance?
D. Proposed Methodology To Quantify
Emissions That Significantly Contribute
or Interfere With Maintenance
1. Explanation of Proposed Approach To
Quantify Significant Contribution
2. Application
3. Discussion of Control Costs for Sources
Other Than EGUs
E. State Emissions Budgets
1. Defining SO2 and Annual NOX State
Emissions Budgets for EGUs
2. Defining Ozone Season NOX State
Emissions Budgets for EGUs
F. Emissions Reductions Requirements
Including Variability
1. Variability
2. State Budgets With Variability Limits
3. Summary of Emissions Reductions
Across All Covered States
G. How the Proposed Approach Is
Consistent With Judicial Opinions
Interpreting Section 110(a)(2)(D)(i)(I) of
the Clean Air Act
H. Alternative Approaches Evaluated But
Not Proposed
V. Proposed Emissions Control Requirements
A. Pollutants Included in This Proposal
B. Source Categories
1. Propose To Control Power Sector
Emissions
2. Other Source Categories Are Not
Included
C. Timing of Proposed Emissions
Reductions Requirements
1. Date for Prohibiting Emissions That
Significantly Contribute or Interfere With
Maintenance of the PM2.5 NAAQS
2. Date for Prohibiting Emissions That
Significantly Contribute or Interfere With
Maintenance of the 1997 Ozone NAAQS
3. Reductions Required by 2012 To Ensure
That Significant Contribution and
Interference With Maintenance Are
Eliminated as Expeditiously as
Practicable
4. How Compliance Deadlines Address the
Court’s Concern About Timing
5. EPA Will Consider Additional
Reductions in Pollution Transport To
Assist in Meeting Any Revised or New
NAAQS
D. Implementing Emission Reduction
Requirements
1. Approach Taken in NOX SIP Call and
CAIR
2. Judicial Opinions
3. Remedy Options Overview
4. State Budgets/Limited Trading Proposed
Remedy
5. State Budgets/Intrastate Trading Remedy
Option
6. Direct Control Remedy Option
E. Projected Costs and Emissions for Each
Remedy Option
1. State Budgets/Limited Trading
2. State Budgets/Intrastate Trading
3. Direct Control
4. State-Level Emissions Projections
F. Transition From the CAIR Cap-andTrade Programs to Proposed Programs
1. Sunsetting of CAIR, CAIR SIPs, and
CAIR FIPs
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2. Change in States Covered
3. Applicability, CAIR Opt-Ins and NOX
SIP Call Units
4. Early Reduction Provisions
5. Source Monitoring and Reporting
G. Interactions With Existing Title IV
Program and NOX SIP Call
1. Title IV Interactions
2. NOX SIP Call Interactions
VI. Stakeholder Outreach
VII. State Implementation Plan Submissions
A. Section 110(a)(2)(D)(i) SIPs for the 1997
Ozone and PM2.5 NAAQS
B. Section 110(a)(2)(D)(i) SIPs for the 2006
PM2.5 NAAQS
C. Transport Rule SIPs
VIII. Permitting
A. Title V Permitting
B. New Source Review
IX. What benefits are projected for the
proposed rule?
A. The Impacts on PM2.5 and Ozone of the
Proposed SO2 and NOX Strategy
B. Human Health Benefit Analysis
C. Quantified and Monetized Visibility
Benefits
D. Benefits of Reducing GHG Emission
E. Total Monetized Benefits
F. How do the benefits compare to the
costs of this proposed rule?
G. What are the unquantified and
unmonetized benefits of the transport
rule emissions reductions?
1. What are the benefits of reduced
deposition of sulfur and nitrogen to
aquatic, forest, and coastal ecosystems?
2. Ozone Vegetation Effects
3. Other Health or Welfare Disbenefits of
the Transport Rule That Have Not Been
Quantified
X. Economic Impacts
XI. Incorporating End-Use Energy Efficiency
Into the Proposed Transport Rule
A. Background
1. What is end-use energy efficiency?
2. How does energy efficiency contribute to
cost-effective reductions of air emissions
from EGUs?
3. How does the proposed rule support
greater investment in energy efficiency?
4. How EPA and states have previously
integrated energy efficiency into air
regulatory programs?
B. Incorporating End-Use Energy Efficiency
Into the Transport Rule
1. Options That Could Be Used To
Incorporate Energy Efficiency Into
Allowance Based Programs
2. Why EPA did not propose these options?
XII. Statutory and Executive Order Reviews
A. Executive Order 12866: Regulatory
Planning and Review
B. Paperwork Reduction Act
C. Regulatory Flexibility Act (RFA)
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
Advancement Act
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J. Executive Order 12898: Federal Actions
To Address Environmental Justice in
Minority Populations and Low-Income
Populations
1. Consideration of Environmental Justice
Issues in the Rule Development Process
2. Potential Environmental and Public
Health Impacts to Vulnerable
Populations
3. Meaningful Public Participation
4. Determination
III. Summary of Proposed Rule and
Background
A. Summary of Proposed Rule
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 notice, EPA proposes to
find that emissions of SO2 and NOX in
32 eastern 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
average PM2.5 NAAQS promulgated in
1997, the 24-hour average PM2.5 NAAQS
promulgated in 2006, and the ozone
NAAQS promulgated in 1997.1 These
emissions are transported downwind
either as SO2 and NOX or, after
transformation in the atmosphere, as
fine particles or ozone. This notice
identifies emission reduction
responsibilities of upwind states, and
also proposes enforceable FIPs to
achieve the required emissions
reductions in each state through costeffective and flexible requirements for
power plants. Each state will have the
option of replacing these Federal rules
with state rules to achieve the required
amount of emissions reductions from
sources selected by the state.
With respect to the annual average
PM2.5 NAAQS, this proposal finds that
24 eastern states have SO2 and NOX
emission reduction responsibilities, and
quantifies each state’s full emission
reduction responsibility under section
110(a)(2)(D)(i)(I). With respect to the 24hour average PM2.5 NAAQS, this
proposal finds that 25 eastern states
have emission reduction
responsibilities. The proposed
reductions will at least partly eliminate,
and subject to further analysis may fully
eliminate, these states’ significant
contribution and interference with
maintenance for purposes of the 24-hour
average PM2.5 standard. In all, emissions
reductions related to interstate transport
1 In the context of the jurisdictions covered by
this proposed rule, EPA uses the term ‘‘states’’ to
include the District of Columbia.
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of fine particles would be required in 28
states.
With respect to the 1997 ozone
NAAQS, this proposal requires
emissions reductions in 26 states. For 16
of these states, we propose that the
required reductions represent their full
significant contribution and interference
with maintenance for the ozone
NAAQS. For an additional 10 states, the
required NOX reductions are needed for
these states to make measurable
progress towards eliminating their
significant contribution and interference
with maintenance. EPA has begun to
conduct additional information
gathering and analysis to determine the
extent to which further reductions from
these states may be needed to fully
eliminate significant contribution and
interference with maintenance with the
1997 ozone NAAQS.
This proposed rule would achieve
substantial near-term emissions
reductions from the power sector. EPA
projects that with the proposed rule,
EGU SO2 emissions would be 5.0
million tons lower, annual NOX
emissions would be 700,000 tons lower,
and ozone season NOX emissions would
be 100,000 tons lower in 2012,
compared to baseline 2012 projections
in the proposed covered states. Further,
EGU SO2 emissions would be 4.6
million tons lower, annual NOX
emissions would be 700,000 tons lower,
and ozone season NOX emissions would
be 100,000 tons lower in 2014,
compared to baseline 2014 projections
(which will have dropped from 2012
due to other federal and state
requirements, thereby lowering the 2014
baseline). See Table III.A–2 for projected
EGU emissions with the proposed rule
compared to baseline, and Table III.A–
3 for projected EGU emissions with the
proposed rule compared to 2005 actual
emissions. The reductions obtained
through the Transport Rule FIPs will
help all but a very few areas in the
eastern part of the country come into
attainment with the 1997 PM2.5 and
ozone standards and take major strides
toward helping states address
nonattainment with the 2006 24-hour
average PM2.5 standard. See Table III.A–
1 for proposed list of covered states.
EPA is committed to fulfilling its
responsibility to ensure that downwind
states receive the relief from upwind
emissions guaranteed under CAA
section 110(a)(2)(D) For the 24-hour
PM2.5 standard, EPA’s air quality
modeling shows that in the areas with
continuing non-attainment or
maintenance problems, the remaining
exceedances occur almost entirely in the
winter months. The relative importance
of particle species such as sulfate and
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nitrate, is quite different between
summer and winter. EPA is moving
ahead before the final rule is published
to determine the extent to which this
wintertime problem is caused by
emissions transported from upwind
states. Further study of the 24-hour
PM2.5 results could lead to a number of
possible outcomes; EPA cannot judge
the relative likelihood of these outcomes
at this time. To the extent possible, EPA
plans to finalize this rule with a full
determination of, and remedy for,
significant contribution and interference
with maintenance for the 24-hour PM2.5
standard. To that end, EPA is
expeditiously proceeding with
examination of the residual wintertime
problem. (See full discussion in section
IV.D.)
In the case of ozone, EPA must
determine whether further NOX
reductions are warranted in certain
upwind states that affect two or three
areas with relatively persistent ozone air
quality problems. To support a full
significant contribution determination
for these states, EPA is expeditiously
conducting further analysis of NOX
control costs, emissions reductions, air
quality impacts, and the nature of the
residual air quality issues. EPA’s current
information indicates that considering
NOX reductions beyond the cost per ton
levels proposed in this rule will require
analysis of reductions from source
categories other than EGUs, as well as
from EGUs. EPA believes that
developing supplemental information to
consider NOX sources beyond EGUs
would substantially delay publication of
a final rule beyond the anticipated
publication of spring 2011. EPA does
not believe that this effort should delay
the reductions and large health benefits
associated with this proposed rule.
Thus, EPA intends to proceed with
additional rulemaking to address fully
the residual significant contribution to
nonattainment and interference with
maintenance with the ozone standard as
quickly as possible. (See full discussion
in section IV.D.)
This proposed rule is the first of
several EPA rules to be issued over the
next 2 years that will yield substantial
health and environmental benefits for
the public through regulation of power
plants. Fossil-fuel-fired power plants
contribute a large and substantial
fraction of the emissions of several key
air pollutants, and the agency has
statutory or judicial obligations to make
several regulatory determinations on
power plant emissions. The
Administrator in January established
improved air quality as an Agency
priority and announced plans to
promote a cleaner and more efficient
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power sector and have strong but
achievable reduction goals for SO2,
NOX, mercury, and other air toxics.’’
In addition to this rule, other
anticipated actions include a section
112(d) rule for electric utilities to be
proposed by March 2011, potential rules
to address pollution transport under
revised NAAQS, revisions to new
source performance standards for coal
and oil-fired utility electric generating
units, and best available retrofit
technology (BART) and regional haze
program requirements to protect
visibility. These actions, and their
relationship to this rule, are discussed
further in section III.E.
Ongoing reviews of the ozone and
PM2.5 NAAQS could result in revised
NAAQS. To address any new NAAQS,
EPA would propose interstate transport
determinations in future notices. Such
proposals could require greater
emissions reductions from states
covered by this proposal and/or require
reductions from states not covered by
this proposal. In addition, while this
action proposes to require reductions
from the power sector only, it is
possible that reductions from other
source categories could be needed to
address interstate transport
requirements related to any new
NAAQS.
With this proposal, EPA is also
responding to the remand of the CAIR
by the Court in 2008. CAIR,
promulgated May 12, 2005 (70 FR
25162) requires 28 states and the
District of Columbia 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. The
CAIR FIPs, promulgated April 26, 2006
(71 FR 25328), regulate EGUs in the
covered states and achieve the
emissions reductions requirements
established by CAIR until states have
approved SIPs to achieve the
reductions. In July 2008, the DC Circuit
Court found CAIR and the CAIR FIPs
unlawful. North Carolina v. EPA, 531
F.3d 896 (DC Cir. 2008). The Court’s
original decision vacated CAIR. Id. 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 v.
EPA, 550 F.3d 1176, 1178 (DC Cir.
2008). The CAIR requirements are
correctly in place and the CAIR’s
regional control programs are operating
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while EPA develops replacement rules
in response to the remand.
As described more fully in the
remainder of this preamble, the
approaches used in this proposed 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 v. EPA and address the
flaws in CAIR identified by the Court
therein. Among other things, the
proposal relies on detailed, bottom-up
scientific and technical analyses,
introduces a state-specific methodology
for identifying significant contribution
to nonattainment and interference with
maintenance, and proposes remedy
options to ensure that all necessary
reductions are achieved in the covered
states.
In this action, EPA proposes to both
identify and address emissions within
states in the eastern United States that
significantly contribute to
nonattainment or interfere with
maintenance by other downwind states.
As discussed in sections III and VII in
this preamble and described in greater
detail in two separate Federal Register
notices published on April 25, 2005 (70
FR 21147) and June 9, 2010 (75 FR
32673), EPA has determined, or
proposed to determine, that the 32 states
covered by this proposal either have not
submitted SIPs adequate to meet the
requirements of 110(a)(2)(D)(i)(I) with
respect to the 1997 and 2006 PM2.5
NAAQS and the 1997 ozone NAAQS, or
that the SIP provisions currently in
place are not adequate to meet those
requirements.
As described in section IV in this
preamble, EPA is proposing a statespecific methodology to identify
specific reductions that states in the
eastern United States must make to
satisfy 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. The
proposed methodology uses statespecific inputs and focuses on the
emissions reductions available in each
individual state to address the Court’s
concern that the approach used in CAIR
(which identified a single level of
emissions achievable by the application
of highly cost effective controls in the
region) was insufficiently state specific.
The proposed methodology uses air
quality analysis to determine whether a
state’s contribution to downwind air
quality problems is above specific
thresholds. If a state’s contribution does
not exceed those thresholds, its
contribution is found to be insignificant
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and it is no longer considered in the
analysis. If a state’s contribution
exceeds those thresholds, EPA takes a
second step that uses a multi-factor
analysis that takes into account both air
quality and cost considerations to
identify the portion of a state’s
contribution that is significant or that
interferes with maintenance. Section
110(a)(2)(D) requires states to eliminate
the emissions that constitute this
‘‘significant contribution’’ and
‘‘interference with maintenance.’’
This proposed methodology for
determining upwind state emission
reduction responsibility is designed to
be applicable to current and potential
future ozone and PM2.5 NAAQS. It is
based on cost and air quality
considerations that are common to any
NAAQS, but also calls for evaluation of
facts specific to a particular NAAQS. As
a result, application of the methodology
to a revised, more stringent NAAQS
might lead to a determination that
greater reductions in transported
pollution from upwind states are
reasonable than for a current, less
stringent NAAQS.
To facilitate implementation of the
requirement that significant
contribution and interference with
maintenance be eliminated, EPA
developed state emissions budgets. By
tying these budgets directly to EPA’s
quantification of each individual state’s
significant contribution and interference
with maintenance, EPA directly linked
the budgets to the mandate in section
110(a)(2)(D)(i)(I), and thus addressed the
Court’s concerns about the development
of budgets for the CAIR. EPA also
addressed these concerns by completely
eschewing any consideration or reliance
on Fuel Adjustment Factors and the
existing allocation of Title IV
allowances.
These new emissions budgets are
based on the Agency’s state-by-state
analysis of each upwind state’s
significant contribution to
nonattainment and interference with
maintenance downwind. A state’s
emissions budget is the quantity of
emissions that would remain after
elimination of the part of significant
contribution and interference with
maintenance that EPA has identified in
an average year (i.e., before accounting
for the inherent variability in power
system operations).2 EPA proposes SO2
and NOX budgets for each state covered
for the 24-hour and/or annual average
PM2.5 NAAQS. EPA proposes an ozone
season 3 NOX budget for each state
covered for the ozone NAAQS.
EPA recognizes that baseline
emissions from a state can be affected by
changing weather patterns, demand
growth, or disruptions in electricity
supply from other units. As a result,
emissions could vary from year to year
in a state where covered sources have
installed all controls and taken all
measures necessary to eliminate the
state’s significant contribution and
interference with maintenance. As
described in detail in section IV of this
preamble, EPA proposes to account for
the inherent variability in power system
operations through ‘‘assurance
provisions’’ based on state variability
limits which extend above the state
emissions budgets. See section V for a
detailed discussion of the assurance
provisions. The small amount of
variability allowed takes into account
the inherent variability in baseline
emissions. Section IV in this preamble
describes the proposed approach to
significant contribution and interference
with maintenance and the state
emissions budgets and variability limits
in detail.
EPA is also proposing FIPs to
immediately implement the emission
reduction requirements identified and
quantified by EPA in this action. For
some covered states, these FIPs will
completely satisfy the emissions
reductions requirements of
110(a)(2)(D)(i)(I) with respect to the
1997 and 2006 PM2.5 NAAQS and the
1997 ozone NAAQS. The exception is
for the 10 eastern states for which EPA
has not completely quantified the total
significant contribution or interference
with maintenance with respect to the
1997 ozone NAAQS and the 15 states
for which EPA has not completely
quantified total significant contribution
or interference with maintenance with
respect to the 2006 PM2.5 NAAQS in
which case the FIPs would achieve
measurable progress towards
implementing that requirement.
The emissions reductions
requirements (i.e., the ‘‘remedy’’) that
EPA is proposing to include in the FIPs
responds to the Court’s concerns that
EPA had not shown that the CAIR
reduction requirements would get all
2 For the 10 states discussed above for which EPA
has only quantified a minimum amount of
emissions reductions needed to make measurable
progress towards eliminating their significant
contribution and interference with maintenance
with respect to the 1997 8-hour ozone NAAQS, the
emissions budget is the emissions that will remain
after removal of those emissions.
3 Consistent with the approach taken by the
Ozone Transport Assessment Group (OTAG), the
NOX SIP call, and the CAIR, we propose to define
the ozone season, for purposes of emissions
reductions requirements in this rule, as May
through September. We recognize that this ozone
season for regulatory requirements differs from the
official state-specific monitoring season.
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necessary reductions ‘‘in the state’’ as
required by section 110(a)(2)(D)(i)(I).
The proposed 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.
The proposed FIPs would regulate
EGUs in the 32 covered states. EPA is
proposing to regulate these sources
through a program that uses statespecific budgets and allows intrastate
and limited interstate trading. EPA is
also taking comment on two alternative
regulatory options. All options would
achieve the emissions reductions
necessary to address the emissions
transport requirements in section
110(a)(2)(D)(i)(I) of the CAA.
The option EPA is proposing for the
FIPs (‘‘State Budgets/Limited Trading’’)
would use state-specific emissions
budgets and allow for intrastate and
limited interstate trading. This approach
would assure environmental results
while providing some limited flexibility
to covered sources. The approach would
also facilitate the transition from CAIR
to the Transport Rule for implementing
agencies and covered sources.
The first alternative remedy option for
which EPA requests comment would
use state-specific emissions budgets and
allow intrastate trading, but prohibit
interstate trading. The second
alternative remedy option, for which
EPA also requests comment, would use
state-specific budgets and emissions rate
limits. See section V for further
discussion of the remedy options.
The proposed remedy option and the
first alternative, both of which are capand-trade approaches, would use new
allowance allocations developed on a
different basis from CAIR. Allowance
allocations, like the state budgets
described previously, would be
developed based on the methodology
used by EPA to quantify each state’s
significant contribution and interference
with maintenance. See section IV for the
proposed state budget approach and
section V for proposed allowance
allocation approaches.
In this action, EPA proposes to
require reductions in SO2 and NOX
emissions in the following 25
jurisdictions that contribute
significantly to nonattainment in, or
interfere with maintenance by, a
downwind area with respect to the 24hour PM2.5 NAAQS promulgated in
September 2006: Alabama, Connecticut,
Delaware, District of Columbia, Georgia,
Illinois, Indiana, Iowa, Kansas,
Kentucky, Maryland, Massachusetts,
Michigan, Minnesota, Missouri,
Nebraska, New Jersey, New York, North
Carolina, Ohio, Pennsylvania,
Tennessee, Virginia, West Virginia, and
Wisconsin.
EPA proposes to require reductions in
SO2 and NOX emissions in the following
24 jurisdictions that contribute
significantly to nonattainment in, or
interfere with maintenance by, a
downwind area with respect to the
annual PM2.5 NAAQS promulgated in
July 1997: Alabama, Delaware, District
of Columbia, Florida, Georgia, Illinois,
Indiana, Iowa, Kentucky, Louisiana,
Maryland, Michigan, Minnesota,
Missouri, New Jersey, New York, North
Carolina, Ohio, Pennsylvania, South
Carolina, Tennessee, Virginia, West
Virginia, and Wisconsin.
EPA also proposes to require
reductions in ozone season NOX
emissions in the following 26
jurisdictions that contribute
significantly to nonattainment in, or
interfere with maintenance by, a
downwind area with respect to the 1997
ozone NAAQS promulgated in July
1997: Alabama, Arkansas, Connecticut,
Delaware, District of Columbia, Florida,
Georgia, Illinois, Indiana, Kansas,
Kentucky, Louisiana, Maryland,
Michigan, Mississippi, New Jersey, New
York, North Carolina, Ohio, Oklahoma,
Pennsylvania, South Carolina,
Tennessee, Texas, Virginia, and West
Virginia.
As discussed previously, EPA also is
proposing FIPs to directly regulate EGU
SO2 and/or NOX emissions in the 32
covered states. The proposed FIPs
would require the 28 jurisdictions
45215
covered for purposes of the 24-hour
and/or annual PM2.5 NAAQS to reduce
SO2 and NOX emissions by specified
amounts. The proposed FIPs would
require the 26 states covered for
purposes of the ozone NAAQS to reduce
ozone season NOX emissions by
specified amounts.
In response to the Court’s opinion in
North Carolina v. EPA, EPA has
coordinated the compliance deadlines
for upwind states to eliminate emissions
that significantly contribute to or
interfere with maintenance in
downwind areas with the NAAQS
attainment deadlines that apply to the
downwind nonattainment and
maintenance areas. EPA proposes to
require that all significant contribution
to nonattainment and interference with
maintenance identified in this action
with respect to the PM2.5 NAAQS be
eliminated by 2014 and proposes an
initial phase of reductions starting in
2012 (covering 2012 and 2013) to ensure
that the reductions are made as
expeditiously as practicable and that no
backsliding from current emissions
levels occurs when the requirements of
the CAIR are eliminated. Sources will be
required to comply by January 1, 2012
and January 1, 2014 for the first and
second phases, respectively. With
respect to the 1997 ozone NAAQS, EPA
proposes to require an initial phase of
NOX reductions starting in 2012 to
ensure that reductions are made as
expeditiously as practicable. Sources
will be required to comply by May 1,
2012 and May 1, 2014 for the first and
second phases, respectively. EPA has
determined, that for many states, these
reductions will be sufficient to
eliminate their significant contribution
with respect to the 1997 ozone NAAQS.
EPA intends to issue a subsequent
proposal that would require all
significant contribution and interference
with maintenance be eliminated by a
future date for the 1997 ozone NAAQS.
See Table III.A–1 for proposed lists of
covered state.
TABLE III.A–1—LISTS OF COVERED STATES FOR PM2.5 AND 8-HOUR OZONE NAAQS
Covered for
24-hour and/or
annual PM2.5
Covered for
8-hour ozone
Required to
reduce SO2 and
NOX
Required to
reduce ozone
Season NOX
X
............................
X
X
X
X
X
X
X
X
X
X
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State
Alabama ...........................................................................................................................................................
Arkansas ..........................................................................................................................................................
Connecticut ......................................................................................................................................................
Delaware ..........................................................................................................................................................
District of Columbia .........................................................................................................................................
Florida ..............................................................................................................................................................
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TABLE III.A–1—LISTS OF COVERED STATES FOR PM2.5 AND 8-HOUR OZONE NAAQS—Continued
Covered for
24-hour and/or
annual PM2.5
Covered for
8-hour ozone
Required to
reduce SO2 and
NOX
Required to
reduce ozone
Season NOX
X
X
X
X
X
X
X
X
X
X
X
............................
X
X
X
X
X
X
............................
X
X
X
............................
X
X
X
X
X
X
............................
X
X
X
X
............................
X
............................
X
............................
............................
X
X
X
X
X
X
X
X
X
X
X
............................
28
26
State
Georgia ............................................................................................................................................................
Illinois ...............................................................................................................................................................
Indiana .............................................................................................................................................................
Iowa .................................................................................................................................................................
Kansas .............................................................................................................................................................
Kentucky ..........................................................................................................................................................
Louisiana ..........................................................................................................................................................
Maryland ..........................................................................................................................................................
Massachusetts .................................................................................................................................................
Michigan ...........................................................................................................................................................
Minnesota ........................................................................................................................................................
Mississippi ........................................................................................................................................................
Missouri ............................................................................................................................................................
Nebraska ..........................................................................................................................................................
New Jersey ......................................................................................................................................................
New York .........................................................................................................................................................
North Carolina ..................................................................................................................................................
Ohio .................................................................................................................................................................
Oklahoma .........................................................................................................................................................
Pennsylvania ....................................................................................................................................................
South Carolina .................................................................................................................................................
Tennessee .......................................................................................................................................................
Texas ...............................................................................................................................................................
Virginia .............................................................................................................................................................
West Virginia ....................................................................................................................................................
Wisconsin .........................................................................................................................................................
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Totals ........................................................................................................................................................
As discussed previously, EPA is
proposing new SO2 and/or NOX
emissions budgets for each covered
state. The budgets are based on the
EPA’s state-by-state analysis of each
upwind state’s significant contribution
to nonattainment and interference with
maintenance downwind, before
accounting for the inherent variability
in power system operations.
As discussed in detail in section IV,
the proposed approach to significant
contribution to nonattainment and
interference with maintenance would
group the 28 states covered for the 24hour and/or annual PM2.5 NAAQS in
two tiers reflecting the stringency of SO2
reductions required to eliminate that
state’s significant contribution to
nonattainment and interference with
maintenance. There would be a
stringent SO2 tier comprising 15 states
(‘‘group 1’’) and a moderate SO2 tier
comprising 13 states (‘‘group 2’’), with
uniform stringency within each tier.4
For these same 28 states, there would be
one annual NOX tier with uniform
stringency of NOX reductions across all
4 With regard to interstate trading, the two SO
2
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.
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28 states. Similarly, for the 26 states
covered for the ozone NAAQS there
would be one ozone season NOX tier
with uniform stringency across all 26
states.
The proposed stringent SO2 tier
(‘‘group 1’’) would include Georgia,
Illinois, Indiana, Iowa, Kentucky,
Michigan, Missouri, New York, North
Carolina, Ohio, Pennsylvania,
Tennessee, Virginia, West Virginia, and
Wisconsin. The proposed moderate SO2
tier (‘‘group 2’’) would include Alabama,
Connecticut, Delaware, District of
Columbia, Florida, Kansas, Louisiana,
Maryland, Massachusetts, Minnesota,
Nebraska, New Jersey, and South
Carolina.
As discussed previously, EPA
proposes to require an initial phase of
reductions starting in 2012 (covering
2012 and 2013) requiring SO2 and NOX
reductions in the 28 states covered for
24-hour and/or annual PM2.5 NAAQS. A
second phase of reductions would be
due in 2014, covering 2014 and
thereafter. As described later, for certain
states the 2014 reduction requirements
would be more stringent, and for certain
states would remain at the same level as
the 2012 requirements.
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For the 15 states in the stringent SO2
tier (‘‘group 1’’), the 2014 phase would
substantially increase the SO2 reduction
requirements (i.e., these states would
have smaller SO2 emissions budgets
starting in 2014), reflecting the greater
reductions needed to eliminate the
portion of significant contribution and
interference with maintenance that EPA
has identified in this proposal from
these states with respect to the 24-hour
PM2.5 NAAQS. For the 13 states in the
moderate SO2 tier (‘‘group 2’’), the 2014
SO2 emissions budgets would remain
the same as the 2012 SO2 budgets for
these states.
The 2014 annual NOX emissions
budgets for all 28 states covered for the
24-hour and/or annual PM2.5 NAAQS
would remain the same as the 2012
annual NOX budgets.
With respect to the ozone NAAQS,
EPA is proposing a single phase of
reductions which begins in 2012. Thus,
the rule does not call for any adjustment
to be made to the 2012 ozone season
NOX budgets for the 26 states covered
for the ozone NAAQS. EPA intends to
issue a subsequent proposal that would,
among other things, address whether an
additional phase of NOX reductions is
necessary to address all significant
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contribution and interference with
maintenance with respect to the 1997
ozone NAAQS. While this proposal
assures downwind states that they will
receive relief from upwind reductions
that will help them achieve the NAAQS,
EPA is committed to fulfilling its
obligation to assure the downwind
states that they receive the full relief
they are entitled to under section
110(a)(2)(D). The Agency intends to
quickly address any remaining
significant contribution to
nonattainment and interference with
maintenance in a subsequent action that
will also address a new more stringent
ozone standard that is expected to be
established by EPA later in 2010.
Tables III.A–2 and III.A–3 show
projected Transport Rule emissions
reductions for EGUs in all states that
EPA proposes to cover.
TABLE III.A–2—PROJECTED SO2 AND NOX EGU EMISSIONS IN COVERED STATES WITH THE TRANSPORT RULE 5
COMPARED TO BASE CASE 6 WITHOUT TRANSPORT RULE OR CAIR
[Million tons]
2012
Base case
emissions
SO2 ...........................................................
Annual NOX .............................................
Ozone Season NOX .................................
2012
Transport
rule
emissions
8.4
2.0
0.7
2012
Emissions
reductions
3.4
1.3
0.6
2014
Base case
emissions
5.0
0.7
0.1
7.2
2.0
0.7
2014
Transport
rule
emissions
2014
Emissions
reductions
2.6
1.3
0.6
4.6
0.7
0.1
TABLE III.A–3—PROJECTED SO2 AND NOX EGU EMISSIONS IN COVERED STATES WITH THE TRANSPORT RULE
COMPARED TO 2005 ACTUAL EMISSIONS
[Million tons]
2005
Actual
emissions
SO2 .......................................................................................
Annual NOX .........................................................................
Ozone Season NOX .............................................................
In addition to the emissions
reductions shown previously, EPA
projects other substantial benefits, as
described in section IX in this preamble.
Air quality modeling was used to
quantify the improvements in PM2.5 and
ozone concentrations that are expected
to result from the emissions reductions
in 2014. The results of this modeling
were used to calculate the average
2012
Transport
rule
emissions
8.9
2.7
0.9
2012
Emissions
reductions
from 2005
3.4
1.3
0.6
reduction in annual average PM2.5, 24hour average PM2.5, and 8-hour ozone
concentrations for monitoring sites in
the eastern U.S. that are projected to be
nonattainment in the 2014 base case.
For annual PM2.5 and 24-hour PM2.5, the
average reductions are 2.4 micrograms
per cubic meter (μg/m3) and 4.3 μg/m3,
respectively. The average reduction in
8-hour ozone at monitoring sites
5.5
1.4
0.3
2014
Transport
rule
emissions
2014
Emissions
reductions
from 2005
2.6
1.3
0.6
6.3
1.4
0.3
projected to be nonattainment in the
2014 base case is 0.3 parts per billion
(ppb). The reductions in annual PM2.5,
24-hour PM2.5, and ozone
concentrations for individual
nonattainment and/or maintenance sites
are provided in section IX.
Table III.A–4 compares projected EGU
emissions with the Transport Rule to
projected EGU emissions with CAIR.
TABLE III.A–4—SIMPLE COMPARISON OF SO2 AND NOX EMISSIONS FROM ELECTRIC GENERATING UNITS IN STATES IN
THE CAIR OR TRANSPORT RULE REGIONS * FOR EACH RULE
2005
2012
Actual
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SO2 (Million Tons) ................................................................
NOX (Million Tons) .............. Annual ................................
Ozone Season ...................
Transport rule
9.5
2.9
1.0
2014
CAIR **
4.1
1.6
0.7
Transport rule
5.1
1.7
0.8
3.3
1.6
0.7
CAIR **
4.6
1.7
0.8
* Emissions totals include states covered by either the Transport Rule or CAIR. For PM2.5 (SO2 and annual NOX), the following 30 states are
included: AL, CT, DE, DC, FL, GA, IL, IN, IA, KS, KY, LA, MD, MA, MI, MN, MS, MO, NE, NJ, NY, NC, OH, PA, SC, TN, TX, VA, WV, WI. For
ozone (ozone-season NOX), the following 30 states are included: AL, AR, CT, DE, DC, FL, GA, IL, IN, IA, KS, KY, LA, MD, MA, MI, MS, MO,
NJ, NY, NC, OH, OK, PA, SC, TN, TX, VA, WV, WI.
** CAIR SO2 totals are interpolations from emissions analysis originally done for 2010 and 2015. CAIR NOX totals are as originally projected
for 2010. This CAIR modeling represents a scenario that differed somewhat from the final CAIR (the modeling did not include a regionwide
ozone season NOX cap and included PM2.5 requirements for the state of Arkansas).
5 Projected Transport Rule emissions result from
individual stae budgets in the proposed approach
and include some banking of allowances in 2012
adn use of that bank in 2014.
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6 EPA’s base case EGU emissions modeling does
not assume enforceable SO2 or NOX reductions
attributed to the Transport Rule or CAIR. In this
base case, a unit with existing SO2 or NOX control
equipment, but without an enforceable federal or
state control requirement, is allowed to choose its
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most economic approach to operation within
existing Acid Rain Program requirements and may
opt not to operate a control. See section IV.C.1 and
the IPM Documentation for further information on
the base case modeling.
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In addition to discussion of EPA’s
proposed regulatory approach
(discussed in sections IV and V), this
preamble also covers the stakeholder
outreach EPA conducted (section VI),
SIP submissions (section VII),
permitting (section VIII), projected
benefits of the proposed rule (section
IX), economic impacts (section X), enduse energy efficiency (section XI), and
statutory and executive order reviews
(section XII).
Table III.A–5 shows the results of the
cost and benefits analysis for the
proposed and alternate remedies.
Further discussion of these results is
contained in preamble section XII-A and
in the Regulatory Impacts Analysis. A
listing of health and welfare effects is
provided in RIA Table 1–6. Estimates
here are subject to uncertainties
discussed further in the body of the
document. The social costs are the loss
of household utility as measured in
Hicksian equivalent variation. The
capital costs spent for pollution controls
installed for CAIR were not included in
the annual social costs since the
Transport Rule did not lead to their
installation. Those CAIR-related capital
investments are roughly estimated to
have an annual social cost less than
$1.15 to $ 1.29 billion (under the two
discount rates.)
Most of the estimated PM-related
benefits in this rule accrue to
populations exposed to higher levels of
PM2.5. Of these estimated PM-related
mortalities avoided, about 80 percent
occur among populations initially
exposed to annual mean PM2.5 level of
10 μg/m3 and about 97 percent occur
among those initially exposed to annual
mean PM2.5 level of 7.5 μg/m3. These are
the lowest air quality levels considered
in the Laden et al. (2006) and Pope et
al. (2002) studies, respectively. This fact
is important, because as we estimate
PM-related mortality among populations
exposed to levels of PM2.5 that are
successively lower, our confidence in
the results diminishes. However, our
analysis shows that the great majority of
the impacts occur at higher exposures.
TABLE III.A–5—SUMMARY OF ANNUAL BENEFITS, COSTS, AND NET BENEFITS OF VERSIONS OF THE PROPOSED REMEDY
OPTION IN 2014 a
[Billions of 2006$]
Preferred remedy—State budgets/
limited trading
Description
Social costs:
3% discount rate ..............................
7% discount rate ..............................
Health-related benefits: b, c
3% discount rate ..............................
7% discount rate ..............................
Net benefits (benefits-costs):
3% discount rate ..............................
7% discount rate ..............................
Direct control
$2.03 .....................................................
$2.23 .....................................................
$2.68 .....................................................
$2.91 .....................................................
$2.49.
$2.70.
$118 to $288 + B ..................................
$108 to $260 + B ..................................
$117 to $286 + B ..................................
$108 to $262 + B ..................................
$113 to $276 + B.
$104 to $252 + B.
$116 to $286 .........................................
$105 to $258 .........................................
$115 to $283 .........................................
$105 to $259 .........................................
$110 to $273.
$101 to $249.
Intrastate trading
Notes: (a) All estimates are rounded to three significant digits and represent annualized benefits and costs anticipated for the year 2014. For
notational purposes, unquantified benefits are indicated with a ‘‘B’’ to represent the sum of additional monetary benefits and disbenefits. Data limitations prevented us from quantifying these endpoints, and as such, these benefits are inherently more uncertain than those benefits that we
were able to quantify. (b) The reduction in premature mortalities account for over 90 percent of total monetized benefits. Benefit estimates are
national. Valuation assumes discounting over the SAB-recommended 20-year segmented lag structure described in Chapter 5. Results reflect 3
percent and 7 percent discount rates consistent with EPA and OMB guidelines for preparing economic analyses (U.S. EPA, 2000; OMB, 2003).
The estimate of social benefits also includes CO2-related benefits calculated using the social cost of carbon, discussed further in Chapter 5. Benefits are shown as a range from Pope et al. (2002) to Laden et al. (2006). Monetized benefits do not include unquantified benefits, such as other
health effects, reduced sulfur deposition or visibility. These models assume that all fine particles, 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. (c) Not all possible benefits or disbenefits are quantified and monetized in this analysis. B is the sum of all
unquantified benefits and disbenefits. Potential benefit categories that have not been quantified and monetized are listed in RIA Table 1–4.
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B. Background
1. What is the source of EPA’s authority
for this action?
The statutory authority for this action
is provided by the CAA, as amended (42
U.S.C. 7401 et seq.). Relevant portions
of the CAA include, but are not
necessarily limited to, sections
110(a)(2)(D), 110(c)(1), and 301(a)(1).
Section 110(a)(2)(D) of the CAA, often
referred to as the ‘‘good neighbor’’
provision of the Act, 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:
(D) Contain adequate provisions—
(i) Prohibiting, consistent with the
provisions of this subchapter, any
source or other type of emissions
activity within the State from emitting
any air pollutant in amounts which
will—
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(I) Contribute significantly to
nonattainment in, or interfere with
maintenance by, any other State with
respect to any such national primary or
secondary ambient air quality standard,
or
(II) Interfere with measures required
to be included in the applicable
implementation plan for any other State
under part C of this subchapter to
prevent significant deterioration of air
quality or to protect visibility.
(ii) Insuring compliance with the
applicable requirements of sections
7426 and 7415 of this title (relating to
interstate and international pollution
abatement). 42 U.S.C. 7410(a)(2)(D).
This proposal addresses the
requirement in section 110(a)(2)(D)(i)(I)
regarding the prohibition of emissions
within a state that significantly
contribute to nonattainment or interfere
with maintenance of the NAAQS in any
other state. As discussed in greater
detail later, EPA has previously issued
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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 v. EPA, 213
F.3d 663 (DC Cir. 2000). The CAIR,
promulgated in 2005, was remanded by
the DC Circuit in North Carolina v. EPA,
531 F.3d 896 (DC Cir. 2008), modified
on reh’g, 550 F.3d. 1176 (DC Cir. 2008).
These decisions provide additional
guidance regarding the requirements of
section 110(a)(2)(D)(i)(I) and are
discussed later in this section.
Section 301(a)(1) of the CAA gives the
Administrator of EPA general authority
to ‘‘prescribe such regulations as are
necessary to carry out [her] functions
under this chapter.’’ 42 U.S.C.
7601(a)(1). Pursuant to this section, EPA
has authority to clarify the applicability
of CAA requirements. In this action,
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Federal Register / Vol. 75, No. 147 / Monday, August 2, 2010 / Proposed Rules
EPA is clarifying the applicability of
section 110(a)(2)(D)(i)(I) by proposing to
identify SO2 and NOX emissions that
each affected state must prohibit
pursuant to that section with respect to
the PM2.5 NAAQS promulgated in 1997
and 2006 and the 8-hour ozone NAAQS
promulgated in 1997. The
improvements in air quality that would
result from the reductions in upwind
state emissions that EPA is proposing to
require would assist downwind states
affected by transported pollution in
developing, pursuant to section 110 of
the CAA, their SIPs to provide for
expeditious attainment and
maintenance of the NAAQS.
Section 110(a) of the CAA assigns to
each state both the primary
responsibility for attaining and
maintaining the NAAQS within such
state, 42 U.S.C. 7410(a)(1), and the
primary responsibility for prohibiting
emissions activity within the state
which will significantly contribute to
nonattainment or interfere with
maintenance in a downwind area. 42
U.S.C. 7410(a)(2)(D)(i)(I). States fulfill
these CAA obligations through the SIP
process described in section 110(a) of
the Act.
Section 110(c)(1) of the Act, however,
requires EPA to act when a state has not
been able to or has not fulfilled its
obligation to submit a SIP that meets the
requirements of the Act. Specifically,
section 110(c)(1) provides that: The
Administrator shall promulgate a
Federal implementation plan at any
time within 2 years after the
Administrator—
(A) Finds that a State has failed to
make a required submission or finds
that the plan or plan revision submitted
by the State does not satisfy the
minimum criteria established under
subsection (k)(1)(A) of this section, or
(B) Disapproves a State
implementation plan submission in
whole or part, unless the State corrects
the deficiency, and the Administrator
approves the plan or plan revision,
before the Administrator promulgates
such Federal implementation plan.
42 U.S.C. 7410(c)(1). Section
110(k)(1)(A), in turn, calls for the
Administrator to establish criteria for
determining whether SIP submissions
are complete. 42 U.S.C. 7410(k)(1)(A).
As discussed in greater detail in
section VII, for all states covered by the
FIPs proposed in this action, EPA either
has taken, has proposed to take, or
believes it may need to take one of the
following actions with respect to the
1997 ozone NAAQS, the 1997 PM2.5
NAAQS and/or the 2006 PM2.5 NAAQS:
(1) Find that the state has failed to make
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site at https://www.epa.gov/acidrain/
effects/. Finally, particle
pollution can stain and damage 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 average and 24hour standards for fine particles, using
PM2.5 as the indicator (62 FR 38652).
These revisions established an annual
standard of 15 μg/m3 and a 24-hour
standard of 65 μg/m3. During 2006, EPA
revised the air quality standards for
PM2.5. The 2006 standards decreased the
2. What air quality problems does this
level of the 24-hour fine particle
proposal address?
standard from 65 μg/m3 to 35 μg/m3,
and retained the annual fine particle
a. Fine Particles
standard at 15 μg/m3.
Fine particles are associated with a
In the preamble to the final rule for
number of serious health effects
CAIR in May 2005, EPA discussed
including premature mortality,
ambient monitoring for 2001–2003, the
aggravation of respiratory and
most recent 3-year period available at
cardiovascular disease (as indicated by
the time. These results showed
increased hospital admissions,
widespread exceedances of the 15 μg/m3
emergency room visits, health-related
annual PM2.5 standard in the eastern
absences from school or work, and
United States, with additional
restricted activity days), lung disease,
exceedances in parts of California and
decreased lung function, asthma attacks, one county in Montana. At that time, 82
and certain cardiovascular problems.
counties in the U.S. had at least one
See EPA, Air Quality Criteria for
monitor that violated the 1997 annual
Particulate Matter (EPA/600/P–99/
PM2.5 standard.
002bF, October 2004) at 9.2.2.3. See also
The PM2.5 ambient air quality
integrated science assessment for the
monitoring for the 2006–2008 period
PM NAAQS review, December 2009,
(most recent available) shows significant
https://cfpub.epa.gov/ncea/cfm/
improvements. Nonetheless, areas
recordisplay.cfm?deid=216546.
which continue to violate the 15 μg/m3
Individuals particularly sensitive to fine annual PM2.5 standard are located across
particle exposure include older adults,
a significant portion of the eastern half
people with heart and lung disease, and of the United States, in parts of
children. This rule, and the NAAQS to
California and one county in Arizona.
which it is related, consider the effects
Based on these nationwide data, 23
of fine particles on vulnerable
counties have at least one monitor that
populations (see further discussion in
violates the annual PM2.5 standard.
section XII.G and section XII.J of this
The PM2.5 ambient air quality
notice). More detailed information on
monitoring for this same 2006–2008
health effects of fine particles can be
time period shows that areas violating
found on EPA’s Web site at: https://
the 2006 24-hour PM2.5 standard of 35
epa.gov/pm/standards.html.
μg/m3 (i.e., the revised 2006 standard
In addition to effects on public health, for 24-hour PM2.5) are located across
fine particles are linked to a number of
much of the eastern half of the United
public welfare effects. First, PM2.5 are
States, in parts of California, and in
the major cause of reduced visibility
some counties in several other western
(haze) in parts of the United States,
states—Alaska, Washington, Oregon,
including many of our national parks
Utah, and Arizona. Based on these
and wilderness areas. For more
nationwide data, 52 counties have at
information about visibility, visit EPA’s least one monitor that violates the 24Web site at https://www.epagov/visibility. hour PM2.5 standard.
Second, particles can be carried over
EPA believes that a great deal of the
long distances by wind and then settle
improvement in PM2.5 annual and 24on ground or water. The effects of this
hour concentrations in the eastern U.S.
settling include: Making lakes and
can be attributed to EGU SO2 reductions
streams acidic; changing the nutrient
achieved due to the CAIR. While the
balance in coastal waters and large river CAIR requirements related to SO2 did
basins; depleting the nutrients in soil;
not begin until 2010, many actions were
damaging sensitive forests and farm
taken by EGU owners and operators in
crops; and affecting the diversity of
anticipation of those requirements.
ecosystems. More information about
Emissions of SO2 from EGUs covered by
these effects is available at EPA’s Web
the CAIR that were also in the acid rain
a SIP submission required by section
110(a)(2)(D)(i)(I) or section 110(k)(5) of
the Act; (2) find that such a SIP
submission is incomplete; or (3)
disapprove such a SIP submission. Once
EPA has taken one of the these actions,
pursuant to section 110(c)(1), it has
authority to promulgate a FIP directly
implementing the requirements of
section 110(a)(2)(D)(i)(I), provided the
state has not submitted and EPA has not
approved a SIP submission that corrects
the SIP deficiency prior to promulgation
of the FIP.
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program (under CAA Title IV) tracking
system decreased from 10.2 million tons
in 2005 to 7.6 million tons in 2008.
Almost all of these emissions reductions
were achieved in the areas of the eastern
United States covered by the CAIR. See
https://www.epa.gov/airmarkt/progress/
ARP_4.html. EPA believes that there
would be substantially more
nonattainment counties for both the
annual and 24-hour standards if the
CAIR were not in effect.
As required by the CAA, and in
response to litigation over the 2006
standards, EPA is currently conducting
a review of the 2006 PM2.5 standards.
Information and documents related to
this review are available at: https://
epa.gov/ttn/naaqs/standards/pm/
s_pm_index.html. EPA expects to
complete this review and to publish any
revised standards that may result from
the review by October 2011. EPA is
planning to propose the revised
standards by February 2011.
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 recent
epidemiological evidence indicating
that there is a correlation between shortterm ozone exposure and premature
mortality.
People who are particularly
susceptible to the effects of ozone
include people with respiratory
diseases, such as asthma. Those who are
exposed to higher levels of ozone
include adults and children who are
active outdoors. This rule, and the
NAAQS which it is related to, consider
the effects of ozone on vulnerable
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populations (see further discussion in
section XII.G and section XII.J of this
notice).
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. More detailed
information on effects of ozone can be
found at the following EPA Web site:
https://www.epa.gov/ttn/naaqs/
standards/ozone/s_o3_index.html.
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.
At the time EPA published the CAIR
and the CAIR FIP rulemakings, wide
geographic areas, including most of the
nation’s major population centers,
experienced ozone levels that violated
the 1997 NAAQS of 8-hour ozone 0.08
ppm (effectively 0.084 ppm as a result
of rounding). These areas included
much of the eastern part of the United
States and large areas of California. The
EPA published the 8-hour ozone
attainment and nonattainment
designations in the Federal Register on
April 30, 2004 (69 FR 23858). These
designations, based on ozone season
monitoring data for the 2001–2003 time
period, resulted in 112 areas designated
as nonattainment. As of December 2009,
significant emissions reductions have
allowed 58 of the original 112
nonattainment areas to be re-designated
to attainment. In addition, a number of
areas still designated as nonattainment
ozone monitoring data for 2006–2008
(most recent data available) show levels
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below the standard. EPA believes a
number of factors contributed to NOX
emissions reductions subsequent to the
2001–2003 time period. First, EGU
emissions were substantially reduced as
EGUs in the eastern U.S. came into
compliance with the NOX SIP Call. A
series of progress reports discussing the
effect of the NOX SIP Call reductions
can be found on EPA’s Web site at:
https://www.epa.gov/airmarkets/
progress/progress-reports.html.
Additional information on emissions
and air quality trends are available in
EPA’s 2007 and 2008 air quality trends
reports, which are available at: https://
www.epa.gov/airtrends/.
Second, mobile source emissions
standards for onroad gasoline and
vehicle emissions standards began to
reduce mobile source emissions as the
fleet began turning over vehicles to meet
tightened NOX emissions standards.
Continued improvement in ozone is
expected with continued reductions in
mobile source emissions.
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 will issue final
standards soon. Information on the 2008
revisions to the ozone standard, and on
all subsequent activity based on the
reconsideration, is available at: https://
www.epa.gov/air/ozonepollution/
actions.html#sep09s.
3. Which NAAQS does this proposal
address?
This proposed action addresses the
requirements of CAA section
110(a)(2)(D)(i)(I) as they relate to:
(1) The 1997 annual PM2.5 standards,
(2) The 2006 daily PM2.5 standards,
and
(3) The 1997 ozone standards
The original CAIR and CAIR FIP
rules, which pre-dated the 2006
standards, addressed the 1997 ozone
and PM2.5 standards only. The 1997 8hour ozone standard is 0.08 ppm. The
1997 PM2.5 standards promulgated in
1997 established a 15 μg/3 standard for
24-hour PM2.5 and a 65 μg/m3 standard
for annual PM2.5. In 2006, the 24-hour
PM2.5 standard was lowered to 35 μg/m3
and the 15 μg/m3 annual PM2.5 standard
was left unchanged.
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For this proposal, EPA fully addresses
the requirements of CAA section
110(a)(2)(D)(i)(I) for the annual PM2.5
standard of 15 μg/m3. For the 24-hour
standard of 35 μg/m3 and 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, but for the remaining states EPA
will address whether further
requirements are needed.
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.
4. EPA Transport Rulemaking History
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a. CAA Provisions
For almost 40 years, Congress has
focused major efforts on curbing
ground-level ozone. In 1970, Congress
amended the CAA to require, in Title I,
that EPA issue and periodically review
and, if necessary, revise NAAQS for
ubiquitous air pollutants (sections 108
and 109). Congress required the states to
submit SIPs to attain and maintain those
NAAQS, and Congress included, in
section 110, a list of minimum
requirements that SIPs must meet.
Congress anticipated that areas would
attain the NAAQS by 1975.
In 1977, Congress amended the CAA
by providing, among other things,
additional time for areas that were not
attaining the ozone NAAQS to do so, as
well as by imposing specific SIP
requirements for those nonattainment
areas. These provisions first required
the designation of areas as attainment,
nonattainment, or unclassifiable, under
section 107; and then required that SIPs
for ozone nonattainment areas include
the additional provisions set out in part
D of Title I, as well as demonstrations
of attainment of the ozone NAAQS by
either 1982 or 1987 (section 172).
In addition, the 1977 Amendments
included two provisions focused on
interstate transport of air pollutants: the
predecessor to current section
110(a)(2)(D), which requires SIPs for all
areas to constrain emissions with
certain adverse downwind effects; and
section 126, which, in general,
authorizes a downwind state to petition
EPA to impose limits directly on
upwind sources found to adversely
affect that state. Section
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110(a)(2)(D)(i)(I), which is key to the
present action, is described in more
detail later.
In 1990, Congress amended the CAA
to better address, among other things,
continued nonattainment of the 1-hour
ozone NAAQS, the requirements that
would apply if EPA revised the 1-hour
standard, and transport of air pollutants
across state boundaries (Pub. L. 101–
549, Nov. 15, 1990, 104 Stat. 2399, 42
U.S.C. 7401–7671q).
As amended in 1990, the CAA further
requires EPA to designate areas as
attainment, nonattainment, and
unclassifiable under a revised NAAQS
(section 107(d)(1); section 6103, Pub. L.
105–178). The CAA authorizes EPA to
classify areas that are designated
nonattainment under the new NAAQS
and to establish for those areas
attainment dates that are as expeditious
as practicable, but not to exceed 10
years from the date of designation
(section 172(a)).
All areas are required to submit SIPs
within certain timeframes (section
110(a)(1)), and those SIPs must include
specified provisions, under section
110(a)(2). In addition, SIPs for
nonattainment areas are generally
required to include additional specified
control requirements, as well as controls
providing for attainment of any revised
NAAQS and periodic reductions
providing ‘‘reasonable further progress’’
in the interim (section 172(c)). If states
do not submit SIPs in a timely or
approvable manner, EPA has the
authority to make findings of failure to
submit or impose FIPs on specific
sources in the state that contribute to
downwind nonattainment and
interference with maintenance.
Significant contribution and
interference with maintenance are
discussed in detail in section IV later.
The 1990 Amendments reflect general
awareness by Congress that ozone is a
regional, and not merely a local,
problem. Ozone and its precursors may
be transported long distances across
state lines, thereby exacerbating ozone
problems downwind. Ozone transport is
recognized as a major reason for the
persistence of the ozone problem,
notwithstanding the imposition of
numerous controls, both Federal and
State, across the country.
The CAA further addresses interstate
transport of pollution in section 126,
which Congress revised slightly in 1990.
Subsection (b) of that provision
authorizes each state (or political
subdivision) to petition EPA for a
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45221
finding designed to protect that entity
from upwind sources of air pollutants.7
In addition, the 1990 Amendments
added section 184, which delineates a
multi-state ozone transport region (OTR)
in the Northeast, requires specific
additional controls for all areas (not
only nonattainment areas) in that
region, and establishes the Ozone
Transport Commission (OTC) for the
purpose of recommending to EPA
regionwide controls affecting all areas in
that region. At the same time, Congress
added section 176A, which authorized
the formation of transport regions for
other pollutants and in other parts of the
country.
In September 1994, the Northeast
OTC states signed a Memorandum of
Understanding (MOU) committing to
reduce NOX emissions throughout the
region. In 1999 through 2002, most of
the OTC states achieved substantial
NOX reductions through an ozone
season cap and trade program for NOX
called the OTC NOX Budget Program,
which EPA administered, and through
NOX emissions rate limits from certain
coal plants under Title IV.
Separate from activity in the OTC,
EPA and the Environmental Council of
the States (ECOS) formed the OTAG in
1995. This workgroup brought together
interested states and other stakeholders,
including industry and environmental
groups. Its primary objective was to
assess the ozone transport problem and
develop a strategy for reducing ozone
pollution throughout the eastern half of
the United States.
Notwithstanding significant efforts,
the states generally were not able to
meet the November 15, 1994 statutory
deadline for the attainment
demonstration and rate of progress
(ROP) SIP submissions required under
section 182(c). The major reason for this
failure was that at that time, states with
downwind nonattainment areas were
not able to address transport from
upwind areas. As a result, EPA
recognized that development of the
necessary technical information, as well
as the control measures necessary to
achieve the large level of reductions
likely to be required, had been
particularly difficult for the states
affected by ozone transport.
Accordingly, as an administrative
remedial matter, EPA established new
timeframes for the required SIP
submittals. To allow time for states to
incorporate the results of the OTAG
7 In addition, section 115 authorizes EPA to
require a SIP revision in certain circumstances
when one or more sources within a state ‘‘cause or
contribute to air pollution which may reasonably be
anticipated to endanger public health or welfare in
a foreign country.’’
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modeling into their local plans, EPA
extended the submittal date to April
1998.8 The OTAG’s air quality modeling
and recommendations formed the basis
for what became the NOX SIP Call
rulemaking and included the most
comprehensive analyses of ozone
transport ever conducted. The EPA
participated extensively in the OTAG
process that generated much useful
technical and modeling information on
regional ozone transport.
OTAG was established to address
transport issues associated with meeting
the 1-hour standard. The EPA did not
promulgate the 8-hour standard until
shortly after OTAG concluded; thus,
OTAG did not recommend strategies to
address the 8-hour NAAQS. However,
because EPA had proposed an 8-hour
standard, OTAG did examine the
impacts of different strategies on 8-hour
average ozone predictions. They found
that ozone transport caused problems
for downwind areas under either the 1hour or 8-hour standard.
EPA’s Transport SIP Call Regulatory
Efforts. Shortly after OTAG began its
work, EPA indicated that it intended to
issue a SIP call to require states to
implement the reductions necessary to
address the ozone transport problem.
On January 10, 1997 (62 FR 1420), EPA
published a notice of intent and
indicated that before taking final action,
EPA would carefully consider the
technical work and any
recommendations of OTAG. The EPA
published the NPR for the NOX SIP Call
by notice dated November 7, 1997 (62
FR 60319). The NPR proposed to make
a finding of significant contribution due
to transported NOX emissions to
nonattainment or maintenance problems
downwind and to assign NOX emissions
budgets for 23 jurisdictions. In light of
OTAG’s work and additional
information, EPA was able to assess
ozone transport as it relates to the 8hour NAAQS and to set forth
requirements as necessary to address the
8-hour standard in the rulemaking. The
regional reductions of NOX that would
have been achieved through this SIP call
for the 1-hour NAAQS were key
components for meeting the new 8-hour
ozone standard in a cost-effective
manner. Therefore, EPA believed that
the OTAG recommendations for how to
address ozone transport were valid for
both NAAQS.
The EPA published a supplemental
notice of proposed rulemaking (SNPR)
dated May 11, 1998 (63 FR 25902),
which proposed a model NOX budget
8 Guidance
for Implementing the 1-hour Ozone
and Pre-Existing PM10 NAAQS, Memorandum from
Richard D. Wilson, dated December 29, 1997.
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trading program and state reporting
requirements and provided the air
quality analyses of the proposed
statewide NOX emissions budgets.
Revision of the Ozone NAAQS. On
July 18, 1997 (62 FR 38856), EPA issued
its final action to revise the NAAQS for
ozone. The EPA’s decision to revise the
standard was based on the Agency’s
review of the available scientific
evidence linking exposures to ambient
ozone to adverse health and welfare
effects at levels allowed by the preexisting 1-hour ozone standards. The 1hour primary standard was replaced by
an 8-hour standard at a level of 0.08
ppm, with a form based on the 3-year
average of the annual fourth-highest
daily maximum 8-hour average ozone
concentration measured at each monitor
within an area. The new primary
standard provided increased protection
to the public, especially children and
other at-risk populations, against a wide
range of ozone-induced health effects.
The pre-existing 1-hour secondary
ozone standard was replaced by an 8hour standard identical to the new
primary standard. The new secondary
standard provided increased protection
to the public welfare against ozoneinduced effects on vegetation.
Section 126 Petitions. In a separate
rulemaking, EPA proposed action on
petitions submitted by 8 northeastern
states 9 under section 126 of the CAA.
Each petition specifically requested that
EPA make a finding that NOX emissions
from certain major stationary sources
significantly contributed to ozone
nonattainment problems in the
petitioning state. Both the NOX SIP Call
and the section 126 petitions were
designed to address ozone transport
through reductions in upwind NOX
emissions. However, the EPA’s response
to the section 126 petitions differed
from EPA’s action in the NOX SIP Call
rulemaking in several ways. In the NOX
SIP Call, EPA was determining that
certain states were or would be
significantly contributing to
nonattainment or maintenance problems
in downwind states. The EPA required
the upwind states to submit SIP
provisions to reduce the amounts of
each state’s NOX emissions that
significantly contributed to downwind
air quality problems. The states had the
discretion to select the mix of control
measures to achieve the necessary
reductions. By contrast, under section
126, if findings of significant
contribution were made for any sources
identified in the petitions, EPA would
8 states were Connecticut, Massachusetts,
Maine, New Hampshire, New York, Pennsylvania,
Rhode Island, and Vermont.
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have determined the necessary
emissions limits to address the amount
of significant contribution and would
have directly regulated the sources. A
section 126 remedy would have applied
only to sources in states named in the
petitions.
b. NOX SIP Call
Based on the findings of OTAG, EPA
proposed a rulemaking known as the
NOX SIP Call in 1997 and finalized it in
1998. (See ‘‘Finding of Significant
Contribution and Rulemaking for
Certain States in the Ozone Transport
Assessment Group Region for Purposes
of Reducing Regional Transport of
Ozone; Rule,’’ (63 FR 57356).) This rule
concluded that NOX emissions in 22
states and the District of Columbia
contribute to ozone nonattainment in
other states, and the rule required
affected states to amend their SIPs and
limit NOX emissions. EPA set an ozone
season NOX budget for each affected
state, essentially a cap on ozone season
(summertime) NOX emissions in the
state. Sources in the affected states were
given the option to participate in a
regional cap and trade program. The
first control period was scheduled for
the 2003 ozone season.
In response to litigation over EPA’s
final NOX SIP Call rule, the Court issued
two decisions concerning the NOX SIP
Call and its technical amendments.10
The Court decisions, discussed later,
generally upheld the NOX SIP Call and
technical amendments, including EPA’s
interpretation of the definition of
’’contribute significantly’’ under CAA
section 110(a)(2)(D). The litigation over
the NOX SIP Call coincided with the
litigation over the 8-hour NAAQS.
Because of the uncertainty caused by
the litigation on the 8-hour NAAQS,
EPA stayed the portion of the NOX SIP
Call based on the 8-hour NAAQS (65 FR
56245, September 18, 2000). Therefore,
for the most part, the Court did not
address NOX SIP Call requirements
under the 8-hour ozone NAAQS.
(1) What was the NOX SIP Call?
The NOX SIP Call was EPA’s principal
effort to reduce interstate transport of
precursors for both the 1-hour ozone
NAAQS and the 8-hour ozone NAAQS.
The EPA’s rulemaking was based on its
consideration of OTAG’s
recommendations, as well as
information resulting from EPA’s
additional work, and extensive public
input generated through notice-andcomment rulemaking. The EPA believed
10 See Michigan v. EPA, 213 F.3d 663 (DC Cir.
2000), cert. denied, 532 U.S. 904 (2001) (NOX SIP
call) and Appalachian Power v. EPA, 251 F.3d 1026
(DC Cir. 2001) (technical amendments).
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that requiring NOX emissions reductions
across the region in amounts achievable
by uniform controls was a reasonable,
cost-effective step to take to mitigate
ozone nonattainment in downwind
states for both the 1-hour and 8-hour
standards.
It was also EPA’s goal to ensure that
sufficient regional reductions were
achieved to mitigate ozone transport in
the eastern half of the United States and
thus, in conjunction with local controls,
enable nonattainment areas to attain and
maintain the ozone NAAQS.
This NOX SIP Call required those
jurisdictions that EPA determined
significantly contribute to 1-hour and
8-hour ozone nonattainment problems
in downwind states to revise their SIPs
to include NOX control measures to
mitigate the significant ozone transport
during summer months known as the
‘‘ozone season’’ (May–September). The
EPA determined emissions reductions
requirements for the covered states and
source categories (see section IV.A for a
description of the approach EPA used to
determine emissions reductions
requirements). The affected states were
required to submit SIPs providing the
specified amounts of emissions
reductions. By eliminating these
amounts of NOX emissions, the control
measures would assure that the
remaining NOX emissions would meet
the level identified in the rule as the
state’s NOX emissions budget and would
not ‘‘significantly contribute to
nonattainment, or interfere with
maintenance by,’’ a downwind state,
under section 110(a)(2)(D)(i)(I).
The SIP requirements permitted each
state to determine what measures to
adopt to prohibit the significant
amounts and hence meet the necessary
emissions budget. Consistent with
OTAG’s recommendations to achieve
decreased NOX emissions primarily
from large stationary sources in a
trading program, EPA encouraged states
to consider electric utility and large
boiler controls under a cap and trade
program as a cost-effective strategy. The
EPA also recognized that promotion of
energy efficiency could contribute to a
cost-effective strategy. See section V.D.1
for a discussion on the approach taken
to implement the emissions reductions
requirements in the NOX SIP Call.
(2) Legal Challenges to the NOX SIP Call
Several petitioners challenged the
NOX SIP Call in the United States Court
of Appeals for the District of Columbia
Circuit (DC Circuit). In Michigan v. EPA,
213 F.3d 663 (DC Cir., 2000), cert.
denied, 532 U.S. 904 (2001), the Court
upheld the rule in most respects. Of
greatest relevance here, the Court
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upheld the essential features of EPA’s
approach to identifying and eliminating
states’’ NOX emissions that significantly
contribute to downwind nonattainment.
It upheld key aspects of EPA’s air
quality modeling and its use of costeffectiveness criteria in defining states’’
‘‘significant contribution.’’ See id. at
673–79. In addition, it accepted EPA’s
use of a uniform control requirement
(i.e., requiring all covered jurisdictions,
regardless of amount of contribution, to
reduce NOX emissions by an amount
achievable with highly cost effective
controls). See id. at 679–80. The Court,
however, agreed with petitioners that
certain specific applications of EPA’s
approach were flawed. It thus vacated
the rule with respect to Wisconsin,
Missouri, and Georgia, and held that
EPA had failed to provide adequate
notice on two specific issues (a change
in the definition of EGU and a change
in control level assumed for specific
sources). See id. at 681–85, 692–94. The
Court also subsequently delayed the
implementation date to May 31, 2004.
Michigan v. EPA, 2000 WL 1341477 (DC
Cir. 2000).
The decision resolved only issues
involving the 1-hour ozone NAAQS and
did not resolve any issues involving the
8-hour NAAQS, which provided
another basis for the rule. See id. at 670–
71. EPA ultimately stayed the 8-hour
basis of the NOX SIP Call. See 65 FR
56245. In addition, in a subsequent case
that reviewed separate EPA rulemakings
making technical corrections to the NOX
SIP Call, the DC Circuit remanded the
case for a better explanation of EPA’s
methodology for computing the growth
component in the EGU heat input
calculation. See Appalachian Power Co.
v. EPA, 251 F.3d 1026 (DC Cir. 2001).
More recently, the Court also rejected a
challenge to a subsequent EPA rule
withdrawing EPA’s findings of
significant contribution for Georgia for
the 1-hour ozone standard. See North
Carolina v. EPA, 587 F.3d 422 (DC Cir.
2009).
(3) How the NOX Budget Trading
Program (NBP) Worked
The NBP was a market-based cap and
trade program created to reduce the
regional transport of emissions of NOX
from power plants and other large
combustion sources that contribute to
ozone nonattainment in the eastern
United States. Over six ozone seasons
(2003–2008), the NBP significantly
lowered NOX emissions from affected
sources, contributing to improvements
in regional air quality across the
Midwest, Northeast, and Mid-Atlantic.
The cap level was intended to protect
public health and the environment and
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45223
to sustain that protection into the future
regardless of growth in the affected
sector. Ozone season NOX emissions
decreased from levels in baseline years
in all states participating in the NBP.
(All NBP states transitioned to the CAIR
NOX ozone season program in 2009
except Rhode Island.) Allowance
trading was generally active from the
start of the program in 2003. Prices and
trading were down in 2008, primarily
due to uncertainty. Compliance
remained virtually 100 percent
throughout the program’s 6 years. Many
nonattainment areas in the East saw
substantial improvements in air quality
concentrations that brought them in line
with ozone NAAQS. The NBP, together
with other Federal, State, and local
programs, contributed to NOX
reductions that have led to
improvements in ozone and PM2.5,
saving 580–1,800 lives annually in
2008.11 Changes in ozone and nitrate
concentrations due to the NBP have also
contributed to improvements in
ecosystems in the East.
EPA stopped administering the NBP
at the conclusion of 2008 control period
activities. States still have the emissions
reductions requirement and could use
the CAIR NOX ozone season trading
program to achieve this.
See section V.D.4.e. for a discussion
of the results of the NOX Budget Trading
Program.
(4) Clean Air Interstate Rule
Following promulgation of the new
NAAQS in 1997, the CAA required all
states, regardless of whether they have
attainment air quality in all areas, to
submit SIPs containing provisions
specified under section 110(a)(2). In
addition, states are required to submit
SIPs for nonattainment areas which are
generally required to include additional
emissions controls providing for
attainment of the NAAQS.
As described previously, section
110(a)(2)(D)(i)(I) provides a tool for
addressing the problem of transported
pollution that significantly contributes
to downwind nonattainment and
maintenance problems. Under section
110(a)(2)(D), a SIP must contain
adequate provisions prohibiting sources
in the state from emitting air pollutants
in amounts that would contribute
significantly to nonattainment or
interfere with maintenance in one or
more downwind states. Section
110(k)(5) authorizes EPA to find that a
SIP is substantially inadequate to meet
any CAA requirement. If EPA makes
such a finding, it is to require the state
11 U.S.EPA. September, 2009. The NO Budget
X
Trading Program: 2008 Environmental Results, p.9.
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to submit, within a specified period, a
SIP revision to correct the inadequacy
(‘‘SIP call’’). In 1998, EPA used this
authority to issue the NOX SIP Call,
discussed previously, to require states to
revise their SIPs to include measures to
reduce NOX emissions that were
significantly contributing to ozone
nonattainment problems in downwind
states.
Sulfur dioxide and NOX are not the
only emissions that contribute to
interstate transport and PM2.5
nonattainment. However, EPA stated in
the CAIR that it believed that, given
current knowledge, it was not
appropriate to specify emissions
reductions requirements for direct PM2.5
emissions or organic precursors (e.g.,
volatile organic compounds (VOCs) or
ammonia (NH3)). Similarly, for 8-hour
ozone, EPA continued to rely on the
conclusion of the OTAG that analysis of
interstate transport control
opportunities should have focused on
NOX, rather than VOCs. 12
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(5) What is the CAIR?
The CAA contains a number of
requirements to address nonattainment
of the PM2.5 and the 8-hour ozone
NAAQS, including requirements that
states address interstate transport that
significantly contributes to such
nonattainment. 13 Based on air quality
modeling, ambient air quality data
analyses, and cost analyses, EPA found
that emissions in certain upwind states
resulted in amounts of transported
PM2.5, ozone, and their emissions
precursors that significantly contributed
to nonattainment in downwind states.
In the CAIR, promulgated on May 12,
2005 (70 FR 25162), EPA required SIP
revisions in 28 states and the District of
Columbia, within 18 months after
publication of the notice of final
rulemaking, to ensure that certain
emissions of SO2 and/or NOX—
important precursors of PM2.5 (NOX and
SO2) and ozone (NOX)—were
prohibited. Achieving the emissions
reductions identified, EPA concluded,
would address the states’ requirements
under section 110(a)(2)(D)(i)(I) of the
CAA and would help PM2.5 and ozone
nonattainment areas in the eastern half
of the United States attain the standards.
Moreover, EPA concluded that such
attainment would be achieved in a more
12 The OTAG was active from 1995–1997 and
consisted of representatives from the 37 states in
that region; the District of Columbia; EPA; and
interested members of the public, including
industry and environmental groups. See discussion
below under NOX SIP Call for further information
on OTAG.
13 The term ‘‘transport’’ includes the transport of
both PM2.5 and their precursor emissions and/or
transport of both ozone and its precursor emissions.
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certain, equitable, and cost-effective
manner than if each nonattainment area
attempted to implement local emissions
reductions alone, and would also assist
the covered states and their neighbors in
making progress toward their visibility
goals.
The CAIR built on EPA’s efforts in the
NOX SIP Call to address interstate
pollution transport for ozone, and was
EPA’s first attempt to address interstate
pollution transport for PM2.5. It required
significant reductions in emissions of
SO2 and NOX, which contribute to fine
particle concentrations. In addition,
NOX emissions contribute to ozone
problems. EGUs were found to be a
major source of the SO2 and NOX
emissions which contributed to fine
particle concentrations and ozone
problems downwind.
CAIR was designed to provide
significant air quality attainment,
health, and environmental
improvements across the eastern U.S. in
a highly cost-effective manner by
reducing SO2 and NOX emissions from
EGUs that contribute to the PM2.5 and
8-hour ozone problems described in the
rule. CAIR’s emissions reductions
requirements were based on controls
that EPA had determined to be highly
cost-effective for EGUs under optional
cap and trade programs. However, states
had the flexibility to choose the
measures to adopt to achieve the
specified emissions reductions. EPA
required the emissions reductions to be
implemented in two phases, with the
first phase in 2009 and 2010 (for NOX
and SO2, respectively), and the second
phase for both pollutants in 2015. These
requirements are described in more
detail in section V.D.1.
In addition to promulgating findings
of significant contribution to
nonattainment, EPA assigned emissions
reductions requirements for SO2 and/or
NOX that each of the identified states
must meet through SIP measures.
Section V.D.1 discusses the approach
taken in CAIR using three model multistate cap and trade programs for SO2
and NOX that EPA developed and that
states could choose to adopt to meet the
required emissions reductions in a
flexible and cost-effective way.
The requirements in the CAIR were
intended to address regional interstate
transport of air pollution. EPA
recognized, however, that additional
local reductions might be necessary to
bring some areas into attainment even
after significantly contributing upwind
emissions were eliminated. 70 FR
25165–66, May 12, 2005. In addition,
states that shared an interstate
nonattainment area were expected to
work together in developing the
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nonattainment SIP for that area,
reducing emissions that contributed to
local-scale interstate transport problems.
CAIR FIPs. When EPA promulgated
the final CAIR in May 2005, EPA also
issued a national finding that states had
failed to submit SIPs to address the
requirements of CAA section
110(a)(2)(D)(i) with respect to the 1997
ozone and PM2.5 NAAQS. States were to
have submitted 110(a)(2)(D)(i) SIPs for
those standards by July 2000. This
action triggered a 2-year clock for EPA
to issue FIPs to address interstate
transport. On March 15, 2006 the EPA
promulgated FIPs to ensure that the
emissions reductions required by the
CAIR are achieved on schedule. The
FIPs did not limit states’’ flexibility in
meeting their CAIR requirements as all
states remained free to submit SIPs at
any time that, if approved by EPA,
would replace the FIP for that state.
As the control strategy for the FIPs,
EPA adopted the model cap and trade
programs that it provided in the CAIR
as a control option for states, with minor
changes to account for federal, rather
than state, implementation. The FIPs
required power plants in affected states
to participate in one or more of three
separate emissions cap and trade
programs that cover: (1) Annual SO2
emissions, (2) annual NOX emissions,
and (3) ozone season NOX emissions.
Emission cap and trade programs are a
proven method for achieving highly
cost-effective emissions reductions
while providing regulated sources with
flexibility in choosing compliance
strategies.
The FIPs also provided states with an
option to submit abbreviated SIPs to
meet CAIR. Under this option, states
could save the time and resources
needed to develop the complete trading
program SIP, while still being able to
make key decisions, such as the
methodology for allocating annual and/
or ozone season NOX allowances.
New Jersey and Delaware. Separately,
on March 15, 2006, EPA issued a final
rule to include Delaware and New
Jersey in the CAIR to control SO2 and
NOX emissions because they contribute
to PM2.5 nonattainment in other states.
71 FR 25288, April 28, 2006. These
states were already included in the
CAIR because their sources contributed
to nonattainment of other states’ 8-hour
ozone air quality standard. The CAIR
FIP established requirements for
Delaware and New Jersey with respect
to both ambient air quality standards.
(6) Legal Challenges to the CAIR
Petitions for review challenging
various aspects of the CAIR were filed
in the U.S. Court of Appeals for the DC
Circuit. In North Carolina v. EPA, 531
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F.3d 896, modified on reh’g 550 F.3d
1176 (D.C. Cir. 2008), the Court granted
several of the petitions for review and
remanded the rule to EPA for further
proceedings. In its July 2008 opinion,
North Carolina, 531 F.3d 896, the Court
upheld several challenged aspects of
EPA’s approach, but also found fatal
flaws in the rule—flaws it found
significant enough to warrant vacatur of
the CAIR and the associated FIPs in
their entirety. In December 2008,
however, the Court responded to
petitions for rehearing and determined
that ‘‘notwithstanding the relative flaws
of CAIR, allowing the 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.
Accordingly, it decided to remand the
rule without vacatur ‘‘so that EPA may
remedy CAIR’s flaws in accordance with
[the Court’s] July 11, 2008 opinion in
this case.’’ Id.
Although the entire rule was
remanded, important parts of EPA’s
rulemaking were upheld by the Court in
its July 2008 ruling. The Court upheld
key aspects of the air quality modeling
portion of EPA’s significant contribution
analysis. It upheld EPA’s decision to
consider upwind states for inclusion in
the CAIR only if those states contributed
to projected nonattainment in 2010. See
North Carolina, 531 F.3d at 913–914.
The Court further upheld the
contribution threshold used in the air
quality modeling portion of the
significant contribution analysis for
PM2.5, EPA’s use of whole states as the
unit of measurement, and the first-phase
NOX compliance deadline of 2009 See
id. at 914–17, 923–27, 928–29.
The Court also found significant flaws
in EPA’s approach. The Court
emphasized the importance of
individual state contributions to
downwind nonattainment areas and
held that EPA had failed to adequately
measure significant contribution from
sources within an individual state to
downwind nonattainment areas in other
states. Id. at 907. Further, the Court
noted that EPA had not provided
adequate assurance that the trading
programs established in the CAIR would
achieve, or even make measurable
progress towards achieving, the section
110(a)(2)(D)(i)(I) mandate to eliminate
significant contribution. See North
Carolina, 532 F.3d at 907–08. For these
reasons, it concluded that EPA had not
shown that the CAIR rule would achieve
measurable progress towards satisfying
the statutory mandate of section
110(a)(2)(D)(i)(I) and thus EPA lacked
authority for its action. See id. at 908.
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Moreover, it emphasized that where the
rule constitutes a complete
110(a)(2)(D)(i)(I) remedy, it must
actually require the elimination of
emissions that contribute significantly
to nonattainment or interfere with
maintenance downwind. See id.
The Court further rejected the state
budgets for SO2 and NOX which were
used to implement the CAIR trading
programs, finding the budgets to be
insufficiently related to the
110(a)(2)(D)(i)(I) mandate of eliminating
significant contribution and interference
with maintenance. See id. at 916–21. It
also rejected EPA’s effort to harmonize
the CAIR SO2 trading program with the
existing requirements of Title IV of the
CAA, holding that section
110(a)(2)(D)(i)(I) did not give EPA
authority to terminate or limit Title IV
allowances. In addition, the Court found
that EPA had failed to give meaning to
the ‘‘interfere with maintenance’’ prong
of section 110(a)(2)(D)(i)(I), that EPA
had not demonstrated that the 2015
compliance deadline used in the CAIR
was coordinated with the downwind
state’s deadlines for attaining the
NAAQS, and that EPA had not
adequately supported its determination
that sources in Minnesota significantly
contributed to nonattainment or
interfered with maintenance in
downwind states. See id. at 908–11,
911–13, and 926–28.
(7) How the Clean Air Interstate Rule
Worked
Building on the emissions reductions
under the NBP and Acid Rain Program
(ARP), CAIR was designed to
permanently lower emissions of SO2
and NOX in the eastern United States.
As explained previously, although the
DC Circuit remanded the rule to EPA, it
did so without vacatur allowing the rule
to remain in effect while EPA addresses
the remand. Thus, CAIR is continuing to
help states address ozone and PM2.5
nonattainment and improve visibility,
reducing transported precursors of SO2
and NOX, through the implementation
of three separate cap and trade
compliance programs for annual NOX,
ozone season NOX, and annual SO2
emissions from power plants.
See section V.D.4.e. for a discussion
on CAIR implementation in 2009, the
first year of the NOX annual and ozone
season programs. The CAIR annual SO2
program began January 1, 2010.
Quarterly emissions will be posted on
EPA’s web site (see https://
camddataandmaps.epa.gov/gdm/) and
an assessment of emissions reduction
data will be available at the end of each
compliance period.
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C. What are the goals of this proposed
rule?
In developing this proposed rule, EPA
was guided by a number of goals and
guiding principles, as discussed in this
section of the preamble.
1. Primary Goals
a. Respond to the Court Remand of the
CAIR
Most importantly, this proposal
responds to the remand of the CAIR by
the Court. As noted previously, the
Court granted several petitions for
review of the CAIR, finding fatal flaws
with the rule; yet, it ultimately decided
to remand the rule without vacatur to
preserve the environmental benefits of
the rule. North Carolina v. EPA, 531
F.3d 896, modified on reh’g, 550 F.3d
1176 (DC Cir. 2008).
The action EPA is proposing would
respond to the July and December 2008
opinions of the DC Circuit and correct
the flaws in the CAIR methodology that
were identified by the Court. The action
responds to the Court’s concerns in
numerous ways. The methodology used
to measure each state’s significant
contribution emphasizes air quality
considerations and uses state specific
data and information. The methodology
also gives independent meaning to the
interfere with maintenance prong of
section 110(a)(2)(D)(i)(I). The state
budgets for SO2, annual NOX and ozone
season NOX are directly linked to the
measurement of each state’s significant
contribution and interference with
maintenance. The compliance deadlines
are coordinated with the attainment
deadlines for the relevant NAAQS. And
the proposed remedy includes
assurance provisions to assure that all
necessary reductions occur in each
individual state.
The action would also propose FIPs
which would replace the remanded
CAIR FIPs. The proposed FIPs would
apply to all states covered by the rule,
including those for which EPA had
previously approved SIPs under the
remanded CAIR. If finalized as
proposed, these FIPs would eliminate
or, at a minimum, make measurable
progress towards eliminating emissions
of SO2 and NOX that significantly
contribute to or interfere with
maintenance of the 1997 and 2006 PM2.5
NAAQS and the 1997 ozone NAAQS in
the eastern half of the United States.
b. Address Transport Requirements
With Respect to the Existing PM2.5
Standards
This proposed rule is designed to
address the requirements of section
110(a)(2)(D)(i)(I) of the CAA as they
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relate to the 1997 and 2006 PM2.5
standards for states in the eastern
United States. The proposed rule would
both identify the emissions from states
in the eastern U.S. that significantly
contribute to nonattainment and
interfere with maintenance of the
NAAQS in downwind states, and
prohibit such emissions.
States are obligated to submit SIPs to
EPA addressing the provisions of
section 110(a)(2), including the
transport provisions of section
110(a)(2)(D)(i)(I), within 3 years of the
promulgation of a new or revised
NAAQS. For the 1997 NAAQS, these
SIPs were due in 2000. On April 25,
2005 (effective May 25, 2005) EPA
issued findings that states had failed to
submit SIPs to satisfy the requirements
of section 110(a)(2)(D)(i) of the Act
under the 1997 ozone and PM2.5
standards. 70 FR 21147, April 25, 2005.
These findings started a 2-year clock for
the promulgation of a FIP by EPA
unless, prior to that time, each state
makes a submission to meet the
requirements of 110(a)(2)(D)(i) and EPA
approves the submission. This 2-year
period expired in May 2007. Because
the Court found CAIR inadequate to
satisfy the requirements of
110(a)(2)(D)(i)(I), neither EPA’s FIP
implementing the requirements of CAIR
nor any states SIPs that relied on CAIR
to satisfy the requirements of this
section, are adequate to meet the
requirements of section
110(a)(2)(D)(i)(I). EPA’s obligation to
issue a FIP has therefore not yet been
met. The requirements of the FIPs
proposed in this rule are designed to
address this obligation.
Revisions to the 1997 PM2.5 standards
were signed by the Administrator on
September 21, 2006, and published in
the Federal Register on October 17,
2006. 71 FR 61144. The revisions were
effective December 18, 2006. EPA
interprets the 3 year deadline for
submission of 110(a)(2) SIPs to be 3
years from the date of signature.
Accordingly, for the 2006 revisions to
the PM2.5 NAAQS, the SIPs under
110(a)(2) were due on September 21,
2009. On June 9, 2010, EPA issued a
notice making findings that states had
not submitted SIPs under the 2006 PM2.5
NAAQS by the September 2009
deadline. 75 FR 32673. These findings
started a 2-year clock for the
promulgation of a FIP by EPA unless,
prior to that time, each state makes a
submission to meet the requirements of
110(a)(2)(D)(i)(I) and EPA approves the
submission. This 2-year period will
expire on July 9, 2012. This proposal is
designed to provide FIPs for the 2006
standards to ensure that the
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110(a)(2)(D)(i)(I) obligation is fully
satisfied as it relates to those standards.
EPA also notes that under FIPs,
reduction requirements are immediately
effective and thus FIPs provide for the
most expeditious means to implement
emissions reduction requirements.
c. Address Transport Requirements
With Respect to the 1997 Ozone
Standards
This proposed rule, in concert with
other actions, largely eliminates upwind
state emissions that contribute
significantly to nonattainment in, or
interfere with maintenance by, any
other state with respect to the 1997 8hour ozone NAAQS. EPA will issue a
subsequent proposal for the 1997 8-hour
ozone NAAQS to address fully the
requirements of CAA Section
110(a)(2)(D)(i)(I). EPA’s goal is to fully
address transport requirements for the
1997 ozone standards as soon as
possible.
d. Provide for a Smooth Transition From
Existing Programs
In addressing the Court remand in a
way that satisfies the CAA transport
requirements, EPA is also mindful of the
need to ensure a smooth transition from
the existing requirements. Substantial
improvements in air quality have
resulted from those requirements with
associated health benefits. It is
important not to lose those benefits as
the new requirements move forward. It
is also important to move quickly with
those portions of the new requirements
that provide the greatest benefits.
2. Key Guiding Principles
a. Appropriately Identify Necessary
Upwind Reductions
Emissions from upwind states can,
alone or in combination with local
emissions, result in air quality levels
that exceed the NAAQS and jeopardize
the health of residents in downwind
communities. Each upwind state is
required by the ‘‘good neighbor
provision’’ to eliminate its individual
significant contribution to downwind
state nonattainment and to eliminate
emissions that interfere with downwind
states’’ maintenance of the air quality
standards. The Act does not require
upwind states to eliminate all emissions
that affect downwind air quality or shift
responsibility for attaining the NAAQS
to the upwind states. Instead, the ‘‘good
neighbor provision’’ requires each
upwind state to, within 3 years of
promulgation or revision of a NAAQS,
submit a SIP to prohibit those emissions
that significantly contribute to
nonattainment or interfere with
maintenance downwind. The
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prohibition on these emissions is
intended to assist downwind states as
they design strategies for ensuring that
the NAAQS are attained and
maintained.
In practice, it is very complex for
individual states to address the
transport requirements. Generally for
transport of ozone, and for transport of
sulfate and nitrate fine particles, each
downwind area is affected by emissions
from multiple upwind states. In
addition, in many cases states are
simultaneously both upwind and
downwind of one another. Further, only
emissions that will significantly
contribute to nonattainment or interfere
with maintenance in another state are
prohibited. Thus, an upwind state’s
obligations are affected by the air
quality downwind. Downwind air
quality, in turn, is affected by both local
emissions and the cumulative impact of
emissions from all of the contributing
upwind states.
The problem of interstate transport is
thus extremely complex and any
remedy must acknowledge the inherent
complexity of the problem. It is
appropriate for EPA in developing such
a remedy to be mindful of the
interaction between upwind emissions
controls and local emissions controls.
The EPA continues to conclude, as it
did in developing the CAIR, that it
would be difficult if not impossible for
many nonattainment areas to reach
attainment through local measures
alone, and EPA finds no information
developed subsequent to development
of CAIR to alter this conclusion. At the
time of the proposed CAIR rule, EPA
conducted a local measures analysis
representing an ambitious set of
measures and emissions reductions that
may in fact be difficult to achieve in
practice. (Ref: Section IX of Technical
Support Document for the Interstate Air
Quality Rule Air Quality Modeling
Analyses, January 2004). This analysis
was intended to provide illustrative
examples of the nature of location
measures and possible reductions. This
analysis was not intended to precisely
identify local emissions control
measures that may be available in a
particular area. The EPA continues to
believe that a strategy based on adopting
cost effective controls on sources of
transported pollutants as a first step will
produce a more reasonable, equitable,
and optimal strategy than one beginning
with local controls. The local measures
analyses we conducted were not,
however, intended to develop a specific
or ‘‘optimal’’ regional and local
attainment strategy for any given area.
Rather, the analysis was intended to
evaluate whether, in light of available
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local measures, it is likely to be
necessary to reduce significant regional
transport from upwind states. EPA
continues to believe that the two local
measures analyses that were conducted
for the CAIR strongly support the need
for regional reductions of SO2 and NOX.
In conclusion, EPA believes that the
proposed rule represents the best
approach for identifying upwind state
emissions that significantly contribute
to nonattainment in, or interfere with
maintenance by, downwind states.
b. Ensuring That Pollution Controls
Operate
The proposed Transport Rule would,
by 2012, cap emissions of SO2 and NOX
on a state-by-state basis and guarantee
that existing and planned pollution
controls operate. EPA is convinced that
the considerable benefits to air quality
and public health that have been
achieved must be ensured going
forward. Keeping emissions of SO2 and
NOX from increasing by 2012 in 27
states and DC assures that recent gains
are maintained and that states that
significantly contribute to downwind
PM2.5 nonattainment and maintenance
areas do not increase their contribution
to those areas. Further, this proposal
would maintain the ozone season
emissions reductions achieved since
2005 in 26 states, ensuring that states
that significantly contribute to
downwind ozone nonattainment and
maintenance areas do not increase their
contribution to those areas. Tables
III.A–2 and III.A–3 in section III.A,
previously, show the projected EGU
emissions for the 2012 phase of the
Transport Rule.
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c. Provide Workable Approach for EPA
and States
Another important goal in developing
the proposed requirements is to provide
requirements that can, as a practical
matter, be implemented by both EPA
and state air quality agencies. Both EPA
and state resources are limited and EPA
recognizes the importance of developing
requirements that make efficient use of
limited EPA and state resources. EPA
also notes that the air quality
improvements brought about by
reducing transport can greatly assist
states in the development of SIPs and
attainment demonstrations.
d. Ensure a Reliable Power Supply
EPA recognizes that requirements for
EGUs must be mindful of the variability
in the operation of the power grid, and
that any requirements for broad
reductions should be structured in a
way that ensures a reliable power
supply.
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e. Provide for Cost-Effectiveness
EPA believes that is important to keep
both cost-effectiveness and air quality
objectives in mind in addressing the
CAA transport requirements.
f. Provide Incentives and Flexibility to
the Regulated Community
EPA seeks to provide approaches that
provide regulated owners/operators of
sources with the incentive to achieve all
cost-effective reductions. EPA’s
experience shows that providing this
incentive, and the flexibility to seek
alternatives to less cost-effective
controls, provides for greater
environmental protection at reduced
cost.
D. Why does this proposed rule focus on
the eastern half of the United States?
For this proposal, we identified a 37
state region for the technical analysis,
including all states east of the Rockies,
from the Dakotas through Texas
eastward. Western states also need to
address the requirements of section
110(a)(2)(D)(i)(I) of the CAA. However,
the transport issues in the eastern
United States are analytically distinct
and this rule focuses only on that subset
of the 110(a)(2)(D)(i)(I) issues.
First, interstate transport of PM2.5 and
ozone is a substantial and critical
component for attaining the ozone and
PM2.5 NAAQS in the eastern United
States. The significant reductions in
ambient air pollutant concentrations
since CAIR, due largely to the large
reductions in transported emissions,
only serve to reinforce this point.
Second, in developing the CAIR, EPA
found that interstate transport
(particularly for anthropogenic
emissions) made much smaller
contributions to exceedances of the
1997 PM2.5 standards in the western
United States. At the time, the only
exceedances of the 15 μg/m3 in those
states were in parts of California, and in
Lincoln County (Libby), Montana. The
Montana location has subsequently
come into attainment.
Technical information developed for
EPA’s recently completed
nonattainment designations suggests
that interstate emissions transport
makes a relatively small contribution to
exceedances in the western United
States under the 2006 PM2.5 standards.
For these designations, EPA identified
several locations in the western U.S.
with exceedances of the 24-hour PM2.5
standards. These locations were in
California and a few other western
states: Alaska, Washington, Oregon,
Utah, and Arizona. Technical support
information describing the nature of the
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24-hour PM2.5 problem at each of these
locations is available at: https://
www.epa.gov/pmdesignations/
2006standards/tech.htm. A review of
this information suggests to EPA that
the Western nonattainment problems
are relatively local in nature with
limited interstate transport. EPA
requests comment on this assessment.
E. Anticipated Rules Affecting Power
Sector
On January 12, 2010, the EPA
Administrator outlined seven priorities
for the Agency. One of them is to
improve air quality. In her description
of this priority she said, ‘‘EPA will
develop a comprehensive strategy for a
cleaner and more efficient power sector,
with strong but achievable reduction
goals for SO2, NOX, mercury, and other
air toxics.’’ In furtherance of this priority
goal, and to respond to statutory and
judicial mandates, EPA is undertaking a
series of regulatory actions over the
course of the next 2 years that will affect
the power sector in particular.
The rules under the CAA will
substantially reduce the emissions of
SO2, NOX, mercury, and other air toxics.
To the extent that the Agency has the
legal authority to do so while fulfilling
its obligations under the Act and other
relevant statutes, the Agency will also
coordinate these utility-related air
pollution rules with upcoming
regulations for the power sector from
EPA’s Office of Water (OW) and its
Office of Resource Conservation and
Recovery (ORCR). EPA expects that this
comprehensive set of requirements will
yield substantial health and
environmental benefits for the public,
benefits that can be achieved while
maintaining a reliable and affordable
supply of electric power across the
economy. In developing and
promulgating these rules, the Agency
will be providing the power industry
with a much clearer picture of what
EPA will require of it in the next
decade. In addition to promulgating the
rules themselves, the Agency will
engage with other federal, state and
local authorities, as well as with
stakeholders and the public at large,
with the goal of fostering investments in
compliance that represent the most
efficient and forward-looking
expenditure of investor, shareholder,
and public funds, resulting, in turn, in
the creation of a clean, efficient, and
completely modern power sector.
The major CAA rules that will drive
these compliance investments are: (1)
This transport rule; (2) potential future
rules that may be needed to address
transport under future revised ozone or
fine particle health standards; (3) the
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CAA Section 112(d) standards; (4)
revisions to the NSPS for coal and oilfired electric utility steam generating
units; and (5) BART requirements and
other requirements that address
visibility and regional haze. Within the
planning and investment horizon for
compliance with these rules, the EPA
very likely will be compelled to respond
a pending petition to set standards for
the emissions of greenhouse gases from
steam electric generating units under
the NSPS program. Furthermore, as set
forth in the recently promulgated
reinterpretation of the Johnson Memo,
beginning in 2011 new and modified
sources of GHG emissions, including
EGUs, will be subject to permits under
the Prevention of Significant
Deterioration program requiring them to
adopt BACT for their GHGs. Finally,
EPA will also pursue with other federal
agencies, states, and other groups energy
efficiency improvements in the use of
electricity throughout the economy that
will contribute to additional
environmental and public health
improvements that the Agency wants to
provide while lowering the costs of
realizing those improvements.
A brief explanation of these major
CAA rulemakings and activities follows.
Transport Rule. This proposed
transport rule includes emissions
reductions requirements for EGUs to
address interstate transport under the
1997 ozone NAAQS, the 1997 PM2.5
NAAQS, and the 2006 PM2.5 NAAQS.
After considering public comments on
this proposal, EPA will endeavor to
issue a final rule in spring 2011.
Rules to Address Transport under
Revised Air Quality Health Standards.
EPA currently is reconsidering its 2008
national ambient air quality standards
for ozone, and is conducting a periodic
review of the particulate matter
NAAQS, including the fine particle
standards. The Act requires EPA to
ensure that primary standards are
requisite to protect public health with
an adequate margin of safety, and to set
secondary standards requisite to protect
public welfare. The Act requires EPA to
review, and revise if appropriate, the
primary and secondary NAAQS on a
5-year schedule to ensure that air
quality standards reflect the latest
scientific information on health and
welfare effects. When air quality
standards are set or revised, the Act
requires revision of SIPs to ensure that
these standards to protect public health
and welfare are met expeditiously and,
in the case of the health-based
standards, within timetables in the Act.
If more protective NAAQS are
promulgated, further emissions
reductions would likely be needed in
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states where pollution levels exceed air
quality standards, and in upwind states
with emissions that significantly
contribute to the air quality problems in
another state. This may result in
additional emission reduction
requirements for facilities in the power
sector, as well as for other sectors. The
reconsideration of the March 2008
ozone air quality standards will be
completed soon, and the review of
particulate matter air quality standards
by October 2011. SIP deadlines and
attainment deadlines would flow from
those dates.
EPA plans to make expeditious
determinations of upwind state
emissions reduction responsibilities for
NAAQS for which interstate transport is
an issue. This approach will lead to
earlier emissions reductions to protect
public health, as well as provide other
benefits. In the North Carolina decision,
the court made clear that downwind
state nonattainment deadlines are
legally relevant to the timing of
reductions under section 110(a)(2)(D).
Thus, expeditious determinations of
upwind state responsibilities under
section 110(a)(2)(D) can promote
upwind reductions in time to help
downwind states meet attainment
deadlines, enable states and EPA to
provide sources with earlier information
on their emission reduction
responsibilities, and maximize sources
lead time to reduce emissions.
If a more protective ozone NAAQS is
issued in August, EPA would plan to
propose an interstate pollution transport
rule for that NAAQS in 2011. We would
expect work on that proposal to proceed
in parallel with efforts to finalize this
Transport Rule for the 1997 and 2006
NAAQS. A final rule to address
interstate pollution transport for a
reconsidered ozone NAAQS would be
anticipated in 2012. In view of the
implementation schedule for a
reconsidered ozone NAAQS,
compliance dates would be later than
the compliance dates proposed for this
Transport Rule, and would take into
account attainment dates for that
NAAQS and other factors such, as
control cost and installation time. For
any revised PM2.5 NAAQS, EPA plans to
conduct a similarly expeditious analysis
of interstate transport to support a
determination as to whether or not
further emissions reductions from the
power sector are required under section
110(a)(2)(D), in light of the emissions
reductions required by other power
sector rules.
A revised SO2 NAAQS was issued on
June 2 creating a new 1-hour SO2
NAAQS which, when implemented,
will protect Americans from asthma and
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respiratory difficulties associated with
short term exposures to SO2. Although
EPA does not expect peak SO2 levels to
be a long-range transport issue, power
plants are among the sources that can
contribute to peak SO2 levels and will
likely be evaluated by states as they
consider control measures to attain the
new standards. Anticipated emissions
reductions from power plants and other
SO2 sources under other Clean Air Act
(CAA or Act) requirements (e.g.,
transport rules, and MACT standards)
are expected to play a significant role in
attainment of the 1-hour SO2 NAAQS.
Section 112(d) Standards for Utility
Units. In 2008, the DC Circuit Court
vacated the CAMR and the 112(n)
Revision Rule, which removed coal- and
oil-fired electric utility steam generating
units from the section 112(c) list of
sources subject to regulation. EPA is in
the early stages of developing
regulations under section 112 of the
CAA that will require existing and new
coal- and oil-fired utility units to meet
emissions limits for mercury and other
HAPs emitted from these sources. As
required by section 112, EPA will issue
a set of emissions standards. In part, the
section 112(d) rule will require that all
existing major sources achieve the
emission limits for HAPs which will be
at least as stringent as the average
emissions reduction currently achieved
by the best performing 12 percent of
these units. Additionally, any new
major source will be required to meet
emission limits that are at least as
stringent as what is currently achieved
by the best-performing single source.
Currently, the Agency is seeking data on
five categories of HAP emissions: (1)
Acid gases (e.g., hydrochloric acid,
hydrogen fluoride, and hydrogen
cyanide); (2) mercury; (3) Non-Hg
metals (e.g., lead, cadmium, selenium,
and arsenic); (4) dioxins/furans; and, (5)
other organic hazardous air pollutants.
EPA expects to receive the requested
data, including stack testing results, by
September 2010. EPA has agreed to sign
the proposed rule by March 16, 2011,
and sign the final rule no later than
November 16, 2011. EPA may provide
existing sources up to 3 years to comply
with section 112(d) standards, and the
CAA authorizes the permit authority to
grant a 1 year extension of the
compliance date on a case-by-case basis
if such extension is necessary for the
installation of controls. The CAA
requires new sources to comply on the
effective date of the final rule or at
startup, whichever is later. If EPA were
to provide 3 years for compliance with
the section 112(d) standards,
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compliance would generally be required
by early 2015.
In developing these rules, EPA will
endeavor to proceed in a way that
provides all stakeholders and other
Federal, State and local decision-makers
with ongoing, up-to-date information
about the full suite of environmental
responsibilities that the power sector
must undertake. This, in turn, will
enable power companies and others
whose policies and decisions affect their
investment choice to adopt compliance
strategies that take full advantage of cocontrol opportunities and efficiencies
and other approaches to maximizing the
cost-effectiveness and leveraging
benefits of their investments.
New Source Performance Standards.
NSPS are administered under section
111 of the CAA. The standards for new,
modified, and reconstructed steam
EGUs are contained in 40 CFR part 60
subpart Da, which was last amended in
2006. The current structure of subpart
Da sets output-based (i.e., lbs of
emission/MWh) emission limits for NOX
and SO2 and optional output-based
standards for particulate matter. EPA is
currently re-evaluating the standards in
Subpart Da to determine whether they
reflect the degree of emission limitation
achievable through the application of
the best system of emission reduction,
which the Administrator determines has
been adequately demonstrated. EPA also
has a pending voluntary remand to
decide whether NSPS standards for this
source category should include limits
on GHG emissions. EPA is considering
the timetable for these actions and
decisions in light of legal obligations
and policy considerations, including the
desirability of the industry knowing its
regulatory obligations to inform
investment decisions.
Regional Haze/BART. States are
required to develop SIPs that address
regional haze in scenic areas such as
national parks and wilderness areas.
EPA regulations for regional haze
appear in Chapter 40 of the CFR in
sections 51.308 and 51.309. One of the
requirements of the regional haze SIPs
is to provide for BART for large
industrial sources including EGUs. The
BART provisions affect EGUs put into
operation between 1962 and 1977.
Energy Efficiency. Policies that will
promote efficient use of electric power
can be an integral, highly cost-effective
component of power companies’’
compliance strategies. Reducing
demand for electricity can in itself
achieve large emissions reductions and
public health benefits, while enhancing
the reliability of the grid. It can also
lower the cost of emissions reductions
for consumers of electricity and for the
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power industry, as investments are
avoided in unnecessary infrastructure.
EPA does not have sole responsibility
for the development of energy policy to
promote efficiency. To facilitate this
component of the power sector’s
compliance strategy, EPA intends to
engage with other federal, state, and
local agencies whose policies and
actions can make it easier for power
companies to adopt, or benefit from,
energy efficiency investments in their
compliance strategies. EPA will
continue to use its authorities to
advance energy efficiency by providing
incentives for energy efficiency in our
regulatory programs (e.g., output-based
standards) and through our successful
existing voluntary programs such as
ENERGY STAR. The Department of
Energy (DOE) also has considerable
resources to encourage efficient use of
electricity. Additional resources have
been made available under the
American Recovery and Reinvestment
Act to both DOE and EPA to promote
energy efficiency. State governments,
both in their environmental programs
and through their public service
commissions, which regulate electric
utility rates, can promote energy
efficiency. Many state governments have
been leaders in promoting efficient use
of electricity through such mechanisms
as energy efficiency standards and
demand response, and EPA and DOE are
assisting state governments in this
effort. Local governments as well,
through building codes, zoning, and
other actions, can and do promote enduse energy efficiency. The Federal
Energy Regulatory Commission (FERC)
regulates wholesale electricity markets
and sets mandatory reliability standards
to assure a safe reliable power system.
In carrying out this mission FERC
recognizes that energy efficiency is a
resource, to be considered along with
other energy resources in reliability and
economic planning.
All of these entities will need to work
in concert to achieve a truly efficient,
reliable, cost-effective electric power
system. EPA is committed to meeting
this challenge.
Non-Air Office Regulations. EPA is
also working on three additional rules
that will have potential impacts on the
power sector. The Office of Solid Waste
and Emergency Response is developing
revised regulations for coal combustion
residues, which are the combustion
byproducts associated with the use of
coal as a fuel. The Administrator signed
the proposed rule on May 4, 2010. Over
the next few years, EPA’s Office of
Water plans to develop two rules
affecting electric generating units; the
precise timing of these rules is being
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determined. One will regulate cooling
water intake structures. The other will
revise the effluent guidelines for
wastewater discharges from power
plants. Each of these rules has cost
implications to the power sector, and
the Agency intends to coordinate these
regulations with the upcoming air
regulations. We intend to maximize
reductions in pollution while
maintaining cost-effective solutions.
As a first step to carrying out its
commitment to promote and facilitate
the most cost-effective and forwardlooking compliance investments and
strategies on the part of the power
sector, EPA will conduct extensive
outreach concerning the full range of the
upcoming environmental
responsibilities of the sector as it
proposes the Transport Rule. Upon this
proposal, the Agency will begin an
outreach effort with the public, the
regulated community, state air
regulators, and others to (1) describe the
Transport Rule proposal, and (2)
provide information on the 2011 section
112 standards for utility units and other
upcoming EPA rulemakings affecting
the power sector. The intent will be to
inform all stakeholders of the industry’s
obligations and opportunities for the
industry to use investments in SO2 and
NOX reductions to help smooth
transition to compliance with the
Section 112(d) standards applicable to
utility units.
At the same time EPA also intends to
expand its outreach to others—who can
play a significant role in promoting or
requiring investment in energy
efficiency. EPA intends to continue
these efforts over time as more
information becomes available in the
development of the various rulemakings
under development for the power
sector.
IV. Defining ‘‘Significant Contribution’’
and ‘‘Interference With Maintenance’’
This section describes EPA’s
proposed approach to define emissions
that significantly contribute to
nonattainment or interfere with
maintenance of the PM2.5 and ozone
NAAQS downwind. The section begins
by providing background on how
‘‘significant contribution’’ and
‘‘interference with maintenance’’ were
defined in the past by EPA for the NOX
SIP Call and the CAIR, describing past
Court opinions on EPA’s approach, and
presenting an overview of EPA’s
proposed Transport Rule approach
(section IV.A). Next, section IV.B
describes the proposed approach to
identify upwind contributing states.
Section IV.C details the air quality
modeling approach and results used for
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this proposed rule. Section IV.D
provides a detailed description of EPA’s
proposed approach to quantify
emissions that significantly contribute
and interfere with maintenance. Section
IV.E includes proposed state emissions
budgets before accounting for the
inherent variability in power system
operations. Section IV.F discusses the
inherent variability in power system
operations, proposes variability limits
on the state budgets, and presents
projected emissions reduction results.
Section IV.G describes how the
proposed approach is consistent with
judicial opinions. Finally, section IV.H
lists alternative approaches to defining
significant contribution and interference
with maintenance that EPA evaluated
but is not proposing.
A. Background
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1. Approach Used in NOX SIP Call and
the CAIR
a. Significant Contribution
Two rules EPA promulgated that
address interstate transport of pollutants
are the NOX SIP Call (63 FR 57356;
October 27, 1998) and the CAIR (70 FR
25162; May 12, 2005), which are
described in section III.B. In both of
these rules, EPA used a 2-step approach
to quantify significant contribution. The
approaches used in both rules were
similar.
In the first step, EPA applied an air
quality threshold to determine a set of
upwind states whose potential for
significant contribution should be
evaluated further. That is, EPA
compared the contributions that
individual upwind states make to
downwind receptors and identified
states whose contributions were greater
than the specified threshold amount.
EPA referred to these states as
significant contributors but did not rely
on this first step to quantify or measure
the states’ significant contribution.
In the second step, EPA determined
the quantity of emissions that the states
collectively could remove using highly
cost-effective controls. EPA defined this
quantity of emissions as the ‘‘significant
contribution.’’ The approach used in
each rule is described in more detail,
later.
NOX SIP Call. EPA addressed the
section 110(a)(2)(D)(i)(I) requirement to
prohibit emissions that significantly
contribute to downwind nonattainment
in the NOX SIP Call. To do so, EPA
developed a methodology for
identifying emissions that constitute
upwind states’ ‘‘significant
contribution.’’ EPA determined that
emissions ‘‘contribute’’ to nonattainment
downwind if they have an impact on
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nonattainment downwind (62 FR
60325). EPA established several criteria
or factors for the ‘‘significant
contribution’’ test (and further indicated
that the same criteria should apply to
the ‘‘interfere with maintenance’’
provision).14
EPA determined the amount of
emissions that significantly contribute
to downwind nonattainment from
sources in a particular upwind state by:
(i) Evaluating, with respect to each
upwind state, several air quality related
factors, including determining that all
emissions from the state have a
sufficiently great impact downwind (in
the context of the collective
contribution nature of the ozone
problem); and (ii) determining the
amount of that state’s emissions that can
be eliminated through the application of
cost-effective controls (63 FR 57403).
Air Quality Factor. The first factor
that EPA used to determine the amount
of emissions that significantly
contribute to downwind nonattainment
was the air quality factor, consisting of
an evaluation of the impact on
downwind air quality of the upwind
state’s emissions.
EPA specifically considered three air
quality factors with respect to each
upwind state:
• The overall nature of the ozone
problem (i.e., ‘‘collective contribution’’);
• The extent of the downwind
nonattainment problems to which the
upwind state’s emissions are linked,
including the ambient impact of
controls required under the CAA or
otherwise implemented in the
downwind areas; and
• The ambient impact of the
emissions from the upwind state’s
sources on the downwind
nonattainment problems (63 FR 57376).
EPA explained the first factor,
collective contribution, by noting,
[V]irtually every nonattainment problem is
caused by numerous sources over a wide
geographic area * * * [. This] factor
suggest[s] that the solution to the problem is
the implementation over a wide area of
controls on many sources, each of which may
have a small or immeasurable ambient
impact by itself (63 FR 57377).
The second air quality factor is the
extent of downwind nonattainment
problems. EPA considered the thencurrent air quality of the area, the
predicted future air quality (assuming
14 In the NO SIP Call, because the same criteria
X
applied, the discussion of the ‘‘contribute
significantly to nonattainment’’ test generally also
applied to the ‘‘interfere with maintenance’’ test.
However, in the NOX SIP Call, EPA stated that the
‘‘interfere with maintenance’’ test applied with
respect to only the 8-hour ozone NAAQS (63 FR
57379–80).
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implementation of required controls but
not the transport requirements that were
the subject of the NOX SIP Call), and,
when air quality designations had
already been made, the boundaries of
the area in light of designation status (63
FR 57377).15
EPA applied the third air quality
factor by projecting the amount of the
upwind state’s entire inventory of
anthropogenic emissions to the year
2007, and then quantifying the impact
of those emissions on downwind
nonattainment through the appropriate
air quality modeling techniques.16
Specifically, (i) EPA determined the
minimum threshold impact that the
upwind state’s emissions must have on
a downwind nonattainment area to be
considered potentially to contribute
significantly to nonattainment; and then
(ii) for states with impacts above that
threshold, EPA developed a set of
metrics for further evaluating the
contribution of the upwind state’s
emissions on a downwind
nonattainment area (63 FR 57378). EPA
referred to states with emissions that
had a sufficiently great impact as
significant contributors; however, the
precise amount of their significant
contribution was not calculated until
the next step. Because the ozone
problem is caused by many relatively
small contributions, even relatively
small contributors must participate in
the solution. For this reason, EPA
determined that even a relatively small
contribution can be significant
contribution given the nature of the
problem, and established relatively low
thresholds.
Cost Factor. The cost factor is the
second major factor that EPA applied to
determine the significant contribution to
nonattainment: ‘‘EPA* * * determined
whether any amounts of the NOX
emissions may be eliminated through
controls that, on a cost-per-ton basis,
may be considered to be highly cost
effective’’ (63 FR 57377). Applying this
cost factor on top of the air quality
factor, EPA determined that emissions
that both were from states that exceeded
15 EPA explained in the NO SIP Call, ‘‘It should
X
be reiterated that EPA relied on the designated area
solely as a proxy to determine which areas have air
quality in nonattainment. This proxy is readily
available under the 1-hour NAAQS because areas
have long been designated nonattainment. The
EPA’s reliance on designated nonattainment areas
for purposes of the 1-hour NAAQS does not
indicate that the reference in section
110(a)(2)(D)(i)(I) to ‘‘nonattainment’’ should be
interpreted to refer to areas designated
nonattainment.’’ (63 FR 57375, footnote 25)
16 Although EPA’s air quality modeling
techniques examined all of the upwind state’s
emissions of ozone precursors (including VOC and
NOX), only the NOX emissions had meaningful
interstate impacts.
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the air quality thresholds and could be
eliminated through the application of
highly cost-effective controls
constituted a given state’s significant
contribution.
Choice of Highly Cost-Effective
Standard. EPA chose the standard of
‘‘highly cost-effective’’ in order to assure
state flexibility in selecting control
strategies to meet the emissions
reduction requirements of the
rulemaking. That is, the rulemaking
required the states to achieve specified
levels of emissions reductions—the
levels achievable if states implemented
the control strategies that EPA identified
as highly cost-effective—but the
rulemaking did not mandate those
highly cost-effective control strategies,
or any other control strategy. Indeed, in
calculating the amount of the required
emissions reductions by assuming the
implementation of highly cost-effective
control strategies, EPA assured that
other control strategies—ones that were
cost-effective, if not highly costeffective—remained available to the
states.
Determination of Highly Cost-Effective
Amount. EPA determined the dollar
amount considered to be highly costeffective by reference to the costeffectiveness of recently promulgated or
proposed NOX controls. EPA
determined that the average costeffectiveness of controls ranged up to
approximately $1,800 per ton of NOX
removed (1990$) on an annual basis.
The EPA considered the controls in the
reference list to be cost-effective.
EPA established $2,000 per ton
(1990$) in average cost-effectiveness for
summer ozone season emissions
reductions as, at least directionally, the
highly cost-effective amount. Identifying
this amount on an ozone season basis
was appropriate because the NOX SIP
Call concerned the ozone standard, for
which emissions reductions during only
the summer ozone season are necessary.
In determining the highly cost-effective
amount, EPA analyzed costs on a
regionwide basis, and assumed a cap
and trade program for EGUs and large
non-EGU boilers and turbines.
Source Categories. EPA then
determined that the source categories
for which highly cost-effective controls
were available included EGUs, large
industrial boilers and turbines, and
cement kilns. At the same time, EPA
determined, for those source categories,
the level of emissions reductions in
each state that would result from the
application of all controls that would be
highly cost-effective and that would be
feasible. The EPA considered other
source categories, but found that highly
cost-effective controls were not
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available for various reasons, including
the size of the sources, the relatively
small amount of emissions from the
sources, or the control costs.
Other Factors. EPA also relied on
several other, secondary considerations
to identify the required amount of
emissions reductions. The first
concerned the consistency of regional
reductions with downwind attainment
needs. The second general consideration
was ‘‘the overall fairness of the control
regimes’’ to which the downwind and
upwind areas were subject. The third
general consideration was ‘‘general cost
considerations.’’ The EPA noted that ‘‘in
general, areas that currently have, or
that in the past have had, nonattainment
problems * * * have already incurred
ozone control costs.’’ The next set of
controls available to these
nonattainment areas would be more
expensive than the controls available to
the upwind areas. The EPA found that
this cost scenario further confirmed the
reasonableness of the upwind control
obligations (63 FR 57379).
In the NOX SIP Call, EPA considered
all of these factors together in
determining the level of controls
considered to be highly cost-effective.
Within the region, the nonattainment
areas already had implemented required
VOC and NOX controls that covered
much of their inventory. However, the
upwind states in the region generally
had not implemented such controls
(except as needed to address their ozone
nonattainment areas). In this context,
EPA considered it reasonable to impose
an additional control burden on the
upwind states. Air quality modeling
showed that residual nonattainment
remained even with this additional level
of upwind controls so that further
reductions from downwind and/or
upwind areas would be necessary.
After ascertaining the controls that
qualified as highly cost-effective, EPA
developed a methodology for
calculating the amount of NOX
emissions that each state was required
to reduce on grounds that those
emissions contribute significantly to
nonattainment downwind. The total
amount of required NOX emissions
reductions was the sum of the amounts
that would be reduced by application of
highly cost-effective controls to each of
the source categories for which EPA
determined that such controls were
available (63 FR 57378).
Electric Generating Units. The largest
of the source categories discussed
previously was EGUs. EPA determined
the amount of reductions associated
with EGU controls by applying the
control rate that EPA considered to
reflect highly cost-effective controls to
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each state’s EGU heat input (adjusted for
projected growth) (70 FR 25173.) In the
NOX SIP Call, EPA evaluated the costs
of control on a region-wide basis.
CAIR. In the CAIR, EPA again
addressed the section 110(a)(2)(D)(i)(I)
requirement to prohibit emissions that
significantly contribute to downwind
nonattainment (70 FR 25162). While the
NOX SIP Call had addressed significant
contribution with respect to the 1997
ozone NAAQS, the CAIR addressed
significant contribution with respect to
both the ozone and annual PM2.5
NAAQS promulgated in 1997. In the
CAIR, EPA used a methodology to
identify states’’ significant contribution
based on and very similar to the
methodology used in the NOX SIP Call.
To quantify the amounts of emissions
that contribute significantly to
nonattainment, EPA explained in the
CAIR that the Agency primarily focused
on the air quality factor reflecting the
upwind state’s ambient impact on
downwind nonattainment areas, and the
cost factor of highly cost-effective
controls. See 70 FR 25174.
Air Quality Factor—PM2.5. EPA
employed air quality modeling
techniques to assess the impact of each
upwind state’s entire inventory of
anthropogenic SO2 and NOX emissions
on downwind nonattainment and
maintenance for the annual PM2.5
NAAQS.17 EPA determined that upwind
NOX and SO2 emissions contribute
significantly to annual PM2.5
nonattainment as of the year 2010.
As in the NOX SIP Call, EPA used a
2-step approach to quantify significant
contribution. In the CAIR, in the first
step EPA adopted a threshold air quality
impact of 0.2 μg/m3 for PM2.5. An
upwind state with contributions to
downwind nonattainment below this
level would not be subject to regulatory
requirements, but a state with
contributions at or higher than this level
would be subject to further evaluation
(70 FR 25174–75).
This level reflects the fact that PM2.5
nonattainment, like ozone, is caused by
many sources in a broad region and
therefore may be solved only by
controlling sources throughout the
region. As with the NOX SIP Call, the
collective contribution condition of
PM2.5 air quality is reflected in the
relatively low threshold (70 FR 25175).
Air Quality Factor—8-Hour Ozone.
EPA employed air quality modeling
techniques to assess the impact of each
upwind state’s inventory of NOX and
VOC emissions on downwind
nonattainment. The EPA determined
17 EPA did not address 24-hour PM
2.5 NAAQS in
CAIR, only the annual PM2.5 NAAQS.
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that upwind NOX emissions contribute
significantly to 8-hour ozone
nonattainment as of the year 2010.
Therefore, EPA projected NOX
emissions to the year 2010, assuming
certain required controls (but not
controls required under the CAIR), and
then modeled the impact of those
projected emissions on downwind
8-hour ozone nonattainment in that year
(70 FR 25175).
EPA used the same threshold amounts
and metrics for 8-hour ozone that it
used in the NOX SIP Call. That is,
emissions from an upwind state were
found to contribute significantly to
nonattainment if the maximum
contribution was at least 2 parts per
billion, the average contribution greater
than one percent, and certain other
numerical criteria were met. EPA also
evaluated frequency, magnitude, and
relative amounts of contribution to
determine which linkages were
significant before costs were considered.
Cost Factor. The second step in the
2-step process is to apply the cost factor.
As in the NOX SIP Call, EPA interpreted
this factor as mandating emissions
reductions in amounts that would result
from application of highly cost-effective
controls. In the CAIR, EPA determined
the level of costs that would be highly
cost-effective on a regional basis by
reference to the cost effectiveness of
other recent controls. EPA concluded
that EGUs were the only source category
for which highly cost-effective SO2 and
NOX controls were available at the time.
EPA determined as highly cost-effective
the dollar amount of cost-effectiveness
that falls near the low end of a reference
range of control costs. See 70 FR 25175.
In the CAIR, as in the NOX SIP Call,
EPA analyzed the costs of control on a
regionwide basis.
Other Factors. As with the NOX SIP
Call, EPA considered other factors that
influence the application of the air
quality and cost factors, and that
confirm the conclusions concerning the
amounts of emissions that upwind
states must eliminate as contributing
significantly to downwind
nonattainment. See 70 FR 25175.
b. Interference With Maintenance
Section 110(a)(2)(D)(i)(I) requires that
SIPs for national primary and secondary
air quality standards contain adequate
provisions prohibiting emissions in
amounts that ‘‘interfere with
maintenance by any other state’’ of any
such standard.
In the NOX SIP Call and in the CAIR,
EPA gave the term ‘‘interfere with
maintenance’’ a meaning much the same
as the meaning given to the term
‘‘significant contribution.’’ That
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approach, which was found inconsistent
with the requirements of
110(a)(2)(D)(i)(I), is described later.
EPA’s proposed new approach to
interpreting ‘‘interfere with
maintenance’’ is described in section
IV.D, later.
NOX SIP Call: In the NOX SIP Call,
EPA explained its approach as follows
(63 FR 57379–80):
After an area has reached attainment of the
8-hour NAAQS, that area is obligated to
maintain that NAAQS. (See sections 110(a)(1)
and 175A.) Emissions from sources in an
upwind area may interfere with that
maintenance. The EPA proposes to apply
much the same approach in analyzing the
first component of the ‘‘interfere-withmaintenance’’ issue, which is identifying the
downwind areas whose maintenance of the
NAAQS may suffer interference due to
upwind emissions. The EPA has analyzed the
‘‘interfere-with-maintenance’’ issue for the
8-hour NAAQS by examining areas whose
current air quality is monitored as attaining
the 8-hour NAAQS [or which have no current
air quality monitoring], but for which air
quality modeling shows nonattainment in the
year 2007. This result is projected to occur,
notwithstanding the imposition of certain
controls required under the CAA, because of
projected increases in emissions due to
growth in emissions generating activity.
Under these circumstances, emissions from
upwind areas may interfere with the
downwind area’s ability to attain.
Ascertaining the impact on the downwind
area’s air quality of the upwind area’s
emissions aids in determining whether the
upwind emissions interfere with
maintenance (62 FR 60326).
In today’s action, EPA is taking the same
positions with respect to the interfere-withmaintenance test as described in the notice
of proposed rulemaking.
In addition, the NOX SIP Call
preamble stated:
This [interfere-with-maintenance]
requirement * * * does not, by its terms,
incorporate the qualifier of ‘‘significantly.’’
Even so, EPA believes that for present
purposes, the term ‘‘interfere’’ should be
interpreted much the same as the term
‘‘contribute significantly,’’ that is, through the
same weight-of-evidence approach.
CAIR: In the CAIR, EPA also
interpreted ‘‘interfere with maintenance’’
in a limited way. EPA only considered
whether upwind state emissions
eventually posed a maintenance
problem for areas that EPA projected to
be in nonattainment in 2010 (the year
that was the focus of the analysis of
significant contribution to
nonattainment). EPA did not examine
whether areas in attainment in 2010
might face a maintenance problem
either in 2010 or thereafter, so no
upwind state controls were considered
to assist such areas with maintaining
clean air. The CAIR preamble stated (70
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FR 25193, footnote 45), ‘‘we believe the
‘interfere with maintenance’ prong may
come into play only in circumstances
where EPA or the state can reasonably
determine or project, based on available
data, that an [nonattainment] area in a
downwind state will achieve
attainment, but due to emissions growth
or other relevant factors is likely to fall
back into nonattainment.’’ 18
In responding to comments on the
CAIR proposal, we also used this
interpretation of the maintenance
provision to help support the need for
Phase II CAIR reductions. For ozone, we
conducted an analysis that looked at (1)
the amount by which receptor locations
were projected to attain in 2015 and (2)
the year-to-year variability in ozone
levels due to weather and other factors
based on a review of historical
monitoring data. This analysis
concluded that areas within 3–5 ppb of
the standard, and sometimes greater
(e.g., Fulton County, Atlanta) had
historic variability as great as 8 ppb, and
that this variability suggests strongly
that upwind states could be interfering
with maintenance even if modeling
shows attainment by up to these
amounts. For PM2.5, while we lacked
historical data to support the same
variability analysis, we characterized
attaining the annual standard by 0.5 μg/
m3 as ‘‘attaining by a narrow margin’’
thus giving rise to maintenance
concerns, and noted that in past (mobile
source) rules we had indicated that
attainment by a margin of 10 percent or
less could be considered to raise
maintenance concerns.
2. Judicial Opinions
a. Significant Contribution
In North Carolina v. EPA, 531 F.3d.
896 (DC Cir. 2008), the Court held that
the approach EPA used in CAIR to
measure each state’s significant
contribution was insufficient. EPA, the
Court concluded, had failed to
‘‘measure[ ] the significant contribution
from sources within an individual state
to downwind nonattainment areas.’’ Id.
at 907. The Court further reasoned that
the lack of a state-specific significant
contribution analysis made it
impossible for EPA to show that the
18 The CAIR final preamble stated: ‘‘EPA has
evaluated the attainment status of the downwind
receptors in 2010 and 2015, and has determined
that each upwind state’s 2010 and 2015 emissions
reductions are necessary to the extent required by
the rule because a downwind receptor linked to that
upwind state will either (i) remain in
nonattainment and continue to experience
significant contribution to nonattainment from the
upwind state’s emissions; or (ii) attain the relevant
NAAQS but later revert to nonattainment due, for
example, to continued growth of the emissions
inventory.’’
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trading programs and state budgets
established to implement the trading
programs, effectuated the section
110(a)(2)(D)(i)(I) statutory mandate to
eliminate emissions within the state that
significantly contribute to
nonattainment or interfere with
maintenance in other states.
Specifically, the court rejected the
regional scope of EPA’s analysis. It
reasoned that ‘‘because EPA evaluated
whether its proposed emissions were
‘highly cost effective’ at the regionwide
level assuming a trading program, it
never measured the ‘significant
contribution’ from sources within an
individual state to downwind
nonattainment areas.’’ Id. at 907. In
reaching this conclusion, however, the
Court also recognized that aspects of
EPA’s methodology for analyzing
significant contribution had been
upheld in Michigan v. EPA, 213 F.3d
663 (DC Cir. 2000), and it left those
holdings undisturbed. Specifically, the
Court acknowledged its prior
conclusion that ‘‘significance may
include cost’’ North Carolina, 531 F.3d
at 919 (citing Michigan 213 F.3d 677–
79), and thus it is acceptable for EPA to
use cost to ‘‘draw the ‘significant
contribution’ line’’. Id. The Court also
recognized that Michigan approved
EPA’s decision to apply a uniform
emissions control requirement to all
upwind states despite different levels of
contribution. See North Carolina, 531
F.3d at 908. The Court thus concluded
that while EPA must ‘‘measure each
state’s ‘significant contribution’ to
downwind nonattainment’’ that
measurement need not ‘‘directly
correlate with each state’s
individualized air quality impact on
downwind nonattainment relative to
other upwind states.’’ Id. at 908.
In North Carolina, the Court also
upheld several aspects of the air quality
modeling EPA used in the significant
contribution analysis. It upheld EPA’s
use of whole state modeling, see id. at
923–26, and deferred to EPA’s selection
of the PM2.5 contribution threshold, see
id. at 914–15. With regard to EPA’s
application of the methodology to
individual states, the Court found that
EPA had failed to respond to comments
by Minnesota Power alleging errors in
the application of this methodology to
determine Minnesota’s contribution to
downwind PM2.5 nonattainment areas.
See id. at 926–28.
b. Interference With Maintenance
In the CAIR case, the Court also
rejected EPA’s approach to the second
prong of section 110(a)(2)(D)(i)(I),
holding that EPA’s failure to give
independent meaning to the term
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‘‘interfere with maintenance’’ was
inconsistent with the statutory mandate.
See North Carolina, 531 F.3d at 910.
The Court rejected the approach used in
CAIR reasoning that it ‘‘provides no
protection for downwind areas that,
despite EPA’s predictions, still find
themselves struggling to meet NAAQS
due to upwind interference in 2010.’’ Id.
at 910–11.
3. Overview of Proposed Approach
In this section, EPA will explain how
it proposes to identify which states are
significantly contributing to downwind
non-attainment and/or interfering with
maintenance of the NAAQS at
downwind sites and to quantify what
that contribution is.
In this action, EPA is proposing to use
a two step approach to measuring each
state’s significant contribution. The
methodology used is based on the
approach used in CAIR and the NOX SIP
Call but modified to address the
concerns raised by the Court. In the first
step of this proposed approach, EPA
uses air quality modeling to quantify
individual states’ contributions to
downwind nonattainment and
maintenance sites in 2012. States whose
contributions to any downwind sites are
greater than 1 percent of the relevant
NAAQS are considered ‘‘linked’’ to those
sites for the purpose of the second step
in the analysis. In the second step, EPA
identifies the portion of each state’s
contribution that constitutes its
‘‘significant contribution’’ and
‘‘interference with maintenance.’’ To do
so, EPA uses maximum cost thresholds,
informed by air quality considerations.
Specifically, for each precursor
pollutant (i.e., SO2 and NOX for PM2.5
and NOX for ozone) emitted by the
upwind states that EPA has identified as
linked to NAAQS nonattainment and
maintenance sites downwind, EPA
identifies, through this process, the
reductions available from EGUs in each
individual upwind state at the
appropriate maximum cost threshold.
These emissions reductions are the
amount of the upwind state’s significant
contribution. The cost thresholds used
in this portion of the analysis, in
contrast to the thresholds used in CAIR
and the NOX SIP Call, are informed by
air quality considerations, in addition to
a comparison of the cost of control in
other regulatory contexts. Specific cost
thresholds were developed for annual
SO2, annual NOX, and ozone-season
NOX. Where appropriate, EPA
developed higher and lower cost
thresholds, based on the downwind air
quality impact of emissions from
different groups of states. Although EPA
in the past has applied a uniform
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remedy to all states found to have a
significant contribution, in this proposal
EPA divides, for individual pollutants,
the significantly contributing states into
two groups: Those whose significant
contribution can be eliminated at a
lower cost threshold; and those whose
significant contribution is not
eliminated (to the extent that it has been
identified in this proposal) until they
reach the higher cost threshold. The
lower cost threshold applies to a state if
the reduction in emissions at that
threshold eliminates nonattainment and
maintenance problems at all ‘‘linked’’
sites.
EPA considers that the maintenance
concept has two components: Year-toyear variability in emissions and air
quality, and continued maintenance of
the air quality standard over time. Both
components of maintenance are
addressed in this proposal.
Step One: Air Quality Analysis
In step one of this proposed approach,
EPA analyzes emissions from 37 states
to quantify the impact of those
emissions on downwind nonattainment
and maintenance sites in 2012 (see
section IV.C for a detailed discussion of
air quality modeling). To begin this
analysis, EPA first identifies all
monitors projected to be in
nonattainment or, based on historic
variability in air quality, projected to
have maintenance problems in 2012.
This baseline analysis takes into
account emissions reductions associated
with the implementation of all federal
rules promulgated by December 2008
and assumes that the CAIR is not in
effect. This baseline presents a unique
situation. EPA has been directed to
replace the CAIR; yet the CAIR remains
in place and has led to significant
emissions reductions in many states.
A key step in the process of
developing a 110(a)(2)(D)(i)(I) rule
involves analyzing existing (base case)
emissions to determine which states
significantly contribute to downwind
nonattainment and maintenance areas.
EPA cannot prejudge at this stage which
states will be affected by the rule. For
example, a state affected by CAIR may
not be affected by the new rule and after
the new rule goes into effect, the CAIR
requirements will no longer apply. For
a state covered by CAIR but not covered
by the new rule, the CAIR requirements
would not be replaced with new
requirements, and therefore an increase
in emissions relative to present levels
could occur in that state. More
fundamentally, the court has made clear
that, due to legal flaws, the CAIR rule
cannot remain in place and must be
replaced. If EPA’s base case analysis
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were to ignore this fact and assume that
reductions from CAIR would continue
indefinitely, areas that are in attainment
solely due to controls required by CAIR
would again face nonattainment
problems because the existing
protection from upwind pollution
would not be replaced. For these
reasons, EPA cannot assume in its base
case analysis, that the reductions
required by CAIR will continue to be
achieved.
Following this logic, the 2012 base
case shows emissions higher than
current levels in some states. Because
EPA has been directed to replace CAIR,
EPA believes that for many states, the
absence of the CAIR NOX program will
lead to the status quo of the NOX Budget
Program, which limits ozone-season
NOX emissions and ensures the
operation of NOX controls in those
states. Also, without the CAIR SO2
program, emission requirements in
many areas would revert to the
comparatively less stringent
requirements of the Title IV Acid Rain
Program. As a result, SO2 emissions in
many states would increase markedly in
the 2012 base case relative to the
present. Efforts to comply with ARP
rules at the least-cost would occur in
many cases without the operation of
existing scrubbers through use of readily
available, inexpensive Title IV
allowances. Notably, all known controls
that are required under state laws,
NSPS, consent decrees, and other
enforceable binding commitments
through 2014 are accounted for in the
base case. It is against this backdrop that
the Transport Rule is analyzed and that
significant contribution to
nonattainment and interference with
maintenance must be addressed.
Step Two: Quantifying Each State’s
Significant Contribution
In step two, EPA identifies the portion
of each state’s contributing emissions
that constitute the emissions from that
state that ‘‘significantly contribute to, or
interfere with maintenance by’’ another
state. To do so with respect to the 1997
ozone NAAQS, EPA analyzes the costs
and associated air quality impacts of
reductions in ozone-season NOX. To do
so with respect to the 1997 and 2006
PM2.5 NAAQS, EPA analyzes the costs
and associated air quality impacts of
reductions in annual SO2 and annual
NOX. The analysis uses cost thresholds,
informed by air quality considerations
and applied on a state specific basis.
EPA considered a number of factors,
including air quality and cost factors
because the circumstances that lead to
nonattainment and maintenance
problems at downwind sites are
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extremely complex. By using both cost
and air quality factors, EPA’s analysis
can address the different circumstances
influencing the linkages between
upwind and downwind states. As such,
EPA believes it is appropriate to
consider these factors in identifying the
emissions that must be prohibited.
While we believe it is important to
consider cost, we also recognize that we
can’t ‘‘just pick a cost for the region and
deem ‘significant’ any emissions that
sources can eliminate more cheaply.’’
North Carolina, 531 F.3d at 918. In
contrast to the approach used in CAIR
and the NOX SIP Call, the cost
thresholds EPA uses in this proposed
approach are informed by air quality
considerations and applied on a state
specific basis. EPA first develops statespecific costs curves showing what level
of emissions reductions could be
achieved at different cost levels in 2012
and 2014. EPA then uses a simplified air
quality assessment tool to examine the
impact of the reductions at specific cost
levels on downwind nonattainment and
maintenance sites. This approach allows
EPA to identify specific cost breakpoints
based on air quality considerations
(such as the cost at which the air quality
assessment analysis projects large
numbers of downwind sites
maintenance and nonattainment
problems would be resolved) or cost
criteria (such as being a cost where large
emissions reductions occur because a
particular technology is widely
implemented at that cost). EPA then
evaluated the reasonableness of the cost
breakpoints using a number of criteria to
determine which of the breakpoints
appropriately represented a cost
threshold with which to define
significant contribution.
These thresholds are then applied on
a state-specific basis to quantify each
individual state’s significant
contribution.
The remainder of this section
provides further detail on the specific
methodology developed by EPA and the
application of this methodology to
identify emissions that significantly
contribute to or interfere with
maintenance of the 1997 ozone NAAQS
and the 1997 and 2006 PM2.5 NAAQS.
the proposed rule, and which states are
not subject to the rule because their
sources’ emissions were found to not
significantly contribute to
nonattainment of the PM2.5 or 8-hour
ozone standards or interfere with
maintenance of those standards, in
downwind states.
The EPA assessed individual upwind
states’’ 2012 projected ambient impacts
on downwind nonattainment and
maintenance receptors for a 37-state
region in the eastern U.S., and
established threshold values for PM2.5
and ozone to identify those states whose
impact does not constitute a significant
contribution to air quality violations in
the downwind states. EPA used these
same threshold values in considering
the potential for upwind state emissions
to interfere with maintenance of the
PM2.5 and 8-hour ozone NAAQS in
downwind areas. The EPA used air
quality modeling of emissions in each
state to estimate the ambient impacts.
The air quality modeling platform and
approach to quantifying interstate
contributions to PM2.5 and ozone are
discussed in section IV.C.
As noted previously, 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 is discussed in
section IV.C., and directly affects the
proposed requirements of this rule. EPA
also considered whether further
reductions were necessary to ensure
continued lack of interference with
maintenance of the NAAQS over time.
EPA concluded that in light of projected
emission trends, and also considering
the emissions reductions from this
proposed rule, no further reductions are
required solely for this purpose at PM
and ozone receptors for which we are
partially or fully determining significant
contribution for the current NAAQS.
(See discussion of emissions trends in
Chapter 7 of TSD entitled ‘‘Emission
Inventories,’’ included in the docket for
this proposal.)
B. Overview of Approach To Identify
Contributing Upwind States
This section describes EPA’s proposal
to require reductions in upwind
emissions of SO2 and NOX to address
PM2.5 transport and to require
reductions in upwind emissions of NOX
to address ozone-related transport. In
addition, this section provides an
overview of EPA’s approach to
identifying which states are subject to
a. For the CAIR, how did EPA determine
which pollutants were necessary to
control to address interstate transport
for PM2.5?
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1. Background
Section II of the January 2004 CAIR
proposal summarized key scientific and
technical aspects of the occurrence,
formation, and origins of PM2.5, as well
as findings and observations relevant to
formulating control approaches for
reducing the contribution of transport to
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fine particle problems (69 FR 4575–87).
Key concepts and provisional
conclusions drawn from this discussion
were summarized as follows in the
preamble to the final CAIR:
(1) Fine particles (measured as PM2.5
for the NAAQS) consist of a diverse
mixture of substances that vary in size,
chemical composition, and source. The
PM2.5 includes both ‘‘primary’’ particles
that are emitted directly to the
atmosphere as particles, and
‘‘secondary’’ particles that form in the
atmosphere through chemical reactions
from gaseous precursors. The major
components of fine particles in the
eastern U.S. can be grouped as follows:
Carbonaceous material (including both
primary and secondary organic carbon
and black carbon); sulfates; nitrates;
ammonium; and crustal material, which
includes suspended dust as well as
some other directly emitted materials.
The major gaseous precursors of PM2.5
include SO2, NOX, NH3, and certain
volatile organic compounds.
(2) Examination of urban and rural
monitors indicate that in the eastern
U.S., sulfates, carbonaceous material,
nitrates, and ammonium associated with
sulfates and nitrates are typically the
largest components of transported
PM2.5, while crustal material tends to be
only a small fraction.
(3) Atmospheric interactions among
particulate ammonium sulfates and
nitrates and gas phase nitric acid and
ammonia vary with temperature,
humidity, and location. Both ambient
observations and modeling simulations
suggest that regional SO2 reductions are
effective at reducing sulfate and
associated ammonium, and, therefore,
PM2.5. Under certain conditions
reductions in particulate ammonium
sulfates can release ammonia as a gas,
which then reacts with gaseous nitric
acid to form nitrate particles, a
phenomenon called ‘‘nitrate
replacement.’’ In such conditions SO2
reductions would be less effective in
reducing PM2.5, unless accompanied by
reductions in NOX emissions to address
the potential increase in nitrates.
(4) Reductions in ammonia can
reduce the ammonium, but not the
sulfate portion of sulfate particles. The
relative efficacy of reducing nitrates
through NOX or ammonia control varies
with atmospheric conditions; the
highest particulate nitrate
concentrations in the East tend to occur
in cooler months and regions. At
present, our knowledge about sources,
emissions, control approaches, and
costs is greater for NOX than for
ammonia. Measures to reduce NOX from
stationary and mobile sources have been
implemented for more than 20 years.
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From a chemical perspective, as NOX
reductions accumulate relative to
ammonia, the atmospheric chemical
system would move towards an
equilibrium in which ammonium nitrate
reductions become more responsive to
further NOX reductions relative to
ammonia reductions.
(5) Much less is known about the
sources of regional transport of
carbonaceous material. Key
uncertainties include how much of this
material is due to biogenic as compared
to anthropogenic sources, and how
much is directly emitted as compared to
formed in the atmosphere.
Based on the understanding of current
scientific and technical information, as
well as EPA’s air quality modeling, as
summarized in the CAIR proposal, EPA
concluded that it was both appropriate
and necessary to focus on control of SO2
and NOX emissions as the most effective
approach to reducing the contribution of
interstate transport to PM2.5.
For the CAIR, the EPA did not include
emissions controls that affect 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). For all of
these components, the lack of
knowledge of and ability to quantify
accurately the interstate transport of
these components limited EPA’s ability
to include these components in the
CAIR.
b. For the CAIR, how did EPA
determine which pollutants were
necessary to control to address interstate
transport for ozone?
In the notice of proposed rulemaking
for the CAIR, EPA provided the
following characterization of the origin
and distribution of 8-hour ozone air
quality problems:
The ozone present at ground level as
a principal component of
photochemical smog is formed in sunlit
conditions through atmospheric
reactions of two main classes of
precursor compound: VOCs and NOX
(mainly NO and NO2). The term ‘‘VOC’’
includes many classes of compounds
that possess a wide range of chemical
properties and atmospheric lifetimes,
which help determine their relative
importance in forming ozone. Sources of
VOCs include man-made sources such
as motor vehicles, chemical plants,
refineries, and many consumer
products, but also natural emissions
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45235
from vegetation. Nitrogen oxides
contributing to ozone formation are
emitted by motor vehicles, power
plants, and other combustion sources,
with lesser amounts from natural
processes including lightning and soils.
Key aspects of current and projected
inventories for NOX and VOC are
summarized in section IV of the
proposal notice and EPA Web sites (e.g.,
https://www.gov/ttn/chief.) The relative
importance of NOX and VOC in ozone
formation and control varies with localand time-specific factors, including the
relative amounts of VOC and NOX
present. In rural 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 largescale stagnation, 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 would
be most effective, whereas VOC
reductions are most effective in more
dense urbanized areas.
Studies conducted in the 1970s
established that ozone occurs on a
regional scale (i.e., 1,000s 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: https://www.epa.gov/airmarkets/
progress/progress-reports.html.
In the notice of proposed rulemaking
for CAIR, EPA noted that we continue
to rely on the assessment of ozone
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transport made in great depth by the
OTAG in the mid-1990s. As indicated in
the NOX SIP Call proposal, the OTAG
Regional and Urban Scale Modeling and
Air Quality Analysis Work Groups
concluded that regional NOX emissions
reductions are effective in producing
ozone benefits; the more NOX reduced,
the greater the benefit.
More recent assessments of ozone, for
example those conducted for the
Regulatory Impact Analysis for the
ozone standards in 2008, continue to
show the importance of NOX transport.
Information on these analyses can be
found at EPA’s Web site at: https://
www.epa.gov/ttn/ecas/regdata/RIAs/
452_R_08_003.pdf.
For addressing interstate ozone
transport in the CAIR, EPA addressed
NOX emissions, 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. The EPA expects
that states will need to examine the
extent to which VOC emissions affect
ozone pollution levels across state lines,
and identify areas where multi-state
VOC strategies might assist in meeting
the 8-hour standard, in planning for
attainment.
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c. For the CAIR, which thresholds were
used to identify states included under
the rule?
(1) Fine Particles
In the CAIR, EPA used as the metric
for identifying a state as significantly
contributing (depending upon further
consideration of costs) to downwind
nonattainment, the predicted change,
due to the upwind state’s NOX and SO2
emissions, in annual19 PM2.5
concentration in the downwind
nonattainment area that receives the
largest ambient impact. The EPA
proposed this metric in the form of a
range of alternatives for a ‘‘bright line,’’
that is, air quality impacts at or greater
than the chosen threshold level
indicated that the upwind state’s
emissions do contribute significantly
(depending on cost considerations), and
that air quality impacts below the
threshold indicate that the upwind
state’s emissions do not contribute
significantly to nonattainment.
This metric addresses how much each
state contributes to a downwind
neighbor. EPA does not believe that a
particular upwind state must contribute
to multiple downwind receptors to be
required to make emissions reductions
19 For the CAIR, 24-hour PM
2.5 was not at issue
because there were little or no exceedances of the
then-existing 65 μg/m3 24-hour standards
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under CAA section 110(a)(2)(D). Under
this provision, an upwind state must
include in the SIP adequate provisions
that prohibit that state’s emissions that
‘‘contribute significantly to
nonattainment in * * * any other State
* * *’’ 42 U.S.C. 7410(a)(2)(D)(i)(I). Our
interpretation of this provision is that
the emphasized terms make clear that
the upwind state’s emissions must be
controlled as long as they contribute
significantly to a single nonattainment
area.
As discussed in section II of the
preamble to the final CAIR, EPA’s
approach to evaluating a state’s impact
on downwind nonattainment
considered the entirety of the state’s SO2
and NOX emissions, rather than treating
them separately. We believed this
approach was consistent with the
chemical interactions in the atmosphere
of SO2 and NOX in forming PM2.5. The
contributions of SO2 and NOX emissions
are generally not additive, but rather are
interrelated due to complex chemical
reactions.
In the CAIR proposal, EPA proposed
to establish a state-level annual average
PM2.5 contribution threshold from
anthropogenic SO2 and NOX emissions
that was a small percentage of the
annual air quality standard of 15.0 μg/
m3. The EPA based this proposal on the
general concept that an upwind state’s
contribution of a relatively low level of
ambient impact should be regarded as
significant (depending on the further
assessment of the control costs). We
based our reasoning on several factors.
The EPA’s modeling indicates that at
least some nonattainment areas will find
it difficult to attain the standards
without reductions in upwind
emissions. In addition, our 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. In the NOX SIP Call
rulemaking, we termed this pattern of
contribution—which is also present for
ozone nonattainment—‘‘collective
contribution.’’
In the case of PM2.5, we have found
collective contribution to be a
pronounced feature of the PM2.5
transport problem, in part because the
annual nature of the PM2.5 NAAQS
means that throughout the entire year
and across a range of wind patterns—
rather than during just one season of the
year or on only the few worst days
during the year which may share a
prevailing wind direction—emissions
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from many upwind states affect the
downwind nonattainment area.
As a result, to address the transport
affecting a given nonattainment or
maintenance area, many upwind states
must reduce their emissions, even
though their individual contributions
may be relatively small. As a result, for
the CAIR EPA determined that a
relatively low value for the PM2.5
transport contribution threshold was
appropriate. For the final CAIR EPA
decided to apply a threshold of 0.20 μg/
m3, such that any model result that is
below this value (0.19 or less) indicates
a lack of significant contribution, while
values of 0.20 or higher exceeded the
threshold.
(2) Ozone
For the CAIR ozone program, in
assessing the contribution of upwind
states to downwind 8-hour ozone
nonattainment, EPA followed the
approach used in the NOX SIP Call and
employed the same contribution
metrics, but with an updated model and
updated inputs.
The air quality modeling approach we
proposed to quantify the impact of
upwind emissions included two
different methodologies: Zero-out and
source apportionment. EPA applied
each methodology to estimate the
impact of all of the upwind state’s
anthropogenic NOX and VOC emissions
on each downwind nonattainment area.
The EPA’s first step in evaluating the
results of these methodologies was to
remove from consideration those states
whose upwind contributions were very
low. Specifically, EPA considered an
upwind state not to contribute
significantly to a downwind
nonattainment area if the state’s
maximum contribution to the area was
either (1) less than 2 ppb; or (2) less than
one percent of total nonattainment in
the downwind area; as indicated by
either of the two modeling techniques.
If the upwind state’s impact exceeded
these thresholds, then EPA conducted a
further evaluation to determine if the
impact was high enough to meet the air
quality portion of the ‘‘contribute
significantly’’ standard. In doing so, EPA
organized the outputs of the two
modeling techniques into a set of
‘‘metrics.’’ The metrics reflect three key
contribution factors:
• The magnitude of the contribution
(actual amount of ozone contributed by
emissions in the upwind state to
nonattainment in the downwind area);
• The frequency of the contribution
(how often contributions above certain
thresholds occur); and
• The relative amount of the
contribution ( the total ozone
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contributed by the upwind state
compared to the total amount of
nonattainment ozone in the downwind
area).
2. Approach for Proposed Rule
a. Which pollutants do we propose to
control?
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For the proposed rule, EPA believes
that the conclusions and findings in the
final CAIR regarding the nature of
pollutant contributions are still
appropriate. EPA proposes to continue
to focus the PM2.5 transport
requirements on SO2 and NOX transport,
and the ozone transport requirements on
NOX.
EPA recognizes that, in some
circumstances, the state’s NOX
contribution to PM2.5 in downwind
states may be considerably smaller than
the state’s SO2 contribution to PM2.5 in
downwind states. In addition, for
monitors in EPA’s speciation trends
network that are located in southern
states with warmer climates, the level of
monitored nitrates can be very small.
For these states, it is possible that
annual NOX controls, within levels that
could realistically be achieved, would
result in a very small change in ambient
PM2.5 levels. EPA considered
identifying states where this was the
case. For a number of reasons, we
propose not to take this course of action.
First, these states can impact downwind
states in cooler climates, and thus
impact nitrate formation in those
downwind states. For example, EPA
modeling results show that Georgia’s
emissions are linked to Ohio, Maryland,
New Jersey, and Pennsylvania where
monitored nitrates are higher. Second,
EPA is concerned with the possibility
for the ‘‘nitrate replacement’’ effect
described previously. That is, there is a
possibility for increases in nitrate
particles if SO2 emissions decrease
without accompanying decreases in
NOX. Third, EPA believes that there
would be important disbenefits to
relaxing annual NOX requirements in
those states. If for those states, EPA were
to relax the annual NOX requirements
currently required for their contribution
to PM2.5, annual NOX emissions would
increase, with potentially harmful
effects on visibility and nitrogen
deposition.
b. Thresholds
For the proposed rule, as for CAIR,
EPA uses air quality thresholds to
identify states whose contributions do
not warrant transport requirements. We
propose air quality thresholds for
annual PM2.5, 24-hour PM2.5, and 8-hour
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ozone. Each threshold is based on 1
percent of the NAAQS.
As we found at the time of the 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. For
ozone, as we found in the CAIR and the
SIP call, we also found important
contributions from multiple upwind
states. In short, EPA continues to find
an upwind ‘‘collective contribution’’ that
is important to both PM2.5 and ozone.
A second reason that low threshold
values are warranted, as EPA discussed
in the notices for the CAIR, is that there
are adverse health impacts associated
with ambient PM2.5 and ozone even at
low levels. See relevant portions of the
CAIR proposal notice (63 FR 4583–84)
and the CAIR final rule notice (70 FR
25189–25192).
For annual PM2.5 for the final CAIR,
as noted previously, EPA decided to use
a single-digit value, 0.2 μg/m3, rather
than the two-digit value in the proposed
CAIR, 0.15 μg/m3. The rationale for the
single digit value for the final rule was
that a single digit is consistent with the
EPA monitoring requirements in part
50, appendix N, section 4.3. The
reporting requirements for annual PM2.5
require that:
Annual PM2.5 standard design values shall
be rounded to the nearest 0.1 μg/m3
(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 μg/m3,
EPA deemed it preferable for the final
CAIR to select the threshold value at the
nearest 0.1 μg/m3 as well, and hence
one percent of the 15 μg/m3, rounded to
the nearest 0.1 μg/m3 became 0.2 μg/m3.
For the 24-hour standard of 35 μg/m3,
we attempted to apply the same
rationale for determining a single-digit
air quality threshold. That is, we
applied rounding conventions in Part
50, Appendix N to a value representing
one percent of the NAAQS. The
rounding requirements for the 24-hour
standard are indicated in section 4.3 as
follows:
24-hour PM2.5 standard design values shall
be rounded to the nearest 1 μg/m3 (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).
One percent of the 24-hour standard
is 0.35 μg/m3, and rounding to the
PO 00000
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Sfmt 4702
45237
nearest whole μg/m3 would yield an air
quality threshold of zero. Thus applying
the same rationale for the final CAIR,
there would be no air quality threshold
for 24-hour PM2.5, which EPA believes
to be counterintuitive and unworkable
as an approach for assessing interstate
contributions.
For the proposed rule, EPA proposes
to decouple the precision of the air
quality thresholds with the monitoring
reporting requirements, and to use
2-digit values representing one percent
of the NAAQS, that is, 0.15 μg/m3 for
the annual standard, and 0.35 μg/m3 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
approach is readily applicable to any
current and future NAAQS. 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 μg/m3 would reduce the air
quality threshold to 0.1 μg/m3. This
would occur because any value less
than 0.15 μg/m3 (e.g., 0.14 μg/m3) would
be rounded down to 0.1 μg/m3. EPA
finds it within its discretion to adjust its
approach to account for the additional
considerations that were not in
existence at the time of the final CAIR.
For the proposal, EPA is proposing to
take a more straightforward approach to
air quality thresholds for ozone than the
multi-factor approach we used for the
NOX SIP Call or for the CAIR. The
proposed approach uses a single ‘‘bright
line’’ threshold for ozone that is one
percent of the 1997 8-hour ozone
standard of 0.08 ppm. As described later
in section IV.C, the 1 percent threshold
is averaged over multiple model days.
EPA believes this to be a robust metric
compared to previous metrics which
might have relied on the maximum
contribution on a single day. Under this
approach, one percent of the NAAQS is
a value of 0.8 ppb. State contributions
of 0.8 ppb and higher are above the
threshold; ozone contributions less than
0.8 ppb are below the threshold. EPA
believes that this approach is preferable
because it is a robust metric, it is
consistent with the approach for PM2.5,
and because it provides for a consistent
approach that takes into account, and is
applicable to, any future ozone
standards below 0.08 ppm.
EPA seeks comment on the pollutants
and air quality thresholds used for
identifying states to be included under
the proposed rule. In particular, EPA
requests comment on alternatives to the
1 percent threshold. In addition, EPA
requests comment on whether EPA
should use the same rounding
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Federal Register / Vol. 75, No. 147 / Monday, August 2, 2010 / Proposed Rules
convention that was used in the final
CAIR for the 15 μg/m3 annual PM2.5
standard, or whether commenters agree
with EPA’s approach that does not use
this rounding convention. To identify
the potential effect of alternative
thresholds for the annual PM2.5
standard, see Table IV.C–13 (showing
state specific contributions to areas with
annual PM2.5 nonattainment and
maintenance issues) and Table IV.C–16
(showing state specific contributions to
areas with 24-hour PM2.5 nonattainment
and maintenance issues).
C. Air Quality Modeling Approach and
Results
erowe on DSK5CLS3C1PROD with PROPOSALS2
1. What air quality modeling platform
did EPA use?
a. Introduction
In this section, we describe the air
quality modeling performed to support
the proposed rule. We used air quality
modeling to (1) identify locations where
we expect there to be nonattainment or
maintenance problems for annual
average PM2.5, 24-hour PM2.5, and/or
8-hour ozone for the analytic years
chosen for this proposal, (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, (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, and (4) assess the health and
welfare benefits of the emissions
reductions expected to result from this
proposal. This section includes
information on the air quality model
applied in support of the proposed rule,
the meteorological and emissions inputs
to these models, the evaluation of the air
quality model compared to measured
concentrations, and the procedures for
projecting ozone and PM2.5
concentrations for future year scenarios.
We also provide in this section the
interstate contributions for annual
average and 24-hour PM2.5, and 8-hour
ozone. The Air Quality Modeling
Technical Support Document
(AQMTSD) contains more detailed
information on the air quality modeling
aspects of this rule.
To support the proposal, air quality
modeling was performed for four
emissions scenarios: A 2005 base year,
a 2012 ‘‘no CAIR’’ base case, a 2014 ‘‘no
CAIR’’ base case, and a 2014 control case
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that reflects the emissions reductions
expected from the proposed FIPs. The
remedy proposed for inclusion in the
FIPs is described in section V.D. 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 2014 base
case and 2014 control case modeling
were used to quantify the benefits of
this proposal.
For CAIR, EPA used the
Comprehensive Air Quality Model with
Extensions (CAMx) version 5 20 to
simulate ozone and PM2.5
concentrations for the 2005 base year
and the 2012 and 2014 future year
scenarios. In contrast, for the CAIR EPA
used two air quality models, CAMx
version 3.1 for modeling ozone and the
Community Multiscale Air Quality
Model (CMAQ) version 4.3 for modeling
PM2.5. Both CAMx and CMAQ are grid
cell-based, multi-pollutant
photochemical models that simulate the
formation and fate of ozone and fine
particles in the atmosphere. The use of
one model for both pollutants, as we
have done for this proposal, provides a
more scientifically integrated ‘‘one
atmosphere’’ approach versus using
different models for ozone and PM2.5. In
addition, using a single model rather
than two models is computationally
more efficient. 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.21 The modeling region (i.e.,
modeling domain) extends from Texas
northward to North Dakota and
eastward to the East Coast and includes
37 states and the District of Columbia.
A map of the air quality modeling
domain is provided in the AQMTSD.
Both CAMx and CMAQ contain
certain 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 CAMx model was chosen
for use in this proposal because the
source apportionment tools in this
20 Comprehensive Air Quality Model with
Extensions Version 5 User’s Guide. Environ
International Corporation. Novato, CA. March 2009.
21 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.
PO 00000
Frm 00030
Fmt 4701
Sfmt 4702
model have had extensive use and
evaluation by states and industry. Also,
the source apportionment tools in
CAMx received favorable comments in
a recent peer review.22
The 2005-based air quality modeling
platform used for the proposal includes
2005 base year emissions and 2005
meteorology for modeling ozone and
PM2.5 with CAMx. This platform
provides an update to the now more
historical data in the 2001-based
platform used for CAIR that included
2001 emissions, 2001 meteorology for
modeling PM2.5, and 1995 meteorology
for modeling ozone. In the remainder of
this section we provide an overview of
(1) the emissions and meteorological
components of the 2005-based platform,
(2) the methods for projecting future
nonattainment and maintenance along
with a list of 2012 base case
nonattainment and maintenance
locations, (3) the approach to
developing metrics to measure interstate
contributions to annual and 24-hour
PM2.5 and ozone, and (4) the predicted
interstate contributions to downwind
nonattainment and maintenance. We
also identify which predicted interstate
contributions are at or above the air
quality impact thresholds described
previously in section IV.B.
b. Emissions Inventories
Emissions estimates were made for a
2005 base year and for 2012 and 2014.
All inventories include emissions from
EGUs, nonEGU point sources, stationary
nonpoint sources, onroad mobile
sources, and nonroad mobile sources.
When emissions were only available at
annual or monthly temporal resolutions,
emissions modeling steps were applied
to estimate hourly emissions. Point
source emissions were assigned to
modeling grid cells based on latitude
and longitude in the inventory, and
county total emissions were allocated to
grid cells. Emissions of NOX, VOCs and
PM2.5 were split into their component
species using other data sources, to
provide the modeling species needed by
CAMx. Elevated point sources were
identified for simulating releases of
emissions from those sources in layers
2 and higher in CAMx. In addition to
the anthropogenic emission sources
described previously, hourly, gridded
biogenic emissions were estimated for
individual modeling days using the
BEIS model version 3.14.23 24 The same
22 Arunachalam, S. Peer Review of Source
Apportionment Tools in CAMx and CMAQ, EP–D–
07–102. University of North Carolina, Institute for
the Environment, August 2009.
23 Pouliot, G., Pierce., T. ‘‘A Tale of Two Models:
A comparison of the Biogenic Emission Inventory
System (BEIS) and Model of Emissions of Gases and
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Federal Register / Vol. 75, No. 147 / Monday, August 2, 2010 / Proposed Rules
biogenic emissions data were used in all
scenarios modeled.
(1) Development of 2005 Base Year
Emissions
Emissions inventory inputs
representing the year 2005 were
developed to provide a base year for
forecasting future air quality, described
in section IV.C.2. The 2005 National
Emission Inventory (NEI), version 2
from October 6, 2008, was the starting
point for the U.S. inventories used for
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.
In addition, a 2006 Canadian inventory
and a 1999 Mexican inventory were
used for the portions of Canada and
Mexico within the modeling domains.
Additional details on these inventories
and the augmentation described here are
available from the Emissions Inventory
Technical Support Document (EITSD)
for the Transport Rule.
The onroad and nonroad emissions
were primarily based on the National
Mobile Inventory Model (NMIM)
monthly, county, process level
emissions from the 2005 NEI v2. The
2005 onroad mobile emissions were
augmented for onroad gasoline
emissions sources with emissions based
on a draft version of the Motor Vehicle
Emissions Simulator (MOVES) for
carbon monoxide (CO), NOX, VOC,
PM2.5, and particulate matter less than
ten microns (PM10). While these data
were preliminary, they more closely
reflect the PM2.5 emissions from the
final release of MOVES 2010. To
account for the temperature dependence
of PM2.5, MOVES-based temperature
adjustment factors were applied to
gridded, hourly emissions using
gridded, hourly meteorology. Additional
information on this approach is
available in the EITSD.
The annual NOX and SO2 emissions
for EGUs in the 2005 NEI v2 are based
primarily on data from EPA’s Clean Air
Markets Division’s Continuous
Emissions Monitoring (CEM) program,
with other pollutants estimated using
emission factors and the CEM annual
heat input. For EGUs without CEMs,
data were obtained from the states as
included in the NEI. For modeling, the
2005 EGU emissions for SO2 and NOX
were augmented by using hourly CEM
data to develop a temporal allocation
approach of the 2005 NEI v2 emissions.
The annual emissions themselves were
unchanged, and match closely with data
from the CEM program except where
states have provided data for partial
CEM and non-CEM units. The 2005
EGUs were identified as all units in
2005 that map to the units modeled by
the version of the Integrated Planning
Model (IPM) used for this proposal, and
include records both with and without
data submitted to the CEM program.
Temporal profiles were used instead of
the actual 2005 CEM data so that the
temporal allocation approach could be
consistent in the future year modeling.
For the 2005 base year, the annual
EGU NEI emissions were allocated to
hourly emissions values needed for
modeling based on the 2004, 2005, and
2006 CEM data. The NOX CEM data
were used to create NOX-specific
profiles, the SO2 data were used to
create SO2-specific profiles, and the heat
input data were used to allocate all
other pollutants. The 3 years of data
were used to create state-specific
profiles to allocate from annual to
monthly values and from daily to hourly
values. Only the 2005 data were used to
create state-specific factors for
allocation from month to day, which is
intended to preserve an appropriate
level of daily temporal variability
needed for this type of modeling.
Other significant augmentations were
also made to the 2005 NEI and include
the following. The nonpoint inventory
was augmented with the oil and gas
exploration inventory 25 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. The
commercial marine category 3 (C3)
vessel 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.’’ The
2005 point source daily wildfire and
prescribed burning emissions were
replaced with average-year countybased inventories. Additionally, the
inventories were processed to provide
the hourly, gridded, model-species
needed by CAMx.
Tables IV.C–1 and IV.C–2 provide
summaries of SO2 and NOX emissions
by state by sector for the 2005 base year
for those states within the eastern 12 km
modeling domain. Emissions for other
states within the 36 km modeling
domain are available in the EISTD. In
the tables, the EGU column summarizes
all units matched to the IPM model and
the nonEGU column is for other point
source units. The Nonpoint column
shows emissions for all nonpoint
stationary sources. The Nonroad column
summarizes emissions for nonroad
mobile sources, including aircraft,
locomotive, and marine sources
including the C3 commercial marine.
The Onroad column summarizes
emissions for the combined NEI and
draft MOVES-based emissions, in which
emissions from the draft MOVES were
used when available, and NEI emissions
based on MOBILE6 were used for the
remainder. Finally, the Fires column
represents the average-year fire
emissions for wildfires and prescribed
burning mentioned previously.
TABLE IV.C–1—2005 BASE CASE SO2 EMISSIONS (TONS/YEAR) FOR EASTERN STATES BY SECTOR
erowe on DSK5CLS3C1PROD with PROPOSALS2
State
EGU
Alabama ...................................................
Arkansas ..................................................
Connecticut ..............................................
Delaware ..................................................
District of Columbia ..................................
Florida ......................................................
Georgia ....................................................
Illinois .......................................................
Indiana .....................................................
Iowa ..........................................................
Kansas .....................................................
460,123
66,384
10,356
32,378
1,082
417,321
616,054
330,382
878,978
130,264
136,520
Aerosols from Nature (MEGAN),’’ 7th Annual
Community Multiscale Analysis System
Conference, Chapel Hill, NC, October 6–8, 2008.
VerDate Mar<15>2010
20:42 Jul 30, 2010
Jkt 220001
NonEGU
70,346
13,066
1,831
34,859
686
57,475
56,116
156,154
95,200
61,241
13,142
Nonpoint
52,325
27,260
18,455
5,859
1,559
70,490
56,829
5,395
59,775
19,832
36,381
Nonroad
6,397
5,678
2,548
11,648
414
93,543
13,331
19,302
9,436
8,838
8,035
24 Donna Schwede, D., Pouliot, G., and Pierce, T.
‘‘Changes to the Biogenic Emissions Inventory
System Version 3 (BEIS3),’’ 4th Annual Community
PO 00000
Frm 00031
Fmt 4701
Sfmt 4702
Onroad
3,199
1,632
1,128
422
172
10,285
5,690
5,716
3,981
1,702
1,824
Fires
983
728
4
6
0
7,018
2,010
20
24
25
103
Total
593,372
114,749
34,320
85,173
3,914
656,131
750,031
516,969
1,047,396
221,902
196,005
Multiscale Analysis System Conference, Chapel
Hill, NC, September 26–28, 2005.
25 The oil and gas exploration inventory was
provided by the Western Regional Air Partnership.
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Federal Register / Vol. 75, No. 147 / Monday, August 2, 2010 / Proposed Rules
TABLE IV.C–1—2005 BASE CASE SO2 EMISSIONS (TONS/YEAR) FOR EASTERN STATES BY SECTOR—Continued
State
EGU
NonEGU
Nonpoint
Nonroad
Onroad
Fires
Total
Kentucky ..................................................
Louisiana ..................................................
Maine .......................................................
Maryland ..................................................
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 ............................................
Wisconsin .................................................
502,731
109,851
3,887
283,205
85,768
349,877
101,666
74,117
284,384
74,955
51,445
57,044
180,847
512,231
137,371
1,116,084
110,081
1,002,202
176
218,782
12,215
266,148
534,949
9
220,248
469,456
180,200
25,811
165,737
18,519
34,988
19,620
76,510
25,169
29,892
78,307
6,429
3,245
7,640
58,562
66,150
9,458
118,468
40,482
85,411
2,743
31,495
1,698
78,206
223,625
902
69,440
48,314
66,807
34,229
2,378
9,969
40,864
25,261
42,066
14,747
6,796
44,573
29,575
7,408
10,726
125,158
22,020
6,455
19,810
7,542
68,349
3,365
30,016
10,347
32,714
109,215
5,385
32,923
14,589
6,369
6,942
73,233
3,725
17,819
25,335
14,533
10,410
6,003
10,464
9,199
805
23,484
20,908
42,743
5,986
15,615
5,015
11,972
2,494
20,477
3,412
6,288
52,749
385
18,420
2,133
7,129
2,711
2,399
834
2,966
2,168
7,204
2,558
2,158
4,251
1,326
630
2,486
5,628
5,341
443
6,293
2,699
5,363
208
2,976
511
4,834
13,470
305
3,829
1,095
3,110
364
892
150
32
93
91
631
1,051
186
105
38
61
113
696
66
22
469
32
1
646
498
277
1,178
49
399
215
70
572,787
354,489
37,084
379,874
158,245
490,280
155,181
120,016
422,165
121,589
63,571
101,441
391,216
649,181
159,779
1,276,292
166,288
1,173,328
8,987
304,393
28,682
388,468
935,187
7,036
345,259
535,802
263,685
Grand total ........................................
10,019,774
1,953,745
1,117,009
596,847
123,547
19,345
13,380,267
TABLE IV.C–2—2005 BASE CASE NOX EMISSIONS (TONS/YEAR) FOR EASTERN STATES BY SECTOR
erowe on DSK5CLS3C1PROD with PROPOSALS2
State
EGU
Alabama ...................................................
Arkansas ..................................................
Connecticut ..............................................
Delaware ..................................................
District of Columbia ..................................
Florida ......................................................
Georgia ....................................................
Illinois .......................................................
Indiana .....................................................
Iowa ..........................................................
Kansas .....................................................
Kentucky ..................................................
Louisiana ..................................................
Maine .......................................................
Maryland ..................................................
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 ............................................
VerDate Mar<15>2010
15:19 Jul 30, 2010
Jkt 220001
NonEGU
133,051
35,407
6,865
11,917
492
217,263
111,017
127,923
213,503
72,806
90,220
164,743
63,791
1,100
62,574
25,618
120,005
83,836
45,166
127,431
52,426
8,827
30,114
63,465
111,576
76,381
258,687
86,204
176,870
545
53,823
15,650
102,934
176,170
297
62,512
159,804
PO 00000
Frm 00032
74,830
37,478
5,824
5,567
501
53,778
53,297
97,504
73,647
39,299
70,785
35,432
165,162
18,309
24,621
18,429
94,139
64,438
53,985
38,604
12,156
3,241
20,598
55,122
44,502
7,545
71,715
73,465
89,208
2,164
29,069
5,035
60,353
292,806
799
60,101
36,913
Fmt 4701
Nonpoint
32,024
21,453
12,554
3,259
1,740
29,533
38,919
47,645
30,185
15,150
42,286
17,557
27,559
7,423
21,715
34,373
43,499
56,700
12,212
32,910
13,820
11,235
26,393
87,608
18,869
10,046
41,466
94,574
53,435
2,964
20,281
5,766
18,676
274,338
3,438
53,605
14,519
Sfmt 4702
Nonroad
61,623
63,493
21,785
15,567
3,494
277,888
95,175
223,697
110,100
92,965
86,553
90,669
301,170
13,379
55,812
74,419
101,087
115,873
79,394
123,228
107,180
9,246
88,486
121,363
135,936
59,635
173,988
55,424
118,774
7,798
68,146
30,324
82,331
377,246
3,951
91,298
32,739
E:\FR\FM\02AUP2.SGM
Onroad
142,221
81,014
69,645
22,569
9,677
460,474
279,449
276,507
187,426
91,795
76,062
127,435
112,889
38,469
129,796
118,148
279,816
146,138
98,060
183,022
58,643
32,537
157,736
282,072
225,756
21,575
270,383
117,240
266,649
13,456
128,765
24,850
207,410
615,715
13,316
194,173
50,040
02AUP2
Fires
3,814
2,654
14
23
0
25,600
7,955
71
88
90
378
1,326
3,254
566
137
341
330
2,300
3,833
678
381
137
223
412
11,424
240
81
1,709
117
4
2,357
1,817
1,012
4,890
179
1,456
785
Total
447,562
241,499
116,688
58,902
15,904
1,064,537
585,812
773,347
614,949
312,105
366,285
437,163
673,824
79,246
294,656
271,327
638,876
469,286
292,649
505,873
244,607
65,223
323,550
610,042
548,064
175,422
816,321
....................
705,053
26,930
302,441
83,442
472,717
1,741,166
21,980
463,145
294,801
45241
Federal Register / Vol. 75, No. 147 / Monday, August 2, 2010 / Proposed Rules
TABLE IV.C–2—2005 BASE CASE NOX EMISSIONS (TONS/YEAR) FOR EASTERN STATES BY SECTOR—Continued
State
EGU
NonEGU
Nonpoint
Nonroad
Onroad
Fires
Total
Wisconsin .................................................
72,170
40,688
21,994
75,981
147,952
256
359,042
Grand total ........................................
3,223,184
1,931,111
1,301,726
3,647,215
5,758,880
80,931
15,943,047
(2) Development of Future Year
Emissions
The future base case scenarios
represent predicted emissions in the
absence of any further controls beyond
those federal measures already
promulgated. For EGUs, all state and
other programs available at the time of
modeling have been included. For
mobile sources, all national measures
available at the time of modeling have
been included. For nonEGU point and
nonpoint stationary sources, any 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. The future base case
scenarios do reflect projected economic
changes and fuel usage for EGU and
mobile sectors, as described in the
EITSD.
Tables IV.C–3 through IV.C–6 provide
2012 and 2014 summaries of emissions
data for 2012 and 2014 modeling for all
sectors for SO2 and NOX for states
included in the 12 km modeling
domain. The EITSD provides summaries
for additional pollutants with additional
detail and for all states in the
nationwide 36 km modeling domain.
TABLE IV.C–3—2012 BASE CASE SO2 EMISSIONS (TONS/YEAR) FOR EASTERN STATES BY SECTOR
State
EGU
NonEGU
Nonpoint
Nonroad
Onroad
Fires
Total
335,734
85,068
5,493
7,841
0
228,360
552,007
724,657
829,988
169,039
59,567
718,980
100,239
15,759
49,078
16,299
287,807
53,596
46,432
445,643
120,790
7,290
37,746
144,074
126,620
77,383
946,667
156,032
966,136
0
149,515
13,453
596,987
327,873
0
145,452
588,392
107,365
70,346
13,054
1,831
10,974
686
57,491
56,122
133,201
95,201
61,242
13,048
25,813
159,722
18,519
34,988
19,622
76,458
25,100
24,426
78,310
6,430
3,245
6,747
58,566
66,128
9,458
105,406
36,912
79,142
2,743
31,452
1,698
77,595
162,915
902
69,166
41,817
66,452
52,315
27,257
18,443
5,858
1,559
70,482
56,817
5,384
59,767
19,821
36,376
34,214
2,373
9,950
40,854
25,242
42,066
14,733
6,788
44,550
29,571
7,396
10,715
125,187
22,000
6,451
19,810
7,536
68,330
3,364
30,005
10,342
32,701
109,199
5,381
32,904
14,583
6,370
2,333
818
1,292
14,193
10
102,076
7,984
1,960
871
482
518
1,368
78,051
3,926
17,112
29,825
7,636
1,342
2,094
1,307
817
72
25,286
12,336
48,861
288
3,456
341
4,938
2,879
22,697
65
828
37,109
6
15,158
443
928
585
336
330
98
41
2,072
1,253
1,174
775
346
302
510
455
156
608
575
1,074
596
375
765
209
142
772
1,541
935
76
1,131
502
1,135
82
532
91
795
2,409
94
883
197
646
983
728
4
6
0
7,018
2,010
20
24
25
103
364
892
150
32
93
91
631
1,051
186
105
38
61
113
696
66
22
469
32
1
646
498
277
1,178
49
399
215
70
462,297
127,259
27,392
38,970
2,296
467,498
676,193
866,396
986,626
250,954
109,915
781,249
341,731
48,460
142,672
91,657
415,132
95,997
81,166
570,761
157,921
18,183
81,327
341,818
265,240
93,722
1,076,493
201,791
1,119,712
9,069
234,846
26,147
709,182
640,682
6,432
263,963
645,646
181,830
Grand total ........................................
erowe on DSK5CLS3C1PROD with PROPOSALS2
Alabama ...................................................
Arkansas ..................................................
Connecticut ..............................................
Delaware ..................................................
District of Columbia ..................................
Florida ......................................................
Georgia ....................................................
Illinois .......................................................
Indiana .....................................................
Iowa ..........................................................
Kansas .....................................................
Kentucky ..................................................
Louisiana ..................................................
Maine .......................................................
Maryland ..................................................
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 ............................................
Wisconsin .................................................
9,243,362
1,802,927
1,116,694
451,705
24,595
19,345
12,658,628
TABLE IV.C–4—2012 BASE CASE NOX EMISSIONS (TONS/YEAR) FOR EASTERN STATES BY SECTOR
State
EGU
Alabama ...................................................
Arkansas ..................................................
Connecticut ..............................................
VerDate Mar<15>2010
15:19 Jul 30, 2010
Jkt 220001
NonEGU
121,809
43,222
2,770
PO 00000
Frm 00033
74,832
37,479
5,830
Fmt 4701
Nonpoint
31,958
21,429
12,475
Sfmt 4702
Nonroad
49,622
48,349
15,865
E:\FR\FM\02AUP2.SGM
Onroad
82,135
46,959
37,847
02AUP2
Fires
3,814
2,654
14
Total
364,171
200,092
74,801
45242
Federal Register / Vol. 75, No. 147 / Monday, August 2, 2010 / Proposed Rules
TABLE IV.C–4—2012 BASE CASE NOX EMISSIONS (TONS/YEAR) FOR EASTERN STATES BY SECTOR—Continued
State
EGU
NonEGU
Nonpoint
Nonroad
Onroad
Fires
Total
Delaware ..................................................
District of Columbia ..................................
Florida ......................................................
Georgia ....................................................
Illinois .......................................................
Indiana .....................................................
Iowa ..........................................................
Kansas .....................................................
Kentucky ..................................................
Louisiana ..................................................
Maine .......................................................
Maryland ..................................................
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 ............................................
Wisconsin .................................................
4,639
2
195,673
78,011
77,920
203,107
66,316
70,823
149,179
44,773
3,139
17,376
6,312
96,874
51,285
37,517
77,571
52,820
2,514
15,987
25,755
61,643
59,547
159,627
86,858
193,032
221
47,762
15,493
68,425
159,738
0
36,036
102,725
49,351
5,567
501
55,017
53,317
92,440
73,651
39,301
70,751
34,875
161,724
18,309
24,624
18,447
93,953
64,250
52,454
38,610
12,159
3,243
18,996
55,167
44,514
7,544
69,075
71,808
85,168
2,168
28,953
5,035
59,594
287,831
800
60,101
35,698
40,694
3,248
1,739
29,475
38,825
47,564
30,125
15,064
42,249
17,446
27,525
7,295
21,647
34,245
43,392
56,581
12,151
32,731
13,788
11,153
26,320
87,776
18,715
10,018
41,378
94,528
53,289
2,959
20,273
5,733
18,573
274,203
3,406
53,496
14,473
21,979
15,511
2,704
282,147
76,901
167,046
83,760
72,031
66,897
72,289
285,562
13,354
53,580
75,149
80,900
92,080
64,138
96,197
81,177
7,308
81,906
100,212
133,476
46,649
133,650
43,057
92,594
7,468
63,564
24,117
65,209
313,204
3,077
79,717
26,040
58,951
10,700
4,857
275,603
158,771
157,915
114,396
58,920
43,914
71,284
64,074
21,896
64,368
57,417
163,505
86,198
52,709
108,298
33,907
19,710
76,979
154,260
126,081
12,111
149,134
71,207
142,217
8,120
75,994
14,957
126,353
303,453
10,328
111,583
27,694
86,315
23
0
25,600
7,955
71
88
90
378
1,326
3,254
566
137
341
330
2,300
3,833
678
381
137
223
412
11,424
240
81
1,709
117
4
2,357
1,817
1,012
4,890
179
1,456
785
256
39,687
9,802
863,515
413,780
542,957
505,127
251,721
295,012
346,399
586,912
64,559
181,731
191,911
478,955
352,694
222,801
354,085
194,233
44,067
220,410
423,582
395,854
136,110
552,945
369,167
566,418
20,940
238,903
67,151
339,166
1,343,319
17,790
342,389
207,415
257,546
Grand Total .......................................
2,485,856
1,904,481
1,299,224
3,075,459
3,232,168
80,932
12,078,120
TABLE IV.C–5—2014 BASE CASE SO2 EMISSIONS (TONS/YEAR) FOR EASTERN STATES BY SECTOR
erowe on DSK5CLS3C1PROD with PROPOSALS2
State
EGU
Alabama ...................................................
Arkansas ..................................................
Connecticut ..............................................
Delaware ..................................................
District of Columbia ..................................
Florida ......................................................
Georgia ....................................................
Illinois .......................................................
Indiana .....................................................
Iowa ..........................................................
Kansas .....................................................
Kentucky ..................................................
Louisiana ..................................................
Maine .......................................................
Maryland ..................................................
Massachusetts .........................................
Michigan ...................................................
Minnesota .................................................
Mississippi ................................................
Missouri ....................................................
Nebraska ..................................................
New Hampshire .......................................
New Jersey ..............................................
New York .................................................
North Carolina ..........................................
North Dakota ............................................
Ohio ..........................................................
Oklahoma .................................................
Pennsylvania ............................................
VerDate Mar<15>2010
15:19 Jul 30, 2010
Jkt 220001
NonEGU
322,130
88,187
5,512
7,806
0
192,903
173,210
200,475
804,294
163,966
65,125
739,592
94,824
11,650
42,635
16,299
275,637
61,447
48,149
500,649
115,695
6,608
37,669
141,354
140,585
80,320
841,194
165,773
972,977
PO 00000
Frm 00034
69,150
13,055
1,834
10,974
686
57,521
56,014
133,109
95,037
60,195
13,048
23,804
151,216
18,520
34,994
19,624
76,437
25,112
24,427
77,086
6,431
3,246
6,756
58,584
66,046
9,458
105,123
36,924
76,256
Fmt 4701
Nonpoint
52,313
27,256
18,440
5,857
1,559
70,480
56,813
5,381
59,764
19,817
36,375
34,210
2,372
9,945
40,851
25,237
42,066
14,728
6,785
44,543
29,570
7,393
10,712
125,196
21,994
5,763
19,810
7,534
68,324
Sfmt 4702
Nonroad
1,873
142
1,294
14,891
4
108,579
8,263
390
193
85
54
258
78,097
4,215
16,966
32,043
7,536
468
1,280
214
55
45
26,589
10,853
52,897
35
2,085
45
4,117
E:\FR\FM\02AUP2.SGM
Onroad
605
347
340
101
42
2,159
1,307
1,221
810
360
313
528
470
160
631
594
1,107
618
385
796
217
148
799
1,594
961
78
1,171
524
1,169
02AUP2
Fires
983
728
4
6
0
7,018
2,010
20
24
25
103
364
892
150
32
93
91
631
1,051
186
105
38
61
113
696
66
22
469
32
Total
447,053
129,714
27,423
39,635
2,291
438,658
297,618
340,596
960,123
244,448
115,018
798,755
327,871
44,640
136,109
93,890
402,874
103,005
82,077
623,473
152,072
17,476
82,585
337,694
283,180
95,720
969,405
211,268
1,122,876
45243
Federal Register / Vol. 75, No. 147 / Monday, August 2, 2010 / Proposed Rules
TABLE IV.C–5—2014 BASE CASE SO2 EMISSIONS (TONS/YEAR) FOR EASTERN STATES BY SECTOR—Continued
State
EGU
NonEGU
Nonpoint
Nonroad
Onroad
Fires
Total
Rhode Island ............................................
South Carolina .........................................
South Dakota ...........................................
Tennessee ...............................................
Texas .......................................................
Vermont ....................................................
Virginia .....................................................
West Virginia ............................................
Wisconsin .................................................
0
156,096
13,459
600,066
373,950
0
135,741
496,307
117,253
2,745
31,453
1,699
77,605
155,720
903
69,177
41,817
66,456
3,364
30,002
10,298
32,696
109,194
5,380
32,899
14,581
6,370
3,128
24,380
22
173
36,109
7
15,624
96
638
85
551
94
829
2,511
101
918
201
675
1
646
498
277
1,178
49
399
215
70
9,323
243,129
26,070
711,647
678,662
6,439
254,758
553,218
191,461
Grand Total .......................................
8,209,536
1,778,244
1,116,600
453,742
25,516
19,345
11,602,982
TABLE IV.C–6—2014 BASE CASE NOX EMISSIONS (TONS/YEAR) FOR EASTERN STATES BY SECTOR
State
EGU
NonEGU
Nonpoint
Nonroad
Onroad
Fires
Total
Alabama ...................................................
Arkansas ..................................................
Connecticut ..............................................
Delaware ..................................................
District of Columbia ..................................
Florida ......................................................
Georgia ....................................................
Illinois .......................................................
Indiana .....................................................
Iowa ..........................................................
Kansas .....................................................
Kentucky ..................................................
Louisiana ..................................................
Maine .......................................................
Maryland ..................................................
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 ............................................
Wisconsin .................................................
118,420
44,792
2,821
4,513
1
180,801
48,091
80,228
200,899
68,146
78,920
148,509
45,457
2,535
19,990
6,619
97,455
51,859
37,142
82,979
52,970
2,515
16,268
28,350
61,747
59,556
164,945
81,122
196,151
281
47,512
15,514
68,779
166,177
0
32,115
100,103
53,774
74,622
37,491
5,854
5,567
501
55,343
53,557
93,059
73,523
38,831
70,730
34,979
161,766
18,316
24,687
18,527
94,079
64,372
52,440
38,744
12,173
3,255
19,089
55,359
44,573
7,549
69,157
72,525
84,111
2,186
28,969
5,039
59,694
282,509
803
60,216
35,700
40,729
31,939
21,422
12,451
3,245
1,738
29,457
38,797
47,540
30,107
15,038
42,238
17,413
27,515
7,257
21,626
34,207
43,360
56,545
12,133
32,677
13,779
11,129
26,298
87,826
18,669
3,969
41,352
94,513
53,246
2,957
20,271
5,157
18,542
274,163
3,397
53,464
14,459
21,974
45,932
44,299
14,410
15,270
2,398
278,920
71,011
151,373
76,024
65,751
61,613
65,805
274,697
13,169
52,501
75,654
73,939
84,040
58,559
88,233
75,252
6,587
78,875
92,841
133,455
42,972
120,900
39,539
83,885
7,384
62,400
22,021
59,145
289,605
2,771
75,461
23,798
53,848
67,011
38,965
31,534
8,736
3,929
225,478
130,240
131,403
94,217
48,836
35,950
57,759
52,360
18,061
53,040
46,748
135,806
71,161
42,525
90,001
27,856
16,260
63,254
129,376
104,150
9,925
122,426
58,382
118,122
6,772
62,996
12,254
104,711
241,009
8,563
92,291
22,863
71,163
3,814
2,654
14
23
0
25,600
7,955
71
88
90
378
1,326
3,254
566
137
341
330
2,300
3,833
678
381
137
223
412
11,424
240
81
1,709
117
4
2,357
1,817
1,012
4,890
179
1,456
785
256
341,738
189,623
67,084
37,353
8,568
795,599
349,650
503,676
474,858
236,692
289,829
325,791
565,049
59,903
171,980
182,095
444,969
330,278
206,633
333,312
182,410
39,884
204,007
394,165
374,018
130,252
518,861
347,790
535,631
19,585
224,505
62,368
311,882
1,258,354
15,713
315,002
197,708
241,743
Grand total ........................................
2,468,057
1,900,624
1,298,473
2,884,338
2,656,134
80,932
11,288,558
erowe on DSK5CLS3C1PROD with PROPOSALS2
Development of Future-Year Emissions
Inventories for Electric Generating Units
Future year 2012 and 2014 base case
EGU emissions used for the air quality
modeling runs that predicted ozone and
PM2.5 were obtained from version 3.02
EISA of the IPM (https://www.epa.gov/
airmarkt/progsregs/epa-ipm/
index.html). The IPM is a multiregional,
dynamic, deterministic linear
VerDate Mar<15>2010
15:19 Jul 30, 2010
Jkt 220001
programming model of the U.S. electric
power sector; version 3.02 EISA features
an updated Title IV SO2 allowance bank
assumption, reflects state rules and
consent decrees through February 3,
2009, and incorporates updates related
to the Energy Independence and
Security Act of 2007. Units with
advanced controls (e.g., scrubber, SCR)
that were not required to run for
compliance with Title IV, New Source
PO 00000
Frm 00035
Fmt 4701
Sfmt 4702
Review (NSR), state settlements, or
state-specific rules were allowed in IPM
to decide on the basis of economic
efficiency whether to operate those
controls. Further details on the EGU
emissions inventory used for this
proposal can be found in the IPM
Documentation. Also note that as
explained in section IV.A.3, the baseline
used in this analysis assumes no CAIR.
If EPA’s base case analysis were to
E:\FR\FM\02AUP2.SGM
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assume that reductions from CAIR
would continue indefinitely, areas that
are in attainment solely due to controls
required by CAIR would again face
nonattainment problems because the
existing protection from upwind
pollution would not be replaced. 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).
Development of Future-Year Emissions
Inventories for Mobile Inventories
Mobile source inventories of onroad
and nonroad mobile emissions were
created for 2012 and 2015 using a
combination of the NMIM and draft
MOVES models. Mobile source
emissions were further interpolated
between 2012 and 2015 to estimate 2014
emissions. Emissions for these years
reflect onroad mobile control programs
including the Light-Duty Vehicle Tier 2
Rule, the Onroad Heavy-Duty Rule, and
the Mobile Source Air Toxics (MSAT)
final rule. Nonroad mobile emissions
reductions for these years 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 EITSD.
The onroad emissions were primarily
based on the NMIM monthly, county,
process level emissions. For both 2012
and 2015, emissions from onroad
gasoline sources were augmented with
emissions based on the same
preliminary version of MOVES as was
used for 2005. MOVES-based emissions
were computed for CO, NOX, VOC,
PM2.5, and PM10. The same MOVESbased PM2.5 temperature adjustment
factors were also applied as in 2005.
Nonroad mobile emissions were
created only with NMIM using a
consistent approach as was used for
2005, but emissions were calculated
using NMIM future-year equipment
population estimates and control
programs for 2012 and 2014. Emissions
from 2012 and 2015 were used for
locomotives and category 1 and 2
(C1 and C2) commercial marine vessels,
based on emissions published in
OTAQ’s Locomotive Marine Rule,
Regulatory Impact Assessment, Chapter
3. For category 3 (C3) commercial
marine vessels, a coordination strategy
of emissions reductions is ongoing that
includes NOX, VOC, and CO reductions
for new C3 engines as early as 2011 and
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fuel sulfur limits that could go into
affect as early as 2012. However, given
the uncertainty about the timing for
parts of these emissions reductions and
the fact that the 2012 modeling was
conducted well in advance of the
December 2009 publication of the rule,
we have not used the controlled
emissions in modeling supporting this
proposal.
Development of Future-Year Emissions
Inventories for Other Inventory Sources
Other inventory sources include
nonEGU point sources, stationary
nonpoint sources, and emissions in
Canada and Mexico. Emissions from
Canada and Mexico for all source
sectors (including EGUs) in these
countries were held constant for all
cases. This approach reflects the
unavailability of future-year emissions
from Canada and Mexico for the future
years of interest in time to support the
modeling for this proposal.
The future year emissions for other
sectors are described next. For all sector
projections, EPA seeks comment on
growth and control approaches,
particularly where a control measure
has not been included. The EITSD
provides more details on these
projections for additional review and we
have included in the EITSD a table for
the public to provide more detailed
control data to EPA.
For nonEGU point sources, emissions
were projected by including emissions
reductions and increases from a variety
of sources. For nonEGUs, emissions
were not grown using economic growth
projections and emissions reductions
were applied through plant closures,
refinery and other consent decrees, and
reductions stemming from several
MACT standards. Since aircraft at
airports were treated as point emissions
sources in the 2005 NEI v2, we also
applied projection factors based on
activity growth projected by the Federal
Aviation Administration Terminal Area
Forecast (TAF) system, published
December 2008. Controls from the NOX
SIP Call were assumed to have been
implemented by 2005 and captured in
the 2005 NEI v2.
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 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
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Sfmt 4702
projected by replacement of obsolete
woodstoves with new woodstoves 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.
(3) Preparation of Emissions for AQ
Modeling
The annual and summer day
emissions inventory files were
processed through the Sparse Matrix
Operator Kernel Emissions (SMOKE)
Modeling System version 2.6 to produce
the gridded model-ready emissions for
input to CAMx. Emissions processing
using SMOKE was performed to create
the hourly, gridded data of CAMx
species required for air quality modeling
for all sectors, including biogenic
emissions. Additional information on
the development of the emissions data
sets for modeling is provided in the
EITSD. Details about preparation of
emissions for contribution modeling are
described in the Transport Rule AQ
Modeling TSD.
c. Preparation of Meteorological and
Other Air Quality Modeling Inputs
The gridded meteorological input data
for the entire year of 2005 were derived
from simulations of the Pennsylvania
State University/National Center for
Atmospheric Research Mesoscale
Model. This model, commonly referred
to as MM5, is a limited-area,
nonhydrostatic, terrain-following
system that solves for the full set of
physical and thermodynamic equations
which govern atmospheric motions.26
The meteorological outputs from MM5
were processed to create model-ready
inputs for CMAQ using the MM5-toCAMx preprocessor (ref CAMx user’s
guide).
The 2005 MM5 meteorological
predictions for selected variables were
compared to measurements as part of
several performance evaluations of the
predicted data. The evaluation approach
included a combination of qualitative
and quantitative analyses to assess the
adequacy of the MM5 simulated fields.
The qualitative aspects involved
comparisons of the model-estimated
synoptic patterns against observed
patterns from historical weather chart
archives. Additionally, the evaluations
compared spatial patterns of monthly
average rainfall and monthly maximum
planetary boundary layer (PBL) heights.
The operational evaluation included
26 Grell, G., J. Dudhia, and D. Stauffer, 1994: A
Description of the Fifth-Generation Penn State/
NCAR Mesoscale Model (MM5), NCAR/TN–
398+STR., 138 pp, National Center for Atmospheric
Research, Boulder CO.
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statistical comparisons of model/
observed pairs (e.g., mean normalized
bias, mean normalized error, index of
agreement, root mean square errors, etc.)
for multiple meteorological parameters.
For this portion of the evaluation, five
meteorological parameters were
investigated: Temperature, humidity,
shortwave downward radiation, wind
speed, and wind direction. The three
individual MM5 evaluations are
described elsewhere.27 28 29 It was
ultimately determined that the bias and
error values associated with the 2005
meteorological data were generally
within the range of past meteorological
modeling results that have been used for
air quality applications. Additional
details on the meteorological inputs can
be found in the AQMTSD.
As noted previously, the CAMx
simulations for this proposal were
performed using a spatial resolution of
12 x 12 km. The concentrations of
pollutants transported into this eastern
U.S. modeling region were obtained
from air quality model simulations
performed at coarser 36 x 36 km
resolution for a modeling domain
covering the lower 48 states and
portions of northern Mexico and
southern Canada. The 12 x 12 km model
simulations were also initialized with
air quality predictions from the coarse
scale modeling. Pollutant
concentrations at the boundaries of the
coarse scale modeling domain were
obtained from a three-dimensional
global atmospheric chemistry model,
the GEOSChem 30 model (standard
version 7–04–11 31). The global
GEOSChem model simulates
atmospheric chemical and physical
processes driven by assimilated
meteorological observations from the
NASA’s Goddard Earth Observing
System (GEOS). This model was run for
2005 with a grid resolution of 2.0
degrees x 2.5 degrees (latitudelongitude). The predictions were used to
27 Baker K. and P. Dolwick. Meteorological
Modeling Performance Evaluation for the Annual
2005 Eastern U.S. 12-km Domain Simulation,
USEPA/OAQPS, February 2, 2009.
28 Baker K. and P. Dolwick. Meteorological
Modeling Performance Evaluation for the Annual
2005 Western U.S. 12-km Domain Simulation,
USEPA/OAQPS, February 2, 2009.
29 Baker K. and P. Dolwick. Meteorological
Modeling Performance Evaluation for the Annual
2005 Continental U.S. 36-km Domain Simulation,
USEPA/OAQPS, February 2, 2009.
30 Yantosca, B., 2006. GEOS–CHEMv7–04–11
User’s Guide, Atmospheric Chemistry Modeling
Group, Harvard University, Cambridge, MA, March
05, 2006.
31 Henze, D.K., J.H. Seinfeld, N.L. Ng, J.H. Kroll,
T-M. Fu, D.J. Jacob, C.L. Heald, 2008. Global
modeling of secondary organic aerosol formation
from aromatic hydrocarbons: high-vs. low-yield
pathways. Atmos. Chem. Phys., 8, 2405–2420.
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provide one-way dynamic boundary
conditions at three-hour intervals and
an initial concentration field for the
coarse scale simulations.
2. How did EPA project future
nonattainment and maintenance for
annual PM2.5, 25-Hour PM2.5, and 8hour ozone?
d. Model Performance Evaluation for
Ozone and PM2.5
In this section we describe the
approach for projecting future
concentrations of ozone and PM2.5 to
identify locations that are expected to be
nonattainment or have a maintenance
problem in 2012. The nonattainment
and maintenance locations are based on
projections of future air quality at
existing ozone and PM2.5 monitoring
sites. These sites are used as the
‘‘receptors’’ for quantifying the
contributions of emissions in upwind
states to nonattainment and
maintenance in downwind locations.
For this analysis we are using the air
quality modeling results in a ‘‘relative’’
sense to project future concentrations.
In this approach, the ratio of future year
model predictions to base year model
predictions are used to adjust ambient
measured data up or down depending
on the relative (percent) change in
model predictions for each location.
The 2005 base year model predictions
for ozone and fine particulate sulfate,
nitrate, organic carbon, elemental
carbon, and crustal material were
compared to measured concentrations
in order to evaluate the performance of
the modeling platform for replicating
observed concentrations. This
evaluation was comprised principally of
statistical assessments of paired
modeled and observed data. Details on
the evaluation methodology and the
calculation of performance statistics are
provided in the AQMTSD. The results
indicate that, overall, the predicted
patterns and day-to-day variations in
regional ozone levels are similar to what
was observed with measured data. The
normalized mean bias for 8-hour daily
maximum ozone concentrations was
¥2.9 percent and the normalized mean
error was 13.2 percent for the months of
May through September 2005, based on
an aggregate of observed-predicted pairs
within the 12 km modeling domain. The
two PM2.5 species that are most relevant
for this proposal are sulfate and nitrate.
For the summer months of June though
August, when observed sulfate
concentrations are highest in the East,
the model predictions of 24-hour
average sulfate were lower than the
corresponding measured values by 7
percent at urban sites and by 9 to 10
percent at rural sites in the IMPROVE 32
and CASTNET 33 monitoring networks,
respectively. For the winter months of
December through February, when
observed nitrate concentrations are
highest in the East, the model
predictions of 24-hour average
particulate nitrate were lower than the
corresponding measured values by 12
percent at urban sites and by 4 percent
at rural sites in the IMPROVE
monitoring network. The model
performance statistics by season for
ozone and PM2.5 component species are
provided in the AQMTSD.
32 Interagency Monitoring of PROtected Visual
Environments (IMPROVE). Debell, L.J., et. al.
Spatial and Seasonal Patterns and Temporal
Variability of Haze and its Constituents in the
United States: Report IV. November 2006.
33 Clean Air Status and Trends Network
(CASTNET) 2005 Annual Report. EPA Office of Air
and Radiation, Clean Air Markets Division.
Washington, DC. December 2006.
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a. How did EPA process ambient ozone
and PM2.5 data for the purpose of
projecting future year concentrations?
In this analysis we use measurements
of ambient ozone and PM2.5 data that
come from monitoring networks
consisting of more than one thousand
ozone monitors and one thousand PM2.5
monitors located across the country.
The monitors are sited according to the
spatial and temporal nature of ozone
and PM2.5, and to best represent the
actual air quality in the United States.
The ambient data used in this analysis
were obtained from EPA’s Air Quality
System (AQS).
In order to use the ambient data, the
raw measurements must be processed
into a form pertinent for useful
interpretations. For this action, the
ozone data were processed consistent
with the formats associated with the
NAAQS for ozone. The resulting
estimates are used to indicate the level
of air quality relative to the NAAQS. For
ozone air quality indicators, we
developed estimates for the 1997 8-hour
ozone standard. The level of the 1997 8hour O3 NAAQS is 0.08 ppm. The 8hour ozone standard is not met if the 3year average of the annual 4th highest
daily maximum 8-hour O3
concentration is greater than 0.08 ppm
(0.085 ppm when rounded up). This 3year average is referred to as the design
value.
The PM2.5 ambient data were
processed consistent with the formats
associated with the NAAQS for PM2.5.
The resulting estimates are used to
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indicate the level of air quality relative
to the NAAQS. For PM2.5, we evaluated
concentrations of both the annual
average PM2.5 NAAQS and the 24-hour
PM2.5 NAAQS. The annual PM2.5
standard is met when the 3-year average
of the annual mean concentration is
15.0 μg/m 3 or less. The 3-year average
annual mean concentration is computed
at each site by averaging the daily
Federal Reference Method (FRM)
samples by quarter, averaging these
quarterly averages to obtain an annual
average, and then averaging the three
annual averages. The 3-year average
annual mean concentration is referred to
as the annual design value.
The 24-hour average standard is met
when the 3-year average of the annual
98th percentile PM2.5 concentration is
35 μg/m 3 or less. The 3-year average
mean 98th percentile concentration is
computed at each site by averaging the
3 individual annual 98th percentile
values at each site. The 3-year average
98th percentile concentration is referred
to as the 24-hour average design value.
As described later, the approach for
projecting future ozone and PM2.5
design values involved the projection of
an average of up to 3 design value
periods which include the years 2003–
2007 (design values for 2003–2005,
2004–2006, and 2005–2007). The
average of the 3 design values creates a
‘‘5-year weighted average’’ value. The 5year weighted average values were then
projected to the future years that were
analyzed for this proposed rule. The
2003–2005, 2004–2006, and 2005–2007
design values are accessible at https://
www.epagov/airtrends/values.html.
The procedures for projecting annual
average PM2.5 and 8-hour ozone
conform to the methodology in the final
attainment demonstration modeling
guidance 34. In the CAIR analysis, EPA
did not project 24-hour PM2.5 design
values 35. The analysis for this proposed
rule, in contrast, uses the 24-hour PM2.5
methodology outlined in the modeling
guidance.
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b. Projection of Future Annual and 24Hour PM2.5 Nonattainment and
Maintenance
Annual PM2.5 modeling was
performed for the 2005 base year
emissions and for the 2012 base case as
34 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.
35 CAIR was promulgated in 2005 before the 35
ug/m 3 PM2.5 NAAQS was finalized in 2006. Since
there were no violations in the eastern United
States (base or future year) of the 1997 65 ug/m3
NAAQS, it was not necessary to project 24 PM2.5
values as part of the modeling for CAIR.
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part of the approach for projecting
which locations (i.e., monitoring sites)
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.
In general, the projection
methodology involves using the model
in a relative sense to estimate the
change in PM2.5 between 2005 and the
future 2012 base case as recommended
in the modeling guidance. Rather than
use the absolute model-predicted future
year ozone and PM2.5 concentrations,
the base year and future year
predictions are used to calculate a
(relative) percent change in ozone and
PM2.5 concentrations. For a particular
location, the percent change in modeled
concentration is multiplied by the
corresponding observed base period
ambient concentration to estimate the
future year design value for that
location. The use of observed ambient
data as part of the calculation helps to
constrain the future year design value
predictions, even if the absolute model
concentrations are over-predicted or
under-predicted.
Concentrations of PM2.5 in 2012 were
estimated by applying the 2005 to 2012
relative change in model-predicted
PM2.5 species to the (2003–2007) PM2.5
design values. The choice of base period
design values is consistent with EPA’s
modeling guidance which recommends
using the average of the three design
value periods centered about the
emissions projection year. Since 2005
was the base emissions year, we used
the design value for 2003–2005, 2004–
2006, and 2005–2007 to represent the
base period PM2.5 concentrations. For
each FRM PM2.5 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
concentration.
The 5-year weighted average
concentrations were used to project
concentrations for the 2012 base case in
order to determine which monitoring
sites are expected to be nonattainment
in this future year. We projected 2012
design values for each of 3 year periods
(i.e., 2003–2005, 2004–2006, and 2003–
2007) and used the highest of these
projections to determine which sites are
expected to have maintenance problems
in 2012.
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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.36 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 736 sites which met this
criteria for the 24-hour NAAQS.37
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. The model
predictions are used in a relative sense
to estimate changes expected to occur in
each of the major PM2.5 species. The
PM2.5 species are sulfate, nitrate,
ammonium, particle bound water,
elemental carbon, salt, other primary
PM2.5, and organic aerosol mass by
difference. Organic aerosol mass by
difference is defined as the difference
between FRM PM2.5 and the sum of the
other components. The procedure for
calculating future year PM2.5 design
values is called the SMAT. The SMAT
approach is codified in a software tool
available from EPA called MATS. The
software (including documentation) is
available at: https://www.epa.gov/
scram001/modelingapps_mats.htm.
(1) Methodology for Projecting Future
Annual PM2.5 Nonattainment and
Maintenance
The following is a brief summary of
the future year annual PM2.5
calculations. Additional details are
provided in the modeling guidance,
MATS documentation, and the
AQMTSD.
We are using the base period (i.e.,
2003 2007) FRM data for projecting
future design values since these data are
used to determine attainment status. In
order to apply SMAT to the FRM data,
information on PM2.5 speciation is
needed for the location of each FRM
monitoring site. Since co-located PM2.5
speciation data are only available at
about 15 percent of FRM monitoring
sites, spatial interpolation techniques
are used to calculate species
concentrations for each FRM monitoring
site. Speciation data from the IMPROVE
and Chemical Speciation Network
36 If there is only one complete design value, then
the nonattainment and maintenance design values
are the same.
37 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.
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(CSN) were interpolated to each FRM
monitor location using the Voronoi
Neighbor Averaging (VNA) technique
(using MATS). Additional information
on the VNA interpolation techniques
and data handling procedures can be
found in the MATS User’s Guide. After
the species fractions are calculated for
each FRM site, the following procedures
were used to estimate future year design
values:
Step 1: Calculate quarterly mean
concentrations for each of the major
species components of PM2.5 (i.e.,
sulfate, nitrate, ammonium, elemental
carbon, organic carbon mass, particle
bound water, salt, and blank mass). This
is done by multiplying the monitored
quarterly mean concentration of FRMderived total PM2.5 by the monitored
fractional composition of PM2.5 species
for each quarter averaged over 3 years 38
(e.g., 20 percent sulfate fraction
multiplied by 15 μg/m3 PM2.5 equals 3
μg/m3 sulfate).
Step 2: For each quarter, calculate the
ratio of future year to base year model
predictions for each of the component
species. The result is a set of speciesspecific relative response factors (RRF)
(e.g., assume that the model-predicted
2005 base year sulfate for a particular
location is 10.0 μg/m3 and the 2012
future concentration is 8.0 μg/m3, then
RRF for sulfate is 0.8). The RRFs are
calculated based on the modeled
concentrations averaged over the nine
grid cells 39 centered at the location of
the monitor.
Step 3: For each quarter and each of
the species, multiply the base year
quarterly mean component
concentration (Step 1) by the speciesspecific RRF obtained in Step 2. This
results in an estimated future year
quarterly mean concentration for each
species (e.g., 3 μg/m3 sulfate multiplied
by 0.8 equals a future sulfate
concentration of 2.4 μg/m3).
Step 4: The future year concentrations
for the remaining species are then
calculated.40 The future year
ammonium is calculated based on the
calculated future year sulfate and nitrate
concentrations, using a constant value
for the degree of neutralization of sulfate
(from the ambient data). The future year
particle bound water concentration is
calculated from an empirical formula.
The inputs to the formula are the future
year concentrations of sulfate, nitrate,
and ammonium (from step 3).
Step 5: Average the four quarterly
mean future concentrations to obtain the
future year annual design value
concentration for each of the component
species. Sum the species concentrations
to obtain the future year annual average
design value for PM2.5.
Step 6: Calculate the maximum future
design value by processing each of the
three base design value periods (2003–
2005, 2004–2006, and 2005–2007)
separately. The highest of the three
future values is the maximum design
value. The maximum design values are
used to determine future year
maintenance sites.
The preceding procedures for
determining future year PM2.5
concentrations were applied for each
FRM site. The calculated annual PM2.5
design values are truncated (i.e.,
discarded) after the second decimal
place.41 This is consistent with the
truncation and rounding procedures for
the annual PM2.5 NAAQS. Any value
that is greater than or equal to 15.05
45247
μg/m3 is rounded to 15.1 μg/m3 and is
considered to be violating the NAAQS.
Thus, sites with future year annual
PM2.5 design values of 15.05 μg/m3 or
greater, based on the projection of 5-year
weighted average concentrations, are
predicted to be nonattainment sites.
Sites with future year maximum design
values of 15.05
μg/m3 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 as part of this proposal.
Table IV.C–7 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
IV.C–8 contains this same information
for projected 2012 maintenance sites.
TABLE IV.C–7—AVERAGE AND MAXIMUM 2003–2007 AND 2012 BASE CASE ANNUAL PM2.5 DESIGN VALUES (μG/M3) AT
PROJECTED NONATTAINMENT SITES
Average
design value
2003–2007
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Monitor ID
State
County
10730023 ......................
10732003 ......................
130210007 ....................
130630091 ....................
131210039 ....................
170310052 ....................
171191007 ....................
171630010 ....................
180190006 ....................
180372001 ....................
180970078 ....................
Alabama ......................
Alabama ......................
Georgia .......................
Georgia .......................
Georgia .......................
Illinois ..........................
Illinois ..........................
Illinois ..........................
Indiana ........................
Indiana ........................
Indiana ........................
Jefferson .....................
Jefferson .....................
Bibb .............................
Clayton ........................
Fulton ..........................
Cook ............................
Madison .......................
Saint Clair ...................
Clark ............................
Dubois .........................
Marion .........................
38 For this analysis, species fractions were
calculated using an average of FRM and speciation
data for the 2004–2006 time period. This was
deemed to be representative of the 2005 base year.
39 The modeling guidance recommends
calculating annual PM2.5 RRFs using a 3 x 3 grid
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15.58
16.40
15.18
15.26
cell array (9 grid cells) for a model resolution of
12km.
40 All of the calculations and assumptions are
consistent with the default MATS settings (as
described in the MATS user’s guide and the
photochemical modeling guidance). Additionally,
we did not explicitly model salt and therefore the
PO 00000
Frm 00039
Fmt 4701
Sfmt 4702
Maximum
design value
2003–2007
18.67
17.45
16.78
16.71
17.47
16.02
17.01
15.74
16.60
15.68
15.43
Average
design value
2012
17.15
15.99
15.33
15.07
16.01
15.16
16.56
15.48
15.96
15.07
15.18
Maximum
design value
2012
17.33
16.35
15.62
15.29
16.04
15.43
16.85
15.63
16.16
15.57
15.36
salt concentration was held constant from the base
to future. Blank mass was assumed to be a constant
mass of 0.5 μg/m3 in both the base and future year.
41 For example, a calculated annual average
concentration of 14.94753 * * * becomes 14.94
when digits beyond two places to the right are
truncated.
E:\FR\FM\02AUP2.SGM
02AUP2
45248
Federal Register / Vol. 75, No. 147 / Monday, August 2, 2010 / Proposed Rules
TABLE IV.C–7—AVERAGE AND MAXIMUM 2003–2007 AND 2012 BASE CASE ANNUAL PM2.5 DESIGN VALUES (μG/M3) AT
PROJECTED NONATTAINMENT SITES—Continued
Monitor ID
180970081
180970083
211110043
261630015
261630033
390170016
390350038
390350045
390350060
390610014
390610042
390610043
390617001
390618001
420030064
420031301
420070014
420710007
421330008
540110006
540391005
Average
design value
2003–2007
State
....................
....................
....................
....................
....................
....................
....................
....................
....................
....................
....................
....................
....................
....................
....................
....................
....................
....................
....................
....................
....................
County
Indiana ........................
Indiana ........................
Kentucky .....................
Michigan ......................
Michigan ......................
Ohio .............................
Ohio .............................
Ohio .............................
Ohio .............................
Ohio .............................
Ohio .............................
Ohio .............................
Ohio .............................
Ohio .............................
Pennsylvania ...............
Pennsylvania ...............
Pennsylvania ...............
Pennsylvania ...............
Pennsylvania ...............
West Virginia ...............
West Virginia ...............
Marion .........................
Marion .........................
Jefferson .....................
Wayne .........................
Wayne .........................
Butler ...........................
Cuyahoga ....................
Cuyahoga ....................
Cuyahoga ....................
Hamilton ......................
Hamilton ......................
Hamilton ......................
Hamilton ......................
Hamilton ......................
Allegheny ....................
Allegheny ....................
Beaver .........................
Lancaster ....................
York .............................
Cabell ..........................
Kanawha .....................
Maximum
design value
2003–2007
16.05
15.90
15.53
15.88
17.50
15.74
17.37
16.47
17.11
17.29
16.85
15.55
16.17
17.54
20.31
16.26
16.38
16.55
16.52
16.30
16.52
16.36
16.27
15.75
16.40
18.16
16.11
18.1
16.98
17.66
17.53
17.25
15.82
16.56
17.90
20.75
16.57
16.45
17.46
17.25
16.57
16.59
Average
design value
2012
15.93
15.77
15.19
15.05
16.57
15.25
16.26
15.42
16.02
16.69
16.33
15.05
15.65
16.93
18.90
15.13
15.23
15.19
15.25
15.25
15.28
Maximum
design value
2012
16.25
16.15
15.41
15.55
17.19
15.61
16.95
15.91
16.55
16.93
16.71
15.32
16.03
17.27
19.31
15.42
15.30
16.01
15.94
15.50
15.34
TABLE IV.C–8—AVERAGE AND MAXIMUM 2003–2007 AND 2012 BASE CASE ANNUAL PM2.5 DESIGN VALUES (μ/M3) AT
PROJECTED MAINTENANCE-ONLY SITES
Monitor ID
170313301
170316005
211110044
360610056
390350027
390350065
390610040
390811001
391130032
391510017
420110011
482011035
540030003
540090005
540291004
540490006
...............
...............
...............
...............
...............
...............
...............
...............
...............
...............
...............
...............
...............
...............
...............
...............
County
Illinois ............................
Illinois ............................
Kentucky ........................
New York .......................
Ohio ...............................
Ohio ...............................
Ohio ...............................
Ohio ...............................
Ohio ...............................
Ohio ...............................
Pennsylvania .................
Texas .............................
West Virginia .................
West Virginia .................
West Virginia .................
West Virginia .................
Cook ..............................
Cook ..............................
Jefferson ........................
New York .......................
Cuyahoga ......................
Cuyahoga ......................
Hamilton ........................
Jefferson ........................
Montgomery ..................
Stark ..............................
Berks .............................
Harris .............................
Berkeley ........................
Brooke ...........................
Hancock ........................
Marion ...........................
erowe on DSK5CLS3C1PROD with PROPOSALS2
(2) Methodology for Projecting Future
24-Hour PM2.5 Nonattainment and
Maintenance
The following is a brief summary of
the procedures used for calculating
future year 24-hour PM2.5 design values.
Additional details are provided in the
modeling guidance, MATS
documentation, and the AQMTSD.
Similar to the annual PM2.5 calculations,
we are using the 2003–2007 base period
FRM data for projecting future year
design values. The 24-hour PM2.5
calculations are computationally similar
to the annual average calculations. The
main difference is that the base period
24-hour 98th percentile PM2.5
VerDate Mar<15>2010
Average
design value
2003–2007
State
15:19 Jul 30, 2010
Jkt 220001
15.24
15.48
15.31
16.18
15.46
15.97
15.50
16.51
15.54
16.15
15.82
15.42
15.93
16.52
15.76
15.03
concentrations are projected to the
future year, instead of the annual
average concentrations. Also, the PM2.5
species fractions and relative response
factors are calculated from observed and
modeled high concentration days,
instead of quarterly average data.
Both the annual PM2.5 and 24-hour
PM2.5 calculations are performed on a
calendar quarter basis. Since all years
and quarters are averaged together in the
annual PM2.5 calculations, the
individual years can be averaged
together early in the calculations.
However, in the 24-hour PM2.5
calculations, only the high quarter from
each year is used in the final
calculations. This represents the 98th
PO 00000
Frm 00040
Fmt 4701
Sfmt 4702
Maximum
design value
2003–2007
15.59
16.07
15.47
17.02
16.13
16.44
15.88
17.17
15.92
16.59
16.19
15.84
16.19
16.80
16.64
15.25
Average
design value
2012
14.73
14.92
14.93
14.98
14.50
14.96
15.03
14.95
15.01
14.99
14.77
14.74
14.95
14.95
14.34
14.96
Maximum
design value
2012
15.06
15.48
15.09
15.74
15.13
15.40
15.40
15.54
15.37
15.40
15.11
15.14
15.20
15.22
15.15
15.18
percentile value, which can come from
any of the 4 quarters in any year.
Therefore all quarters and years must be
carried through to near the end of the
calculations when the individual future
year high quarter values are selected. To
calculate final future year design values,
the high quarter for each year is
identified and then a five year weighted
average of the high quarters for each site
was calculated to derive the future year
design value.
The following are the steps followed
for calculating the 2012 base case 24hour PM2.5 design values:
Step 1: At each FRM monitoring site,
we identify the maximum 24-hour PM2.5
concentration in each quarter that is less
E:\FR\FM\02AUP2.SGM
02AUP2
45249
Federal Register / Vol. 75, No. 147 / Monday, August 2, 2010 / Proposed Rules
2) by the quarterly 44 species-specific
than or equal to the 98th percentile
value over the entire year. This results
RRF obtained in step 3. This leads to an
in a data set for each year (for up to 5
estimated future quarterly concentration
years) for each site containing one
for each component. (e.g., 21.0 μg/m3
quarter with the observed 98th
nitrate × 0.75 = future nitrate of 15.75
percentile value and three quarters with μg/m3).
Step 5: The future year concentrations
the maximum highest values from each
quarter that are less than or equal to the for the remaining species are then
98th percentile value for the year. All 20 calculated.45 The future year
ammonium is calculated based on the
quarters (i.e., 4 quarters in each of 5
calculated future year sulfate and nitrate
years) of data are carried through the
concentrations, using a constant value
calculations until the high future year
for the degree of neutralization of sulfate
quarter value is identified in step 6.
Step 2: In this step we calculate
(from the ambient data). The future year
quarterly ambient concentrations on
particle bound water concentration is
‘‘high’’ 42 days for each of the major
calculated from an empirical formula.
component species of PM2.5 (sulfate,
The inputs to the formula are the
nitrate, ammonium, elemental carbon,
calculated future year concentrations of
organic carbon mass, particle bound
sulfate, nitrate, and ammonium (from
step 4).
water, salt, and blank mass). This
Step 6: We sum the species
calculation is performed by multiplying
concentrations to obtain quarterly PM2.5
the monitored concentrations of FRMvalues. This step is repeated for each
derived total PM2.5 mass on the 10
quarter and for each of the 5 years of
percent highest days from each quarter,
by the monitored fractional composition ambient data. The highest daily value
(from the 4 quarterly values) for each
of PM2.5 species on the 10 percent
year at each monitor is considered to be
highest PM2.5 days for each quarter,
averaged over 3 years 43 (e.g., 20 percent the estimated future year 98th percentile
24-hour design value for that year.
sulfate fraction multiplied by 40 μg/m3
Step 7: The estimated 98th percentile
PM2.5 equals 8 μg/m3 sulfate).
Step 3: For each quarter, we calculate values for each of the 5 years are
averaged over 3 year intervals to create
the ratio of future year (i.e., 2012) to
the 3 year average design values. These
base year (i.e., 2005) predictions for
design values are averaged to create a 5
each component species for the top 10
year weighted average for each
percent of days based on predicted
monitoring site.
concentrations of 24-hour PM2.5. The
Step 8: The maximum future design
result is a set of species-specific relative
response factors (RRF) for the high PM2.5 value is calculated by following the
previous steps for each of the three base
days in each quarter (e.g., assume that
the 2005 predicted sulfate concentration design value periods (2003–2005, 2004–
on the 10 percent highest PM2.5 days for 2006, and 2005–2007) separately. The
highest of the three future values is the
a quarter for a particular location is 20
maximum design value. This maximum
μg/m3 and the 2012 base case
concentration is 16 μg/m3, then RRF for value is used to identify the 24-hour
PM2.5 maintenance receptors.
sulfate is 0.8). The RRFs are calculated
The preceding procedures for
based on the modeled concentrations at
the single grid cell where the monitor is determining future year 24-hour PM2.5
concentrations were applied for each
located.
Step 4: For each quarter, we multiply
FRM site. The 24-hour PM2.5 design
the quarterly species concentration (step values are truncated after the first
decimal place. This approach is
consistent with the truncation and
rounding procedures for the 24-hour
PM2.5 NAAQS. Any value that is greater
than or equal to 35.5 μg/m3 is rounded
to 36 μg/m3 and is violating the
NAAQS. Sites with future year 5 year
weighted average design values of 35.5
μg/m3 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 μg/m3
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. 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 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 proposal.
Table IV.C–9 contains the 2003–2007
base period average and maximum 24hour 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 IV.C–10 contains
this same information for projected 2012
24-hour maintenance sites.
TABLE IV.C–9—AVERAGE AND MAXIMUM 2003–2007 AND 2012 BASE CASE 24-HOUR PM2.5 DESIGN VALUES (μG/M3) AT
PROJECTED NONATTAINMENT SITES
Average
design value
2003–2007
erowe on DSK5CLS3C1PROD with PROPOSALS2
Monitor ID
State
County
10730023 ......................
10732003 ......................
90091123 ......................
170310052 ....................
Alabama ......................
Alabama ......................
Connecticut .................
Illinois ..........................
Jefferson .....................
Jefferson .....................
New Haven .................
Cook ............................
42 High ambient data and model days were
defined as the top 10 percent days in each quarter
based on 24-hour concentrations of PM2.5.
43 For this analysis, species fractions were
calculated using an average of FRM and speciation
data for the 2004–2006 time period. This was
deemed to be representative of the 2005 modeling
year.
VerDate Mar<15>2010
20:42 Jul 30, 2010
Jkt 220001
44.0
40.3
38.3
40.2
44 Since there is only one modeled base year,
there are a single set of four quarterly RRFs. The
modeled quarterly RRF for quarter 1 is multiplied
by the ambient data for quarter 1 for each of the 5
years of ambient data. The same procedure is
applied for the other 3 quarters.
45 All of the calculations and assumptions are
consistent with the default MATS settings (as
PO 00000
Frm 00041
Fmt 4701
Sfmt 4702
Maximum
design value
2003–2007
44.2
40.8
40.3
41.4
Average
design value
2012
40.0
38.1
35.7
38.5
Maximum
design value
2012
40.7
38.9
36.6
39.7
described in the MATS user’s guide and the
photochemical modeling guidance). Additionally,
we did not explicitly model salt and therefore the
salt concentration was held constant from the base
to future. Blank mass was assumed to be a constant
mass of 0.5 ug/m3 in both the base and future year.
E:\FR\FM\02AUP2.SGM
02AUP2
45250
Federal Register / Vol. 75, No. 147 / Monday, August 2, 2010 / Proposed Rules
TABLE IV.C–9—AVERAGE AND MAXIMUM 2003–2007 AND 2012 BASE CASE 24-HOUR PM2.5 DESIGN VALUES (μG/M3) AT
PROJECTED NONATTAINMENT SITES—Continued
erowe on DSK5CLS3C1PROD with PROPOSALS2
Monitor ID
170310057
170310076
170311016
170312001
170313103
170313301
170316005
171190023
171191007
171192009
171193007
180190006
180372001
180830004
180890022
180890026
180970042
180970043
180970066
180970078
180970079
180970081
180970083
181570008
191630019
210590005
211110043
211110044
211110048
245100040
245100049
261150005
261250001
261470005
261610008
261630015
261630016
261630019
261630033
261630036
290990012
291831002
295100007
295100087
340171003
340172002
340390004
360050080
360610056
360610128
390170003
390170016
390170017
390171004
390350038
390350045
390350060
390350065
390490024
390490025
390610006
390610014
390610040
390610042
390610043
390617001
390618001
390811001
391130032
....................
....................
....................
....................
....................
....................
....................
....................
....................
....................
....................
....................
....................
....................
....................
....................
....................
....................
....................
....................
....................
....................
....................
....................
....................
....................
....................
....................
....................
....................
....................
....................
....................
....................
....................
....................
....................
....................
....................
....................
....................
....................
....................
....................
....................
....................
....................
....................
....................
....................
....................
....................
....................
....................
....................
....................
....................
....................
....................
....................
....................
....................
....................
....................
....................
....................
....................
....................
....................
VerDate Mar<15>2010
Average
design value
2003–2007
State
County
Illinois ..........................
Illinois ..........................
Illinois ..........................
Illinois ..........................
Illinois ..........................
Illinois ..........................
Illinois ..........................
Illinois ..........................
Illinois ..........................
Illinois ..........................
Illinois ..........................
Indiana ........................
Indiana ........................
Indiana ........................
Indiana ........................
Indiana ........................
Indiana ........................
Indiana ........................
Indiana ........................
Indiana ........................
Indiana ........................
Indiana ........................
Indiana ........................
Indiana ........................
Iowa .............................
Kentucky .....................
Kentucky .....................
Kentucky .....................
Kentucky .....................
Maryland .....................
Maryland .....................
Michigan ......................
Michigan ......................
Michigan ......................
Michigan ......................
Michigan ......................
Michigan ......................
Michigan ......................
Michigan ......................
Michigan ......................
Missouri .......................
Missouri .......................
Missouri .......................
Missouri .......................
New Jersey .................
New Jersey .................
New Jersey .................
New York ....................
New York ....................
New York ....................
Ohio .............................
Ohio .............................
Ohio .............................
Ohio .............................
Ohio .............................
Ohio .............................
Ohio .............................
Ohio .............................
Ohio .............................
Ohio .............................
Ohio .............................
Ohio .............................
Ohio .............................
Ohio .............................
Ohio .............................
Ohio .............................
Ohio .............................
Ohio .............................
Ohio .............................
Cook ............................
Cook ............................
Cook ............................
Cook ............................
Cook ............................
Cook ............................
Cook ............................
Madison .......................
Madison .......................
Madison .......................
Madison .......................
Clark ............................
Dubois .........................
Knox ............................
Lake ............................
Lake ............................
Marion .........................
Marion .........................
Marion .........................
Marion .........................
Marion .........................
Marion .........................
Marion .........................
Tippecanoe .................
Scott ............................
Daviess .......................
Jefferson .....................
Jefferson .....................
Jefferson .....................
Baltimore City ..............
Baltimore City ..............
Monroe ........................
Oakland .......................
St. Clair .......................
Washtenaw .................
Wayne .........................
Wayne .........................
Wayne .........................
Wayne .........................
Wayne .........................
Jefferson .....................
Saint Charles ..............
St. Louis City ...............
St. Louis City ...............
Hudson ........................
Hudson ........................
Union ...........................
Bronx ...........................
New York .....................
New York .....................
Butler ...........................
Butler ...........................
Butler ...........................
Butler ...........................
Cuyahoga ....................
Cuyahoga ....................
Cuyahoga ....................
Cuyahoga ....................
Franklin .......................
Franklin .......................
Hamilton ......................
Hamilton ......................
Hamilton ......................
Hamilton ......................
Hamilton ......................
Hamilton ......................
Hamilton ......................
Jefferson .....................
Montgomery ................
15:19 Jul 30, 2010
Jkt 220001
PO 00000
Frm 00042
Fmt 4701
Sfmt 4702
Maximum
design value
2003–2007
37.3
38.0
43.0
37.7
39.6
40.2
39.1
37.3
39.1
34.9
34.0
37.5
35.3
35.9
38.9
38.4
34.2
38.4
38.3
36.6
35.6
38.2
36.6
35.6
37.1
33.8
35.4
36.1
36.4
39.0
38.1
38.8
39.9
39.6
39.4
40.1
42.9
40.9
43.8
37.1
33.4
33.1
33.1
34.3
39.0
41.4
40.4
38.8
39.7
39.4
39.2
37.1
37.9
37.1
44.2
38.5
42.1
38.6
38.5
38.4
37.6
38.2
36.7
37.3
35.9
38.8
40.6
41.9
37.8
E:\FR\FM\02AUP2.SGM
38.6
39.1
46.3
40.6
40.3
43.3
41.8
38.1
40.1
35.9
34.6
39.4
36.9
36.3
44.0
41.3
35.3
39.9
39.6
37.6
36.7
39.2
37.0
36.7
37.1
33.8
36.1
36.6
37.2
40.9
38.1
39.6
40.4
40.6
40.8
40.6
45.4
41.4
44.2
37.9
34.2
34.7
33.5
34.7
40.5
41.4
41.4
40.2
40.6
41.8
41.1
37.7
37.9
38.1
47.0
41.5
45.7
41.0
39.7
39.1
37.6
39.4
37.7
38.2
36.2
39.6
40.9
45.5
40.0
02AUP2
Average
design value
2012
35.7
36.3
41.0
35.6
38.1
38.2
37.4
39.4
40.0
37.2
36.5
38.1
36.5
35.9
37.3
36.3
36.3
40.5
40.3
38.7
37.2
40.1
39.0
35.9
36.8
37.0
35.8
36.0
35.6
36.3
35.5
37.0
37.9
38.4
38.1
38.5
40.6
38.6
42.1
36.3
35.7
35.5
36.0
36.4
35.7
38.2
36.7
35.9
37.1
36.2
40.3
37.5
38.5
37.8
41.2
36.0
39.4
36.5
36.6
36.1
38.0
37.5
35.8
37.2
36.0
37.7
39.6
36.5
36.3
Maximum
design value
2012
37.0
37.3
44.1
38.2
38.7
41.0
39.8
40.2
40.6
38.2
37.3
40.2
38.0
36.5
42.1
39.3
37.2
42.0
41.8
39.7
38.3
41.1
39.3
36.9
36.8
37.0
36.4
36.5
36.4
38.3
35.5
38.0
38.4
39.4
39.8
39.1
43.0
39.1
42.6
36.9
36.5
37.1
36.3
36.9
36.1
38.2
37.2
36.2
38.0
38.0
42.3
37.8
38.5
38.6
44.0
39.0
42.8
38.9
37.6
36.4
38.0
38.5
36.8
38.0
36.4
38.1
40.3
39.9
38.5
45251
Federal Register / Vol. 75, No. 147 / Monday, August 2, 2010 / Proposed Rules
TABLE IV.C–9—AVERAGE AND MAXIMUM 2003–2007 AND 2012 BASE CASE 24-HOUR PM2.5 DESIGN VALUES (μG/M3) AT
PROJECTED NONATTAINMENT SITES—Continued
Monitor ID
391530017
420030008
420030064
420030093
420030116
420031008
420031301
420070014
420110011
420210011
420430401
420710007
421330008
471251009
540090011
550790010
550790026
550790043
550790099
Average
design value
2003–2007
State
....................
....................
....................
....................
....................
....................
....................
....................
....................
....................
....................
....................
....................
....................
....................
....................
....................
....................
....................
County
Ohio .............................
Pennsylvania ...............
Pennsylvania ...............
Pennsylvania ...............
Pennsylvania ...............
Pennsylvania ...............
Pennsylvania ...............
Pennsylvania ...............
Pennsylvania ...............
Pennsylvania ...............
Pennsylvania ...............
Pennsylvania ...............
Pennsylvania ...............
Tennessee ..................
West Virginia ...............
Wisconsin ....................
Wisconsin ....................
Wisconsin ....................
Wisconsin ....................
Summit ........................
Allegheny ....................
Allegheny ....................
Allegheny ....................
Allegheny ....................
Allegheny ....................
Allegheny ....................
Beaver .........................
Berks ...........................
Cambria .......................
Dauphin .......................
Lancaster ....................
York .............................
Montgomery ................
Brooke .........................
Milwaukee ...................
Milwaukee ...................
Milwaukee ...................
Milwaukee ...................
Maximum
design value
2003–2007
38.0
39.4
64.2
45.6
42.5
41.3
40.3
43.4
37.7
39.0
38.0
40.8
38.2
36.3
43.9
38.6
37.3
39.9
37.7
39.6
39.9
68.2
51.5
42.5
42.8
42.4
44.6
39.1
39.4
39.0
44.0
40.7
37.5
44.9
40.0
41.3
40.8
38.7
Average
design value
2012
35.6
35.9
58.8
41.1
37.1
38.0
36.6
37.7
35.8
40.3
35.7
37.7
35.9
36.6
39.9
37.7
36.3
38.8
36.8
Maximum
design value
2012
37.2
36.3
62.3
46.2
37.1
39.3
38.6
39.1
37.0
40.7
37.1
40.1
38.8
37.9
40.8
39.0
40.1
39.7
37.7
TABLE IV.C–10—AVERAGE AND MAXIMUM 2003–2007 AND 2012 BASE CASE 24-HOUR PM2.5 DESIGN VALUES (μG/M3)
AT PROJECTED MAINTENANCE-ONLY SITES
erowe on DSK5CLS3C1PROD with PROPOSALS2
Monitor ID
110010041
110010042
170310022
170310050
170314007
171630010
171971002
180390003
180431004
181670023
191390015
210290006
211451004
212270007
240031003
245100035
261630001
295100085
360610062
360610079
390350027
390350034
390810017
390950024
390950026
390990014
391130031
391351001
391550007
420030095
420033007
420410101
421255001
471650007
540090005
550250047
550790059
551330027
...............
...............
...............
...............
...............
...............
...............
...............
...............
...............
...............
...............
...............
...............
...............
...............
...............
...............
...............
...............
...............
...............
...............
...............
...............
...............
...............
...............
...............
...............
...............
...............
...............
...............
...............
...............
...............
...............
VerDate Mar<15>2010
Average
design value
2003–2007
State
County
Washington DC .............
Washington DC .............
Illinois ............................
Illinois ............................
Illinois ............................
Illinois ............................
Illinois ............................
Indiana ...........................
Indiana ...........................
Indiana ...........................
Iowa ...............................
Kentucky ........................
Kentucky ........................
Kentucky ........................
Maryland ........................
Maryland ........................
Michigan ........................
Missouri .........................
New York .......................
New York .......................
Ohio ...............................
Ohio ...............................
Ohio ...............................
Ohio ...............................
Ohio ...............................
Ohio ...............................
Ohio ...............................
Ohio ...............................
Ohio ...............................
Pennsylvania .................
Pennsylvania .................
Pennsylvania .................
Pennsylvania .................
Tennessee .....................
West Virginia .................
Wisconsin ......................
Wisconsin ......................
Wisconsin ......................
Washington DC .............
Washington DC .............
Cook ..............................
Cook ..............................
Cook ..............................
Saint Clair ......................
Will .................................
Elkhart ...........................
Floyd ..............................
Vigo ...............................
Muscatine ......................
Bullitt ..............................
McCracken ....................
Warren ...........................
Anne Arundel ................
Baltimore (City) .............
Wayne ...........................
St. Louis City .................
New York .......................
New York .......................
Cuyahoga ......................
Cuyahoga ......................
Jefferson ........................
Lucas .............................
Lucas .............................
Mahoning .......................
Montgomery ..................
Preble ............................
Trumbull ........................
Allegheny .......................
Allegheny .......................
Cumberland ...................
Washington ...................
Sumner ..........................
Brooke ...........................
Dane ..............................
Milwaukee .....................
Waukesha .....................
15:19 Jul 30, 2010
Jkt 220001
PO 00000
Frm 00043
Fmt 4701
Sfmt 4702
Maximum
design value
2003–2007
36.3
34.9
36.6
36.1
34.3
33.7
36.4
34.4
33.2
34.8
36.0
34.6
33.6
33.1
35.5
37.7
37.8
33.2
38.8
37.9
36.6
36.5
40.7
36.3
34.9
36.8
35.7
32.8
36.2
38.7
37.5
38.0
38.1
33.6
39.4
35.5
35.5
35.4
E:\FR\FM\02AUP2.SGM
37.8
37.0
38.6
38.0
36.4
34.1
37.1
36.3
34.5
36.1
37.7
35.8
35.9
35.1
37.4
39.2
40.1
33.8
41.6
40.2
38.8
37.9
42.4
38.6
36.7
38.2
37.1
33.9
37.8
40.7
43.1
40.2
39.9
34.5
41.5
36.9
37.0
36.2
02AUP2
Average
design value
2012
34.0
33.0
34.9
34.1
33.6
35.3
35.1
33.8
34.3
35.1
34.5
35.0
34.4
33.7
33.8
34.7
35.4
35.3
35.3
34.2
34.5
33.7
35.3
34.2
33.6
34.2
34.3
34.3
33.9
34.3
33.8
35.3
33.9
35.1
33.9
35.1
34.8
34.9
Maximum
design value
2012
35.6
35.6
36.6
35.8
35.7
35.9
35.8
35.6
35.7
36.5
36.0
36.3
36.8
36.3
36.7
35.5
37.8
35.7
37.0
36.4
36.6
35.7
36.8
36.5
35.6
35.8
35.6
35.5
35.6
36.6
38.5
37.0
35.5
36.0
36.1
36.1
36.3
35.6
45252
Federal Register / Vol. 75, No. 147 / Monday, August 2, 2010 / Proposed Rules
(3) Methodology for Projecting Future
8-Hour Ozone Nonattainment and
Maintenance
The following is a brief summary of
the future year 8-hour average ozone
calculations. Additional details are
provided in the modeling guidance,
MATS documentation, and the
AQMTSD.
We are using the base period 2003–
2007 ambient ozone design value data
for projecting future year design values.
The ozone projection procedure is
relatively simple, since ozone is a single
species. It is not necessary to interpolate
ambient ozone data, since ambient
ozone design values and gridded,
modeled ozone is all that is needed for
the projections.
To project 8-hour ozone design values
we used the 2005 base year and 2012
future base case model-predicted ozone
concentrations to calculate relative
response factors. The methodology we
followed is consistent with the
attainment demonstration modeling
guidance. The RRFs were applied to the
2003–2007 ozone design values through
the following steps:
Step 1: For each monitoring site we
calculate the average concentration
across all days with 8-hour daily
maximum predictions greater than or
equal to 85 ppb 46 using the predictions
in the nine grid cells that include or
surround the location of the monitoring
site. The RRF for a site is the ratio of the
mean prediction in the future year to the
mean prediction in the 2005 base year.
The RRFs were calculated on a site-bysite basis.
Step 2: The RRF for each site is then
multiplied by the 2003–2007 5-year
weighted average ambient design value
for that site, yielding an estimate of the
future year design value at that
particular monitoring location.
Step 3: We calculate the maximum
future design value 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 preceding procedures for
determining future year 8-hour average
ozone design values were applied for
each ozone monitoring site. The future
year design values are truncated to
integers in units of ppb. This approach
is consistent with the 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. 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 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 as part of
this proposal.
Table IV.C–11 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 IV.C–12 contains
this same information for projected 2012
8-hour ozone maintenance sites.
TABLE IV.C–11—AVERAGE AND MAXIMUM 2003–2007 AND 2012 BASE CASE 8-HOUR OZONE DESIGN VALUES (PPB) AT
PROJECTED NONATTAINMENT SITES
Monitor ID
220330003
361030002
361030009
421010024
480391004
482010051
482010055
482010062
482010066
482011039
484391002
Average
design value
2003–2007
State
...........
...........
...........
...........
...........
...........
...........
...........
...........
...........
...........
County
Louisiana .......................
New York .......................
New York .......................
Pennsylvania .................
Texas .............................
Texas .............................
Texas .............................
Texas .............................
Texas .............................
Texas .............................
Texas .............................
East Baton Rouge .........
Suffolk ............................
Suffolk ............................
Philadelphia ...................
Brazoria .........................
Harris .............................
Harris .............................
Harris .............................
Harris .............................
Harris .............................
Tarrant ...........................
Maximum
design value
2003–2007
92
90
90.3
90.3
94.7
93
100.7
95.7
92.3
96.3
93.3
96
91
91
91
97
98
103
99
96
100
95
Average
design value
2012
87.8
86.3
85.1
85.3
88.8
88.4
95.7
90.5
89.9
90.5
85.1
Maximum
design value
2012
91.6
87.2
85.8
86
91
93.1
97.9
93.7
93.5
93.9
86.7
TABLE IV.C–12—AVERAGE AND MAXIMUM 2003–2007 AND 2012 BASE CASE 8-HOUR OZONE DESIGN VALUES (PPB) AT
PROJECTED MAINTENANCE-ONLY SITES
erowe on DSK5CLS3C1PROD with PROPOSALS2
Monitor ID
State
County
90010017 ...................
90011123 ...................
90013007 ...................
Connecticut ...............
Connecticut ...............
Connecticut ...............
Average
design
value
2003–2007
Fairfield ......................
Fairfield ......................
Fairfield ......................
46 As specified in the attainment demonstration
modeling guidance, if there are less than 10
modeled days > 85 ppb, then the threshold is
VerDate Mar<15>2010
20:42 Jul 30, 2010
Jkt 220001
Maximum
design
value 2003–
2007
88
92.3
90
lowered in 1 ppb increments (to as low as 70 ppb)
until there are 10 days. If there are less than 5 days
PO 00000
Frm 00044
Fmt 4701
Sfmt 4702
90
94
92
Average
design
value
2012
83.1
84.8
84.5
Maximum
design
value
2012
85
86.4
86.4
> 70 ppb, then an RRF calculation is not completed
for that site.
E:\FR\FM\02AUP2.SGM
02AUP2
Federal Register / Vol. 75, No. 147 / Monday, August 2, 2010 / Proposed Rules
45253
TABLE IV.C–12—AVERAGE AND MAXIMUM 2003–2007 AND 2012 BASE CASE 8-HOUR OZONE DESIGN VALUES (PPB) AT
PROJECTED MAINTENANCE-ONLY SITES—Continued
Monitor ID
State
County
90093002 ...................
130890002 .................
131210055 .................
361192004 .................
420170012 .................
481130069 .................
481130087 .................
482010024 .................
482010029 .................
482011015 .................
482011035 .................
482011050 .................
484392003 .................
Connecticut ...............
Georgia ......................
Georgia ......................
New York ...................
Pennsylvania .............
Texas .........................
Texas .........................
Texas .........................
Texas .........................
Texas .........................
Texas .........................
Texas .........................
Texas .........................
New Haven ................
DeKalb .......................
Fulton ........................
Westchester ..............
Bucks .........................
Dallas ........................
Dallas ........................
Harris .........................
Harris .........................
Harris .........................
Harris .........................
Harris .........................
Tarrant .......................
3. How did EPA assess interstate
contributions to nonattainment and
maintenance?
erowe on DSK5CLS3C1PROD with PROPOSALS2
Average
design
value
2003–2007
This section documents the
procedures used by EPA to quantify the
impact of emissions in specific upwind
states on air quality concentrations in
projected downwind nonattainment and
maintenance locations for annual PM2.5,
24-hour PM2.5, and 8-hour ozone. These
procedures are the first of the two-step
approach for determining significant
contribution, as described previously in
section IV.A.3.
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. Details of the
modeling techniques and postprocessing procedures are described in
this section.
CAMx employs enhanced source
apportionment techniques which track
the formation and transport of ozone
and particulate matter from specific
emissions sources and calculates the
contribution of sources and precursors
to ozone and PM2.5 for individual
receptor locations. The strength of the
photochemical model source
apportionment technique is that all
modeled ozone and/or PM2.5 mass at a
given receptor location in the modeling
domain is tracked back to specific
sources of emissions and boundary
conditions to fully characterize culpable
sources. This type of emissions
apportionment is useful to understand
the types of sources or regions that are
contributing to ozone and PM2.5
estimated by the model.
Source apportionment is an
alternative approach to zero-out
VerDate Mar<15>2010
15:19 Jul 30, 2010
Jkt 220001
Maximum
design
value 2003–
2007
90.3
88.7
91.7
87.7
88
87
87
88
91.7
89
86.3
89.3
93.7
modeling 47 and other methods to track
pollutant formation in photochemical
models. Source apportionment
completely characterizes source
contributions to model-estimated ozone
and PM2.5, which is not possible with an
emissions sensitivity approach such as
zero-out, since the change in emissions
leads to changes in pollutant
concentrations, meaning the sum of
estimated ozone or PM2.5 in all zero-out
simulations may not exactly match the
ozone or PM2.5 estimated in the base
model simulation. Photochemical model
source apportionment has the additional
advantage over emissions sensitivitybased approaches of being more
computationally efficient. There is
currently no technical evidence
showing that one technique is clearly
superior to the other for evaluating
contributions to ozone and PM2.5 from
various emission sources. However,
since source apportionment explicitly
tracks the formation and transport of all
ozone and PM2.5 mass, it is particularly
well suited for quantifying interstate
contributions as part of this proposal.
More details on the implementation of
photochemical source apportionment in
CAMx can be found in the CAMx user’s
guide. In the analysis performed for
CAIR, EPA conducted zero-out
modeling for PM2.5, and both zero-out
and source apportionment modeling for
ozone. The CAIR modeling was
conducted at 36 km resolution for PM2.5
and 12 km resolution for ozone. In
contrast, the analysis for the Transport
47 Zero-out modeling is a technique in which all
emissions are removed (e.g., NOX and VOC
emissions from a particular state) in a model run
and then compared to the results of a second model
run in which the same emissions have not been
removed. The difference between the two model
runs represents sensitivity or contribution from the
emissions that were removed.
PO 00000
Frm 00045
Fmt 4701
Sfmt 4702
93
93
94
90
92
90
88
92
93
96
95
92
95
Average
design
value
2012
82.9
81.6
84.4
84.7
81.8
82.9
84.6
83.3
84.4
83.7
82
83.9
84
Maximum
design
value
2012
85.4
85.6
86.5
86.9
85.6
85.8
85.6
87.1
85.6
90.3
90.3
86.5
85.2
Rule was performed at 12 km resolution
for both ozone and PM2.5. When
choosing the modeling techniques to
use for the Transport Rule, we carefully
considered all of the pros and cons of
each technique, including the lengthy
model run times and large file sizes of
the 12 km eastern U.S. modeling
domain. Due to the scientific credibility
of the source apportionment technique
and significant time and resource
savings compared to zero-out modeling,
we chose to perform the modeled
contribution analyses for PM2.5 and
ozone with photochemical source
apportionment.
The EPA performed source
apportionment modeling for both ozone
and PM2.5 for the 2012 base case
emissions. In this modeling we tracked
the ozone and PM2.5 formed from
emissions from sources in each upwind
state in the 12 km modeling domain.
The results were used to calculate the
contributions of these upwind
emissions to downwind nonattainment
and maintenance receptors. The states
EPA analyzed using source
apportionment for ozone and for PM2.5
are: Alabama, Arkansas, Connecticut,
Delaware, Florida, Georgia, Illinois,
Indiana, Iowa, Kansas, Kentucky,
Louisiana, Maine, Maryland,
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, Washington DC, and
Wisconsin. 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
E:\FR\FM\02AUP2.SGM
02AUP2
45254
Federal Register / Vol. 75, No. 147 / Monday, August 2, 2010 / Proposed Rules
erowe on DSK5CLS3C1PROD with PROPOSALS2
or assess the contribution from
emissions in these states.
In contrast to CAIR, all contributions
to downwind nonattainment and
maintenance receptors for the Transport
Rule were calculated using a relative
approach. This is similar to the
approach used to calculate future year
design values, as described in section
IV.C.2.a. In CAIR we used absolute and
relative metrics to examine air quality
contributions. Although absolute
contributions are useful for certain
applications, there are advantages of
examining the relative contributions for
both ozone and PM2.5. The main
advantage of relative contributions is
that they help to minimize biases
introduced by model over-predictions
and under-predictions. Also, the relative
approach constrains the total
contributions to the measurements of
ozone and PM2.5 species concentrations
at each downwind receptor. Since
model performance is variable across
the domain, EPA judged the relative
approach to be the most appropriate
technique for the Transport Rule.
a. Annual and 24-Hour PM2.5
Contribution Modeling Approach
EPA used the CAMx Particulate
Source Apportionment Technique
(PSAT) to calculate downwind PM2.5
contributions to nonattainment and
maintenance. The CAMx PSAT is
capable of ‘‘tagging’’ (i.e., tracking)
source category emissions for certain
PM species and precursor emissions.
For this proposal, we ran PSAT to tag
emissions of NOX, SO2, and primary
PM2.5 from the individual states listed
previously. Due to small modeled
concentrations of secondary organic
aerosols (SOA), and the relatively large
runtime penalty of the SOA PSAT
mechanism, we chose not to track SOA.
Through emissions pre-processing
procedures, EPA tagged all of the
anthropogenic NOX, SO2, and primary
PM2.5 emissions in each upwind state.
Each state was a separate tag, and the
tagged emissions followed state
boundaries (not grid cells).
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 IV.B., the nitrate and sulfate
contributions were combined and used
to evaluate interstate contributions of
PM2.5, as described in section IV.C.4,
later.
We developed and applied several
post-processing steps to transform the
VerDate Mar<15>2010
15:19 Jul 30, 2010
Jkt 220001
PSAT modeling outputs to PM2.5
downwind contributions. The approach
involved processing the PSAT model
outputs using MATS along with other
post-processing software to calculate the
contribution of each upwind state to
each downwind nonattainment and/or
maintenance receptor. This process
involved calculating a ratio which uses
the PSAT-predicted absolute
contribution for each species (e.g.,
sulfate) coupled with the CAMxpredicted absolute 2012 base case
concentration of the same species. The
PSAT-derived ratios were then
multiplied by the corresponding species
component concentrations comprising
the 2012 base case PM2.5 design value.
For calculating annual contributions, we
included the PSAT data for each day of
the modeled year. For 24-hour
calculations, the contributions are based
on the 10 percent highest of the days in
each quarter, as predicted for each
receptor in the 2012 base case. In the 24hour calculations, only the upwind
contribution to the highest quarter at
each receptor was used (i.e., highest
quarter based on 2012 PM2.5 mass). For
both annual and 24-hour PM2.5, the total
PM2.5 mass contribution was calculated
by summing the contributions of sulfate,
nitrate, ammonium, and particle bound
water. 48 Details on the procedures for
calculating the contribution metrics are
provided in the AQMTSD.
b. 8-Hour Ozone Contribution Modeling
Approach
EPA used the CAMX Ozone Source
Apportionment Technique (OSAT) in
order to calculate downwind 8-hour
ozone contributions to nonattainment
and maintenance. OSAT tracks the
formation of ozone from NOX and VOC
emissions. Through emissions preprocessing procedures, EPA tagged all of
the NOX and VOC emissions in each
upwind state. A separate tag was created
for each state, and the tagged emissions
followed state boundaries (not grid
cells).
All anthropogenic sources of NOX and
VOC were tracked in the OSAT
simulation. Upwind NOX and VOC
emissions were tracked to downwind
ozone concentrations. There are several
48 The water and ammonium contributions are
calculated by MATS using the default assumptions
that were used to calculate future year 2012 PM2.5
concentrations. The ammonium contribution is
calculated assuming that all particulate nitrate is in
the form of ammonium nitrate and the ammonium
associated with sulfate is based on the degree of
neutralization of the base year ambient data. In this
way, the ammonium contribution is attributed to
sulfate and nitrate precursors, not ammonia
emissions. The water concentration is calculated
based on an empirical formula that uses sulfate,
nitrate, and ammonium concentrations.
PO 00000
Frm 00046
Fmt 4701
Sfmt 4702
post-processing steps needed to
transform the raw model outputs to
ozone downwind contributions. We
developed and applied several postprocessing steps to transform the OSAT
modeling outputs to ozone
contributions at downwind receptors.
The approach for ozone was similar to
the approach for PM2.5 in that the OSAT
model outputs were processed using
MATS along with other post-processing
software to calculate the contribution of
each upwind state to each downwind
nonattainment and/or maintenance
receptor. This process involved
calculating a ratio which uses the
OSAT-predicted absolute contribution
of ozone coupled with the CAMxpredicted absolute 2012 base case ozone
concentration. The OSAT-derived ratios
were then multiplied by the
corresponding 2012 base case ozone
design value. The contributions to each
downwind receptor are averaged across
all days with modeled 2012 base case
concentrations greater than 85 ppb 49 (at
the given receptor). Details on the
procedures for calculating the
contribution metrics are provided in the
AQMTSD.
c. Use of Projected Nonattainment and
Maintenance Contributions
The previous steps provide the details
for calculating 8-hour ozone and annual
and 24-hour PM2.5 contributions to all
downwind receptors. After the postprocessing of the model results is
complete, we then evaluate the
contributions of each upwind state to
nonattainment and maintenance
receptors. The nonattainment receptors
are those monitoring sites which are
projected to exceed the NAAQS in the
2012 base case, based on 5-year
weighted average design values. The
maintenance receptors are those
monitoring sites which are projected to
exceed the NAAQS in the 2012 base
case based on the highest design value
period. The upwind ozone and PM2.5
contributions from each state are
calculated for each downwind receptor.
Contributions to nonattainment and
maintenance receptors are evaluated
independently for each state to
determine if they are above the 1
percent threshold criteria.
For each upwind state, the maximum
contribution to nonattainment is
calculated based on the single largest
49 Ozone contributions are averaged over a
minimum of 5 days. If there are fewer than 5 days
greater than 85 ppb at a receptor, then the 85 ppb
criterion is lowered in 1 ppb increments until there
are 5 days of data for use in the calculations. If there
are fewer than 5 modeled days greater than 70 ppb
at the receptor, then the receptor is not used in the
contribution calculations.
E:\FR\FM\02AUP2.SGM
02AUP2
Federal Register / Vol. 75, No. 147 / Monday, August 2, 2010 / Proposed Rules
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.
4. What are the estimated interstate
contributions to annual PM2.5, 24-Hour
PM2.5, and 8-Hour ozone nonattainment
and maintenance?
a. Contributions to Annual and 24-Hour
PM2.5 Nonattainment and Maintenance
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. We also
present the interstate contributions from
emissions in upwind states to
downwind nonattainment and
maintenance sites for the 24-hour PM2.5
NAAQS. As described previously in
section IV.B., states which contribute
0.15 μg/m3or more to annual PM2.5
nonattainment or maintenance in
another state are identified as states
with contributions to downwind
attainment and maintenance sites large
enough to warrant further analysis. For
24-hour PM2.5, states which contribute
0.35 μg/m3 or more to 24-hour PM2.5
nonattainment or maintenance in
another state are identified as states
with contributions to downwind
attainment and maintenance sites large
enough to warrant further analysis. As
described previously in section IV.C.3,
we performed air quality modeling to
quantify the contributions to annual and
24-hour PM2.5 from emissions in each of
the following 37 states individually:
Alabama, Arkansas, Connecticut,
Delaware, Florida, Georgia, Illinois,
Indiana, Iowa, Kansas, Kentucky,
45255
Louisiana, Maine, Maryland combined
with the District of Columbia,
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.
For annual PM2.5, we calculated each
state’s contribution to each of the 32
monitoring sites that are projected to be
nonattainment and each of the 16 sites
that are projected to have maintenance
problems for the annual PM2.5 NAAQS
in the 2012 base case. The largest
contribution from each state to annual
PM2.5 nonattainment in downwind sites
is provided in Table IV.C–13. The
largest contribution from each state to
annual PM2.5 maintenance in downwind
sites is also provided in Table IV.C–13.
The contributions from each state to all
projected 2012 nonattainment and
maintenance sites for the annual PM2.5
NAAQS are provided in the AQMTSD.
TABLE IV.C–13—LARGEST CONTRIBUTION TO DOWNWIND ANNUAL PM2.5 (μG/M3) NONATTAINMENT AND MAINTENANCE
FOR EACH OF 37 STATES
erowe on DSK5CLS3C1PROD with PROPOSALS2
Upwind state
Largest
downwind contribution to nonattainment for annual
PM2.5 (μg/m3)
Largest
downwind contribution to maintenance
for annual PM2.5
(μg/m3)
Alabama ...................................................................................................................................................
Arkansas ..................................................................................................................................................
Connecticut ..............................................................................................................................................
Delaware ..................................................................................................................................................
Florida ......................................................................................................................................................
Georgia ....................................................................................................................................................
Illinois .......................................................................................................................................................
Indiana .....................................................................................................................................................
Iowa .........................................................................................................................................................
Kansas .....................................................................................................................................................
Kentucky ..................................................................................................................................................
Louisiana ..................................................................................................................................................
Maine .......................................................................................................................................................
Maryland/Washington, D.C. .....................................................................................................................
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 .....................................................................................................................................................
0.46
0.09
0.04
0.20
0.29
0.63
1.01
2.09
0.31
0.09
1.68
0.11
0.01
0.63
0.07
0.72
0.19
0.07
1.38
0.08
0.01
0.34
0.49
0.19
0.05
1.49
0.08
0.83
0.01
0.26
0.02
0.68
0.13
0.00
0.36
0.18
0.04
0.09
0.14
0.07
0.18
0.63
1.78
0.30
0.05
1.01
0.34
0.02
0.56
0.13
0.71
0.17
0.03
0.27
0.06
0.02
0.68
0.47
0.11
0.05
2.03
0.05
1.60
0.01
0.04
0.02
0.64
0.06
0.00
0.37
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E:\FR\FM\02AUP2.SGM
02AUP2
45256
Federal Register / Vol. 75, No. 147 / Monday, August 2, 2010 / Proposed Rules
TABLE IV.C–13—LARGEST CONTRIBUTION TO DOWNWIND ANNUAL PM2.5 (μG/M3) NONATTAINMENT AND MAINTENANCE
FOR EACH OF 37 STATES—Continued
Upwind state
Largest
downwind contribution to nonattainment for annual
PM2.5 (μg/m3)
Largest
downwind contribution to maintenance
for annual PM2.5
(μg/m3)
West Virginia ............................................................................................................................................
Wisconsin .................................................................................................................................................
0.98
0.46
1.17
0.42
Based on the state-by-state
contribution analysis, there are 22 states
and the District of Columbia 50 which
contribute 0.15 μg/m3 or more to
downwind annual PM2.5 nonattainment.
These states are: Alabama, Delaware, the
District of Columbia, Florida, Georgia,
Illinois, Indiana, Iowa, Kentucky,
Maryland, Michigan, Minnesota,
Missouri, New Jersey, New York, North
combined Maryland and the District of
Columbia as a single entity in our contribution
modeling. This is a logical approach because of the
small size of the District of Columbia and, hence,
its emissions and its close proximity to Maryland.
erowe on DSK5CLS3C1PROD with PROPOSALS2
50 EPA
VerDate Mar<15>2010
15:19 Jul 30, 2010
Jkt 220001
Carolina, Ohio, Pennsylvania, South
Carolina, Tennessee, Virginia, West
Virginia, and Wisconsin. In Table IV.C–
14, we provide a list of the downwind
nonattainment sites to which each
upwind state contributes 0.15 μg/m3 or
more (i.e., the upwind state to
downwind nonattainment ‘‘linkages’’).
There are 19 states and the District of
Columbia 51 which contribute 0.15 μg/
51 As noted above, we combined Maryland and
the District of Columbia as a single entity in our
contribution modeling. This is a logical approach
because of the small size of the District of Columbia
and, hence, its emissions and its close proximity to
Maryland.
PO 00000
Frm 00048
Fmt 4701
Sfmt 4702
m3 or more to downwind annual PM2.5
maintenance. These states are: Alabama,
the District of Columbia, Georgia,
Illinois, Indiana, Iowa, Kentucky,
Louisiana, Maryland, Michigan,
Minnesota, Missouri, New Jersey, New
York, Ohio, Pennsylvania, Tennessee,
Virginia, West Virginia, and Wisconsin.
In Table IV.C–15, we provide a list of
the downwind maintenance sites to
which each upwind state contributes
0.15 μg/m3 or more (i.e., the upwind
state to downwind maintenance
‘‘linkages’’).
E:\FR\FM\02AUP2.SGM
02AUP2
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6
Number of
linkages
15:19 Jul 30, 2010
7
Georgia ......................................................................
Jkt 220001
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4
27
Fmt 4701
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E:\FR\FM\02AUP2.SGM
25
1
17
2
Michigan ....................................................................
2
Kentucky ....................................................................
Maryland ....................................................................
31
Iowa ...........................................................................
Indiana .......................................................................
29
3
Florida .......................................................................
Illinois ........................................................................
2
Delaware ...................................................................
Minnesota ..................................................................
Missouri .....................................................................
New Jersey ...............................................................
Bibb, GA
(130210007)
Lancaster, PA
(420710007)
Jefferson, AL
(10730023)
Jefferson, AL
(10730023)
Jefferson, AL
(10730023)
Marion, IN
(180970078)
Cuyahoga, OH
(390350038)
Hamilton, OH
(390618001)
Kanawha, WV
(540391005)
Jefferson, AL
(10730023)
Saint Clair, IL
(171630010)
Cuyahoga, OH
(390350060)
Allegheny, PA
(420031301)
Cook, IL
(170310052)
Jefferson, AL
(10730023)
Saint Clair, IL
(171630010)
Wayne, MI
(261630033)
Hamilton, OH
(390610043)
York, PA
(421330008)
Lancaster, PA
(420710007)
Cook, IL
(170310052)
Marion, IN
(180970083)
Hamilton, OH
(390610042)
Lancaster, PA
(420710007)
Cook, IL
(170310052)
Cook, IL
(170310052)
Marion, IN
(180970083)
Hamilton, OH
(390618001)
Lancaster, PA
(420710007)
02AUP2
Madison, IL
(171191007)
Jefferson, KY
(211110043)
Cabell, WV
(540110006)
York, PA
(421330008)
Jefferson, AL
(10732003)
Jefferson, KY
(211110043)
Hamilton, OH
(390618001)
Beaver, PA
(420070014)
Madison, IL
(171191007)
Jefferson, AL
(10732003)
Clark, IN
(180190006)
Butler, OH
(390170016)
Hamilton, OH
(390617001)
Cabell, WV
(540110006)
York, PA
(421330008)
Madison, IL
(171191007)
Jefferson, KY
(211110043)
Hamilton, OH
(390610043)
York, PA
(421330008)
Clayton, GA
(130630091)
York, PA
(421330008)
Bibb, GA
(130210007)
Jefferson, AL
(10732003)
Jefferson, AL
(10732003)
Marion, IN
(180970081)
Cuyahoga, OH
(390350045)
Allegheny, PA
(420030064)
Saint Clair, IL
(171630010)
Butler, OH
(390170016)
Kanawha, WV
(540391005)
Saint Clair, IL
(171630010)
Butler, OH
(390170016)
Hamilton, OH
(390617001)
Cabell, WV
(540110006)
Bibb, GA
(130210007)
Wayne, MI
(261630015)
Hamilton, OH
(390610014)
Lancaster, PA
(420710007)
Saint Clair, IL
(171630010)
Bibb, GA
(130210007)
Dubois, IN
(180372001)
Cuyahoga, OH
(390350038)
Hamilton, OH
(390618001)
Kanawha, WV
(540391005)
Clayton, GA
(130630091)
Clark, IN
(180190006)
Fulton, GA
(131210039)
Marion, IN
(180970083)
Cuyahoga, OH
(390350060)
Allegheny, PA
(420031301)
Fulton, GA
(131210039)
Clark, IN
(180190006)
Hamilton, OH
(390610014)
Clark, IN
(180190006)
Cuyahoga, OH
(390350038)
Hamilton, OH
(390618001)
Kanawha, WV
(540391005)
Clayton, GA
(130630091)
Wayne, MI
(261630033)
Hamilton, OH
(390610042)
York, PA
(421330008)
Dubois, IN
(180372001)
Clayton, GA
(130630091)
Marion, IN
(180970078)
Cuyahoga, OH
(390350045)
Allegheny, PA
(420030064)
Dubois, IN
(180372001)
Bibb, GA
(130210007)
Jefferson, KY
(211110043)
Hamilton, OH
(390610014)
Beaver, PA
(420070014)
Clark, IN
(180190006)
Dubois, IN
(180372001)
Hamilton, OH
(390610042)
Dubois, IN
(180372001)
Cuyahoga, OH
(390350045)
Allegheny, PA
(420030064)
Fulton, GA
(131210039)
Marion, IN
(180970081)
Cuyahoga, OH
(390350060)
Allegheny, PA
(420031301)
Fulton, GA
(131210039)
Butler, OH
(390170016)
Hamilton, OH
(390610043)
Cabell, WV
(540110006)
Jefferson, KY
(211110043)
Clayton, GA
(130630091)
Wayne, MI
(261630015)
Hamilton, OH
(390610042)
Lancaster, PA
(420710007)
Dubois, IN
(180372001)
Counties containing downwind 24-hour PM2.5 nonattainment sites (monitoring site ID)
Marion, IN
(180970078)
Hamilton, OH
(390610043)
Marion, IN
(180970078)
Cuyahoga, OH
(390350060)
Allegheny, PA
(420031301)
Cook, IL
(170310052)
Marion, IN
(180970083)
Hamilton, OH
(390610014)
Beaver, PA
(420070014)
Cook, IL
(170310052)
Cuyahoga, OH
(390350038)
Hamilton, OH
(390617001)
Kanawha, WV
(540391005)
Kanawha, WV
(540391005)
Clark, IN
(180190006)
Wayne, MI
(261630033)
Hamilton, OH
(390610043)
York, PA
(421330008)
Jefferson, KY
(211110043)
TABLE IV.C–14—UPWIND STATE TO DOWNWIND NONATTAINMENT SITE ‘‘LINKAGES’’ FOR ANNUAL PM2.5
Alabama ....................................................................
Upwind State
erowe on DSK5CLS3C1PROD with PROPOSALS2
Marion, IN
(180970081)
Hamilton, OH
(390617001)
Marion, IN
(180970081)
Hamilton, OH
(390610014)
Beaver, PA
(420070014)
Madison, IL
(171191007)
Wayne, MI
(261630015)
Hamilton, OH
(390610042)
Lancaster, PA
(420710007)
Madison, IL
(171191007)
Cuyahoga, OH
(390350045)
Allegheny, PA
(420030064)
Cabell, WV
(540110006)
Dubois, IN
(180372001)
Butler, OH
(390170016)
Hamilton, OH
(390617001)
Cabell, WV
(540110006)
Federal Register / Vol. 75, No. 147 / Monday, August 2, 2010 / Proposed Rules
45257
VerDate Mar<15>2010
8
15:19 Jul 30, 2010
Jkt 220001
Ohio ...........................................................................
PO 00000
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Fmt 4701
Sfmt 4702
4
29
3
E:\FR\FM\02AUP2.SGM
8
West Virginia .............................................................
Wisconsin ..................................................................
25
Virginia ......................................................................
Tennessee .................................................................
South Carolina ..........................................................
25
23
North Carolina ...........................................................
Pennsylvania .............................................................
3
New York ...................................................................
Number of
linkages
Cuyahoga, OH
(390350038)
York, PA
(421330008)
Bibb, GA
(130210007)
Jefferson, AL
(10730023)
Saint Clair, IL
(171630010)
Wayne, MI
(261630015)
Cabell, WV
(540110006)
Bibb, GA
(130210007)
Dubois, IN
(180372001)
Butler, OH
(390170016)
Hamilton, OH
(390617001)
Bibb, GA
(130210007)
Jefferson, AL
(10730023)
Saint Clair, IL
(171630010)
Wayne, MI
(261630033)
Hamilton, OH
(390610043)
Kanawha, WV
(540391005)
Lancaster, PA
(420710007)
Fulton, GA
(131210039)
Dubois, IN
(180372001)
Cuyahoga, OH
(390350060)
Allegheny, PA
(420031301)
Cook, IL
(170310052)
Cuyahoga, OH
(390350045)
York, PA
(421330008)
Bibb, GA
(130210007)
Jefferson, KY
(211110043)
Hamilton, OH
(390610014)
Beaver, PA
(420070014)
Dubois, IN
(180372001)
Clayton, GA
(130630091)
Jefferson, AL
(10732003)
Clark, IN
(180190006)
Wayne, MI
(261630033)
Kanawha, WV
(540391005)
Clayton, GA
(130630091)
Marion, IN
(180970078)
Cuyahoga, OH
(390350038)
Hamilton, OH
(390618001)
Clayton, GA
(130630091)
Jefferson, AL
(10732003)
Dubois, IN
(180372001)
Butler, OH
(390170016)
Hamilton, OH
(390617001)
Cuyahoga, OH
(390350045)
Cabell, WV
(540110006)
Clayton, GA
(130630091)
Wayne, MI
(261630015)
Hamilton, OH
(390610042)
Lancaster, PA
(420710007)
Marion, IN
(180970078)
Fulton, GA
(131210039)
Marion, IN
(180970081)
Cuyahoga, OH
(390350045)
Cabell, WV
(540110006)
Fulton, GA
(131210039)
Bibb, GA
(130210007)
Marion, IN
(180970078)
Cuyahoga, OH
(390350038)
Hamilton, OH
(390618001)
Fulton, GA
(131210039)
Bibb, GA
(130210007)
Dubois, IN
(180372001)
Allegheny, PA
(420030064)
Cuyahoga, OH
(390350060)
Kanawha, WV
(540391005)
Clark, IN
(180190006)
Wayne, MI
(261630033)
Hamilton, OH
(390610043)
York, PA
(421330008)
Marion, IN
(180970081)
Clayton, GA
(130630091)
Marion, IN
(180970081)
Cuyahoga, OH
(390350045)
Allegheny, PA
(420030064)
Cook, IL
(170310052)
Marion, IN
(180970083)
Cuyahoga, OH
(390350060)
Kanawha, WV
(540391005)
Clayton, GA
(130630091)
Marion, IN
(180970078)
Allegheny, PA
(420031301)
Allegheny, PA
(420030064)
02AUP2
Marion, IN
(180970083)
Marion, IN
(180970078)
Butler, OH
(390170016)
Hamilton, OH
(390617001)
Fulton, GA
(131210039)
Marion, IN
(180970083)
Cuyahoga, OH
(390350060)
Allegheny, PA
(420031301)
Madison, IL
(171191007)
Jefferson, KY
(211110043)
Hamilton, OH
(390610014)
Fulton, GA
(131210039)
Marion, IN
(180970081)
Beaver, PA
(420070014)
Allegheny, PA
(420031301)
Counties containing downwind 24-hour PM2.5 nonattainment sites (monitoring site ID)
Wayne, MI
(261630015)
Marion, IN
(180970081)
Cuyahoga, OH
(390350038)
Hamilton, OH
(390618001)
Clark, IN
(180190006)
Jefferson, KY
(211110043)
Hamilton, OH
(390610014)
Beaver, PA
(420070014)
Saint Clair, IL
(171630010)
Wayne, MI
(261630015)
Hamilton, OH
(390610042)
Cook, IL
(170310052)
Marion, IN
(180970083)
Lancaster, PA
(420710007)
Beaver, PA
(420070014)
TABLE IV.C–14—UPWIND STATE TO DOWNWIND NONATTAINMENT SITE ‘‘LINKAGES’’ FOR ANNUAL PM2.5—Continued
Upwind State
erowe on DSK5CLS3C1PROD with PROPOSALS2
Wayne, MI
(261630033)
Marion, IN
(180970083)
Cuyahoga, OH
(390350045)
Allegheny, PA
(420030064)
Madison, IL
(171191007)
Wayne, MI
(261630015)
Hamilton, OH
(390610042)
Cabell, WV
(540110006)
Clark, IN
(180190006)
Wayne, MI
(261630033)
Hamilton, OH
(390610043)
Madison, IL
(171191007)
Jefferson, KY
(211110043)
York, PA
(421330008)
Lancaster, PA
(420710007)
45258
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VerDate Mar<15>2010
1
Number of
linkages
15:19 Jul 30, 2010
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2
PO 00000
Frm 00051
Louisiana ...................................................................
2
1
Kentucky ....................................................................
Fmt 4701
1
Michigan ....................................................................
Sfmt 4702
E:\FR\FM\02AUP2.SGM
9
New Jersey ...............................................................
New York ...................................................................
9
2
Missouri .....................................................................
14
10
4
9
Ohio ...........................................................................
6
Minnesota ..................................................................
15
Maryland ....................................................................
12
Iowa ...........................................................................
16
13
Illinois ........................................................................
Indiana .......................................................................
1
Georgia ......................................................................
Pennsylvania .............................................................
Tennessee .................................................................
Virginia ......................................................................
West Virginia .............................................................
Jefferson, KY
(211110044)
Jefferson, KY
(211110044)
Jefferson, KY
(211110044)
Berks, PA
(420110011)
Cook, IL
(170313301)
Jefferson, OH
(390811001)
Hancock, WV
(540291004)
Cook, IL
(170313301)
Cook, IL
(170313301)
Stark, OH
(391510017)
Harris, TX
(482011035)
Berks, PA
(420110011)
Cook, IL
(170313301)
Jefferson, OH
(390811001)
Marion, WV
(540490006)
Cook, IL
(170316005)
Cook, IL
(170313301)
New York, NY
(360610056)
Cuyahoga, OH
(390350027)
Hancock, WV
(540291004)
Cook, IL
(170313301)
Hancock, WV
(540291004)
Cook, IL
(170313301)
Jefferson, OH
(390811001)
Jefferson, KY
(211110044)
Brooke, WV
(540090005)
New York, NY
(360610056)
Jefferson, KY
(211110044)
Stark, OH
(391510017)
Cook, IL
(170316005)
Berks, PA
(420110011)
Cuyahoga, OH
(390350065)
Marion, WV
(540490006)
Cook, IL
(170316005)
Marion, WV
(540490006)
Cook, IL
(170316005)
Montgomery, OH
(391130032)
Cuyahoga, OH
(390350027)
Hancock, WV
(540291004)
Berks, PA
(420110011)
New York, NY
(360610056)
Berks, PA
(420110011)
Berkeley, WV
(540030003)
Cook, IL
(170316005)
Montgomery, OH
(391130032)
Cuyahoga, OH
(390350027)
Harris, TX
(482011035)
Cook, IL
(170316005)
Montgomery, OH
(391130032)
Marion, WV
(540490006)
Cook, IL
(170316005)
Cook, IL
(170316005)
Berkeley, WV
(540030003)
02AUP2
Jefferson, KY
(211110044)
Stark, OH
(391510017)
Cuyahoga, OH
(390350065)
Marion, WV
(540490006)
Berkeley, WV
(540030003)
Cuyahoga, OH
(390350027)
Jefferson, KY
(211110044)
Jefferson, OH
(390811001)
Jefferson, KY
(211110044)
Jefferson, KY
(211110044)
Stark, OH
(391510017)
Cuyahoga, OH
(390350027)
Brooke, WV
(540090005)
Cuyahoga, OH
(390350065)
Berkeley, WV
(540030003)
Jefferson, KY
(211110044)
Stark, OH
(391510017)
Marion, WV
(540490006)
Cuyahoga, OH
(390350065)
New York, NY
(360610056)
Berkeley, WV
(540030003)
Hamilton, OH
(390610040)
New York, NY
(360610056)
Stark, OH
(391510017)
Hamilton, OH
(390610040)
New York, NY
(360610056)
Berks, PA
(420110011)
Cuyahoga, OH
(390350065)
Hancock, WV
(540291004)
Hamilton, OH
(390610040)
Brooke, WV
(540090005)
New York, NY
(360610056)
Berks, PA
(420110011)
Hamilton, OH
(390610040)
Cuyahoga, OH
(390350027)
Brooke, WV
(540090005)
Jefferson, OH
(390811001)
Berks, PA
(420110011)
Berks, PA
(420110011)
Montgomery, OH
(391130032)
Cuyahoga, OH
(390350027)
Berkeley, WV
(540030003)
Hamilton, OH
(390610040)
Marion, WV
(540490006)
Jefferson, OH
(390811001)
Hancock, WV
(540291004)
Cuyahoga, OH
(390350027)
Harris, TX
(482011035)
Counties containing downwind 24-hour PM2.5 nonattainment sites (monitoring site ID)
Jefferson, OH
(390811001)
Cuyahoga, OH
(390350065)
Hancock, WV
(540291004)
Montgomery, OH
(391130032)
Berkeley, WV
(540030003)
Berkeley, WV
(540030003)
Stark, OH
(391510017)
Cuyahoga, OH
(390350065)
Brooke, WV
(540090005)
Jefferson, OH
(390811001)
Montgomery, OH
(391130032)
Marion, WV
(540490006)
Cuyahoga, OH
(390350065)
Berkeley, WV
(540030003)
TABLE IV.C–15—UPWIND STATE TO DOWNWIND MAINTENANCE SITE ‘‘LINKAGES’’ FOR ANNUAL PM2.5
Alabama ....................................................................
Upwind State
erowe on DSK5CLS3C1PROD with PROPOSALS2
Montgomery, OH
(391130032)
Hamilton, OH
(390610040)
Marion, WV
(540490006)
Stark, OH
(391510017)
Brooke, WV
(540090005)
Brooke, WV
(540090005)
Hamilton, OH
(390610040)
Hancock, WV
(540291004)
Montgomery, OH
(391130032)
Hamilton, OH
(390610040)
Brooke, WV
(540090005)
Stark, OH
(391510017)
Federal Register / Vol. 75, No. 147 / Monday, August 2, 2010 / Proposed Rules
45259
VerDate Mar<15>2010
Wisconsin ..................................................................
2
Number of
linkages
Cook, IL
(170313301)
Cook, IL
(170316005)
Counties containing downwind 24-hour PM2.5 nonattainment sites (monitoring site ID)
TABLE IV.C–15—UPWIND STATE TO DOWNWIND MAINTENANCE SITE ‘‘LINKAGES’’ FOR ANNUAL PM2.5—Continued
Upwind State
erowe on DSK5CLS3C1PROD with PROPOSALS2
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Federal Register / Vol. 75, No. 147 / Monday, August 2, 2010 / Proposed Rules
For 24-hour PM2.5, we calculated each
state’s contribution to each of the 92
monitoring sites that are projected to be
nonattainment and each of the 38 sites
that are projected to have maintenance
problems for the 24-hour PM2.5 NAAQS
in the 2012 base case. The largest
contribution from each state to 24-hour
PM2.5 nonattainment in downwind sites
is provided in Table IV.C–16. The
largest contribution from each state to
24-hour PM2.5 maintenance in
downwind sites is also provided in
Table IV.C–16. The contributions from
each state to all projected 2012
nonattainment and maintenance sites
for the 24-hour PM2.5 NAAQS are
provided in the AQMTSD.
TABLE IV.C–16—LARGEST CONTRIBUTION TO DOWNWIND 24-HOUR PM2.5 (μG/M3) NONATTAINMENT AND MAINTENANCE
FOR EACH OF 37 STATES
Largest downwind contribution to nonattainment for
24-hour PM2.5
(μg/m3)
Upwind State
erowe on DSK5CLS3C1PROD with PROPOSALS2
Alabama ...................................................................................................................................................................
Arkansas ..................................................................................................................................................................
Connecticut ..............................................................................................................................................................
Delaware ..................................................................................................................................................................
Florida ......................................................................................................................................................................
Georgia ....................................................................................................................................................................
Illinois .......................................................................................................................................................................
Indiana .....................................................................................................................................................................
Iowa .........................................................................................................................................................................
Kansas .....................................................................................................................................................................
Kentucky ..................................................................................................................................................................
Louisiana ..................................................................................................................................................................
Maine .......................................................................................................................................................................
Maryland/Washington, DC .......................................................................................................................................
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 ............................................................................................................................................................
Wisconsin .................................................................................................................................................................
Largest downwind contribution to maintenance for 24hour PM2.5
(μg/m3)
0.48
0.20
0.41
0.50
0.08
0.95
7.28
9.91
1.87
0.77
6.53
0.23
0.19
2.63
0.67
2.35
0.91
0.09
5.03
0.62
0.21
2.69
5.82
0.50
0.27
5.84
0.16
3.67
0.05
0.19
0.13
3.92
0.21
0.06
1.32
3.51
0.80
0.32
0.17
0.70
0.36
0.08
0.41
6.57
8.94
1.67
0.45
6.91
0.18
0.19
1.82
0.71
3.35
0.86
0.04
4.82
0.39
0.23
4.74
1.17
0.45
0.15
5.56
0.21
4.86
0.06
0.19
0.09
4.70
0.28
0.07
2.26
4.83
1.01
Based on the state-by-state
contribution analysis, there are 24 states
and the District of Columbia 52 which
contribute 0.35 μg/m3 or more to
downwind 24-hour PM2.5
nonattainment. These states are:
Alabama, the District of Columbia,
Georgia, Illinois, Indiana, Iowa, Kansas,
Kentucky, Maryland, Massachusetts,
Michigan, Minnesota, Missouri,
Nebraska, New Jersey, New York, North
Carolina, Ohio, Pennsylvania,
Tennessee, Virginia, West Virginia, and
Wisconsin. In Table IV.C–17, we
provide a list of the downwind
nonattainment counties to which each
upwind state contributes 0.35 μg/m3 or
more (i.e., the upwind state to
downwind nonattainment ‘‘linkages’’).
There are 23 states and the District of
Columbia which contribute 0.35 μg/m3
or more to downwind 24-hour PM2.5
maintenance. These states are:
Connecticut, Delaware, the District of
Columbia, Georgia, Illinois, Indiana,
Iowa, Kansas, Kentucky, Maryland,
Massachusetts, Michigan, Minnesota,
Missouri, Nebraska, New Jersey, New
York, North Carolina, Ohio,
Pennsylvania, Tennessee, Virginia, West
Virginia, and Wisconsin. In Table IV.C–
18, we provide a list of the downwind
maintenance sites to which each
upwind state contributes 0.35 μg/m3 or
more (i.e., the upwind state to
downwind maintenance ‘‘linkages’’).
52 As noted above, we combined Maryland and
the District of Columbia as a single entity in our
contribution modeling. This is a logical approach
because of the small size of the District of Columbia
and, hence, its emissions and its close proximity to
Maryland.
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Federal Register / Vol. 75, No. 147 / Monday, August 2, 2010 / Proposed Rules
TABLE IV.C–17—UPWIND STATE TO DOWNWIND NONATTAINMENT SITE ‘‘LINKAGES’’ FOR 24-HOUR PM2.5
Upwind State
Number of
linkages
Counties containing downwind 24-hour PM2.5 nonattainment sites (monitoring site ID)
5
Connecticut ................
3
Delaware ....................
2
Georgia .......................
12
Illinois .........................
70
Indiana ........................
75
Iowa ............................
17
Kansas .......................
erowe on DSK5CLS3C1PROD with PROPOSALS2
Alabama .....................
3
Kentucky .....................
81
VerDate Mar<15>2010
15:19 Jul 30, 2010
Monroe, MI
(261150005)
Hudson, NJ
(340172002)
Union, NJ
(340390004)
Jefferson, AL
(10730023)
Butler, OH
(390171004)
Jefferson, AL
(10730023)
Lake, IN
(180890022)
Marion, IN
(180970079)
Jefferson, KY
(211110043)
Washtenaw, MI
(261610008)
Jefferson, MO
(290990012)
Butler, OH
(390170003)
Cuyahoga, OH
(390350060)
Hamilton, OH
(390610040)
Montgomery, OH
(391130032)
Allegheny, PA
(420031301)
Milwaukee, WI
(550790010)
Jefferson, AL
(10730023)
Cook, IL
(170311016)
Madison, IL
(171191007)
Jefferson, KY
(211110044)
Wayne, MI
(261630015)
Saint Charles, MO
(291831002)
New York, NY
(360610056)
Cuyahoga, OH
(390350038)
Hamilton, OH
(390610006)
Hamilton, OH
(390618001)
Allegheny, PA
(420030093)
Cambria, PA
(420210011)
Milwaukee, WI
(550790026)
Cook, IL
(170310052)
Cook, IL
(170313301)
St. Louis City, MO
(295100007)
Milwaukee, WI
(550790010)
Jefferson, AL
(10730023)
Cook, IL
(170311016)
Madison, IL
(171191007)
Lake, IN
(180890026)
Marion, IN
(180970081)
Jkt 220001
PO 00000
Wayne, MI
(261630015)
New York, NY
(360610056)
Dauphin, PA
(420430401)
Jefferson, AL
(10732003)
Hamilton, OH
(390610006)
Jefferson, AL
(10732003)
Lake, IN
(180890026)
Marion, IN
(180970081)
Jefferson, KY
(211110044)
Wayne, MI
(261630015)
Saint Charles, MO
(291831002)
Butler, OH
(390170016)
Cuyahoga, OH
(390350065)
Hamilton, OH
(390610042)
Summit, OH
(391530017)
Beaver, PA
(420070014)
Milwaukee, WI
(550790026)
Jefferson, AL
(10732003)
Cook, IL
(170312001)
Madison, IL
(171192009)
Jefferson, KY
(211110048)
Wayne, MI
(261630016)
St. Louis City, MO
(295100007)
New York, NY
(360610128)
Cuyahoga, OH
(390350045)
Hamilton, OH
(390610014)
Jefferson, OH
(390811001)
Allegheny, PA
(420030116)
Dauphin, PA
(420430401)
Milwaukee, WI
(550790043)
Cook, IL
(170310057)
Cook, IL
(170316005)
Milwaukee, WI
(550790010)
Milwaukee, WI
(550790026)
Jefferson, AL
(10732003)
Cook, IL
(170312001)
Madison, IL
(171192009)
Marion, IN
(180970042)
Marion, IN
(180970083)
Frm 00054
Fmt 4701
Hamilton, OH
(390610006)
New York, NY
(360610128)
Hamilton, OH
(390610014)
Hamilton, OH
(390618001)
Baltimore City, MD
(245100040)
Hamilton, OH
(390610014)
New Haven, CT
(90091123)
Marion, IN
(180970042)
Marion, IN
(180970083)
Jefferson, KY
(211110048)
Wayne, MI
(261630016)
St. Louis City, MO
(295100007)
Butler, OH
(390170017)
Franklin, OH
(390490024)
Hamilton, OH
(390610043)
Allegheny, PA
(420030064)
Berks, PA
(420110011)
Milwaukee, WI
(550790043)
New Haven, CT
(90091123)
Cook, IL
(170313103)
Madison, IL
(171193007)
Monroe, MI
(261150005)
Wayne, MI
(261630019)
St. Louis City, MO
(295100087)
Butler, OH
(390170003)
Cuyahoga, OH
(390350060)
Hamilton, OH
(390610040)
Montgomery, OH
(391130032)
Allegheny, PA
(420031008)
York, PA
(421330008)
Milwaukee, WI
(550790099)
Cook, IL
(170310076)
Madison, IL
(171191007)
Milwaukee, WI
(550790026)
Milwaukee, WI
(550790099)
New Haven, CT
(90091123)
Cook, IL
(170313103)
Madison, IL
(171193007)
Marion, IN
(180970043)
Tippecanoe, IN
(181570008)
Baltimore City, MD
(245100049)
Hamilton, OH
(390618001)
Clark, IN
(180190006)
Marion, IN
(180970043)
Tippecanoe, IN
(181570008)
Monroe, MI
(261150005)
Wayne, MI
(261630019)
St. Louis City, MO
(295100087)
Butler, OH
(390171004)
Franklin, OH
(390490025)
Hamilton, OH
(390617001)
Allegheny, PA
(420030093)
Cambria, PA
(420210011)
Milwaukee, WI
(550790099)
Cook, IL
(170310052)
Cook, IL
(170313301)
Scott, IA
(191630019)
Oakland, MI
(261250001)
Wayne, MI
(261630033)
Hudson, NJ
(340171003)
Butler, OH
(390170016)
Cuyahoga, OH
(390350065)
Hamilton, OH
(390610042)
Summit, OH
(391530017)
Allegheny, PA
(420031301)
Montgomery, TN
(471251009)
Union, NJ
(340390004)
Montgomery, OH
(391130032)
Dubois, IN
(180372001)
Marion, IN
(180970066)
Scott, IA
(191630019)
Oakland, MI
(261250001)
Wayne, MI
(261630033)
Union, NJ
(340390004)
Cuyahoga, OH
(390350038)
Hamilton, OH
(390610006)
Hamilton, OH
(390618001)
Allegheny, PA
(420030116)
Montgomery, TN
(471251009)
Butler, OH
(390170016)
York, PA
(421330008)
Knox, IN
(180830004)
Marion, IN
(180970078)
Daviess, KY
(210590005)
St. Clair, MI
(261470005)
Wayne, MI
(261630036)
New York, NY
(360610128)
Cuyahoga, OH
(390350045)
Hamilton, OH
(390610014)
Jefferson, OH
(390811001)
Allegheny, PA
(420031008)
Brooke, WV
(540090011)
Cook, IL
(170310057)
Cook, IL
(170316005)
Daviess, KY
(210590005)
St. Clair, MI
(261470005)
Wayne, MI
(261630036)
Union, NJ
(340390004)
Butler, OH
(390170017)
Franklin, OH
(390490024)
Hamilton, OH
(390610043)
Allegheny, PA
(420030008)
Beaver, PA
(420070014)
Brooke, WV
(540090011)
Cook, IL
(170310076)
Madison, IL
(171190023)
Jefferson, KY
(211110043)
Washtenaw, MI
(261610008)
Jefferson, MO
(290990012)
Bronx, NY
(360050080)
Butler, OH
(390171004)
Franklin, OH
(390490025)
Hamilton, OH
(390617001)
Allegheny, PA
(420030064)
Berks, PA
(420110011)
Milwaukee, WI
(550790010)
Cook, IL
(170311016)
Lake, IN
(180890022)
Milwaukee, WI
(550790043)
Cook, IL
(170312001)
Lake, IN
(180890026)
Milwaukee, WI
(550790099)
Cook, IL
(170313103)
Jefferson, MO
(290990012)
Cook, IL
(170310052)
Cook, IL
(170313301)
Clark, IN
(180190006)
Marion, IN
(180970066)
Scott, IA
(191630019)
Cook, IL
(170310057)
Cook, IL
(170316005)
Dubois, IN
(180372001)
Marion, IN
(180970078)
Monroe, MI
(261150005)
Cook, IL
(170310076)
Madison, IL
(171190023)
Knox, IN
(180830004)
Marion, IN
(180970079)
Oakland, MI
(261250001)
Sfmt 4702
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Federal Register / Vol. 75, No. 147 / Monday, August 2, 2010 / Proposed Rules
45263
TABLE IV.C–17—UPWIND STATE TO DOWNWIND NONATTAINMENT SITE ‘‘LINKAGES’’ FOR 24-HOUR PM2.5—Continued
Upwind State
Number of
linkages
Counties containing downwind 24-hour PM2.5 nonattainment sites (monitoring site ID)
11
Massachusetts ...........
3
Michigan .....................
48
Minnesota ...................
4
Missouri ......................
56
Nebraska ....................
3
New Jersey ................
erowe on DSK5CLS3C1PROD with PROPOSALS2
Maryland .....................
9
New York ....................
23
VerDate Mar<15>2010
15:19 Jul 30, 2010
St. Clair, MI
(261470005)
Wayne, MI
(261630036)
Union, NJ
(340390004)
Butler, OH
(390171004)
Franklin, OH
(390490025)
Hamilton, OH
(390617001)
Allegheny, PA
(420030064)
Berks, PA
(420110011)
Milwaukee, WI
(550790026)
New Haven, CT
(90091123)
New York, NY
(360610128)
New Haven, CT
(90091123)
Cook, IL
(170310052)
Cook, IL
(170313301)
Knox, IN
(180830004)
St. Louis City, MO
(295100007)
Cuyahoga, OH
(390350065)
Jefferson, OH
(390811001)
Allegheny, PA
(420030116)
Montgomery, TN
(471251009)
Milwaukee, WI
(550790099)
Milwaukee, WI
(550790010)
Cook, IL
(170310052)
Cook, IL
(170313301)
Clark, IN
(180190006)
Marion, IN
(180970043)
Tippecanoe, IN
(181570008)
Monroe, MI
(261150005)
Butler, OH
(390170003)
Hamilton, OH
(390610006)
Hamilton, OH
(390618001)
Milwaukee, WI
(550790043)
Milwaukee, WI
(550790010)
New Haven, CT
(90091123)
Dauphin, PA
(420430401)
New Haven, CT
(90091123)
Wayne, MI
(261630019)
Cuyahoga, OH
(390350038)
Summit, OH
(391530017)
Jkt 220001
PO 00000
Washtenaw, MI
(261610008)
Jefferson, MO
(290990012)
Bronx, NY
(360050080)
Cuyahoga, OH
(390350038)
Hamilton, OH
(390610006)
Hamilton, OH
(390618001)
Allegheny, PA
(420030093)
Cambria, PA
(420210011)
Milwaukee, WI
(550790043)
Hudson, NJ
(340171003)
Berks, PA
(420110011)
New York, NY
(360610056)
Cook, IL
(170310057)
Cook, IL
(170316005)
Lake, IN
(180890022)
St. Louis City, MO
(295100087)
Franklin, OH
(390490024)
Montgomery, OH
(391130032)
Allegheny, PA
(420031008)
Brooke, WV
(540090011)
Wayne, MI
(261630015)
Saint Charles, MO
(291831002)
New York, NY
(360610128)
Cuyahoga, OH
(390350045)
Hamilton, OH
(390610014)
Jefferson, OH
(390811001)
Allegheny, PA
(420030116)
York, PA
(421330008)
Milwaukee, WI
(550790099)
Hudson, NJ
(340172002)
Dauphin, PA
(420430401)
New York, NY
(360610128)
Cook, IL
(170310076)
Madison, IL
(171190023)
Lake, IN
(180890026)
New York, NY
(360610128)
Franklin, OH
(390490025)
Summit, OH
(391530017)
Allegheny, PA
(420031301)
Milwaukee, WI
(550790010)
Wayne, MI
(261630016)
St. Louis City, MO
(295100007)
Butler, OH
(390170003)
Cuyahoga, OH
(390350060)
Hamilton, OH
(390610040)
Montgomery, OH
(391130032)
Allegheny, PA
(420031008)
Montgomery, TN
(471251009)
Wayne, MI
(261630019)
St. Louis City, MO
(295100087)
Butler, OH
(390170016)
Cuyahoga, OH
(390350065)
Hamilton, OH
(390610042)
Summit, OH
(391530017)
Allegheny, PA
(420031301)
Brooke, WV
(540090011)
Wayne, MI
(261630033)
Hudson, NJ
(340171003)
Butler, OH
(390170017)
Franklin, OH
(390490024)
Hamilton, OH
(390610043)
Allegheny, PA
(420030008)
Beaver, PA
(420070014)
Milwaukee, WI
(550790010)
Union, NJ
(340390004)
Lancaster, PA
(420710007)
Bronx, NY
(360050080)
York, PA
(421330008)
New York, NY
(360610056)
Cook, IL
(170311016)
Madison, IL
(171191007)
Scott, IA
(191630019)
Cuyahoga, OH
(390350038)
Hamilton, OH
(390610014)
Allegheny, PA
(420030008)
Beaver, PA
(420070014)
Milwaukee, WI
(550790026)
Cook, IL
(170312001)
Madison, IL
(171192009)
Jefferson, MO
(290990012)
Cuyahoga, OH
(390350045)
Hamilton, OH
(390617001)
Allegheny, PA
(420030064)
Cambria, PA
(420210011)
Milwaukee, WI
(550790043)
Cook, IL
(170313103)
Madison, IL
(171193007)
Saint Charles, MO
(291831002)
Cuyahoga, OH
(390350060)
Hamilton, OH
(390618001)
Allegheny, PA
(420030093)
Dauphin, PA
(420430401)
Milwaukee, WI
(550790026)
Cook, IL
(170310057)
Cook, IL
(170316005)
Dubois, IN
(180372001)
Marion, IN
(180970066)
Scott, IA
(191630019)
Oakland, MI
(261250001)
Butler, OH
(390170016)
Hamilton, OH
(390610014)
Montgomery, OH
(391130032)
Milwaukee, WI
(550790099)
Milwaukee, WI
(550790026)
Baltimore City, MD
(245100049)
Lancaster, PA
(420710007)
Baltimore City, MD
(245100040)
Wayne, MI
(261630033)
Cuyahoga, OH
(390350045)
Berks, PA
(420110011)
Milwaukee, WI
(550790043)
Cook, IL
(170310076)
Madison, IL
(171190023)
Knox, IN
(180830004)
Marion, IN
(180970078)
Daviess, KY
(210590005)
Washtenaw, MI
(261610008)
Butler, OH
(390170017)
Hamilton, OH
(390610040)
Allegheny, PA
(420030116)
Milwaukee, WI
(550790099)
Cook, IL
(170311016)
Madison, IL
(171191007)
Lake, IN
(180890022)
Marion, IN
(180970079)
Jefferson, KY
(211110043)
Wayne, MI
(261630015)
Butler, OH
(390171004)
Hamilton, OH
(390610042)
Montgomery, TN
(471251009)
Cook, IL
(170312001)
Madison, IL
(171192009)
Lake, IN
(180890026)
Marion, IN
(180970081)
Jefferson, KY
(211110044)
Wayne, MI
(261630033)
Franklin, OH
(390490024)
Hamilton, OH
(390610043)
Milwaukee, WI
(550790010)
Cook, IL
(170313103)
Madison, IL
(171193007)
Marion, IN
(180970042)
Marion, IN
(180970083)
Jefferson, KY
(211110048)
Wayne, MI
(261630036)
Franklin, OH
(390490025)
Hamilton, OH
(390617001)
Milwaukee, WI
(550790026)
New York, NY
(360610056)
New York, NY
(360610128)
Berks, PA
(420110011)
St. Clair, MI
(261470005)
Hudson, NJ
(340171003)
Cuyahoga, OH
(390350065)
Lancaster, PA
(420710007)
Washtenaw, MI
(261610008)
Hudson, NJ
(340172002)
Franklin, OH
(390490024)
York, PA
(421330008)
Wayne, MI
(261630016)
Union, NJ
(340390004)
Franklin, OH
(390490025)
Frm 00055
Fmt 4701
Milwaukee, WI
(550790099)
Bronx, NY
(360050080)
York, PA
(421330008)
Baltimore City, MD
(245100049)
Wayne, MI
(261630036)
Cuyahoga, OH
(390350060)
Dauphin, PA
(420430401)
Sfmt 4702
E:\FR\FM\02AUP2.SGM
02AUP2
45264
Federal Register / Vol. 75, No. 147 / Monday, August 2, 2010 / Proposed Rules
TABLE IV.C–17—UPWIND STATE TO DOWNWIND NONATTAINMENT SITE ‘‘LINKAGES’’ FOR 24-HOUR PM2.5—Continued
Upwind State
Number of
linkages
Counties containing downwind 24-hour PM2.5 nonattainment sites (monitoring site ID)
11
Ohio ............................
72
Pennsylvania ..............
77
Tennessee ..................
erowe on DSK5CLS3C1PROD with PROPOSALS2
North Carolina ............
61
Virginia .......................
13
VerDate Mar<15>2010
20:42 Jul 30, 2010
Baltimore City, MD
(245100040)
New York, NY
(360610056)
Jefferson, AL
(10730023)
Cook, IL
(170311016)
Madison, IL
(171191007)
Lake, IN
(180890022)
Marion, IN
(180970079)
Jefferson, KY
(211110043)
Oakland, MI
(261250001)
Wayne, MI
(261630033)
Hudson, NJ
(340171003)
Allegheny, PA
(420030008)
Beaver, PA
(420070014)
Montgomery, TN
(471251009)
Jefferson, AL
(10730023)
Cook, IL
(170311016)
Madison, IL
(171192009)
Lake, IN
(180890026)
Marion, IN
(180970081)
Jefferson, KY
(211110048)
Washtenaw, MI
(261610008)
Jefferson, MO
(290990012)
Union, NJ
(340390004)
Butler, OH
(390170017)
Franklin, OH
(390490024)
Hamilton, OH
(390610043)
Montgomery, TN
(471251009)
Jefferson, AL
(10730023)
Madison, IL
(171193007)
Marion, IN
(180970066)
Scott, IA
(191630019)
Oakland, MI
(261250001)
Jefferson, MO
(290990012)
Butler, OH
(390170003)
Cuyahoga, OH
(390350065)
Hamilton, OH
(390610042)
Summit, OH
(391530017)
York, PA
(421330008)
New Haven, CT
(90091123)
Jkt 220001
PO 00000
Baltimore City, MD
(245100049)
Berks, PA
(420110011)
Jefferson, AL
(10732003)
Cook, IL
(170312001)
Madison, IL
(171192009)
Lake, IN
(180890026)
Marion, IN
(180970081)
Jefferson, KY
(211110044)
St. Clair, MI
(261470005)
Wayne, MI
(261630036)
Hudson, NJ
(340172002)
Allegheny, PA
(420030064)
Berks, PA
(420110011)
Brooke, WV
(540090011)
Jefferson, AL
(10732003)
Cook, IL
(170312001)
Madison, IL
(171193007)
Marion, IN
(180970042)
Marion, IN
(180970083)
Baltimore City, MD
(245100040)
Wayne, MI
(261630015)
Saint Charles, MO
(291831002)
Bronx, NY
(360050080)
Butler, OH
(390171004)
Franklin, OH
(390490025)
Hamilton, OH
(390617001)
Brooke, WV
(540090011)
Jefferson, AL
(10732003)
Clark, IN
(180190006)
Marion, IN
(180970078)
Daviess, KY
(210590005)
St. Clair, MI
(261470005)
Saint Charles, MO
(291831002)
Butler, OH
(390170016)
Franklin, OH
(390490024)
Hamilton, OH
(390610043)
Allegheny, PA
(420030093)
Hudson, NJ
(340171003)
Dauphin, PA
(420430401)
New Haven, CT
(90091123)
Cook, IL
(170313103)
Madison, IL
(171193007)
Marion, IN
(180970042)
Marion, IN
(180970083)
Jefferson, KY
(211110048)
Washtenaw, MI
(261610008)
Jefferson, MO
(290990012)
Union, NJ
(340390004)
Allegheny, PA
(420030093)
Cambria, PA
(420210011)
Milwaukee, WI
(550790010)
New Haven, CT
(90091123)
Cook, IL
(170313103)
Madison, IL
(171190023)
Marion, IN
(180970043)
Tippecanoe, IN
(181570008)
Baltimore City, MD
(245100049)
Wayne, MI
(261630016)
St. Louis City, MO
(295100007)
New York, NY
(360610056)
Cuyahoga, OH
(390350038)
Hamilton, OH
(390610006)
Hamilton, OH
(390618001)
Milwaukee, WI
(550790026)
New Haven, CT
(90091123)
Dubois, IN
(180372001)
Marion, IN
(180970079)
Jefferson, KY
(211110043)
Washtenaw, MI
(261610008)
St. Louis City, MO
(295100007)
Butler, OH
(390170017)
Franklin, OH
(390490025)
Hamilton, OH
(390617001)
Allegheny, PA
(420030116)
Hudson, NJ
(340172002)
Lancaster, PA
(420710007)
Cook, IL
(170310052)
Cook, IL
(170313301)
Clark, IN
(180190006)
Marion, IN
(180970043)
Tippecanoe, IN
(181570008)
Baltimore City, MD
(245100040)
Wayne, MI
(261630015)
Saint Charles, MO
(291831002)
Bronx, NY
(360050080)
Allegheny, PA
(420030116)
Dauphin, PA
(420430401)
Milwaukee, WI
(550790026)
Cook, IL
(170310052)
Cook, IL
(170313301)
Clark, IN
(180190006)
Marion, IN
(180970066)
Scott, IA
(191630019)
Monroe, MI
(261150005)
Wayne, MI
(261630019)
St. Louis City, MO
(295100087)
New York, NY
(360610128)
Cuyahoga, OH
(390350045)
Hamilton, OH
(390610014)
Jefferson, OH
(390811001)
Milwaukee, WI
(550790043)
Madison, IL
(171190023)
Knox, IN
(180830004)
Marion, IN
(180970081)
Jefferson, KY
(211110044)
Wayne, MI
(261630015)
St. Louis City, MO
(295100087)
Butler, OH
(390171004)
Hamilton, OH
(390610006)
Hamilton, OH
(390618001)
Allegheny, PA
(420031008)
Union, NJ
(340390004)
York, PA
(421330008)
Cook, IL
(170310057)
Cook, IL
(170316005)
Dubois, IN
(180372001)
Marion, IN
(180970066)
Scott, IA
(191630019)
Baltimore City, MD
(245100049)
Wayne, MI
(261630016)
St. Louis City, MO
(295100007)
New York, NY
(360610056)
Allegheny, PA
(420031008)
Lancaster, PA
(420710007)
Milwaukee, WI
(550790043)
Cook, IL
(170310057)
Cook, IL
(170316005)
Dubois, IN
(180372001)
Marion, IN
(180970078)
Jefferson, KY
(211110043)
Oakland, MI
(261250001)
Wayne, MI
(261630033)
Hudson, NJ
(340171003)
Butler, OH
(390170003)
Cuyahoga, OH
(390350060)
Hamilton, OH
(390610040)
Montgomery, OH
(391130032)
Milwaukee, WI
(550790099)
Madison, IL
(171191007)
Marion, IN
(180970042)
Marion, IN
(180970083)
Jefferson, KY
(211110048)
Wayne, MI
(261630033)
Union, NJ
(340390004)
Cuyahoga, OH
(390350038)
Hamilton, OH
(390610014)
Jefferson, OH
(390811001)
Allegheny, PA
(420031301)
Bronx, NY
(360050080)
Baltimore City, MD
(245100040)
Baltimore City, MD
(245100049)
Hudson, NJ
(340171003)
Hudson, NJ
(340172002)
Union, NJ
(340390004)
Frm 00056
Fmt 4701
Sfmt 4702
E:\FR\FM\02AUP2.SGM
02AUP2
Cook, IL
(170310076)
Madison, IL
(171190023)
Knox, IN
(180830004)
Marion, IN
(180970078)
Daviess, KY
(210590005)
Monroe, MI
(261150005)
Wayne, MI
(261630019)
St. Louis City, MO
(295100087)
New York, NY
(360610128)
Allegheny, PA
(420031301)
York, PA
(421330008)
Milwaukee, WI
(550790099)
Cook, IL
(170310076)
Madison, IL
(171191007)
Knox, IN
(180830004)
Marion, IN
(180970079)
Jefferson, KY
(211110044)
St. Clair, MI
(261470005)
Wayne, MI
(261630036)
Hudson, NJ
(340172002)
Butler, OH
(390170016)
Cuyahoga, OH
(390350065)
Hamilton, OH
(390610042)
Summit, OH
(391530017)
Madison, IL
(171192009)
Marion, IN
(180970043)
Tippecanoe, IN
(181570008)
Monroe, MI
(261150005)
Wayne, MI
(261630036)
New York, NY
(360610128)
Cuyahoga, OH
(390350045)
Hamilton, OH
(390610040)
Montgomery, OH
(391130032)
Cambria, PA
(420210011)
45265
Federal Register / Vol. 75, No. 147 / Monday, August 2, 2010 / Proposed Rules
TABLE IV.C–17—UPWIND STATE TO DOWNWIND NONATTAINMENT SITE ‘‘LINKAGES’’ FOR 24-HOUR PM2.5—Continued
Upwind State
Number of
linkages
Counties containing downwind 24-hour PM2.5 nonattainment sites (monitoring site ID)
West Virginia ..............
84
Wisconsin ...................
12
Bronx, NY
(360050080)
York, PA
(421330008)
Jefferson, AL
(10730023)
Cook, IL
(170311016)
Madison, IL
(171192009)
Marion, IN
(180970043)
Tippecanoe, IN
(181570008)
Baltimore City, MD
(245100049)
Wayne, MI
(261630016)
St. Louis City, MO
(295100007)
New York, NY
(360610056)
Cuyahoga, OH
(390350038)
Hamilton, OH
(390610006)
Hamilton, OH
(390618001)
Allegheny, PA
(420030093)
Cambria, PA
(420210011)
Cook, IL
(170310052)
Cook, IL
(170313301)
New York, NY
(360610056)
New York, NY
(360610128)
Berks, PA
(420110011)
Dauphin, PA
(420430401)
Lancaster, PA
(420710007)
Jefferson, AL
(10732003)
Cook, IL
(170312001)
Madison, IL
(171193007)
Marion, IN
(180970066)
Scott, IA
(191630019)
Monroe, MI
(261150005)
Wayne, MI
(261630019)
St. Louis City, MO
(295100087)
New York, NY
(360610128)
Cuyahoga, OH
(390350045)
Hamilton, OH
(390610014)
Jefferson, OH
(390811001)
Allegheny, PA
(420030116)
Dauphin, PA
(420430401)
Cook, IL
(170310057)
Cook, IL
(170316005)
New Haven, CT
(90091123)
Cook, IL
(170313301)
Clark, IN
(180190006)
Marion, IN
(180970078)
Jefferson, KY
(211110043)
Oakland, MI
(261250001)
Wayne, MI
(261630033)
Hudson, NJ
(340171003)
Butler, OH
(390170003)
Cuyahoga, OH
(390350060)
Hamilton, OH
(390610040)
Montgomery, OH
(391130032)
Allegheny, PA
(420031008)
Lancaster, PA
(420710007)
Cook, IL
(170310076)
Lake, IN
(180890022)
Cook, IL
(170310052)
Cook, IL
(170316005)
Dubois, IN
(180372001)
Marion, IN
(180970079)
Jefferson, KY
(211110044)
St. Clair, MI
(261470005)
Wayne, MI
(261630036)
Hudson, NJ
(340172002)
Butler, OH
(390170016)
Cuyahoga, OH
(390350065)
Hamilton, OH
(390610042)
Summit, OH
(391530017)
Allegheny, PA
(420031301)
York, PA
(421330008)
Cook, IL
(170311016)
Lake, IN
(180890026)
Cook, IL
(170310057)
Madison, IL
(171190023)
Lake, IN
(180890026)
Marion, IN
(180970081)
Jefferson, KY
(211110048)
Washtenaw, MI
(261610008)
Jefferson, MO
(290990012)
Union, NJ
(340390004)
Butler, OH
(390170017)
Franklin, OH
(390490024)
Hamilton, OH
(390610043)
Allegheny, PA
(420030008)
Beaver, PA
(420070014)
Montgomery, TN
(471251009)
Cook, IL
(170312001)
Scott, IA
(191630019)
Cook, IL
(170310076)
Madison, IL
(171191007)
Marion, IN
(180970042)
Marion, IN
(180970083)
Baltimore City, MD
(245100040)
Wayne, MI
(261630015)
Saint Charles, MO
(291831002)
Bronx, NY
(360050080)
Butler, OH
(390171004)
Franklin, OH
(390490025)
Hamilton, OH
(390617001)
Allegheny, PA
(420030064)
Berks, PA
(420110011)
Milwaukee, WI
(550790043)
Cook, IL
(170313103)
Wayne, MI
(261630016)
TABLE IV.C–18—UPWIND STATE TO DOWNWIND MAINTENANCE SITE ‘‘LINKAGES’’ FOR 24-HOUR PM2.5
Upwind State
Number of
linkages
Counties containing downwind 24-hour PM2.5 nonattainment sites (monitoring site ID)
Connecticut ................
1
Delaware ....................
2
Georgia .......................
3
Illinois .........................
29
erowe on DSK5CLS3C1PROD with PROPOSALS2
Indiana ........................
34
Iowa ............................
VerDate Mar<15>2010
15:19 Jul 30, 2010
9
New York, NY
(360610062)
Cumberland, PA
(420410101)
Baltimore City, MD
(245100035)
District of Columbia
(110010041)
Bullitt, KY
(210290006)
Cuyahoga, OH
(390350027)
Montgomery, OH
(391130031)
Sumner, TN
(471650007)
District of Columbia
(110010041)
Will, IL
(171971002)
Wayne, MI
(261630001)
Jefferson, OH
(390810017)
Trumbull, OH
(391550007)
Brooke, WV
(540090005)
Cook, IL
(170310022)
Jkt 220001
PO 00000
New York, NY
(360610079)
Lucas, OH
(390950026)
District of Columbia
(110010042)
McCracken, KY
(211451004)
Cuyahoga, OH
(390350034)
Preble, OH
(391351001)
Brooke, WV
(540090005)
District of Columbia
(110010042)
Muscatine, IA
(191390015)
St. Louis City, MO
(295100085)
Lucas, OH
(390950024)
Allegheny, PA
(420030095)
Dane, WI
(550250047)
Cook, IL
(170310050)
Frm 00057
Fmt 4701
Preble, OH
(391351001)
Elkhart, IN
(180390003)
Floyd, IN
(180431004)
Vigo, IN
(181670023)
Muscatine, IA
(191390015)
Warren, KY
(212270007)
Jefferson, OH
(390810017)
Trumbull, OH
(391550007)
Dane, WI
(550250047)
Cook, IL
(170310022)
Wayne, MI
(261630001)
Lucas, OH
(390950024)
Allegheny, PA
(420030095)
Milwaukee, WI
(550790059)
Cook, IL
(170310050)
St. Louis City, MO
(295100085)
Lucas, OH
(390950026)
Allegheny, PA
(420033007)
Waukesha, WI
(551330027)
Cook, IL
(170314007)
New York, NY
(360610079)
Mahoning, OH
(390990014)
Washington, PA
(421255001)
Saint Clair, IL
(171630010)
Bullitt, KY
(210290006)
New York, NY
(360610062)
Lucas, OH
(390950026)
Allegheny, PA
(420033007)
Milwaukee, WI
(550790059)
Cook, IL
(170314007)
McCracken, KY
(211451004)
New York, NY
(360610079)
Mahoning, OH
(390990014)
Cumberland, PA
(420410101)
Waukesha, WI
(551330027)
Will, IL
(171971002)
Warren, KY
(212270007)
Cuyahoga, OH
(390350027)
Montgomery, OH
(391130031)
Washington, PA
(421255001)
Anne Arundel, MD
(240031003)
Cuyahoga, OH
(390350034)
Preble, OH
(391351001)
Sumner, TN
(471650007)
Elkhart, IN
(180390003)
St. Louis City, MO
(295100085)
Sfmt 4702
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Federal Register / Vol. 75, No. 147 / Monday, August 2, 2010 / Proposed Rules
TABLE IV.C–18—UPWIND STATE TO DOWNWIND MAINTENANCE SITE ‘‘LINKAGES’’ FOR 24-HOUR PM2.5—Continued
Upwind State
Number of
linkages
Counties containing downwind 24-hour PM2.5 nonattainment sites (monitoring site ID)
Kansas .......................
2
Kentucky .....................
33
Maryland .....................
5
Massachusetts ...........
1
Michigan .....................
28
Minnesota ...................
4
Missouri ......................
20
Nebraska ....................
2
New Jersey ................
5
New York ....................
9
North Carolina ............
3
Ohio ............................
29
erowe on DSK5CLS3C1PROD with PROPOSALS2
Pennsylvania ..............
VerDate Mar<15>2010
32
15:19 Jul 30, 2010
Dane, WI
(550250047)
Muscatine, IA
(191390015)
District of Columbia
(110010041)
Will, IL
(171971002)
Wayne, MI
(261630001)
Jefferson, OH
(390810017)
Trumbull, OH
(391550007)
Dane, WI
(550250047)
District of Columbia
(110010041)
New York, NY
(360610062)
District of Columbia
(110010041)
Elkhart, IN
(180390003)
Cuyahoga, OH
(390350034)
Preble, OH
(391351001)
Brooke, WV
(540090005)
Muscatine, IA
(191390015)
Cook, IL
(170310022)
Floyd, IN
(180431004)
Jefferson, OH
(390810017)
Milwaukee, WI
(550790059)
Muscatine, IA
(191390015)
District of Columbia
(110010041)
District of Columbia
(110010041)
Lucas, OH
(390950024)
Baltimore City, MD
(245100035)
District of Columbia
(110010041)
Will, IL
(171971002)
McCracken, KY
(211451004)
New York, NY
(360610062)
Sumner, TN
(471650007)
District of Columbia
(110010041)
Will, IL
(171971002)
Warren, KY
(212270007)
Cuyahoga, OH
(390350027)
Montgomery, OH
(391130031)
Jkt 220001
PO 00000
Milwaukee, WI
(550790059)
Milwaukee, WI
(550790059)
District of Columbia
(110010042)
Elkhart, IN
(180390003)
St. Louis City, MO
(295100085)
Lucas, OH
(390950024)
Allegheny, PA
(420030095)
Milwaukee, WI
(550790059)
District of Columbia
(110010042)
Waukesha, WI
(551330027)
Cook, IL
(170310022)
Cook, IL
(170310050)
Cook, IL
(170314007)
Saint Clair, IL
(171630010)
Floyd, IN
(180431004)
New York, NY
(360610062)
Lucas, OH
(390950026)
Allegheny, PA
(420033007)
Waukesha, WI
(551330027)
New York, NY
(360610062)
Vigo, IN
(181670023)
New York, NY
(360610079)
Mahoning, OH
(390990014)
Washington, PA
(421255001)
Muscatine, IA
(191390015)
Cuyahoga, OH
(390350027)
Montgomery, OH
(391130031)
Sumner, TN
(471650007)
Anne Arundel, MD
(240031003)
Cuyahoga, OH
(390350034)
Preble, OH
(391351001)
Brooke, WV
(540090005)
New York, NY
(360610079)
Cumberland, PA
(420410101)
Cook, IL
(170310022)
Cook, IL
(170310050)
Cook, IL
(170314007)
Saint Clair, IL
(171630010)
Will, IL
(171971002)
Vigo, IN
(181670023)
Jefferson, OH
(390810017)
Trumbull, OH
(391550007)
Dane, WI
(550250047)
Dane, WI
(550250047)
Cook, IL
(170310050)
Vigo, IN
(181670023)
Lucas, OH
(390950026)
Waukesha, WI
(551330027)
Milwaukee, WI
(550790059)
Anne Arundel, MD
(240031003)
Muscatine, IA
(191390015)
Lucas, OH
(390950024)
Allegheny, PA
(420030095)
Milwaukee, WI
(550790059)
Milwaukee, WI
(550790059)
Cook, IL
(170314007)
Muscatine, IA
(191390015)
Montgomery, OH
(391130031)
Warren, KY
(212270007)
Lucas, OH
(390950026)
Allegheny, PA
(420033007)
Waukesha, WI
(551330027)
Waukesha, WI
(551330027)
Saint Clair, IL
(171630010)
Bullitt, KY
(210290006)
Preble, OH
(391351001)
St. Louis City, MO
(295100085)
Mahoning, OH
(390990014)
Washington, PA
(421255001)
Cuyahoga, OH
(390350027)
Montgomery, OH
(391130031)
Sumner, TN
(471650007)
Will, IL
(171971002)
McCracken, KY
(211451004)
Sumner, TN
(471650007)
Elkhart, IN
(180390003)
Warren, KY
(212270007)
Dane, WI
(550250047)
New York, NY
(360610062)
New York, NY
(360610079)
Cumberland, PA
(420410101)
District of Columbia
(110010042)
Lucas, OH
(390950026)
New York, NY
(360610062)
District of Columbia
(110010042)
Elkhart, IN
(180390003)
Warren, KY
(212270007)
New York, NY
(360610079)
Brooke, WV
(540090005)
District of Columbia
(110010042)
Elkhart, IN
(180390003)
Anne Arundel, MD
(240031003)
Cuyahoga, OH
(390350034)
Preble, OH
(391351001)
Anne Arundel, MD
(240031003)
Baltimore City, MD
(245100035)
Cuyahoga, OH
(390350027)
Cuyahoga, OH
(390350034)
Cumberland, PA
(420410101)
New York, NY
(360610079)
Cook, IL
(170310022)
Cook, IL
(170310050)
Cook, IL
(170314007)
Saint Clair, IL
(171630010)
Floyd, IN
(180431004)
Anne Arundel, MD
(240031003)
Allegheny, PA
(420030095)
Dane, WI
(550250047)
Cook, IL
(170310022)
Vigo, IN
(181670023)
Baltimore City, MD
(245100035)
Allegheny, PA
(420033007)
Milwaukee, WI
(550790059)
Cook, IL
(170310050)
Muscatine, IA
(191390015)
Wayne, MI
(261630001)
Cumberland, PA
(420410101)
Waukesha, WI
(551330027)
Cook, IL
(170314007)
Bullitt, KY
(210290006)
St. Louis City, MO
(295100085)
Washington, PA
(421255001)
Saint Clair, IL
(171630010)
Floyd, IN
(180431004)
Baltimore City, MD
(245100035)
Jefferson, OH
(390810017)
Trumbull, OH
(391550007)
Vigo, IN
(181670023)
Wayne, MI
(261630001)
Lucas, OH
(390950024)
Sumner, TN
(471650007)
Muscatine, IA
(191390015)
New York, NY
(360610062)
Lucas, OH
(390950026)
Brooke, WV
(540090005)
Bullitt, KY
(210290006)
New York, NY
(360610079)
Mahoning, OH
(390990014)
Dane, WI
(550250047)
Frm 00058
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E:\FR\FM\02AUP2.SGM
02AUP2
45267
Federal Register / Vol. 75, No. 147 / Monday, August 2, 2010 / Proposed Rules
TABLE IV.C–18—UPWIND STATE TO DOWNWIND MAINTENANCE SITE ‘‘LINKAGES’’ FOR 24-HOUR PM2.5—Continued
Upwind State
Number of
linkages
Counties containing downwind 24-hour PM2.5 nonattainment sites (monitoring site ID)
Tennessee ..................
21
Virginia .......................
7
West Virginia ..............
35
Wisconsin ...................
6
Milwaukee, WI
(550790059)
Cook, IL
(170314007)
Muscatine, IA
(191390015)
Jefferson, OH
(390810017)
Trumbull, OH
(391550007)
District of Columbia
(110010041)
Cumberland, PA
(420410101)
District of Columbia
(110010041)
Elkhart, IN
(180390003)
Anne Arundel, MD
(240031003)
Cuyahoga, OH
(390350027)
Montgomery, OH
(391130031)
Washington, PA
(421255001)
Cook, IL
(170310022)
b. Results of 8-Hour Ozone Contribution
Modeling
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 IV.B., 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
performed air quality modeling to
quantify the contributions to 8-hour
Waukesha, WI
(551330027)
Saint Clair, IL
(171630010)
Bullitt, KY
(210290006)
Lucas, OH
(390950024)
Allegheny, PA
(420033007)
District of Columbia
(110010042)
District of Columbia
(110010042)
Floyd, IN
(180431004)
Baltimore City, MD
(245100035)
Cuyahoga, OH
(390350034)
Preble, OH
(391351001)
Sumner, TN
(471650007)
Cook, IL
(170310050)
Will, IL
(171971002)
McCracken, KY
(211451004)
Lucas, OH
(390950026)
Washington, PA
(421255001)
Anne Arundel, MD
(240031003)
Elkhart, IN
(180390003)
Warren, KY
(212270007)
Mahoning, OH
(390990014)
Floyd, IN
(180431004)
Wayne, MI
(261630001)
Montgomery, OH
(391130031)
Vigo, IN
(181670023)
St. Louis City, MO
(295100085)
Preble, OH
(391351001)
Baltimore City, MD
(245100035)
New York, NY
(360610062)
New York, NY
(360610079)
Cook, IL
(170310050)
Cook, IL
(170314007)
Saint Clair, IL
(171630010)
Will, IL
(171971002)
Vigo, IN
(181670023)
Wayne, MI
(261630001)
Jefferson, OH
(390810017)
Trumbull, OH
(391550007)
Dane, WI
(550250047)
Cook, IL
(170314007)
Muscatine, IA
(191390015)
St. Louis City, MO
(295100085)
Lucas, OH
(390950024)
Allegheny, PA
(420030095)
Milwaukee, WI
(550790059)
Will, IL
(171971002)
Bullitt, KY
(210290006)
New York, NY
(360610062)
Lucas, OH
(390950026)
Allegheny, PA
(420033007)
Waukesha, WI
(551330027)
Elkhart, IN
(180390003)
Warren, KY
(212270007)
New York, NY
(360610079)
Mahoning, OH
(390990014)
Cumberland, PA
(420410101)
ozone from emissions in each of the
following 37 states individually:
Alabama, Arkansas, Connecticut,
Delaware, Florida, Georgia, Illinois,
Indiana, Iowa, Kansas, Kentucky,
Louisiana, Maine, Maryland combined
with the District of Columbia,
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.
We calculated each state’s
contribution to each of the 11
Muscatine, IA
(191390015)
monitoring sites that are projected to be
nonattainment and each of 14 53 sites
that are projected to have maintenance
problems for the 8-hour ozone NAAQS
in the 2012 Base Case. The largest
contribution from each state to 8-hour
ozone nonattainment in downwind sites
is provided in Table IV.C–19. The
largest contribution from each state to 8hour ozone maintenance in downwind
sites is also provided in Table IV.C–19.
The contributions from each state to all
projected 2012 nonattainment and
maintenance sites for the 8-hour ozone
NAAQS are provided in the AQMTSD.
TABLE IV.C–19—LARGEST CONTRIBUTION TO DOWNWIND 8-HOUR OZONE NONATTAINMENT AND MAINTENANCE FOR EACH
OF 37 STATES
Largest downwind contribution to nonattainment for
ozone
(ppb)
erowe on DSK5CLS3C1PROD with PROPOSALS2
Upwind State
Alabama ...................................................................................................................................................................
Arkansas ..................................................................................................................................................................
Connecticut ..............................................................................................................................................................
Delaware ..................................................................................................................................................................
Florida ......................................................................................................................................................................
Georgia ....................................................................................................................................................................
53 For two of the 16 projected maintenance sites
(Harris Co., Texas sites 482011015 and 482011035)
there were less than 5 days with 8-hour ozone
VerDate Mar<15>2010
15:19 Jul 30, 2010
Jkt 220001
predictions of at least 70 ppb. Thus, we did not
calculate contributions for these two maintenance
sites.
PO 00000
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Fmt 4701
Sfmt 4702
E:\FR\FM\02AUP2.SGM
02AUP2
Largest downwind contribution to maintenance for
ozone
(ppb)
4.7
1.4
1.7
3.3
0.8
2.1
4.7
1.8
1.6
2.5
2.1
1.7
45268
Federal Register / Vol. 75, No. 147 / Monday, August 2, 2010 / Proposed Rules
TABLE IV.C–19—LARGEST CONTRIBUTION TO DOWNWIND 8-HOUR OZONE NONATTAINMENT AND MAINTENANCE FOR EACH
OF 37 STATES—Continued
Largest downwind contribution to nonattainment for
ozone
(ppb)
Upwind State
Largest downwind contribution to maintenance for
ozone
(ppb)
0.8
1.1
0.3
0.6
2.3
11.4
0.0
6.1
0.6
0.9
0.1
5.2
0.7
0.2
0.1
16.8
0.4
1.7
0.1
2.8
2.1
8.9
0.1
0.6
0.0
1.6
1.6
0.0
4.2
2.7
0.3
0.6
1.0
0.3
0.8
1.8
10.6
0.0
4.2
0.5
0.5
0.2
2.5
0.6
0.2
0.1
15.8
22.7
2.0
0.0
2.6
2.7
8.1
0.1
0.8
0.0
3.0
0.6
0.1
4.5
2.3
0.2
Illinois .......................................................................................................................................................................
Indiana .....................................................................................................................................................................
Iowa .........................................................................................................................................................................
Kansas .....................................................................................................................................................................
Kentucky ..................................................................................................................................................................
Louisiana ..................................................................................................................................................................
Maine .......................................................................................................................................................................
Maryland/Washington, DC .......................................................................................................................................
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 ............................................................................................................................................................
Wisconsin .................................................................................................................................................................
Based on the state-by-state
contribution analysis, there are 22 states
and the District of Columbia 54 which
contribute 0.8 ppb or more to
downwind 8-hour ozone nonattainment.
These states are: Alabama, Arkansas,
Connecticut, Delaware, the District of
Columbia, Florida, Georgia, Illinois,
Indiana, Kentucky, Louisiana,
Maryland, Michigan, Mississippi, New
Jersey, North Carolina, Ohio, Oklahoma,
Pennsylvania, Tennessee, Texas,
Virginia, and West Virginia. In Table
IV.C–20, 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’’).
There are 22 states and the District of
Columbia which contribute 0.8 ppb or
more to downwind 8-hour ozone
maintenance. These states are: Alabama,
Arkansas, Connecticut, Delaware, the
District of Columbia, Florida, Georgia,
Indiana, Kansas, Kentucky, Louisiana,
Maryland, Mississippi, New Jersey, New
York, North Carolina, Ohio, Oklahoma,
Pennsylvania, South Carolina,
Tennessee, Virginia, and West Virginia.
In Table IV.C–21, 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’’).
TABLE IV.C–20—UPWIND STATE TO DOWNWIND NONATTAINMENT ‘‘LINKAGES’’ FOR 8-HOUR OZONE
Upwind State
Number of
linkages
Counties containing downwind 24-hour PM2.5 nonattainment sites (monitoring site ID)
erowe on DSK5CLS3C1PROD with PROPOSALS2
Alabama .....................
Arkansas ....................
8
3
East Baton Rouge,
LA
(220330003)
Harris, TX
(482011039)
East Baton Rouge,
LA
(220330003)
54 As noted above, we combined Maryland and
the District of Columbia as a single entity in our
contribution modeling. This is a logical approach
VerDate Mar<15>2010
15:19 Jul 30, 2010
Jkt 220001
Brazoria, TX
(480391004)
Harris, TX
(482010051)
Tarrant, TX
(484391002)
Brazoria, TX
(480391004)
Harris, TX
(482010055)
Tarrant, TX
(484391002)
because of the small size of the District of Columbia
and, hence, its emissions and its close proximity to
Maryland. Under our analysis, Maryland and the
PO 00000
Frm 00060
Fmt 4701
Sfmt 4702
Harris, TX
(482010062)
Harris, TX
(482010066)
District of Columbia are linked as significant
contributors to the same downwind nonattainment
counties.
E:\FR\FM\02AUP2.SGM
02AUP2
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Federal Register / Vol. 75, No. 147 / Monday, August 2, 2010 / Proposed Rules
TABLE IV.C–20—UPWIND STATE TO DOWNWIND NONATTAINMENT ‘‘LINKAGES’’ FOR 8-HOUR OZONE—Continued
Upwind State
Number of
linkages
Counties containing downwind 24-hour PM2.5 nonattainment sites (monitoring site ID)
Connecticut ................
1
Delaware ....................
3
Florida ........................
2
Georgia .......................
7
Illinois .........................
2
Indiana ........................
3
Kentucky .....................
6
Louisiana ....................
7
Maryland .....................
3
Michigan .....................
1
Mississippi ..................
8
New Jersey ................
3
North Carolina ............
3
Ohio ............................
3
Oklahoma ...................
1
Pennsylvania ..............
2
Tennessee ..................
7
Texas ..........................
1
Virginia .......................
3
West Virginia ..............
3
Suffolk, NY
(361030009)
Suffolk, NY
(361030002)
Harris, TX
(482010062)
Brazoria, TX
(480391004)
Tarrant, TX
(484391002)
Suffolk, NY
(361030009)
Suffolk, NY
(361030002)
Suffolk, NY
(361030002)
Brazoria, TX
(480391004)
Tarrant, TX
(484391002)
Suffolk, NY
(361030002)
Suffolk, NY
(361030009)
East Baton Rouge,
LA
(220330003)
Harris, TX
(482011039)
Suffolk, NY
(361030002)
Suffolk, NY
(361030002)
Suffolk, NY
(361030002)
Tarrant, TX
(484391002)
Suffolk, NY
(361030002)
Philadelphia, PA
(421010024)
Harris, TX
(482011039)
East Baton Rouge,
LA
(220330003)
Suffolk, NY
(361030002)
Suffolk, NY
(361030002)
Suffolk, NY
(361030009)
Tarrant, TX
(484391002)
Harris, TX
(482010051)
Philadelphia, PA
(421010024)
Harris, TX
(482010055)
Harris, TX
(482010062)
Harris, TX
(482010066)
Harris, TX
(482011039)
Harris, TX
(482010055)
Suffolk, NY
(361030009)
Philadelphia, PA
(421010024)
Harris, TX
(482010051)
Philadelphia, PA
(421010024)
Harris, TX
(482010051)
Harris, TX
(482010055)
Harris, TX
(482010055)
Harris, TX
(482010062)
Harris, TX
(482010062)
Harris, TX
(482010066)
Harris, TX
(482011039)
Harris, TX
(482011039)
Suffolk, NY
(361030009)
Philadelphia, PA
(421010024)
Brazoria, TX
(480391004)
Harris, TX
(482010051)
Harris, TX
(482010055)
Harris, TX
(482010062)
Harris, TX
(482010066)
Tarrant, TX
(484391002)
Suffolk, NY
(361030009)
Suffolk, NY
(361030009)
Suffolk, NY
(361030009)
Philadelphia, PA
(421010024)
Philadelphia, PA
(421010024)
Philadelphia, PA
(421010024)
Suffolk, NY
(361030009)
Brazoria, TX
(480391004)
Harris, TX
(482010051)
Harris, TX
(482010055)
Harris, TX
(482010062)
Harris, TX
(482010066)
Suffolk, NY
(361030009)
Suffolk, NY
(361030009)
Philadelphia, PA
(421010024)
Philadelphia, PA
(421010024)
TABLE IV.C–21—UPWIND STATE TO DOWNWIND MAINTENANCE ‘‘LINKAGES’’ FOR 8-HOUR OZONE
Upwind State
Number of
linkages
Counties containing downwind 24-hour PM2.5 nonattainment sites (monitoring site ID)
6
Arkansas ....................
4
Connecticut ................
1
Delaware ....................
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Alabama .....................
1
Florida ........................
4
Georgia .......................
4
Indiana ........................
4
Kansas .......................
1
Kentucky .....................
6
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15:19 Jul 30, 2010
DeKalb, GA
(130890002)
Dallas, TX
(481130069)
Westchester, NY
(361192004)
Bucks, PA
(420170012)
DeKalb, GA
(130890002)
Harris, TX
(482010024)
Fairfield, CT
(90010017)
Dallas, TX
(481130069)
Fairfield, CT
(90010017)
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PO 00000
Fulton, GA
(131210055)
Dallas, TX
(481130087)
Harris, TX
(482010024)
Harris, TX
(482011050)
Harris, TX
(482010029)
Tarrant, TX
(484392003)
Fulton, GA
(131210055)
Harris, TX
(482010029)
New Haven, CT
(90093002)
Harris, TX
(482010024)
Harris, TX
(482011050)
Westchester, NY
(361192004)
Harris, TX
(482010029)
Tarrant, TX
(484392003)
Bucks, PA
(420170012)
Fairfield, CT
(90011123)
Fairfield, CT
(90013007)
New Haven, CT
(90093002)
Frm 00061
Fmt 4701
Sfmt 4702
E:\FR\FM\02AUP2.SGM
Harris, TX
(482011050)
Tarrant, TX.
(484392003).
Westchester, NY
(361192004)
Bucks, PA.
(420170012).
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Federal Register / Vol. 75, No. 147 / Monday, August 2, 2010 / Proposed Rules
TABLE IV.C–21—UPWIND STATE TO DOWNWIND MAINTENANCE ‘‘LINKAGES’’ FOR 8-HOUR OZONE—Continued
Upwind State
Number of
linkages
Counties containing downwind 24-hour PM2.5 nonattainment sites (monitoring site ID)
Louisiana ....................
6
Maryland .....................
6
Mississippi ..................
7
New Jersey ................
6
New York ....................
5
North Carolina ............
5
Ohio ............................
6
Oklahoma ...................
3
Pennsylvania ..............
5
South Carolina ...........
2
Tennessee ..................
5
Virginia .......................
6
West Virginia ..............
6
Dallas, TX
(481130069)
Fairfield, CT
(90010017)
DeKalb, GA
(130890002)
Tarrant, TX
(484392003)
Fairfield, CT
(90010017)
Fairfield, CT
(90010017)
Fairfield, CT
(90011123)
Fairfield, CT
(90010017)
Dallas, TX
(481130069)
Fairfield, CT
(90010017)
Fulton, GA
(131210055)
DeKalb, GA
(130890002)
Fairfield, CT
(90010017)
Fairfield, CT
(90010017)
Dallas, TX
(481130087)
Fairfield, CT
(90011123)
Fulton, GA
(131210055)
Harris, TX
(482010024)
Fairfield, CT
(90013007)
Dallas, TX
(481130087)
Harris, TX
(482010029)
New Haven, CT
(90093002)
Harris, TX
(482010024)
Harris, TX
(482011050)
Westchester, NY
(361192004)
Harris, TX
(482010029)
Tarrant, TX.
(484392003).
Bucks, PA.
(420170012).
Harris, TX.
(482011050).
Fairfield, CT
(90011123)
Fairfield, CT
(90011123)
Fairfield, CT
(90013007)
Fairfield, CT
(90011123)
Dallas, TX
(481130087)
Fairfield, CT
(90011123)
Harris, TX
(482010029)
Fulton, GA
(131210055)
Fairfield, CT
(90011123)
Fairfield, CT
(90011123)
Fairfield, CT
(90013007)
Fairfield, CT
(90013007)
New Haven, CT
(90093002)
Fairfield, CT
(90013007)
Tarrant, TX
(484392003)
Fairfield, CT
(90013007)
New Haven, CT
(90093002)
New Haven, CT
(90093002)
Westchester, NY
(361192004)
New Haven, CT
(90093002)
Westchester, NY
(361192004)
Bucks, PA
(420170012)
Bucks, PA
(420170012)
Westchester, NY
(361192004)
Bucks, PA.
(420170012).
New Haven, CT
(90093002)
Westchester, NY
(361192004)
Bucks, PA
(420170012)
Fairfield, CT
(90013007)
Fairfield, CT
(90013007)
Harris, TX
(482010024)
New Haven, CT
(90093002)
New Haven, CT
(90093002)
Harris, TX
(482011050)
Westchester, NY
(361192004)
Westchester, NY
(361192004)
eastern states have SO2 and NOX
emission reduction responsibilities. We
apply the proposed methodology to
fully quantify the SO2 and NOX
In this section, EPA explains its
emissions from each of these states that
general approach to quantifying the
significantly contribute to or interfere
amount of emissions that represent
with maintenance in downwind areas.
significant contribution and interference
With respect to the 24-hour PM2.5
with maintenance. EPA then applies
NAAQS, this proposal finds that 25
that approach for the three different
eastern states have emission reduction
NAAQS being addressed in today’s
responsibilities. We use the proposed
notice: The 1997 ozone NAAQS, the
methodology to quantify emissions
1997 annual PM2.5 NAAQS and the 2006 reductions that these states must
24-hour PM2.5 NAAQS.
achieve to make, at a minimum,
With respect to the 1997 ozone
measurable progress towards
NAAQS, we apply this methodology to
eliminating the state’s significant
fully quantify the significant
contribution and interference with
contribution and interference with
maintenance. Further analysis will be
maintenance for 16 states. We also use
needed to determine if these reductions
the methodology to quantify, for 10
are sufficient to fully eliminate any or
additional states, NOX emissions
all of these states’ significant
reductions that are necessary to make
contribution and interference with
measurable progress towards
maintenance for purposes of the 24-hour
eliminating their significant
PM2.5 standard. As is explained in
contribution and interference with
greater detail in section IV.D.2.a, EPA
maintenance. Additional information
intends to finalize, to the extent possible
gathering and analysis is needed to
a determination of the complete amount
determine the extent to which further
of emissions that represents significant
reductions from these states may be
contribution and interference with
needed to fully eliminate significant
maintenance. If further analysis shows
contribution and interference with
that the amounts of emissions proposed
maintenance with the ozone NAAQS.
in today’s notice include all emissions
As is further explained in section
that significantly contribute or interfere
IV.D.2.b EPA will fully address this
with maintenance of the 24-hour PM2.5
issue in a future rulemaking as quickly
standard or that more SO2 emissions
as possible.
should be included, we believe that we
With respect to the annual PM2.5
will be able to issue a supplemental
proposal and finalize a rule fully
NAAQS, this proposal finds that 24
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D. Proposed Methodology To Quantify
Emissions That Significantly Contribute
or Interfere With Maintenance
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Bucks, PA.
(420170012).
Bucks, PA.
(420170012).
Bucks, PA.
(420170012).
quantifying significant contribution and
interference with maintenance with
respect to the 24-hour PM2.5 standard. If
further analysis shows that other
reductions should be considered as part
of significant contribution or
interference with maintenance with
respect to the 24-hour PM2.5 standard
these emissions would be fully
addressed in a separate rulemaking
effort.
1. Explanation of Proposed Approach
To Quantify Significant Contribution
After using air quality analysis to
identify upwind states that are ‘‘linked’’
to downwind air quality monitoring
sites with nonattainment and
maintenance problems because the
upwind states’ emissions contribute one
percent or more to the air quality value
at the downwind site, EPA quantifies
the portion of each state’s contribution
that constitutes its ‘‘significant
contribution’’ and ‘‘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 and interference
with maintenance with respect to the
PM2.5 NAAQS and the ozone NAAQS.
For this portion of the analysis, EPA
expands upon the methodology used in
the NOX SIP Call and CAIR, but
modifies it in significant respects. In the
NOX SIP Call and CAIR, EPA’s
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methodology relied upon defining
significant contribution as those
emissions that could be removed with
the use of ‘‘highly cost effective’’
controls. In this action, rather than
relying solely on determining
reductions based on ‘‘highly cost
effective’’ controls, EPA uses a number
of factors that account for both cost and
air quality improvement. Furthermore,
unlike the NOX SIP Call and CAIR
where EPA only defined an amount of
reductions needed to address significant
contribution to nonattainment, EPA is
proposing to define an amount of
emissions reductions that addresses
both significant contribution to
nonattainment and interference with
maintenance.
The methodology takes into account
both the DC 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.
The methodology defines each state’s
significant contribution and interference
with maintenance as the emissions that
can be eliminated for a specific cost.
Unlike the NOX SIP Call and CAIR,
where EPA’s significant contribution
analysis had a regional focus, the
methodology used in today’s proposal
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.
In step one, EPA identifies what
emissions reductions are available at
various costs, quantifying emissions
reductions that would occur within
each state at ascending costs per ton of
emissions reductions. For purposes of
this discussion, we refer to these as
‘‘cost curves’’.
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 state, at different cost-perton levels, would have on air quality at
downwind monitor sites that had
nonattainment and/or maintenance
problems.
In step three, EPA examines cost and
air quality information to identify cost
‘‘breakpoints.’’ Breakpoints are the
places where there is a noticeable
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change on one of the cost curves, such
as a point where a large reduction
occurs because a certain type of
emissions control becomes costeffective. EPA then uses a multi-factor
assessment to determine the amount of
emissions that represents significant
contribution to nonattainment and
interference with maintenance. The
factors considered include both the air
quality and cost considerations used in
developing the breakpoints along with
additional air quality and cost
considerations. This assessment is
performed for each transported NAAQS
pollutant or precursor which EPA has
concluded must be regulated due to its
impact on downwind receptors. In this
rule, as discussed in section IV.B, EPA
is proposing to regulate SO2 and NOX.
The methodology also allows EPA,
where appropriate, to define multiple
cost thresholds that vary for a particular
pollutant for different upwind states.
In step four, EPA quantifies the
emissions reductions available in each
‘‘linked’’ state at the appropriate cost
threshold. This information is then used
to develop a state ‘‘budget,’’ representing
the remaining emissions for the state in
an average year, and to identify a
variability limit associated with that
budget. These budgets and variability
limits are used to develop enforceable
requirements under the proposed and
two alternative remedy options. State
emissions budgets are discussed in
section IV.E and the variability limit is
discussed in section IV.F.
EPA’s proposed methodology
considers both cost and air quality
factors to address complex
circumstances. We believe it is
important to consider both factors
because circumstances related to
different downwind receptors can vary
and consideration of multiple factors
can help EPA appropriately identify
each state’s significant contribution
under different circumstances. For
instance, there may be cases when
upwind states contributing to a specific
downwind nonattainment area have
already done a great deal to reduce
emissions while the downwind state in
which the nonattainment area is located
has done very little. Conversely, the
downwind state may have made large
reductions while one or more
contributing upwind states may have
done very little. There may be cases
where some states (upwind or
downwind) have large emissions (and a
correspondingly large impact
downwind) not because their sources
are poorly controlled, but because they
have a greater number of sources—the
operation of which is critical to the
reliability of the electric grid.
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45271
Conversely, there may be cases where a
state (upwind or downwind) contributes
less in total emissions because it has a
smaller number of plants, but those
plants are poorly controlled and could
be better controlled at a relatively low
cost.
Air quality factors alone are not able
to discern these types of differences.
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. 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 emissions
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 interfere with
maintenance in another state, but does
not shift the responsibility for achieving
or maintaining the NAAQS to the
upwind state.
In developing and implementing this
methodology, EPA was cognizant of a
number of factors. First, in many areas,
transported emissions are a key
component of the downwind air quality
problem. Second, there are large
amounts of low cost emission reduction
opportunities in upwind states. Third,
EPA recognizes that section 110(a)(2)(D)
does not grant EPA authority to require
emissions reductions solely because
they provide large health and
environmental benefits: reductions
required pursuant to section
110(a)(2)(D)(i)(I) must be related to the
goal of eliminating upwind state
emissions that significantly contribute
to nonattainment or interfere with
maintenance of the NAAQS in
downwind areas.
Fourth, EPA is cognizant of the
relationship between the upwind and
downwind state requirements in the
Act. The Act requires upwind states to
eliminate significant interstate pollution
transport under section 110(a)(2)(D). It
also requires each state to assure
attainment and maintenance of the
NAAQS within its borders. Thus, a
downwind state must adopt controls to
demonstrate timely attainment of the
NAAQS despite any pollution transport
from upwind states that is not
eliminated under section 110(a)(2)(D).
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Given this structure, interpreting
significant contribution and interfere
with maintenance inherently involves a
policy decision on how much emissions
control responsibility should be
assigned to upwind states, and how
much responsibility should be left to
downwind states. In virtually all areas,
PM2.5 and ozone problems result from a
combination of local, in-state, and
upwind state emissions. EPA’s proposed
methodology for determining what
portion of a state’s total contribution is
its significant contribution and
interference with maintenance is
intended to assign a substantial but
reasonable amount of responsibility to
upwind states.
There are several reasons that EPA
believes upwind state sources
contributing to air quality degradation
in a downwind state should bear
substantial responsibility to control
their emissions. First, the plain language
of this good neighbor provision requires
upwind states to prohibit emissions that
significantly contribute to
nonattainment or interfere with
maintenance in a downwind state.
Second, interstate pollution transport
increases pollution levels and health
risks in the downwind state. Third, the
influx of pollution from upwind states
raises the pollution level in a downwind
state, making it necessary for the
downwind state to obtain deeper
pollution reductions to attain and
maintain air quality standards, which
increases costs of control in the
downwind state. Fourth, from the
standpoint of a downwind state, the
pollution contribution of each upwind
state adds up to a larger, cumulative
degradation of the downwind state’s air
quality. Fifth, reducing interstate
pollution enhances prospects that
attainment in downwind states can be
achieved within the Act’s deadlines and
as expeditiously as practicable. All of
these points support the position that
upwind state sources should bear
substantial responsibility to control
their emissions.
On the other hand, the proposed
methodology ensures that upwind states
are not required to shoulder the entire
responsibility for the downwind state’s
attainment and maintenance of the
NAAQS. Among other things, our
methodology implicitly assumes
controls at the same cost per ton level
in the downwind state as in the upwind
contributing states.55 In addition, in
55 We also recognize that there can be reasons to
depart from an equal cost per ton allocation of
responsibility before a receptor’s attainment and
maintenance problem is fully resolved, such as
when a receptor’s air quality problem has an
unusually high local component.
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almost all cases, states with downwind
nonattainment and maintenance areas
are also required to reduce emissions
based on the fact that they are also
upwind states that are ‘‘linked’’ to other
downwind states with nonattainment
and maintenance problems.
The proposed methodology also
directly ties each state’s reduction
requirements to EPA’s analysis of that
state’s significant contribution and
interference with maintenance. The
required reductions would provide very
substantial air quality improvements.
For the annual PM2.5 standard, EPA
projects that this rule will help assure
that all but one area in the East attain
the standard by 2014. It will also help
a number of areas achieve the standard
earlier. The methodology provides
similar assistance for ozone, assuring
upwind reductions that will mitigate the
amount that downwind states may need
to do. It reduces ozone concentration
levels in 2012 and helps assure that
even absent this additional local
control, all but 3 areas’ nonattainment
and maintenance problems are resolved
by 2014. Air quality in the few areas
with remaining problems will be
improved, providing both health
benefits and assistance for these local
areas in meeting the NAAQS
requirements.
a. Step 1. Emissions Reductions Cost
Curves
The first step in EPA’s methodology
for determining the quantity of
emissions that represents each state’s
significant contribution is to identify
reductions available at different costs.
To do so, EPA developed a set of cost
curves that show, at various cost
increments, the available emissions
reductions for EGUs in a state. In other
words, EPA determined for specific cost
per ton thresholds, the emissions
reductions that would be achieved in a
state if all EGUs in that state used all
emission controls and emission
reduction measures available at that cost
threshold. The zero point of the curve
shows what emissions would occur
absent any additional investment in
emissions reductions (i.e., the base case
emissions). Additional points on the
curves show the emissions that would
occur after the installation of all
controls that could be installed at
specific cost levels (dollars per ton of
emissions reduced). In developing these
cost curves, EPA used IPM to identify
costs for reducing emissions from EGUs
by modeling emissions reductions
available at multiple cost increments.
EPA also applied the same cost
constraint for each state in each
modeling iteration. For example, in one
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Fmt 4701
Sfmt 4702
iteration, all covered sources in the
states examined were constrained to
emit at levels achievable by the
application of all controls available for
$100/ton. In a second iteration, all states
examined were assumed to achieve all
reductions in each state that were
available at $200/ton. The resulting cost
curves for SO2 and annual NOX can be
found in section IV.D.2.a of this
preamble and the curves for ozone
season NOX in section IV.D.2.b. For
more detail on the development of the
cost curves, see the TSD, ‘‘Analysis to
Quantify Significant Contribution,’’ in
the docket for this rule.
Although the cost curves presented in
this proposal only include EGU
reductions, EPA also conducted a
preliminary assessment of reductions
available for source categories other
than EGUs. This preliminary assessment
suggested that there likely would be
very large emissions reductions
available from EGUs before costs reach
the point for which non-EGU sources
have available reductions. EPA therefore
initially created cost curves based solely
on reductions from EGUs and
determined appropriate cost thresholds
based on that analysis. EPA then reexamined non-EGUs to determine the
accuracy of its initial assumptions that
there were little or no reductions
available from non-EGUs at costs lower
than the thresholds that EPA had
chosen. EPA’s analysis of the costs of
and opportunities for non-EGU
emissions reductions is discussed in
more detail in section IV.D.3, later. For
the reasons explained in that section,
EPA believes there are little or no nonEGU reductions available at the cost
thresholds used in this rule. Therefore,
EPA believes it is reasonable at this time
to use cost curves that include only EGU
reductions. However, EPA is continuing
to conduct analyses and believes that it
will be necessary to further consider
non-EGU emission reduction
opportunities in future transport rules.
To develop cost curves, emissions
available at various costs were assessed
in 2012 for ozone season NOX and 2014
for annual NOX and SO2. As described
in section V.C, EPA coordinated the
deadlines for eliminating significant
contribution and interference with
maintenance with the NAAQS
attainment deadlines for downwind
states and determined that all
significant contribution and interference
with maintenance with respect to the
1997 and 2006 PM2.5 NAAQS must be
eliminated by 2014, or as expeditiously
as practicable. The cost curves show,
among other things, that the amount of
emissions reductions that can be
achieved for a given cost varies over
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time. This is true because, among other
things, control options that are available
in a longer timeframe may not be
available in a shorter timeframe. For
instance, it takes approximately 27
months to build a flue gas
desulfurization unit (FGD, or
‘‘scrubber’’) to reduce SO2 emissions
(Boilermaker Labor Analysis and
Installation Timing, USEPA, March
2005), so if this rule is finalized in mid2011, emissions reductions from
scrubbers by 2012 or 2013 can only
reasonably be achieved if that scrubber
either exists today, or if it is currently
under construction. However, by 2014,
additional reductions could be obtained
from the construction of new scrubbers.
It takes approximately 21 months to
construct a selective catalytic reduction
(SCR) unit to reduce emissions of NOX.
(Boilermaker Labor Analysis and
Installation Timing, USEPA, March
2005).
There are approximately 30 months
between mid-2011 (when the Agency
anticipates finalizing this rule) and
January 2014 (the proposed Phase 2
compliance deadline). EPA believes this
is sufficient time for sources to install
the advanced emissions controls
projected to be retrofit. EPA expects
about 14 GW of FGD and less than 1 GW
of SCR capacity to be retrofit for Phase
2 of this rule. This is significantly less
than the capacity that was retrofit in the
same length of time after CAIR was
finalized. EPA is not aware of problems
or issues with sources meeting the CAIR
compliance deadlines, either in
equipment deliveries or labor
availability. EPA believes the proposed
Transport Rule compliance deadlines
are reasonable, and will result in
emissions reductions as quickly as
practicable, delivering health benefits to
the public and aiding states with
NAAQS attainment deadlines.
EPA requests comment on the
schedule for scrubber and SCR
installations, the availability of
boilermaker labor, and any comment on
whether there might be alternative postcombustion cost-effective technologies
that could reduce SO2 and/or NOX
emissions. We also solicit comment on
whether advanced coal preparation
processes might provide emissions
reductions at the significant
contribution cost levels identified in
this proposal, whether such processes
have been commercialized, and what
the costs will be. In addition, EPA seeks
comment on, whether other factors,
such as other EPA regulatory actions,
will create an increase in boilermaker
demand earlier than today’s proposal, in
2010 and beyond. We solicit comments
on whether other factors might increase
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demand for boilermakers or control
equipment, and what these factors
would be. Comments in support of or
opposed to the proposed compliance
deadlines should include information to
support the commenter’s position.
Unlike add-on pollution controls such
as scrubbers and SCRs, EPA believes
that low-NOX burners could be installed
by 2012. See TSD, ‘‘Installation Timing
for Low NOX Burners,’’ in the docket for
this rule.
EPA also believes that sources can
switch coals by 2012. Eastern
bituminous coals used for power
generation typically have more than
sufficient sulfur content to facilitate
highly efficient collection of fly ash in
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.
Relatively inexpensive practices to
maintain high ESP performance on
lower sulfur bituminous coals are
available and are being used
successfully where necessary. These
include a range of upgrades to ESP
components and flue gas conditioning.
EPA assumes in the Transport Rule
analysis that it will not be necessary for
units that switch from higher to lower
sulfur bituminous to make a costly
replacement of the ESP. EPA’s analysis
therefore does not add capital or
operations and maintenance costs for
coal switching from higher to lower
sulfur bituminous coals.
EPA’s analysis does not allow a unit
designed for bituminous to switch to
(very low sulfur) subbituminous coal
unless the unit has demonstrated that
capability in the past. EPA assumes
units with that capability have already
made any investments needed to handle
a switch to subbituminous coals. EPA
therefore assumes that any modeled coal
switching from bituminous to
subbituminous has no cost or schedule
impact.
EPA requests comment on the
reasonableness of EPA’s assumption
that coal switching within the
bituminous coal grades will have
relatively little cost or schedule impact
on most units.
b. Step 2. Performing the Air Quality
Assessment
In the second step, EPA uses an air
quality assessment tool to estimate the
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impact of the upwind emissions
reductions on downwind ambient
concentrations.56 This tool is useful for
identifying cost breakpoints for
significant improvements in downwind
air quality changes, including estimated
effects on downwind attainment. While
less rigorous than the air quality models
used for attainment demonstrations,
EPA believes this air quality assessment
tool is acceptable for assessing the
impact of numerous options on upwind
reductions in the process of identifying
upwind state significant contribution. It
allows the Agency to analyze many
more potential scenarios than the timeand resource-intensive more refined air
quality modeling would permit. This
tool assesses the impact that reductions
at a given cost breakpoint from all of the
contributing states (as well as the state
with the nonattainment area itself) had
on pollutant concentrations at that
downwind area. The resulting
information is used in step three. For
each downwind area with a
nonattainment and/or maintenance
problem, it shows the total
improvement in air quality for each cost
level and associated pollutant
reduction, the amount of the remaining
problem caused by each upwind state
(by constituent), and the amount of the
remaining problem caused by sources
within the state (by constituent). It also
shows, overall, how much of the
downwind air quality problem had been
addressed at different cost levels. More
detail on the tool itself, what EPA has
done to verify the underlying
assumptions, and the specific
application of the tool to examining
significant contribution for ozone and
PM2.5 can be found in the TSD,
‘‘Analysis to Quantify Significant
Contribution,’’ in the docket for this
rule.
c. Step 3. Identifying Appropriate
Cost Thresholds
In the third step of this analysis, EPA
examines the information developed in
the first two steps to identify potential
cost thresholds. It then uses a multifactor assessment to identify which cost
56 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
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.
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threshold 57 or thresholds should be
used to quantify states’ significant
contribution and interference with
maintenance. This new methodology
responds to the Court’s statements in
North Carolina v. EPA both criticizing
the manner in which cost was used in
the CAIR rule and acknowledging its
prior acceptance (in Michigan v. EPA,
213 F.3d 663) of EPA’s use of a uniform
cost threshold and the uniform control
requirements associated with the use of
such a cost threshold. See North
Carolina v. EPA, 531 F.3d at 908,
917.920. In both the NOX SIP Call and
CAIR, EPA evaluated the cost of
controls relative to the cost of controls
required by other CAA regulations to
identify a single cost threshold referred
to as the ‘‘highly-cost-effective’’
threshold. In contrast, in this proposed
rule, EPA considers multiple factors to
identify appropriate cost thresholds,
allowing EPA to give greater weight to
air quality considerations and making it
possible to tailor the significant
contribution measurement more closely
to different conditions in different
groups of states.
This step of the analysis begins with
an examination of the cost and air
quality data to identify breakpoints on
the emissions reductions cost curves
developed in steps 1 and 2 related to
(1) air quality (e.g., points at which all
areas (other than those with an
unusually predominant local pollution
problem) reach attainment and have
maintenance fully addressed), and/or (2)
cost (e.g., points at which significant
reductions are available because a
certain technology is widely deployed).
EPA identifies potential breakpoints and
then uses a multi-factor assessment to
evaluate whether one or more of the
potential breakpoints represent a
reasonable cost at which to define
significant contribution for some or all
upwind states. The factors in this multifactor assessment can be divided into
two broad categories: Those that focus
on air quality considerations and those
that focus on cost considerations. Air
quality considerations include, for
example, how much air quality
improvement in downwind states
results from upwind state emissions
reductions at different levels; whether,
considering upwind emissions
reductions and assumed local (in-state)
reductions, the downwind air quality
problems would be resolved; and the
components of the remaining
57 The cost thresholds identified in today’s
proposal are specific to the section 110(a)(2)(D)
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.
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downwind air quality problem (e.g., is
it a predominantly local or in-state
problem, or does it still contain a large
upwind component). Cost
considerations include, for example,
how the cost per ton compares with the
cost per ton of existing federal and state
rules for the same pollutant, and
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); the
cost increase required to achieve the
next increment of air quality
improvement; and whether, given
timing considerations, emissions
reductions requirements could be more
costly than indicated in the modeling
because sources could choose one shortterm solution and then switch to
another long-term solution (e.g.,
switching coals can involve plant
modifications. While these costs are low
when amortized over a number of years,
if a source quickly installs controls, and
switches coals again, costs may be
higher than projected).
Because upwind state sources should
bear substantial responsibility for
controlling emissions that contribute to
air quality degradation in downwind
states, EPA believes that cost per ton
levels that are consistent with widely
deployed existing controls, or are within
the cost per ton range of controls
already required by existing and
proposed Federal and State rules (i.e.,
similar to the highly cost effective
concept in the NOX SIP Call and CAIR),
are reasonable for upwind states from a
cost standpoint. Higher cost per ton
levels also may be reasonable for
upwind states based on examination of
air quality and cost factors. One reason
is that achieving attainment and
maintenance of the air quality standard
may require controls in upwind and
downwind states that are more costly
than previous controls (particularly if it
is a new standard).
Based on this multi-factor assessment,
EPA identifies a specific cost per ton
threshold for quantifying the amount of
significant contribution from each state
for each precursor pollutant. While we
continue to believe that under certain
circumstances it may be appropriate for
us to use a single uniform cost per ton
threshold to quantify significant
contribution for all states, we believe it
is also important to retain the flexibility
to use multiple cost thresholds. For
example, we believe it is appropriate to
use multiple thresholds where one
group of states can, for a lower cost,
eliminate nonattainment and
maintenance for all the downwind
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nonattainment and maintenance areas to
which they are linked.
d. Step 4. Identify Required Emissions
Reductions
In the final step of this analysis, EPA
uses the cost thresholds identified in the
previous step to determine, on a stateby-state basis, the amount of emissions
that could be reduced at a specific cost.
The results of this analysis are used to
develop the state budgets and variability
limits, which are in turn used to
implement the requirements to
eliminate significant contribution and
interference with maintenance. See
sections IV.E and IV.F.
2. Application
The discussion that follows explains
how the methodology described
previously was applied to quantify
significant contribution with respect to
the 1997 and 2006 PM2.5 NAAQS and
the 1997 ozone NAAQS. EPA also
believes that the methodology proposed
today could also be used to address
transport concerns under other NAAQS,
including revisions to the ozone and
PM2.5 NAAQS.
All of the air quality considerations
included in the multi-factor assessment
are based on analysis using the air
quality assessment tool. EPA believes
that it is appropriate to use this tool
because of the advantages it has over
more refined air quality modeling to
perform analysis of a large number of
scenarios very quickly (more refined air
quality modeling can take several
months, while multiple scenarios can be
evaluated using the air quality
assessment tool in a single day). EPA
has done more refined air quality
modeling of the proposed emissions
budgets. The more refined air quality
modeling confirms EPA’s overall
methodology, but does suggest that, in
the case of daily PM2.5, the air quality
assessment tool slightly over-predicts
the air quality benefit of the proposed
reductions.
For this reason, EPA is also requesting
comment on whether we should modify
our conclusions regarding the amount of
specific states’ significant contribution
and interference with maintenance;
whether there are ways to use our air
quality modeling in conjunction with
the air quality assessment tool to carry
out the significant contribution analysis
in a way that would not extend the time
needed to complete this rulemaking;
and whether there are ways to improve
the air quality assessment tool.
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a. Specific Application to PM2.5
(1) Year for Quantifying Significant
Contribution
EPA’s significant contribution
analysis for PM2.5 used a multi-factor
assessment to identify cost thresholds
for 2014. EPA believes this is the most
appropriate year to consider because it
is consistent with attainment dates for
both the annual and daily PM2.5
standards. Furthermore, EPA believes
that 2014 provides sources sufficient
lead time to install emissions controls or
take other actions necessary to achieve
the required reductions. After
determining the amount of emissions
that represents each state’s significant
contribution, EPA then considers
whether it would be appropriate to
establish an interim compliance
deadline to ensure that the reductions
are achieved as expeditiously as
practicable. For this part of the analysis,
EPA focused on determining what
portion of each state’s significant
contribution could be eliminated by
2012, the first year in which it would be
possible to get reductions following
promulgation of this rule in 2011. EPA
believes it is possible to achieve much
of the required emissions reductions by
2012. EPA also believes that it is
important to get the reductions as
expeditiously as practicable and to
coordinate the compliance dates both
with the downwind states’’ maximum
attainment deadlines and with the
requirement that they eliminate
nonattainment as expeditiously as
practicable.
(2) Step 1. Emissions Reductions Cost
Curves
This subsection provides more detail
on the cost curves that EPA developed
to assess the costs of reducing SO2 and
NOX to address transport related to
PM2.5. It summarizes the information
from the curves and then provides
EPA’s interpretation of that information.
EPA uses the information from the cost
curves in step 3 to quantify the cost per
ton of emissions reductions which
should be used to calculate each state’s
significant contribution and interference
with maintenance, and the resulting
state-specific emissions budgets.
To measure significant contribution
and interference with maintenance with
respect to the PM2.5 NAAQS, EPA
developed cost curves showing the
annual NOX and annual SO2 reductions
available in 2014 at different cost
increments. Specifically, EPA
developed cost curves that show
reductions available in 2014 from EGUs
at various costs (in 2006 $) up to $2,500/
ton for annual NOX, $5,000/ton for
ozone season NOX, and $2,400/ton for
SO2. For example, this means that EPA
examined reductions of annual NOX
that are available at a cost of $2,500 per
ton or less. For SO2, the projected cost
considered for reducing a ton of
emissions is $2,400 or less.
Table IV.D–1 shows the annual NOX
emissions from EGUs at various levels
of control cost for 2014.
TABLE IV.D–1—2014 ANNUAL NOX EMISSIONS FROM ELECTRIC GENERATING UNITS FOR EACH STATE IN THE
TRANSPORT REGION AT VARIOUS COSTS
[(2006 $) per ton (thousand tons)]
Base case
level
Marginal cost per ton
$500
$1,500
$2,500
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Alabama ...........................................................................................................................
Connecticut ......................................................................................................................
Delaware ..........................................................................................................................
Florida ..............................................................................................................................
Georgia ............................................................................................................................
Illinois ...............................................................................................................................
Indiana .............................................................................................................................
Iowa .................................................................................................................................
Kansas .............................................................................................................................
Kentucky ..........................................................................................................................
Louisiana ..........................................................................................................................
Maryland ..........................................................................................................................
Massachusetts .................................................................................................................
Michigan ...........................................................................................................................
Minnesota ........................................................................................................................
Missouri ............................................................................................................................
Nebraska ..........................................................................................................................
New Jersey ......................................................................................................................
New York .........................................................................................................................
North Carolina ..................................................................................................................
Ohio .................................................................................................................................
Pennsylvania ....................................................................................................................
South Carolina .................................................................................................................
Tennessee .......................................................................................................................
Virginia .............................................................................................................................
West Virginia ....................................................................................................................
Wisconsin .........................................................................................................................
119
8
6
196
48
80
201
68
79
149
46
36
13
99
55
83
53
27
36
63
165
205
48
69
38
100
55
62
8
6
138
46
56
114
56
38
72
37
36
13
68
38
82
34
23
35
63
104
123
36
29
37
54
44
62
8
6
113
45
56
114
50
36
72
37
36
13
68
38
61
28
23
32
62
98
122
36
29
37
49
43
50
8
6
80
45
56
107
47
35
71
28
36
13
66
38
55
28
20
31
61
88
86
35
29
36
45
41
Total ..........................................................................................................................
2,144
1,455
1,375
1,241
Before applying the information in the
cost curves in step 3 of the analysis,
EPA evaluated the cost curves to better
understand how reductions at various
cost levels reflect changes in the
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generation mix (e.g., dispatch changes,
fuel use changes, or installation or
operation of controls). From the cost
curves, EPA concluded that in 2014,
there are large NOX reductions available
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at approximately $500/ton. At costs
above $500/ton and up to at least
$2,500/ton, potential reductions
increase slowly. This is because the base
case assumed that sources would not
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run their SCR units unless they are
required to run those SCR units
pursuant to mandates other than CAIR
(which will be replaced by this rule
when it is finalized). This is especially
relevant for winter use of SCRs. Even
without CAIR, the NOX SIP Call will
provide an incentive to run many SCRs
during the ozone season.
The cost curves demonstrate that
many of these sources would operate
their SCR units when emissions
reductions that cost $500/ton are
required. In addition, at this $500/ton
level some additional units would likely
install advanced combustion control
technology. Below $500/ton, there are
very few other NOX reductions.
Significant additional reductions would
not be achieved without application of
controls costing more than $2,500/ton.
In 2014, more reductions could be
achieved with installation of additional
add-on controls, such as SCR.
The cost curves for SO2 show the
same effect as those for NOX (large
emissions reductions at relatively low
costs and additional reductions at
relatively high costs) but the effect was
not as pronounced. In 2014, more than
1,000,000 tons of SO2 reductions can be
achieved at a cost of less than $200 per
ton. Most of these reductions can be
achieved by requiring companies to
operate existing scrubbers that they
would not have an incentive to run
absent the requirements of CAIR.
Additional reductions can be achieved
at higher costs. For instance, in many
cases, companies are currently using
lower sulfur coals to comply with CAIR,
but there is no guarantee they will
continue to do so. Many, but not all, of
these reduction opportunities (e.g.,
operating current equipment and
continued use of low sulfur coal) are
available at below $500/ton.
Table IV.D–2 shows that in 2014 there
are increased SO2 emission reduction
opportunities beyond just operating
existing scrubbers and switching to low
sulfur coal. Installation of new
scrubbers becomes feasible by 2014,
thus increasing reduction opportunities
at costs between $500/ton and $2,000/
ton (and above).
TABLE IV.D–2—2014 SO2 EMISSIONS FROM ELECTRIC GENERATING UNITS FOR EACH STATE IN THE TRANSPORT REGION
AT VARIOUS COSTS
[(2006$) per ton (thousand tons)]
Base
case level
Marginal cost per ton
$100
$200
$500
$1,000
$1,400
$1,800
$2,000
$2,400
Alabama .......................................
Connecticut ..................................
Delaware ......................................
Florida ..........................................
Georgia ........................................
Illinois ...........................................
Indiana .........................................
Iowa ..............................................
Kansas .........................................
Kentucky ......................................
Louisiana ......................................
Maryland ......................................
Massachusetts .............................
Michigan .......................................
Minnesota .....................................
Missouri ........................................
Nebraska ......................................
New Jersey ..................................
New York .....................................
North Carolina ..............................
Ohio ..............................................
Pennsylvania ................................
South Carolina .............................
Tennessee ...................................
Virginia .........................................
West Virginia ................................
Wisconsin .....................................
322
6
8
195
173
200
804
164
65
740
95
45
17
276
62
501
116
40
143
141
841
975
156
600
137
496
117
307
6
9
178
166
185
478
140
64
275
95
45
18
254
57
289
119
40
142
141
583
825
138
154
134
179
111
257
6
9
171
136
165
433
130
56
270
95
45
18
253
55
238
113
27
143
141
553
441
137
131
134
170
108
171
6
9
117
133
165
328
106
49
248
95
45
10
214
49
213
74
21
135
130
408
337
134
127
109
161
97
166
6
9
113
117
164
291
105
46
196
95
45
10
209
48
212
73
21
118
114
294
202
125
126
106
160
92
146
3
9
111
101
165
284
104
46
178
95
45
10
207
48
212
71
20
114
104
260
175
83
108
93
143
89
101
3
9
79
92
161
242
102
33
127
95
42
9
177
48
196
69
18
100
99
236
154
78
108
65
132
87
84
3
8
74
86
155
227
101
31
115
82
42
9
163
48
183
45
17
70
91
221
145
57
100
54
119
81
71
3
8
70
67
143
190
70
24
100
36
40
6
116
46
94
33
14
63
63
203
125
42
79
45
98
64
Total ......................................
7,436
5,133
4,435
3,692
3,263
3,025
2,660
2,410
1,912
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(3) Step 2. Air Quality Assessment of
Potential Emissions Reductions
After developing cost curves to show
the state-by-state cost-effective
emissions reductions available, EPA
used the air quality assessment tool to
evaluate the impact these upwind
reductions would have on air quality in
‘‘linked’’ downwind nonattainment and
maintenance areas. This section
summarizes the results of that
evaluation and provides analysis that
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informs EPA’s multi-factor assessment,
explained in step 3, later.
EPA performed air quality analysis for
each downwind receptor with a
nonattainment and/or maintenance
problem. For each receptor, EPA
assessed the air quality improvement
resulting when a group of states,
consisting of the upwind states that are
‘‘linked’’ to the downwind receptor (i.e.,
EPA modeling showed that they
exceeded the one percent contribution
threshold, based on it’s 2012 linkage
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analysis), and the downwind state
where the receptor is located, all made
the emissions reductions that EPA
identified as available at each cost
threshold (as described previously).
This analysis did not assume any
reductions in upwind states covered by
this rule but not ‘‘linked’’ to the
downwind receptor (even if the state
was ‘‘linked’’ to a different receptor),
beyond those assumed in the base case.
The percent emissions reductions
(and percent air quality improvement)
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to the same percent reduction in air
quality sulfate contribution from that
upwind state. For example, if a state
made a 50 percent reduction in SO2
emissions, its sulfate contribution to any
monitor downwind is assumed to be
reduced by 50 percent.
EPA determines the cumulative air
quality improvement that could be
expected at a particular downwind
receptor by multiplying each upwind
state’s percent reduction by its air
quality contribution and summing the
results for all upwind states. In EPA’s
air quality analysis of each downwind
receptor, all air quality improvements
are measured relative to baseline
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emissions and air quality contributions
in 2012.
Figures IV.D–1 through IV.D–4 show
that at increased costs, there are
substantial increased emissions
reductions. As explained previously,
each decrease in emissions is assumed
to lead to a corresponding improvement
in downwind air quality. These changes
apply to both the daily and annual PM2.5
NAAQS. While the pattern differs from
state to state, many states see noticeable
decreases in sulfate contribution for
costs of $500/ton or less. Reductions in
downwind contribution level off, then
many states start to see an additional
decrease in contribution at higher costs
(in general about $1,500/ton).
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that could be made by each upwind
state in 2014 at different cost per ton
levels are shown in Figures IV.D–1
through IV.D–4, later. These figures
show the percent reduction in SO2
emissions as a function of cost (using
the emissions at zero dollars per ton in
2014 as the baseline reference). A
percentage reduction of zero means that
emissions are not reduced from the
levels that exist at the 2014 zero dollar
per ton (base case) cost level. It is
assumed that reductions in SO2
emissions are linearly and directly
proportional to downwind sulfate
contributions. In other words, it is
assumed that a specific percent
reduction in SO2 emissions would lead
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EPA also identified the overall air
quality reductions projected by the air
quality assessment tool at downwind
nonattainment and maintenance
receptor locations. As explained
previously, the multi-factor assessment
in step 3 analyzed the results from the
downwind receptor analysis in step 2
for the annual and daily PM2.5
standards. Tables IV.D–3 and IV.D–4
show the air quality improvements in
2014 from the emissions reductions
projected to occur at various costs.
Table IV.D–4 also shows the average
decrease in ambient daily PM2.5 for
different sets of downwind sites for
various reductions in SO2.
TABLE IV.D–3—ESTIMATED NUMBER OF NONATTAINMENT AND/OR MAINTENANCE MONITOR SITES IN 2014 FOR ANNUAL
PM2.5
[As a function of SO2 cost-per-ton levels]
2014
Number of remaining nonattainment
monitor sites
Marginal cost per ton
2014
Number of remaining nonattainment and
maintenance
monitor sites
12
3
2
2
1
1
1
1
1
1
1
1
0
0
0
19
6
3
3
2
2
1
1
1
1
1
1
1
1
1
>$0 ...........................................................................................................................................................................
>$100 .......................................................................................................................................................................
>$200 .......................................................................................................................................................................
>$300 .......................................................................................................................................................................
>$400 .......................................................................................................................................................................
>$500 .......................................................................................................................................................................
>$600 .......................................................................................................................................................................
>$800 .......................................................................................................................................................................
>$1,000 ....................................................................................................................................................................
>$1,200 ....................................................................................................................................................................
>$1,400 ....................................................................................................................................................................
>$1,600 ....................................................................................................................................................................
>$1,800 ....................................................................................................................................................................
>$2,000 ....................................................................................................................................................................
>$2,400 ....................................................................................................................................................................
TABLE IV.D–4—DAILY AIR QUALITY IMPACTS VS. SO2 COST PER TON LEVELS IN 2014
Number of
remaining
nonattainment and
maintenance monitor sites
Marginal SO2 cost per ton
>$0 ...................................................................................................................................
>$100 ...............................................................................................................................
>$200 ...............................................................................................................................
>$300 ...............................................................................................................................
>$400 ...............................................................................................................................
>$500 ...............................................................................................................................
>$600 ...............................................................................................................................
>$800 ...............................................................................................................................
>$1,000 ............................................................................................................................
>$1,200 ............................................................................................................................
>$1,400 ............................................................................................................................
>$1,600 ............................................................................................................................
>$1,800 ............................................................................................................................
>$2,000 ............................................................................................................................
>$2,400 ............................................................................................................................
Air quality improvement (average μg/
m∧3 Reduction)
relative to 2014 base case (zero dollars/
ton)
All sites in
2012 base
64
16
12
8
*6
6
6
6
6
6
6
5
4
** 3
1
0.0
3.7
4.4
4.7
5.0
5.1
5.3
5.4
5.6
5.7
5.8
6.0
6.2
6.4
6.8
6 selected
sites *
3 selected
sites **
0.0
2.0
2.4
2.6
2.9
3.0
3.1
3.3
3.4
3.4
3.5
3.6
3.7
3.9
4.1
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* The six sites are: Allegheny County, PA (2 sites); Baltimore County, MD; Wayne County, MI; Lake County, IN; Cook County, IL.
** The three sites are: Lake County, IN; Cook County, IL; Allegheny County, PA.
A number of conclusions can be
drawn from Tables IV.D–3 and IV.D–4.
Very low cost SO2 reductions result in
significant air quality benefits.58 As
explained previously, this is because
58 Measured in terms of downwind area
nonattainment and/or maintenance concerns being
addressed. This is also true in terms of
improvements in air concentrations of PM2.5.
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there are significant reductions available
from sources that operate existing
scrubbers and, in a number of cases, use
relatively low cost, lower sulfur coal. At
the same time, in 2014 enough lead time
exists for considerable emission
reduction opportunities from new
scrubber installations. Other programs
are also achieving reductions (for
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example, some state rules and
enforcement consent decrees require
SO2 and NOX reductions in 2013 and
2014). The analysis also shows that
higher cost reductions continue to
provide downwind air quality
improvements.
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0.0
1.8
2.1
2.3
2.6
2.6
2.8
2.9
3.0
3.0
3.1
3.2
3.3
3.4
3.7
Federal Register / Vol. 75, No. 147 / Monday, August 2, 2010 / Proposed Rules
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(4) Identifying Cost Thresholds
(a) Considerations for 2014
For PM2.5, EPA considered three cost
breakpoints for SO2 and one for NOX.
First EPA looked at a point at which
EGUs operated all installed controls,
continued to burn coals with sulfur
contents consistent with what they were
burning in 2009, and operated any
additional controls they are currently
planning to install by 2014. For NOX,
this point is similar to the $500/ton cost.
For SO2, it is similar to the $300 to $400
cost. EPA believes this is an appropriate
starting point, because if a state is
‘‘linked’’ to a downwind state (i.e., if our
air quality analysis showed it was
contributing above the 1 percent
threshold), EPA believes it is
appropriate to prohibit that state from
increasing its emissions which could
worsen downwind air quality problems.
EPA then considered what additional
cost thresholds should be considered.
For SO2 EPA considered two
breakpoints: (1) $2,000/ton SO2 and (2)
$2,400/ton SO2. EPA’s state-by-state cost
modeling at that point indicates that
scrubbers would be installed on units
generating about 20 GW of electricity.
Since slightly over 21 GWs of scrubbers
were installed in both 2008 and 2009
(see EPA Analysis of Alternative SO2
and NOX Caps for Senator Carper—July
31, 2009 Appendix B, page 15), EPA
believes that it is clearly possible for the
power sector to install at least that
quantity of scrubbers by 2014. The
$2,400/ton SO2 breakpoint represents
the point where analysis from the air
quality assessment tool projects that
both nonattainment and maintenance
concerns would be fully addressed in all
areas, except for Allegheny County,
Pennsylvania, when considering
reductions from only states that
contribute more than 1 percent.59 As is
explained later in this section, EPA
believes that the monitor in Allegheny
County that remains in nonattainment is
in an area where the air quality problem
is primarily local. Since EPA’s analysis
suggests that the only remaining
nonattainment problem is primarily
local, EPA did not consider higher cost
thresholds.
EPA did not consider additional cost
thresholds for NOX beyond $500/ton
because there are minimal additional
NOX reductions until one considers cost
levels higher than $2,400/ton, and SO2
reductions are generally more effective
59 When considering all reductions made,
including those by states that contribute less than
1 percent, the air quality assessment tool projects
that both nonattainment and maintenance will be
fully addressed in all areas except for Allegheny
County, PA at $2,000/ton.
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than NOX reductions at reducing PM2.5.
EPA did not consider lower cost
thresholds than $2,000/ton for SO2
because: There are clearly continued air
quality benefits at higher costs (as
evidenced by increases in average air
quality improvements in downwind
sites); there is very little change in the
number of downwind nonattainment
and/or maintenance sites, indicating
that the number of upwind states
contributing would not be expected to
change much; and costs of up to $2,000/
ton of SO2 are reasonable in comparison
to other existing regulations.
First EPA assessed $2,000/ton.
Reductions at $2,000/ton would
improve air quality at several locations
with nonattainment and/or maintenance
problems. We also believe that, as
explained in the introduction to this
section, it is reasonable to require a
substantial level of control of upwind
state emissions that significantly
contribute to nonattainment or
maintenance problems in another state.
We believe that $2,000/ton is reasonable
for SO2 considering that this cost per
ton level is based on EGU control
technologies that are proven and already
widely deployed. Furthermore,
compared to other control measures that
address SO2, this cost per ton level is
relatively low. A survey of the control
options that EPA examined in the PM2.5
RIA shows that non-EGU SO2 reduction
opportunities cost from $2,270/ton to
over $16,000/ton.
While analysis with the air quality
assessment tool shows that a site in
Allegheny County, Pennsylvania would
be in nonattainment and two other
sites—Lake County, Indiana and Cook
County, Illinois—would have
maintenance problems, if we assume
reductions at $2,000/ton and additional
reductions made by states because of
their contribution to other downwind
sites that do not contribute to these
three problem areas, the maintenance
problems in Lake County, Indiana and
Cook County, Illinois would be resolved
and only Allegheny County,
Pennsylvania, would continue to have a
nonattainment/maintenance problem.
Because reductions at $2,000/ton
continue to have significant air quality
benefit for downwind sites with
nonattainment and/or maintenance
problems, it has been demonstrated
historically that the amount of control
equipment that is projected to be
needed at $2,000/ton could be installed
in the timeframe required and these
costs are reasonable when compared to
other options to reduce SO2. Therefore,
EPA believes that requiring a cost
threshold of at least $2,000/ton would
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45281
be appropriate for determining
significant contribution.
Because our analysis shows that one
area (Allegheny County, Pennsylvania)
would have continuing nonattainment
and maintenance problems, EPA
continued to perform its multi-factor
assessment for the higher $2,400/ton
breakpoint to see if any additional
emissions should also be considered
significant. For this receptor monitor,
EPA considered the local circumstances
in the Liberty-Clairton area in Allegheny
County that were leading to continued
nonattainment. It is well-established
that, in addition to being impacted by
regional sources, the Liberty-Clairton
area is significantly affected by a large
increment of local emissions from a
sizable coke production facility and
other nearby sources. (See https://
www.epa.gov/pmdesignations/
2006standards/final/TSD/
tsd_4.0_4.3_4.3.3_r03_PA_2.pdf). High
concentrations of organic carbon
indicate the unique local problem for
this location.
Because the remaining PM2.5 problem
is more local in nature than the problem
at other receptors, EPA does not believe
that it is appropriate to establish a
higher cost threshold solely for states
that are ‘‘linked’’ to this monitor.
(b) Amount of Reductions That Could
Be Achieved by 2012
After determining that the amount of
emissions that could be reduced for
$2,000/ton in 2014 is an appropriate
quantification of a state’s significant
contribution, EPA considered whether
any of these emissions 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. While EPA
believes that it is not possible to require
the installation of post-combustion SO2
controls (scrubbers) or post-combustion
NOX controls (SCRs) before 2014
(because it takes about 27 months to
install a scrubber and 21 months to
install an SCR), EPA believes that there
are significant reductions that can occur
earlier. For SO2, reductions from
operating existing scrubbers up to their
design removal efficiencies and from the
use of lower sulfur coals are possible by
2012. For NOX, reductions from
operating existing SCRs on a year-round
basis and up to their design removal
efficiencies and the installation of
limited amounts of low NOX burners are
possible by 2012. For this reason, EPA
believes it is appropriate to require
these emissions to be removed in 2012,
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Federal Register / Vol. 75, No. 147 / Monday, August 2, 2010 / Proposed Rules
consistent with the Act’s requirement
that downwind states attain the NAAQS
as expeditiously as practicable. Section
IV.E explains how these 2012 emissions
reductions requirements are defined.
(c) Off-Ramp for States That Eliminate
Their Significant Contribution for Less
Than $2,000/Ton
Table IV.D.4, previously, shows that
for large numbers of monitoring sites
where there are nonattainment and or
maintenance problems, those problems
are fully resolved before all states
achieve all of the emissions reductions
that could be achieved at or below
$2,000/ton. EPA used the air quality
assessment tool to analyze the impact of
requiring all states linked to the
downwind state site with an air quality
problem, as well as the downwind state,
to reduce emissions consistent with the
levels discussed for 2012 in section
IV.D.2.a(2), previously. The air quality
assessment tool shows that those 2012
reductions will resolve the
nonattainment and maintenance
problems for all of the areas to which
the following states are linked:
Alabama, Connecticut, Delaware, the
District of Columbia, Florida, Kansas,
Louisiana, Maryland, Massachusetts,
Minnesota, Nebraska, New Jersey and
South Carolina (referred to as group 2
states). EPA also assessed whether, in
2014, the combination of this level of
reduction from the group 2 states and
the remaining states (referred to as
group 1 states) continued to result in all
downwind areas—except for Allegheny
County, Pennsylvania—fully addressing
their nonattainment and or/maintenance
problems, and determined that it did.
The states in group 1 and group 2 are
rationally grouped considering air
quality and cost. EPA proposes that it
would not be appropriate to assign the
same cost per ton to group 2 and group
1 states because a significantly lower
cost per ton 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, our
analysis indicated that the cost per ton
needed to resolve downwind air quality
problems varied only to a limited extent
among states within group 1 and among
states within group 2. The cost per ton
did vary greatly between the group 1
and group 2 states. Limitations on the
accuracy of our cost and air quality
analyses, and the ruling in the Michigan
decision accepting EPA’s prior use of a
uniform cost approach, support the
decision to use uniform costs for a
group of states.
(d) Proposed Cost Thresholds for PM2.5
Summary of methodology. In
summary, EPA determined that SO2
emissions that could be reduced for
$2,000/ton in 2014 should be
considered a state’s significant
contribution, unless EPA determined
that a lesser reduction would fully
resolve the nonattainment and/or
maintenance problem for all the
downwind monitoring sites 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. EPA
also determined that all states linked to
downwind PM2.5 nonattainment and
maintenance problems should be
required to achieve those emissions
reductions that can be reasonably
achieved by 2012. Finally, EPA
determined that all states linked to
downwind PM2.5 nonattainment (see
Table IV.D–5) and maintenance
problems should, by 2012, remove all
NOX emissions that can be reduced for
$500/ton in 2012.
TABLE IV.D–5—STATES COVERED FOR SO2 GROUP 1, SO2 GROUP 2, AND NOX ANNUAL
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States covered
SO2 group 1
SO2 group 2
NOX annual
Alabama .......................................................................................................................................
Connecticut ..................................................................................................................................
Delaware ......................................................................................................................................
District of Columbia .....................................................................................................................
Florida ..........................................................................................................................................
Georgia ........................................................................................................................................
Illinois ...........................................................................................................................................
Indiana .........................................................................................................................................
Iowa .............................................................................................................................................
Kansas .........................................................................................................................................
Kentucky ......................................................................................................................................
Louisiana ......................................................................................................................................
Maryland ......................................................................................................................................
Massachusetts .............................................................................................................................
Michigan .......................................................................................................................................
Minnesota ....................................................................................................................................
Missouri ........................................................................................................................................
Nebraska ......................................................................................................................................
New Jersey ..................................................................................................................................
New York .....................................................................................................................................
North Carolina ..............................................................................................................................
Ohio .............................................................................................................................................
Pennsylvania ................................................................................................................................
South Carolina .............................................................................................................................
Tennessee ...................................................................................................................................
Virginia .........................................................................................................................................
West Virginia ................................................................................................................................
Wisconsin .....................................................................................................................................
........................
........................
........................
........................
........................
X
X
X
X
........................
X
........................
........................
........................
X
........................
X
........................
........................
X
X
X
X
........................
X
X
X
X
X
X
X
X
X
........................
........................
........................
........................
X
........................
X
X
X
........................
X
........................
X
X
........................
........................
........................
........................
X
........................
........................
........................
........................
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
15
13
28
Totals ....................................................................................................................................
VerDate Mar<15>2010
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Federal Register / Vol. 75, No. 147 / Monday, August 2, 2010 / Proposed Rules
After completing the process to
propose appropriate state-by-state cost
thresholds, EPA used these thresholds
to develop the specific state-by-state
budgets. This step in the process is fully
described in section IV.E.
erowe on DSK5CLS3C1PROD with PROPOSALS2
(e) Request for Comment on Issues
Related to EPA’s Modeling Methods
EPA believes that the methodology
described previously is a sound and
analytically efficient approach to
addressing the requirements of
110(a)(2)(D)(i)(I) for the PM2.5 standards.
While it would be possible for EPA to
add additional analytical steps to the
methodology, and such analyses would
provide more information, EPA believes
that the methodology selected strikes an
appropriate balance between the
competing requirements of
comprehensive analysis and timely
action. EPA believes that the technical
analysis completed provides a sound
basis for action. EPA also seeks to avoid
burdensome technical analyses which
could prevent EPA from fulfilling our
obligation to the Court to act in a timely
way. In this section, EPA generally
requests comment on issues related to
its efforts to strike an appropriate
balance. EPA identifies several areas of
recognized limitations on our
methodology, and requests comments
both on the implications of these
limitations and on possible options for
addressing these limitations without
unduly delaying necessary action.
(f) Use of Air Quality Assessment Tool;
Results of More Detailed Air Quality
Modeling Used To Evaluate the Tool
As discussed previously, EPA uses a
simplified air quality assessment tool,
rather than actual air quality modeling,
to identify air quality impacts of the
options considered. This assessment
tool enables efficient evaluation of
multiple options quickly. We did,
however, conduct more refined air
quality modeling of the select emissions
budgets and this more detailed
modeling serves as a check on the
appropriateness of the method. This
check confirmed the directional
conclusions of the air quality
assessment tool and largely confirmed
the more detailed results of the air
quality assessment tool, but raised
several issues on which EPA is
requesting comment.
For the annual PM2.5 standard, the air
quality assessment tool projected that,
after implementation of the proposed
FIPs, only one area (Allegheny County,
PA) would have a continuing NAAQS
air quality problem under the
maintenance criteria. The results of the
refined air quality modeling are very
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similar. This modeling projects similar
annual PM2.5 reductions in downwind
states and projects that Allegheny
County, PA would remain in
nonattainment and that Birmingham,
AL would exceed the threshold for
‘‘maintenance’’ by a slight amount (less
than 0.1 ug/m 3). Given the unique local
nature of the Allegheny County, PA
receptor (see discussion previously),
EPA does not believe that the fact that
the air quality assessment tool projects
the area to have only a maintenance
problem, while the refined air quality
modeling suggests that the area would
remain in nonattainment, raises any
serious issues about the conclusions
regarding significant contribution to
nonattainment and interference with
maintenance with the annual PM2.5
standard. Similarly, because the refined
air quality modeling projects that
Birmingham, AL will exceed the
maintenance criteria by only an
extremely slight amount and because
reductions from nearby point sources
will reduce local emissions in the area,
EPA does not believe the refined air
quality modeling demonstrates that
upwind reductions beyond those in the
proposed FIPs are required to address
significant contribution and interference
with maintenance of the annual PM2.5
NAAQS in Birmingham. For these
reasons, EPA does not believe that the
more refined air quality modeling for
the annual PM2.5 standard changes any
of EPA’s conclusions with respect to
reductions required to eliminate
significant contribution and interference
with maintenance with respect to this
standard. EPA is, however, taking
comment on whether Florida, the one
group 2 state that was identified as
linked to Birmingham, should be moved
from group 2 to group 1. EPA notes that
no group 2 states are linked to
Allegheny County, PA.
For the 24-hour PM2.5 standard, the
simplified air quality assessment tool
results suggest that under EPA’s
proposed FIPs, only one problem site,
Allegheny County, PA, would remain.
In contrast, the more refined CAMx air
quality modeling results show a greater
24-hour PM2.5 problem, with 10
nonattainment and 4 maintenance areas.
As described later, EPA is evaluating the
impact of this refined air quality
modeling on the methodology used and
the conclusions it has reached regarding
significant contribution and interference
with maintenance with regard to the 24hour PM2.5 NAAQS.
EPA has completed some preliminary
analysis of the difference between the
air quality assessment tool and CAMx
results (see the TSDs ‘‘Analysis to
Quantify Significant Contribution’’ and
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45283
‘‘Air Quality Modeling’’). This analysis
suggests that the main difference is that
in the winter months, the CAMx
modeling shows smaller air quality
reductions compared to the assessment
tool. This is because the CAMx air
quality modeling more accurately
reflects the complex nature of the winter
portion of the 24-hour PM2.5 problem.
Unlike summer days, for which sulfate
is the dominant contributor to PM2.5,
sulfate concentrations are typically a
lesser contributor to the overall PM2.5
concentrations on winter days.
Moreover, for winter days, reductions in
this already reduced amount of sulfate
appear to be less responsive to
reductions in SO2 emissions than for
summer days. That is, while for the
summer a 50 percent reduction in SO2
emissions would likely yield a nearly 50
percent reduction in sulfate
concentrations, in the winter such a
reduction in SO2 would reduce sulfate
by less than 50 percent. Thus, EPA
believes that more study of the winter
portion of the problem is warranted to
address the issues raised by the CAMx
modeling. EPA believes it is important
to understand the degree to which these
winter exceedances are transport-related
or locally generated, and the degree to
which upwind states’ emissions of NOX,
SO2, and other transported pollutants
are significantly contributing to these
winter exceedances.
Because the CAMx results indicate
additional nonattainment and
maintenance areas compared to the air
quality assessment tool, EPA requests
comment on whether the $2,000/ton
cost cutoff for SO2 resulting from the
assessment tool should be raised to a
higher cost cutoff. While the CAMx
results may suggest that it would be
appropriate to use a cutoff greater than
$2,000/ton, the results do not suggest
that the cutoff could be less than
$2,000/ton. Instead, the results confirm
the importance of achieving, at a
minimum, all reductions available at the
$2,000/ton cost threshold.
Additionally, EPA is requesting
comment on whether some group 2
states should be moved to group 1.
These group 2 states are: Connecticut,
Kansas, Maryland, Massachusetts,
Minnesota, Nebraska, and New Jersey.
These states were all placed in group
two because the air quality assessment
tool indicates that the 2012 reductions
will resolve the nonattainment or
maintenance problems at all areas to
which they are linked. However, for
these states, the CAMx modeling
indicates that one or more of the states
to which they are linked will have
continuing nonattainment and
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Federal Register / Vol. 75, No. 147 / Monday, August 2, 2010 / Proposed Rules
maintenance problems after the
implementation of the 2012 reductions.
EPA also notes that during the winter,
PM2.5 contains a larger nitrate
component than in summer months.
One reason for this is that some nitrates
that are particles in cooler weather
volatize and exist as gases during
warmer weather. Given this larger
contribution from nitrates in the winter,
EPA is also taking comment on whether
there should be a higher cost threshold
for annual nitrogen oxides. This may be
appropriate for states that have been
identified as contributing significantly
to sites that the CAMx air quality
modeling continues to show as having
a residual nonattainment and/or
maintenance concern in 2014.
Finally, EPA requests comment on
how and whether EPA should
incorporate the use of detailed models
such as CAMx into our methodology for
significant contribution and interference
with maintenance.
(g) Possibility for Emissions Increases in
Noncontributing States
EPA also evaluated whether the
proposed rule could cause changes in
operation of electric generating units in
states not regulated under the proposal
(that is states not listed in table IV.D–
5). Specifically, EPA evaluated whether
such changes could lead to increases in
emissions in those states, potentially
affecting whether they would exceed the
1 percent contribution thresholds used
to identify linkages between upwind
and downwind states. (See sections IV.B
and IV.C previously for more discussion
of the 1 percent thresholds). Such
changes are possible in part because of
the interconnected nature of the
country’s energy system (including both
the electricity grid and coal and natural
gas supplies). In addition, our models
project that the rule affects the cost of
coal (generally lowering the cost of
higher sulfur coals and raising the cost
of lower sulfur coals). If these price
effects took place and if the rule is
finalized as proposed, sources in states
not covered by the proposed rule might
choose to use higher sulfur coals.
Increased use of such coals could thus
increase SO2 emissions in those states.
EPA’s modeling confirms this,
projecting that, after the proposed rule
is implemented in states regulated for
SO2, emissions in some states not
covered by the proposed rule would
increase (i.e., their emissions are greater
in the control case modeling than in the
base case modeling). As shown in table
IV.D–6, Arkansas, Mississippi, North
Dakota, South Dakota, and Texas all
exhibit 2012 SO2 emissions increases
over the base case and above 5,000
tons.60 For reference, we also include
the statewide 2012 base case emissions
from all sources within the state.
TABLE IV.D–6—UNREGULATED STATES WITH MORE THAN 5,000 TONS OF PROJECTED SO2 INCREASES UNDER THE
PROPOSED TRANSPORT RULE
2012 SO2 increase from
base case
(thousand
tons)
State
Arkansas ..................................................................................................................................................................
Mississippi ................................................................................................................................................................
North Dakota ............................................................................................................................................................
South Dakota ...........................................................................................................................................................
Texas .......................................................................................................................................................................
Further analysis with the air quality
assessment tool indicates that these
projected increases in the Texas SO2
emissions would increase Texas’s
contribution to an amount that would
exceed the 0.15 μg/m3 threshold for
annual PM2.5. For this reason, EPA takes
comment on whether Texas should be
included in the program as a group 2
state.
erowe on DSK5CLS3C1PROD with PROPOSALS2
(h) Providing Downwind States Full
Relief From Upwind Emissions
EPA takes very seriously its
responsibility to ensure that upwind
reductions are made in a timely way so
that downwind states can meet their
attainment obligations.
EPA recognizes, as discussed
previously, that while this proposal
fully addresses the annual PM2.5
standard, it may not fully address the
24-hour PM2.5 standard. Where this may
be the case, as explained previously,
EPA’s air quality modeling shows that
the remaining component of nonattainment is almost entirely occurring
in the winter months. Also as noted
previously the atmospheric chemistry
related to secondary particle formation,
and the relative importance of particle
species such as sulfate and nitrate, is
quite different between summer and
winter. Because of this, EPA is moving
ahead with further efforts, before the
final rule is published, to determine the
extent to which this winter problem is
caused by emissions transported from
upwind states and, if this is the case, to
identify the total amount of emissions
that represents significant contribution
and interference with maintenance. To
the extent possible, EPA plans to
finalize a rule that fully defines this
amount.
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127
80
94
26
640
Based on the information that EPA
currently has, EPA believes there are a
number of possible outcomes of this
further study. Possible outcomes
include:
(1) Identification of the additional
amount of SO2 emissions reductions
needed to eliminate significant
contribution and interference with
maintenance from upwind states
contributing to the residual 24-hour
PM2.5 problem sites.
(2) Identification of the additional
amount of NOX emissions reductions
needed to eliminate significant
contribution and interference with
maintenance from upwind states
contributing to the residual 24-hour
PM2.5 problem sites.
(3) Identification of another pollutant
that should be considered part of
significant contribution and interference
with maintenance for states that
60 While Colorado is also a state that may see
projected increases in emissions, it was not within
the domain the EPA analyzed.
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contribute to the residual 24-hour PM2.5
problem sites.
(4) Determination that the reductions
proposed in today’s rulemaking would
fully address significant contribution
and interference with maintenance at
these sites.
If EPA determines that more SO2
emissions should be considered part of
this amount based on the analysis
performed for today’s proposal, EPA
believes that the next set of emissions
that can be reduced above the $2,000/
ton threshold would likely still come
from the power sector. If EPA
determines that more SO2 emissions
reductions are required or that the
amount of emissions of SO2 and NOX
that it has proposed as significantly
contributing to nonattainment are the
appropriate amounts to address this
winter portion of the problem, EPA
intends to supplement today’s proposal
and finalize a rule that would fully
addresses emissions that significantly
contribute to or interfere with
maintenance of the 2006 daily PM2.5
standard.
To the extent that EPA determines
that more NOX reductions are needed or
that reductions of another pollutant are
needed, EPA believes that we could
provide the greatest assistance to states
in addressing transport by finalizing this
rule quickly and promulgating a
separate rule to achieve any necessary
additional NOX reductions. This is
because those emissions reductions
would likely involve placing reduction
requirements on sources other than
EGUs and that additional approaches
would need to be addressed. EPA
believes that developing supplemental
information to address these sources
and concepts would substantially delay
publication of a final rule, beyond the
anticipated publication of spring 2011.
EPA plans to move forward
aggressively in the event that these
further reductions are needed. We do
not, however, intend to delay the
reductions in this proposed rule because
those reductions have a substantial
impact on states’ abilities to attain the
NAAQS in the required time period and
have large health benefits.
erowe on DSK5CLS3C1PROD with PROPOSALS2
b. Specific Application to Ozone
This section discusses, for the 1997
ozone standards, how EPA applies its
multi-step methodology for defining
each state’s significant contribution. For
some aspects of the methodology,
further work is needed to complete the
methodology for ozone and this further
work will be completed in a separate
proposal.
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(1) Years for Quantifying Significant
Contribution
In this subsection, we discuss how
EPA identifies for ozone the years to
analyze for eliminating significant
contribution. Similar to the previous
discussion for PM2.5, EPA believes that
the selection of the year for eliminating
significant contribution is informed by
the attainment deadline and by the Act’s
requirement to attain the NAAQS ‘‘as
expeditiously as practicable.’’
As noted earlier, the 2012 ozone
season is the last ozone season before
the 2013 attainment deadline for ozone
areas classified as ‘‘serious’’ for the 1997
ozone air quality standards. Thus, for
any states ‘‘linked’’ to ‘‘serious area’’
locations for which 2012 is the latest
ozone season prior to their attainment
deadline, EPA believes that 2012 is the
appropriate year for eliminating
significant contribution, to the extent
that purpose can be achieved given the
short time period. Because this
proposed rule would not be finalized
until 2011, the year 2012 also represents
the earliest time by which emissions
reductions could be achieved, which is
consistent with statutory provisions
calling for downwind states to achieve
attainment ‘‘as expeditiously as
practicable.’’ This also is relevant for
certain other areas with lower ozone
classifications that are projected in our
analysis to have continuing air quality
problems and to be affected by
transported pollution from certain
upwind states in amounts greater than
the 1 percent threshold.61
EPA is concerned that the timing of
this rule presents difficult challenges in
eliminating significant contribution and
interference with maintenance with
regard to the 1997 ozone NAAQS by the
attainment date. For states with a 2012
(or earlier) attainment date for which we
project continuing ozone problems, we
are concerned that strict adherence to a
2012 date for reductions could be
viewed as an artificial constraint on our
ability to require appropriate
reductions. EPA believes that the
current situation for ozone, involving a
transport rulemaking within months of
the attainment date (and in a number of
cases, after the current attainment date)
is a unique situation created by the
Court’s remand of the CAIR. Under
normal circumstances adhering to the
CAA schedule for addressing transport
within 3 years after a NAAQS is
promulgated, transport requirements
61 This is possible where: (1) Latest monitoring
data indicate attainment of the 1997 ozone
standard, (2) the area is operating under one-year
extensions of their 2009 deadline, or (3) EPA has
not made a formal finding of failure to attain.
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would be in place years before the
attainment date. For purposes of our
analysis of ozone for areas with a 2012
attainment date, EPA proposes that we
should not be constrained to only
considering those reductions that are
possible by 2012.
Another reason that it would be
inappropriate to limit upwind state
responsibility based on the downwind
area’s current attainment date is that the
statute contains provisions for extension
of attainment dates. To the extent that
downwind states have continuing ozone
air quality problems after 2012, the Act
requires that they be reclassified, which
allows the downwind area to qualify for
a later attainment date that is as
expeditious as practicable but no later
than 2019 (2018 emissions year).62 In
addition, two 1-year attainment date
extensions can be granted if an area
comes close to attaining, based on
specific criteria. In addition, history
shows many examples of states not
meeting air quality standards by their
attainment deadlines, often due in part
to interstate pollution transport. Even if
a downwind area attains on time,
further upwind reductions may be
important to assure continued
maintenance of the standard.
If in determining upwind state
reduction responsibilities EPA were to
automatically assume that downwind
states will attain on time despite
pollution transport, this assumption
would have the effect of absolving the
upwind state of responsibility for any
reductions in pollution transport that
could not be achieved by the downwind
area’s current attainment date. EPA does
not believe this would be appropriate.
This would transfer emissions control
responsibility from the upwind state to
the downwind state in any case when
the area did not attain by its current
attainment date, and could delay for
years the date when the public would
breathe air that meets health-based
standards.
Accordingly, for all the reasons
discussed previously, we address both
2012 and 2014 in our analysis, and we
do not believe that examining 2012 only
would be appropriate. EPA has chosen
to examine 2014 air quality results
because, based on a conservative
estimate, 2014 is the earliest year for
which significantly more stringent NOX
limits (e.g., reflecting SCR) could
conceivably be considered in a swift,
subsequent rulemaking.
One area in the eastern half of the
U.S. covered by this proposal, Houston,
62 In the case of PM , under subpart I, areas can
2.5
qualify for an extension beyond 5 years, to as many
as 10 years, based on certain statutory criteria.
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is classified as ‘‘severe.’’ For Houston, it
is relevant to consider both that (1) the
latest permissible attainment date for
severe areas is June 2019, which would
require emissions reductions by the
2018 ozone season, and (2) the state
implementation plan must provide for
attainment as expeditiously as
practicable. In light of this, EPA may
select a year between 2012 and 2018
that is as expeditious as practicable as
the appropriate year for eliminating
significant contribution. Because, as
explained later, further analysis is
needed to quantify any additional
reductions necessary to eliminate
significant contribution to Houston,
EPA requests comment on which year
we should select within this 2012 to
2018 time period for this analysis.
(2) Step 1. Emissions Reductions Cost
Curves for EGU Ozone Season NOX
Using IPM, EPA developed cost
curves for 2012 for ozone season NOX,
showing the ozone season (May–
September) NOX reductions available in
2012 at different cost increments.
Specifically, EPA developed cost curves
that show reductions available in 2012
from EGUs at various costs (in 2006 $)
up to $5,000/ton. These EGU cost curves
are presented in Table IV.D–7.
Generally, projected emissions
reductions for 2012 are modest because,
by 2012, it is not feasible to install addon equipment. Some highly effective
and widely employed NOX control
technologies such as SCR could not be
planned and installed in significant
numbers within a 1-year time period
(i.e., because a single SCR unit on
average takes 21 months to install,63
SCR-based limits in 2012, if feasible at
all, would require an unacceptably steep
cost premium).
For some states (particularly those
which are not regulated by the NOX SIP
Call) EPA identified potential
reductions from the installation of some
combustion controls/low NOX burners
and the use of existing SCR units that,
in the absence of CAIR, would not be
required to operate. These reductions
are available at approximately $500/ton
in 2012. There were very few emissions
reductions available below this cost.
TABLE IV.D–7—2012 OZONE-SEASON NOX EMISSIONS FROM ELECTRIC GENERATING UNITS FOR EACH STATE AT
VARIOUS COSTS (2006$) PER TON (THOUSAND TONS)
Marginal cost per ton
$0
$500
$1,000
$1,500
$2,000
$2,500
$3,000
$3,500
$5,000
30
21
3
2
101
35
24
51
31
31
22
14
30
17
7
16
27
42
43
51
16
12
79
18
24
30
11
3
2
74
33
24
50
15
31
17
14
30
8
7
16
27
41
27
51
16
12
67
18
24
30
11
3
2
60
33
25
49
15
30
17
14
30
8
7
16
27
41
27
51
16
12
67
18
23
30
11
3
2
59
33
25
48
15
30
17
14
30
8
7
16
27
41
27
51
15
12
67
18
23
30
11
3
2
59
33
25
47
14
30
17
14
30
8
7
16
27
41
27
50
15
12
7
18
22
30
11
3
2
59
33
25
47
14
30
17
14
30
8
7
16
27
42
26
50
15
12
66
18
23
30
11
3
2
59
33
25
47
14
29
17
14
29
8
7
16
27
42
26
50
15
12
66
17
22
29
11
3
2
58
33
25
46
14
29
17
14
28
8
7
16
27
42
26
50
15
12
66
17
22
29
11
3
2
57
33
25
46
14
29
17
14
28
8
7
16
27
42
26
48
15
12
66
17
18
Total ..........................................................................
erowe on DSK5CLS3C1PROD with PROPOSALS2
Alabama ...........................................................................
Arkansas ..........................................................................
Connecticut ......................................................................
Delaware ..........................................................................
Florida ..............................................................................
Georgia ............................................................................
Illinois ...............................................................................
Indiana .............................................................................
Kansas .............................................................................
Kentucky ..........................................................................
Louisiana ..........................................................................
Maryland ...........................................................................
Michigan ...........................................................................
Mississippi ........................................................................
New Jersey ......................................................................
New York ..........................................................................
North Carolina ..................................................................
Ohio ..................................................................................
Oklahoma .........................................................................
Pennsylvania ....................................................................
South Carolina .................................................................
Tennessee .......................................................................
Texas ...............................................................................
Virginia .............................................................................
West Virginia ....................................................................
746
648
632
628
625
622
620
618
609
As discussed in section IV.D.3 later,
little or no ozone season NOX
reductions are available for non-EGU
sources from control measures costing
(at or below) $500/ton. The ozone
season NOX cost curves in Table IV.D–
7 include EGU reductions only. EPA
believes that for costs at or below $500/
ton, these curves include all available
reductions (because only EGUs have
substantial reduction opportunities at or
below $500/ton), but for greater costs
the curves do not include all available
reductions as they do not include nonEGU reductions.
For this reason, we are not addressing
in this proposal whether cost per ton
levels higher than $500/ton are justified
for some upwind states and downwind
receptors for ozone purposes. However,
we are presenting the information we
have on potential EGU reductions at
higher cost levels for informational
purposes. EPA intends to develop
similar emissions reductions and cost
information for sources other than EGUs
and, in a future rulemaking, to consider
whether or not reductions at a higher
cost per ton are warranted for EGUs and
other source categories.
EPA developed EGU emissions
reductions cost curves for 2014 as well
as 2012. EPA believes it is useful to
understand and display emissions
reductions capabilities for 2014, the first
year for which further emissions
reductions could be achieved through
the installation of add-on controls such
as SCR. These 2014 ozone season
63 Estimate from EPA report, ‘‘Engineering and
Economic Factors Affecting the Installation of
Control Technologies for Multi-Pollutant
Strategies,’’ CAIR docket no. OAR–2003–0053–
0106).
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emissions cost curves are presented in
Table IV.D–8. The 2014 results have
similarities to the 2012 results in that
there is an initial drop in emissions
when controls are applied at costs of
$500 per ton, which represents the use
of SCR units in states that would not be
mandated to so. Also similar to the 2012
results, relatively few reductions are
seen between $500/ton and $2,500/ton.
In contrast to the 2012 results, add-on
controls become feasible in 2014 at costs
between $2,500/ton and $5,000/ton and
more EGU emissions reductions are
possible at those cost levels.
TABLE IV.D–8—2014 OZONE-SEASON NOX EMISSIONS FROM ELECTRIC GENERATING UNITS FOR EACH STATE AT
VARIOUS COSTS (2006$) PER TON (THOUSAND TONS)
Marginal cost per ton
$0
$500
$1,000
$1,500
$2,000
$2,500
$3,000
$3,500
$5,000
Alabama ...........................................................................
Arkansas ..........................................................................
Connecticut ......................................................................
Delaware ..........................................................................
Florida ..............................................................................
Georgia ............................................................................
Illinois ...............................................................................
Indiana .............................................................................
Kansas .............................................................................
Kentucky ..........................................................................
Louisiana ..........................................................................
Maryland ...........................................................................
Michigan ...........................................................................
Mississippi ........................................................................
New Jersey ......................................................................
New York ..........................................................................
North Carolina ..................................................................
Ohio ..................................................................................
Oklahoma .........................................................................
Pennsylvania ....................................................................
South Carolina .................................................................
Tennessee .......................................................................
Texas ...............................................................................
Virginia .............................................................................
West Virginia ....................................................................
27
22
3
2
95
22
24
49
35
30
21
15
30
17
10
17
27
45
39
53
16
12
80
16
24
27
12
3
3
72
20
24
48
16
30
17
15
30
8
10
17
27
44
24
53
16
12
69
16
24
27
12
3
3
58
20
24
48
16
30
17
15
30
8
10
17
27
43
24
52
15
12
68
16
24
27
12
3
3
57
20
24
47
16
29
17
15
30
8
10
16
27
43
24
52
15
12
68
16
21
27
12
3
3
57
20
24
47
16
29
17
15
29
8
10
16
27
42
24
52
15
12
67
16
22
27
11
3
3
56
20
24
47
16
29
17
15
29
8
10
16
27
42
23
52
15
12
66
16
20
27
11
3
3
53
20
24
46
16
29
17
15
29
8
10
15
27
42
23
52
15
12
66
16
20
26
11
3
3
43
20
24
44
15
29
13
15
29
8
10
15
27
41
23
52
15
12
66
16
19
26
12
3
3
37
19
24
43
15
28
13
15
28
7
9
15
26
38
20
41
15
12
66
15
19
Total ..........................................................................
732
639
621
614
610
604
598
579
547
(3) Step 2. Air Quality Assessment of
Potential 2012 Emissions Reductions
EPA uses an air quality assessment
tool for ozone to assess the effect of NOX
reductions on downwind ozone
concentrations. This air quality
assessment tool assumes a linear
relationship between the reduction in
an upwind state’s ozone season NOX
reductions and the reduction in that
state’s contribution to downwind ozone
levels. For example, if a given upwind
state reduced its ozone season NOX
emissions by 20 percent, the air quality
assessment tool estimates that there
would also be a 20 percent reduction in
the state’s contribution to downwind
ozone. Using this assessment tool, EPA
projected the air quality impact of the
emissions reductions at the $500/ton
NOX level, the level for which we have
complete estimates of potential
emissions reductions. The assessment
shows significant improvements in 2012
at downwind air quality locations, as
evidenced by a reduction in the number
of nonattainment and maintenance
locations. EPA presents these 2012
ozone season results in Table IV.D–9.
EPA also includes in Table IV.D–9
results for 2014 before and after the
imposition of currently installed
controls (that is, for the base case or zero
dollars per ton, and for the case for
which all controls are applied up to
$500/ton). Because there are substantial
reductions in ozone season NOX from
mobile source fleet turnover between
2012 and 2014, there are
correspondingly substantial
improvements in ozone in the base case,
even in the absence of additional EGU
or other stationary source controls.
Additionally, in this 2014 analysis,
when these mobile source reductions
are combined with EGU reductions at
$500/ton, the simplified air quality
assessment tool projects that almost all
sites, with the exception of Houston, TX
(nonattainment) and Baton Rouge, LA
(maintenance), have resolved their
ozone problems.
TABLE IV.D–9—ESTIMATED NUMBER OF REMAINING NONATTAINMENT OR NONATTAINMENT AND MAINTENANCE MONITOR
SITES IN 2012 AND 2014 AS A FUNCTION OF OZONE-SEASON NOX COST PER TON LEVELS
erowe on DSK5CLS3C1PROD with PROPOSALS2
2012
2014
2014
Number of Remaining Nonattainment
Monitor Sites
Marginal Cost per Ton
2012
Number of Remaining Nonattainment and
Maintenance
Monitor Sites
Number of Remaining Nonattainment Monitor Sites
Number of Remaining Nonattainment and Maintenance Monitor
sites
11
10
25
19
4 (all in Houston, TX) .....................
1 .....................................................
7 (Houston, TX; Baton Rouge, LA).
7.
>$0 ..................................................
>$500 ..............................................
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(4) Step 3. Selection of Cost Thresholds,
Taking Into Account Cost and Air
Quality Considerations
Using the multi-factor cost and air
quality methodology described in
section IV.D.1, EPA identifies, for a
number of states, the 2012 emissions
reductions that eliminate the significant
contribution to nonattainment of the
1997 ozone NAAQS and interference
with maintenance to the 1997 ozone
NAAQS.
erowe on DSK5CLS3C1PROD with PROPOSALS2
(a) Cost Considerations
As discussed previously, $500/ton
represents the cost level for which EPA
has complete information across source
categories and represents the level for
which significant emissions reductions
are available in 2012. Large additional
reductions in 2012 cannot be achieved
given the insufficient amount of time for
sources to install controls. Compared to
NOX reduction levels determined to be
highly cost effective in both the NOX
SIP Call and the CAIR, $500/ton is a
very low cost for requiring ozone season
NOX reductions, and reductions at this
level show measurable downwind air
quality benefit. EPA believes that $500/
ton continues to be an extremely cost
effective level for NOX control relative
to benchmarks provided by the cost per
ton of NOX reductions in existing rules
or available from technologies in
various sectors, and the $500/ton level
is based on proven and widely deployed
technology.
Considering the upwind-downwind
state policy considerations discussed
previously, $500/ton NOX clearly is not
an unreasonable cost level of control for
all upwind states that contribute more
than threshold amounts to ozone air
quality problems in downwind states.
EPA believes that on purely
reasonableness or highly cost effective
grounds, a value considerably greater
than $500/ton could be justified. EPA
notes that the $2,000/ton threshold for
highly cost effective ozone season NOX
controls for the NOX SIP Call was
calculated based on 1990 dollars. If this
threshold were updated based on a more
recent year, such as the 2006 year used
for recent EPA RIA documents, the
$2,000/ton threshold would become
approximately $3,200 per ton. As a
result, EPA believes that controlling to
at least this level should be considered,
unless air quality considerations suggest
an ‘‘off-ramp’’ at lower cost levels.
(b) Air Quality Considerations
Using the air quality assessment tool,
EPA determined that emissions
reductions from ozone season NOX
controls at $500/ton would have a
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significant reduction in nonattainment
and maintenance receptors in 2012.
Accordingly, EPA believes that
requiring the reductions that can be
achieved at $500/ton are justified based
upon the 2012 air quality results.
EPA proposes, as discussed
previously, that EPA is not artificially
constrained in considering reductions
beyond 2012 and that it is relevant to
address possible air quality impacts of
additional emissions reductions that
could be achieved by 2014, the first year
for significant additional controls. At
the same time, EPA proposes that while
2014 is a relevant year to consider, it is
also relevant to consider the nature of
the air quality problem in 2014 even in
the absence of further transport controls
that could be achieved by that date.
Taking all of these 2014 considerations
into account, the air quality assessment
tool results show that in 2014 ozone
problems remain only for locations in
Houston and Baton Rouge. Thus, EPA
believes that additional post-2012
controls, beyond the $500/ton
reductions that are justified based on
2012, are possibly warranted for states
that are linked to Houston and Baton
Rouge. (See also discussion later on the
issue regarding New York City raised by
air quality modeling results.)
(c) Proposed Cost Threshold for Ozone
Based on the cost and air quality
considerations, EPA proposes $500/ton
as the appropriate cost threshold for the
following states which contribute to
downwind nonattainment and/or
maintenance problems in 2012, but
which are not linked to ozone air
quality problems in either Houston or
Baton Rouge: Connecticut, Delaware,
the District of Columbia, Indiana, Iowa,
Kansas, Maryland, Massachusetts, New
Jersey, New York, North Carolina, Ohio,
Oklahoma, Pennsylvania, South
Carolina, Virginia, and West Virginia.
For states linked to ozone air quality
problems in Houston or Baton Rouge,
EPA has not yet identified a cost
threshold for eliminating significant
contribution. EPA does, however,
propose to find that those states must
make at least all of the reductions that
can be achieved for $500/ton in 2012.
These states are: Alabama, Arkansas,
Florida, Georgia, Illinois, Kentucky,
Louisiana, Mississippi, Tennessee, and
Texas. For these states, the $500/ton
threshold represents emissions
reductions that EPA believes are an
essential part of the ultimate emissions
reductions amount that will be required
to eliminate the significant contribution
and interference with maintenance. This
level does not represent a complete
significant contribution determination
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for these states because neither the
analysis of costs up to $500/ton, nor the
analysis of air quality impacts of the
corresponding emissions reductions,
suggest that those reductions necessarily
represent all reasonable upwind state
reductions. For the reasons stated
previously in subsection 2.b, EPA
believes it is appropriate and consistent
with the statutory mandate to consider
whether section 110(a)(2)(D)(i)(I)
requires further reductions from these
states after 2012 for purposes of the
1997 ozone standard.
To determine whether further
reductions are warranted, EPA is
expeditiously conducting further
analysis. EPA is continuing to develop
and evaluate NOX control costs,
emissions reductions, and air quality
impact information for NOX controls
greater than $500/ton, and to examine
facts involving Houston and Baton
Rouge, to support a complete
determination of significant
contribution and interference with
maintenance for states that contribute to
one or both of those areas. Based on the
analysis done for today’s proposal, EPA
believes that any additional NOX
reduction requirements would involve
reductions from sources beyond EGUs.
If this is the case, EPA believes it is
likely that we could provide the greatest
assistance to states in addressing
transport by promulgating a separate
rule to achieve those NOX reductions.
EPA believes that developing
supplemental information to address
these sources beyond EGUs would
substantially delay publication of a final
rule, beyond the anticipated publication
of spring 2011. While EPA intends to
move forward aggressively on this issue
in gathering the necessary information,
EPA does not believe that this effort
should delay the reductions and large
health benefits associated with this
proposed rule. EPA fully intends to
proceed with additional rulemaking to
fully address the residual significant
contribution to nonattainment and
interference with maintenance as
quickly as possible.
(5) Request for Comment Concerning
New York City and Contributing States
As in the case of PM2.5, EPA has done
additional refined air quality analysis of
a 2014 scenario that assumes
implementation of the proposed ozone
season NOX emissions reductions, that
is, the reductions that would be
achieved based on the $500/ton NOX
cost threshold. This air quality analysis,
conducted with the CAMx model, can
be compared to the results using the air
quality assessment tool. The CAMx
modeling demonstrated that the
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required NOX reductions would assist
many downwind areas with achieving
and maintaining the NAAQS. The
CAMx air quality modeling for 2014
confirmed the conclusion that Houston
and Baton Rouge would continue to
have nonattainment/maintenance
concerns even with the reduction of
NOX emissions that could be reduced
for (at or below) $500/ton. The modeling
also showed that the locations within
the New York City nonattainment area
would continue to have a maintenance
problem despite the modeled reductions
(including those in New York State).
That is, the New York City area is
possibly at risk of being in
nonattainment in light of historical yearto-year variability in ozone levels in the
New York City area. For that reason,
EPA is taking comment on whether it
should consider and analyze the NOX
reductions that can be achieved for
greater than $500/ton in states that are
linked to the New York area sites. These
states include: Connecticut, Delaware,
Indiana, Kentucky, Maryland, New
Jersey, North Carolina, Ohio,
Pennsylvania, Virginia, and West
Virginia. If EPA were to conclude that
additional analysis is necessary, it
would present the results of this in a
future notice that would also consider
whether and to what extent states linked
to New York City, Houston, and Baton
Rouge should be required to make
additional NOX reductions in order to
eliminate all significant contribution
with respect to the 1997 ozone NAAQS.
3. Discussion of Control Costs for
Sources Other Than EGUs
Previously in this section (see
discussion in IV.D.2 previously) EPA
discusses its proposed cost criteria for
identifying SO2 and NOX emissions
reductions necessary to eliminate at
least part of each state’s significant
contribution and to eliminate at least
part of each upwind state’s interference
with maintenance of the PM2.5 NAAQS.
In addition, EPA discusses interim cost
criteria for ozone. Consistent with these
criteria, EPA does not believe that other
source categories have emissions that
are currently significantly contributing
to nonattainment or interfering with
maintenance of the 1997 and 2006 PM2.5
NAAQS. Thus, with respect to the 1997
and 2006 PM2.5 NAAQS, we are not
proposing to include in the FIPs
emissions reductions requirements for
other source categories.
(a) SO2 Sources and Costs
As described previously, EPA is
proposing to define significant
contribution on the basis of cost
informed by air quality impacts, and to
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conclude $2,000/ton represents the
highest cost value necessary for SO2 to
eliminate significant contribution and
interference with maintenance. For SO2,
as described previously, EPA is
proposing to conclude that significant
contribution and interference with
maintenance would be eliminated at
costs of no more than $2,000/ton, and in
some states, at lower costs. The EPA has
not identified SO2 reductions for
sources other than EGUs at $2,000/ton
or less (in year 2006 $).
For the CAIR, EPA included a
technical support document 64 which
noted that for SO2, EGUs were the
dominant contributor to transported
emissions, but that there were a few
additional categories for which regional
emissions exceeded 1 percent of the
overall inventory in the eastern half of
the U.S. EPA has updated this analysis
with a review of the year 2012
inventory, with similar conclusions. See
TSD—‘‘Non-EGU Emissions Reductions
Cost and Potential.’’ The highestemitting categories of non-EGU SO2
emissions are: (1) Industrial,
commercial, and institutional (ICI)
boilers, (2) Portland cement
manufacturing, (3) petroleum refining,
and (4) sulfuric acid manufacturing.
For ICI boilers, most of the SO2
emissions are from coal-fired boilers,
and to a lesser degree from residual or
distillate oil-fired boilers. Possible ways
to reduce SO2 emissions from ICI boilers
include fuel switching, flue gas
desulfurization, and dry sorbent duct
injection. Because of variability in
operations, it is difficult to identify
precise cost per ton estimates for fuel
switching and sorbent injection. For
industrial boilers, the capacity factor
(that is, the fraction of boiler capacity
that is used in a year) can have a
significant impact on the cost per ton
estimate. Regarding flue gas
desulfurization, a recent report prepared
by NESCAUM 65 suggests scrubber costs
are typically well above $2,000/ton for
ICI boilers.
For Portland cement manufacturing,
information from a 2006 report prepared
by the Lake Michigan Air Directors
Consortium (LADCO) estimated costs
for SO2 scrubbing to be between $2,211–
6,917 per ton (in year 2003 $). The
LADCO ‘‘white papers’’ discussion is
available from the following Web site:
64 Identification and Discussion of Sources of
Regional Point Source NOX and SO2 emissions
other than EGUs. EPA/OAQPS and CAMD. January
2004.
65 Reference: NESCAUM Applicability and
Feasibility of NOX, SO2, and PM Emissions Control
Technologies for Industrial, Commercial, and
Institutional (ICI) Boilers. NESCAUM, November
2008. pp. xvii, 3–12–13.
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https://www.ladco.org/reports/control/
final_reports/identification_and_
evaluation_of_candidate_control_
measures_ii_june_2006.pdf.
For petroleum refining, the largest
sources of SO2 emissions are from
catalytic cracking, sulfur recovery units,
and process heaters. For each of the
sources in the petroleum refining sector,
EPA believes that SO2 controls at or
below $2,000/ton will generally not be
available at refineries covered by the
recent settlement agreements EPA has
entered into with numerous petroleum
refineries. Moreover, such agreements
cover 88 percent of U.S refining
capacity, and will lead to up to 250,000
tons of SO2 emissions reductions
annually. Compliance with these
agreements has already taken place at
most affected refineries, and these
reductions are generally reflected in our
2012 base case emissions inventory.66
For sulfuric acid manufacturing, the
SO2 emissions are related to the percent
recovery of sulfuric acid product.
Because the percent recovery is plantspecific, the available emissions
reductions and the cost per ton of
controls are highly variable. At the time
of the CAIR, EPA made rough
calculations that the then-existing
126,000 tons of SO2 would be reduced
by about one-half if all of the sulfuric
acid manufacturing in the eastern U.S.
was controlled to meet the NSPS level
of 4 pounds of SO2 per ton of product.
EPA did not develop cost estimates for
these approximate reductions and such
cost estimates are still not available.
EPA notes, however, that it has entered
into a number of settlement agreements
with sources in the sulfuric acid
production industry, and a significant
amount of the estimated available
reductions has already been realized.
Over 36,000 tons of SO2 reductions have
taken place at 22 plants in the U.S. by
2012 as a result of 6 settlement
agreements.67 More than half of these
plants are in states affected by this
proposal.
This information shows that few if
any SO2 reductions are available from
other source categories and thus, along
with other information available to EPA,
supports EPA’s proposal not to include
non-EGU SO2 reduction requirements
for addressing PM2.5 transport for the
proposed rule. EPA seeks comment on
whether non-EGU emissions reductions
should be required and on the specific
66 U.S. EPA. Petroleum Refinery National Priority
Case Results. Available at https://www.epa.gov/
compliance/resources/cases/civil/caa/oil/index.
html.
67 U.S. EPA. Acid Plant NSR Enforcement
Priority. Available at https://www.epa.gov/
compliance/civil/caa/acidplant-nsr/.
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control measures that would serve as
the basis for those reductions.
Because sulfur content of both
gasoline and diesel fuel are now subject
to very stringent sulfur requirements,
EPA believes there are no available onroad and nonroad engine measures to
reduce mobile source SO2 at or below
$2,000/ton.
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b. NOX From Non-EGU Sources
For NOX, the methodology described
previously in section IV.D.2 requires all
states linked to PM2.5 nonattainment
and maintenance areas to ensure that
emissions do not increase above 2009
levels. This translates into a cost cutoff
of $500/ton. In addition, for ozone, EPA
determined that a number of states can
eliminate their significant contribution
and interference with maintenance by
installing controls at this same $500/ton
cost threshold.
For the CAIR, the technical support
document 68 evaluating non-EGU
controls contained a discussion of nonEGU category contributions to the
overall NOX emissions inventory and a
discussion of available controls. This
analysis identified source categories for
which regional emissions exceeded
1 percent of the overall inventory in the
eastern half of the U.S. EPA has updated
this analysis of non-EGU NOX controls
done for the CAIR with a review of the
year 2012 inventory. See TSD—‘‘NonEGU Emissions Reductions Cost and
Potential.’’ The highest-emitting
stationary source categories of non-EGU
NOX emissions are: (1) Stationary
reciprocating internal combustion
engines (RICE), (2) industrial,
commercial, and institutional (ICI)
boilers, (3) Portland cement
manufacturing, (4) petroleum refining,
(5) glass manufacturing, (6) pulp and
paper production, and (7) iron and steel
production.
EPA has not identified additional
non-EGU controls that can be achieved
at $500/ton or less. For example,
available information 69 suggests that
costs of various types of NOX controls
are greater than this level for non-EGU
sources such as ICI boilers, iron and
steel mills, petroleum refineries, 70 glass
manufacturing plants, and asphalt
manufacturing plants. For industrial
boilers, a recent report prepared by
68 Identification and Discussion of Sources of
Regional Point Source NOX and SO2 emissions
other than EGUs. EPA/OAQPS and CAMD. January
2004.
69 Reference: Identification and Evaluation of
Candidate Control Measures. Phase II Final Report.
LADCO, June. 2006. Appendix B.
70 Reference: Assessment of Control Technology
Options For Petroleum Refineries in the MidAtlantic Region. Final Report. MARAMA, January
2007. p. 2–24.
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NESCAUM 71 suggests NOX control
costs are typically well above $500/ton
for ICI boilers. In addition, a recent
report prepared by LADCO 72 indicated
NOX control costs are also well above
$500/ton for glass manufacturing plants
and asphalt manufacturing plants.
For the NOX SIP Call, EPA identified
a number of categories where costs were
less than $2,000/ton (1990 dollars),
including large ICI boilers with
capacities greater than 250 million BTU/
hour, cement kilns, and large RICE
emitting more than 1 ton NOX per day.
For each of these categories regulated
under the NOX SIP Call, EPA believes
there are no available control measures
(especially that could be implemented
by 2012) at or below $500/ton.
EPA has not identified further
controls for stationary nonpoint sources
or mobile source NOX measures that
have costs at or below $500 per ton.
E. State Emissions Budgets
As described later, EPA used the cost
thresholds identified for each covered
state in the previous section and applied
them to state-specific data to develop
individual state emissions budgets.
These budgets facilitate implementation
of the requirement that significant
contribution and interference with
maintenance be eliminated. A state’s
emissions budget is the quantity of
emissions that would remain in that
state from covered sources after
elimination of that portion of each
state’s significant contribution and
interference with maintenance that EPA
has identified in today’s proposal,
before accounting for the inherent
variability in power system operations
(see discussion of variability in section
IV.F, later). The state emissions budget
is a mechanism for converting the
quantity of emissions that a state must
reduce (i.e., the state’s significant
contribution and interference with
maintenance) into enforceable control
requirements. In other words, it
provides a quantity of emissions to use
in developing a remedy (e.g., the
remedy should be designed to achieve
the budget in an average year).
Because the budget represents
emissions that would remain without
accounting for variability, it also
represents the amount of emissions that
would remain after significant
contribution and interference with
71 Reference: NESCAUM Applicability and
Feasibility of NOX, SO2, and PM Emissions Control
Technologies for Industrial, Commercial, and
Institutional (ICI) Boilers. NESCAUM, November
2008. pp. xvii, 3–12–13.
72 Reference: Identification and Evaluation of
Candidate Control Measures. Phase II Final Report.
LADCO, June 2006. Appendix B.
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maintenance have been addressed, in an
average year. In a year when base case
emissions would have been higher than
average (e.g., because a large nuclear
unit was out of service and more fossilfuel-fired generation was needed), the
emissions that would remain after
significant contribution and interference
with maintenance had been addressed
also would be higher. The variability
limits discussed in section IV.F address
this issue. Application of variability
limits in the remedies is described in
section V.D.
1. Defining SO2 and Annual NOX State
Emissions Budgets for EGUs
For group 1 states required to make
deeper emissions reductions in 2014,
EPA based each state’s 2014 budgets on
the same projections from IPM that were
used as inputs into the cost curves
explained in section IV.D.2.a
previously. For SO2, the values were
taken from an IPM run requiring all SO2
reductions available at $2,000/ton. For
group 2 states (and for the first phase
2012 budgets for sources required to
make greater reductions in 2014), EPA
took a different approach. These states
are only required to make SO2
reductions that could be made through
(1) the operation of existing scrubbers,
(2) scrubbers that are expected to be
built by 2012 and (3) the use of low
sulfur coal. Because those strategies
were already being applied in most
states covered by this rule in 2009,73
EPA believes that the actual
performance units achieved in 2009 is
more representative of expected
emissions than what EPA modeled
using IPM. This is because real data
takes into account actual unit by unit
information that is represented at a
more aggregate level in IPM. The only
exception to this rule is if a source was
modeled to install a scrubber by 2012
(because of rules requiring that
installation and/or because of
information that the company had
already contracted to install a scrubber).
In this case, EPA adjusted emissions
from the unit to account for the new
scrubber.
For 2012 NOX budgets, EPA used the
same general methodology for all states
that was used for the group 2 states for
SO2. The $500/ton cost threshold, that
EPA has determined can be used to
calculate the minimum significant
contribution from upwind states linked
to downwind nonattainment and
maintenance areas, almost exclusively
73 Even though allowance prices dropped
significantly in 2008 after the Court decision, most
sources appear to have continued with the same
reduction strategies.
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represents reductions from turning on
SCR units. EPA believes that instead of
defining the budgets based on IPM
projections of what will happen when
SCR units are turned on, it is better to
use real data, therefore EPA has
developed budgets based on a
combination of historical heat input,
historical emissions rates, and, where
new SCR units are expected between
45291
now and 2012, projected emissions rates
for those new SCR units. The emissions
budgets developed using the previous
methodology are as follows in Table
IV.E–1:
TABLE IV.E–1—SO2 AND ANNUAL NOX STATE EMISSIONS BUDGETS FOR ELECTRIC GENERATING UNITS BEFORE
ACCOUNTING FOR VARIABILITY 74
[Tons]
SO2, 2012 and
2013
SO2, 2014 and
later
Alabama .......................................................................................................................................
Connecticut ..................................................................................................................................
Delaware ......................................................................................................................................
District of Columbia .....................................................................................................................
Florida ..........................................................................................................................................
Georgia ........................................................................................................................................
Illinois ...........................................................................................................................................
Indiana .........................................................................................................................................
Iowa .............................................................................................................................................
Kansas .........................................................................................................................................
Kentucky ......................................................................................................................................
Louisiana ......................................................................................................................................
Maryland ......................................................................................................................................
Massachusetts .............................................................................................................................
Michigan .......................................................................................................................................
Minnesota ....................................................................................................................................
Missouri ........................................................................................................................................
Nebraska ......................................................................................................................................
New Jersey ..................................................................................................................................
New York .....................................................................................................................................
North Carolina ..............................................................................................................................
Ohio .............................................................................................................................................
Pennsylvania ................................................................................................................................
South Carolina .............................................................................................................................
Tennessee ...................................................................................................................................
Virginia .........................................................................................................................................
West Virginia ................................................................................................................................
Wisconsin .....................................................................................................................................
161,871
3,059
7,784
337
161,739
233,260
208,957
400,378
94,052
57,275
219,549
90,477
39,665
7,902
251,337
47,101
203,689
71,598
11,291
66,542
111,485
464,964
388,612
116,483
100,007
72,595
205,422
96,439
161,871
3,059
7,784
337
161,739
85,717
151,530
201,412
86,088
57,275
113,844
90,477
39,665
7,902
155,675
47,101
158,764
71,598
11,291
42,041
81,859
178,307
141,693
116,483
100,007
40,785
119,016
66,683
69,169
2,775
6,206
170
120,001
73,801
56,040
115,687
46,068
51,321
74,117
43,946
17,044
5,960
64,932
41,322
57,681
43,228
11,826
23,341
51,800
97,313
113,903
33,882
28,362
29,581
51,990
44,846
Total ......................................................................................................................................
3,893,870
2,500,003
1,376,312
State
For more detail on how the budgets
were developed, see the TSD: ‘‘State
Budgets, Unit Allocations, and Unit
Emissions Rates’’.
TABLE IV.E–2—OZONE-SEASON NOX
STATE EMISSIONS BUDGETS FOR
ELECTRIC GENERATING UNITS BEFORE ACCOUNTING FOR VARIABILITY—Continued
2. Defining Ozone Season NOX State
Emissions Budgets for EGUs
TABLE IV.E–2—OZONE-SEASON NOX
STATE EMISSIONS BUDGETS FOR
ELECTRIC GENERATING UNITS BEFORE ACCOUNTING FOR VARIABILITY
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[Tons]
State
Alabama ....................................
Arkansas ...................................
NOX ozone
season, all
years
29,738
16,660
74 The impact of variability on the budgets is
discussed in section IV.F, later.
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TABLE IV.E–2—OZONE-SEASON NOX
STATE EMISSIONS BUDGETS FOR
ELECTRIC GENERATING UNITS BEFORE ACCOUNTING FOR VARIABILITY—Continued
[Tons]
Ozone season NOX budgets were
developed the same way as the annual
NOX budgets were developed (explained
in IV.E.1, previously).
Connecticut ...............................
Delaware ...................................
District of Columbia ..................
Florida .......................................
Georgia .....................................
Illinois ........................................
Indiana ......................................
Kansas ......................................
Kentucky ...................................
Louisiana ..................................
Maryland ...................................
Michigan ...................................
Mississippi ................................
New Jersey ...............................
New York ..................................
North Carolina ..........................
Ohio ..........................................
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[Tons]
NOX ozone
season, all
years
State
Sfmt 4702
NOX annual,
all years
1,315
2,450
105
56,939
32,144
23,570
49,987
21,433
30,908
21,220
7,232
28,253
16,530
5,269
11,090
23,539
40,661
State
NOX ozone
season, all
years
Oklahoma .................................
Pennsylvania ............................
South Carolina ..........................
Tennessee ................................
Texas ........................................
Virginia ......................................
West Virginia ............................
37,087
48,271
15,222
11,575
75,574
12,608
22,234
Total ...................................
641,614
These budgets are based on a 5 month
ozone season (May 1 through September
30). Consistent with the approach taken
by the OTAG, the NOX SIP Call, and the
CAIR, we propose to define the ozone
season, for purposes of emissions
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reductions requirements in this rule, as
May through September. We recognize
that this ozone season for regulatory
requirements will have differences from
the official state-specific ozone
monitoring season. EPA requests
comment on whether the budgets for the
final rule should be based on a longer
ozone season, such as March through
October.
F. Emission Reduction Requirements
Including Variability
In this section, EPA discusses the
inherent variability in electric power
system operation and presents proposed
variability limits for each state. As
explained below, EPA proposes to
calculate variability limits for each state
and to use those variability limits in
conjunction with the budgets (which are
based on expected average conditions)
to provide limited flexibility (within the
limits allowed by the variability
provisions) to address years in which
more fossil generation occurs than
projected in the average base case year.
This section also presents projected
emission reduction results.
1. Variability
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a. Introduction to Power Sector
Variability
Historically, power sector emissions
have varied over time. Factors, such as
fuel switching and installing new
emissions controls, which can lead to
significant decreases in emissions,
primarily affect emissions rates rather
than generation and change largely as a
result of pollution regulation.
Even when emissions rates do not
change from year to year, overall
emissions can change because of factors
including power demand, timing of
maintenance activities, and unexpected
shutdowns of units. Extreme weather
conditions, sudden economic shocks,
and other unpredictable events can also
significantly impact power generation
from fossil units. These factors relate
directly to heat input, generation, and
the routine operation of power plants to
supply our electricity, and thus affect
total emissions.
As discussed previously, EPA has
identified a specific amount of
emissions that must be prohibited by
each state to satisfy the requirements of
CAA section 110(a)(2)(D)(i)(I). EPA has
also developed state budgets based on
its projections of state emissions in an
average year after the elimination of
such emissions. However, because of
the unavoidable variability in baseline
emissions—resulting from the inherent
variability in power plant operations—
state-level emissions may vary
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somewhat after all significant
contribution and interference with
maintenance that EPA has identified in
this proposal are eliminated. This
occurs even when the emissions rates of
the units within the state do not change.
For this reason, EPA has determined
that it is appropriate to develop
variability limits for each state budget.
These limits are used to identify the
range of emissions that EPA believes
may occur in each state following the
elimination of all significant
contribution and interference with
maintenance.
For the proposed rule, EPA proposes
to factor this variability explicitly in its
consideration of how to control
emissions. The Agency believes that
because baseline emissions are variable,
emissions after the elimination of all
significant contribution are also variable
and thus it is appropriate to take this
variability into account.
As discussed in detail in section V,
EPA proposes and considers specific
regulatory remedies that are designed to
meet the emissions budget in an average
year. Because base case emissions may
vary from projections, EPA believes
these same remedies may incorporate
provisions that account for variability.
This variability, however, must be
limited to provide downwind states
with assurance that necessary
reductions will be made in upwind
states. This section describes how EPA
calculated variability limits for each
state to achieve this goal.
Remedies (i.e., regulatory approaches
for achieving emissions reductions) can
range from emissions rate-based ‘‘direct
control’’ options to options which allow
for interstate trading. EPA believes that
inherent variability in power system
operations affects each state’s baseline
emissions and thus also affects a state’s
emissions after elimination of all
significant contribution and interference
with maintenance. Thus, emissions may
vary somewhat after implementation of
the remedies under consideration.
Under an emissions rate-based
approach, emissions rate limits could be
developed that would meet the budget
assuming a given pattern of operation
for the affected units. If some of the
units with higher emissions rates
actually operated more than projected,
the state’s actual emissions would be
higher. In an interstate trading program,
budgets could be developed that each
state would be projected to meet in an
average year. In some years, however,
generation from units in one state may
increase (with a corresponding increase
in emissions), but because variability in
a larger region is less significant than
within a single state, the increase in one
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Fmt 4701
Sfmt 4702
state would be expected to be offset by
decreases in other states. Finally, even
in an intrastate-only trading program,
the ability to bank allowances could
mean that in one year, emissions would
be below the budget, while in another
year they would be above.
In all these cases, variability limits
can be used to retain the flexibilities
that the various remedies provide to
deal with real-world variability in the
operating system, while still providing
downwind states reasonable certainty
about the level of upwind emissions.
EPA also notes that explicit
consideration of variability in the
emissions resulting from a remedy is
consistent with removing a state’s
‘‘significant contribution.’’ As noted
previously, even if the emissions result
is variable from year to year, there is
still a similar increment of emissions
reductions. For example, because
increased emissions in the control case
would also correspond to increased
emissions in the base case, the
increment of emissions representing
significant contribution and interference
with maintenance would still be
removed. Finally, as is explained more
below in IV.F.b, the variability limits (as
applied, for instance, in the State
Budgets/Limited Trading remedy in
section V.D.4) are relatively low and
thus the total amount of variability
allowed is very small compared to total
EGU emissions and even smaller when
considering all of the emissions within
a state. It is also worth noting that in the
proposed State Budgets/Limited Trading
remedy, variability is taken into account
in such a way that does not allow an
overall increase in emissions. Under
this remedy, an individual state could
emit up to its budget plus variability
limit. However, the requirement that all
sources hold allowances to cover
emissions, and the fact that those
allowances are allocated based on statespecific budgets absent variability,
would ensure that total emissions do
not increase. This remedy, therefore,
ensures not only that total emissions do
not increase above state budgets, but
also that reductions occur in each and
every state.
b. How EPA Accounted for Inherent
Power Sector Variability
EPA determined 1-year variability
limits and 3-year rolling average
variability limits for each state. First,
EPA determined 1-year variability limits
based on historical variability in heat
input. Second, EPA determined 3-year
rolling average variability limits using
statistical methods to convert the 1-year
variability into 3-year variability. The
approaches EPA used to determine the
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1-year and 3-year limits are summarized
later and described in more detail in the
Power Sector Variability TSD.
Expected variability over a single
year. EPA performed analyses using
historical data to demonstrate that there
is year-to-year variability in baseline
emissions (even when emissions rates
for all units are held constant) and to
quantify the magnitude of this
variability. This year-to-year variability
in emissions is reflected, in combination
with other factors, in year-to-year
variability in air quality.
The focus of the analysis is on
quantifying the magnitude of the
inherent variability in the baseline
emissions (on both a 1-year and a 3-year
basis). The goals of this analysis,
therefore, are to determine the typical
variability in emissions that is due to
changes in generation, and not due to
changes in emission limits, and to set
emissions criteria limits that can be
used as part of a remedy to ensure that
states are eliminating their significant
contribution and interference with
maintenance to protect air quality.
EPA used statewide average emissions
rates projected using IPM to convert
historical heat input variability into
corresponding emissions variability
limits. The approach assessed the
variability in state-level heat input over
a 7-year time period (2002 through
2008) using the standard deviation and
then determined the difference in
emissions from the 95th percent twotailed confidence level and the mean.75
The approach resulted in a maximum
allowable variability, in tons, for each
state. These values were then divided by
the mean emissions values over the 7year time period to yield a percentage
variability value for each state. See the
Power Sector Variability TSD for details.
From the state-by-state tonnage and
percentage emission variability values,
EPA identified a single set of variability
levels (that is, a tonnage and a
percentage) based on the historic
variability. EPA made the decision to
adopt a single, uniform tonnage and
percentage level pairing 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. The effect
of the pairing is to ensure that each state
is allowed adequate variability while
minimizing the total amount of
emissions allowed. Using, for all states,
only a constant percentage (reflecting
emissions variability in smaller states
with a greater range of emissions in
75 The
two-tailed 95th percent confidence level is
the equivalent of the 97.5th upper (single-tailed)
confidence level.
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percentage terms) would result in large
states being allowed greater variability
than needed. Conversely, using only a
constant tonnage (reflecting emissions
variability in larger states with a greater
range of emissions in tonnage terms)
would result in small states being
allowed greater variability than needed.
To ensure adequate variability limits—
even in states with small numbers of
units where expected variability would
be more pronounced in percentage
terms, and in large states where
expected variability would be more
pronounced in absolute tonnage terms—
EPA derived variability limits both as a
percentage and in terms of absolute
emissions (tons) that serve to minimize
the total amount of emissions allowed
under this combination variability limit
approach.
For the tonnage and percentage limit
criteria, EPA looked at a wide range of
percentage and tonnage combinations,
and chose for further investigation
combinations that provided states
sufficient variability limits (based on
historic variability) and fit the
requirement of minimizing the allowed
emissions. Power plants in states that
were close to the variability limits were
evaluated more closely to ensure the
modeling reflected all controls known to
operate. EPA believes that the chosen
limits would not be tighter than these
states could be expected to meet.
This approach (identifying both a
tonnage and a percentage) addresses the
difficulty that smaller states with fewer
units could face if only percentages
were used to set the limits. For instance,
in a small state with a budget of 5,000
tons of SO2, an infrequently used unit
that on average emitted 500 tons when
it operated 10 percent of the time could
increase its emissions to 1,500 tons by
operating 30 percent of the time in a
year when there is unusually high
demand for that unit. That would result
in a 20 percent increase in statewide
emissions. In a much larger state, with
a budget of 50,000 tons, such a change
in operation would only lead to a
1 percent change in statewide
emissions.
For both annual NOX and SO2, the
percentage variability limits are 10
percent of a state’s budget and the
corresponding tonnage variability limits
are 5,000 and 1,700 tons for NOX and
SO2, respectively. These are the values
that result from the approach described
previously, i.e., these variability levels
allow the necessary variability for every
state based on its historic variability,
while minimizing the amount of
emissions allowed.
EPA assigned each state one of these
values—either the tonnage limit or the
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45293
percent limit, whichever was greater for
that state. For instance, 10 percent of
Connecticut’s SO2 budget is less than
1,700 tons, so Connecticut received a
1-year 1,700 ton variability limit for its
EGU SO2 emissions. EGU sources in
Connecticut could emit up to the state’s
SO2 budget plus the variability limit of
an additional 1,700 tons of SO2 in a
year, and still eliminate the state’s
significant contribution and interference
with maintenance. Proposed 1-year
variability limits for each covered state
are shown in the tables in section
IV.F.2, later. See the Power Sector
Variability TSD for more details on
EPA’s variability approach.
Expected variability over a 3-year
time period. Because air quality is
assessed under the Act annually on a
rolling 3-year time period, EPA believes
that it is appropriate to also evaluate the
inherent variability in emissions over
similar time periods, and to establish
state budgets with variability limits that
ensure that the significant contribution
and interference with maintenance that
EPA has identified in this notice be
eliminated.
While the year-to-year variability in
emissions could lead to variability in
3-year rolling averages, inherent
variability is lower over a 3-year time
period than over a 1-year period and
thus a state’s 3-year variability limit will
be lower than the state’s 1-year
variability limit. Establishing such
3-year limits thus provides an
opportunity to ensure that the
variability limits do not allow greater
fluctuation in emissions than justified
based on historic variability. EPA
estimated the variability in a state’s
emissions over a 3-year time period
based on the expected variability in
emissions for a single year.
As summarized later and described in
the Power Sector Variability TSD, the
Agency used statistical methods to
estimate the 3-year variability based on
1-year variability. The average
variability of a multi-year sample is the
average variability of a single year
divided by the square root of the
number of years in the multi-year
sample.76 Thus, the variability of a
3-year average is equal to the annual
variability divided by the square root of
three. EPA used this approach to
determine 3-year variability limits based
on the 1-year limits. For example, the
Agency calculated the 3-year variability
that corresponds to a 1-year variability
of 5,000 tons as 5,000 divided by the
76 Moore, David S. and George P. McCabe.
Introduction to the Practice of Statistics. 2nd ed.
New York: W.H. Freeman and Company, 1993. p.
395.
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square root of three, or 2,887 tons.
Similarly, EPA calculated the 3-year
variability that corresponds to a 1-year
variability of 1,700 tons as 1,700
divided by the square root of three, or
981 tons. EPA decided to use three years
instead of some other interval in order
to be consistent with 3-year averaging
used to assess attainment with the
NAAQS, as explained earlier in this
section.
Proposed 3-year variability limits for
each covered state are shown in the
tables in section IV.F.2, later. See the
Power Sector Variability TSD for more
details on EPA’s variability approach.
2. State Budgets With Variability Limits
As explained previously, EPA
determined variability limits for each
state. EPA then applied these variability
limits on a state-by-state basis to
calculate state-specific emissions
budgets with variability limits. EPA
calculated state budgets with both
1-year and 3-year variability limits.
Table IV.F–1 shows proposed
variability limits by state on SO2
emissions for 2014 and later. Table
IV.F–2 shows proposed variability
limits by state on NOX annual emissions
for 2014 and later. EPA requests
comment on the proposed variability
limits.
EPA also requests comment on an
alternative calculation method for
variability. The alternative method
would use the results of the proposed
method but add a ceiling based on the
maximum percentage of variability
among covered states as observed in the
historic heat input data described
previously. For both NOX annual and
SO2, the percentage limits calculated
using this alternative methodology are
21 and 28 percent of a state’s budget,
respectively. Under this alternative
calculation method, a state’s variability
limit would be no lower than 10 percent
of its budget and no higher than 21 or
28 percent, for NOX and SO2,
respectively. Because no state varied
more than these percentages, EPA
believes they could serve as reasonable
caps on variability limits. These limits
would address the issue of small states
receiving very large variability limits as
a fraction of their budgets.
For instance, although Connecticut’s
proposed 1-year variability limit of
1,700 tons is greater than 10 percent of
its SO2 budget of 3,059 tons (306 tons),
it is also greater than 28 percent of the
budget (857 tons). Therefore, under this
alternative calculation method,
Connecticut’s 1-year SO2 variability
limit would be 857 tons (28 percent of
the state’s SO2 budget). Similarly, for
annual NOX, while Connecticut’s
proposed 1-year variability limit of
5,000 tons is greater than 10 percent of
its NOX annual budget of 2,775 (278
tons), it is greater than 21 percent of the
budget (583 tons). Therefore, under this
alternative approach, Connecticut’s
1-year annual NOX variability limit
would be 583 tons. Tables IV.F–1
through IV.F–3 show the variability
limits under the proposed and
alternative calculation methods. See the
Power Sector Variability TSD in the
docket for this rule for more details.
TABLE IV.F–1—VARIABILITY LIMITS ON SO2 ANNUAL EMISSIONS FOR 2014 AND LATER FOR ELECTRIC GENERATING UNITS
[Tons]
Proposed
SO2 annual
emissions
budget
1-year limit
Alabama ...................................................................................................
Connecticut ..............................................................................................
Delaware ..................................................................................................
District of Columbia ..................................................................................
Florida ......................................................................................................
Georgia ....................................................................................................
Illinois .......................................................................................................
Indiana .....................................................................................................
Iowa .........................................................................................................
Kansas .....................................................................................................
Kentucky ..................................................................................................
Louisiana ..................................................................................................
Maryland ..................................................................................................
Massachusetts .........................................................................................
Michigan ...................................................................................................
Minnesota ................................................................................................
Missouri ....................................................................................................
Nebraska ..................................................................................................
New Jersey ..............................................................................................
New York .................................................................................................
North Carolina ..........................................................................................
Ohio .........................................................................................................
Pennsylvania ............................................................................................
South Carolina .........................................................................................
Tennessee ...............................................................................................
Virginia .....................................................................................................
West Virginia ............................................................................................
Wisconsin .................................................................................................
161,871
3,059
7,784
337
161,739
85,717
151,530
201,412
86,088
57,275
113,844
90,477
39,665
7,902
155,675
47,101
158,764
71,598
11,291
42,041
81,859
178,307
141,693
116,483
100,007
40,785
119,016
66,683
16,187
1,700
1,700
1,700
16,174
8,572
15,153
20,141
8,609
5,728
11,384
9,048
3,967
1,700
15,568
4,710
15,876
7,160
1,700
4,204
8,186
17,831
14,169
11,648
10,001
4,079
11,902
6,668
Total ..................................................................................................
2,500,003
State
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Alternative
3-year
average
limit
9,346
981
981
981
9,338
4,949
8,749
11,629
4,970
3,307
6,573
5,224
2,290
981
8,988
2,719
9,166
4,134
981
2,427
4,726
10,295
8,181
6,725
5,774
2,355
6,871
3,850
1-year limit
16,187
857
1,700
94
16,174
8,572
15,153
20,141
8,609
5,728
11,384
9,048
3,967
1,700
15,568
4,710
15,876
7,160
1,700
4,204
8,186
17,831
14,169
11,648
10,001
4,079
11,902
6,668
3-year
average
limit
9,346
495
981
54
9,338
4,949
8,749
11,629
4,970
3,307
6,573
5,224
2,290
981
8,988
2,719
9,166
4,134
981
2,427
4,726
10,295
8,181
6,725
5,774
2,355
6,871
3,850
Proposed 1-year variability limits are the larger of (1) 1,700 tons or (2) 10 percent of the state’s budget. 3-year limits are the 1-year limits divided by the square root of three.
The alternative 1-year variability limit is 1,700 tons as long as that amount is between 10 and 28 percent of the state’s budget. If 1,700 tons is
greater than 28 percent of the state’s budget, the state’s limit is set at 28 percent of its budget. If 1,700 tons is less than 10 percent of the state’s
budget, the state’s limit is set at 10 percent of its budget.
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TABLE IV.F–2—VARIABILITY LIMITS ON NOX ANNUAL EMISSIONS FOR 2014 AND LATER FOR ELECTRIC GENERATING UNITS
[Tons]
Proposed
NOX annual
State
1-year limit
Alabama ...................................................................................................
Connecticut ..............................................................................................
Delaware ..................................................................................................
District of Columbia ..................................................................................
Florida ......................................................................................................
Georgia ....................................................................................................
Illinois .......................................................................................................
Indiana .....................................................................................................
Iowa .........................................................................................................
Kansas .....................................................................................................
Kentucky ..................................................................................................
Louisiana ..................................................................................................
Maryland ..................................................................................................
Massachusetts .........................................................................................
Michigan ...................................................................................................
Minnesota ................................................................................................
Missouri ....................................................................................................
Nebraska ..................................................................................................
New Jersey ..............................................................................................
New York .................................................................................................
North Carolina ..........................................................................................
Ohio .........................................................................................................
Pennsylvania ............................................................................................
South Carolina .........................................................................................
Tennessee ...............................................................................................
Virginia .....................................................................................................
West Virginia ............................................................................................
Wisconsin .................................................................................................
69,169
2,775
6,206
170
120,001
73,801
56,040
115,687
46,068
51,321
74,117
43,946
17,044
5,960
64,932
41,322
57,681
43,228
11,826
23,341
51,800
97,313
113,903
33,882
28,362
29,581
51,990
44,846
Total ..................................................................................................
6,917
5,000
5,000
5,000
12,000
7,380
5,604
11,569
5,000
5,132
7,412
5,000
5,000
5,000
6,493
5,000
5,768
5,000
5,000
5,000
5,180
9,731
11,390
5,000
5,000
5,000
5,199
5,000
Alternative
3-year
average
limit
3,993
2,887
2,887
2,887
6,928
4,261
3,235
6,679
2,887
2,963
4,279
2,887
2,887
2,887
3,749
2,887
3,330
2,887
2,887
2,887
2,991
5,618
6,576
2,887
2,887
2,887
3,002
2,887
1-year limit
6,917
583
1,303
36
12,000
7,380
5,604
11,569
5,000
5,132
7,412
5,000
3,579
1,252
6,493
5,000
5,768
5,000
2,483
4,902
5,180
9,731
11,390
5,000
5,000
5,000
5,199
5,000
3-year
average
limit
3,993
336
752
21
6,928
4,261
3,235
6,679
2,887
2,963
4,279
2,887
2,066
723
3,749
2,887
3,330
2,887
1,434
2,830
2,991
5,618
6,576
2,887
2,887
2,887
3,002
2,887
1,376,312
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Proposed 1-year variability limits are the larger of (1) 5,000 tons or (2) 10 percent of the state’s budget. 3-year limits are the 1-year limits divided by the square root of three.
The alternative 1-year variability limit is 5,000 tons as long as that amount is between 10 and 21 percent of the state’s budget. If 5,000 tons is
greater than 21 percent of the state’s budget, the state’s limit is set at 21 percent of its budget. If 5,000 tons is less than 10 percent of the state’s
budget, the state’s limit is set at 10 percent of its budget.
The NOX ozone season variability
limits have been calculated based on
five months of data corresponding to the
May through September ozone season.
EPA is proposing to use the same
approach to calculate ozone season
limits that the Agency used to calculate
the proposed SO2 and NOX annual
variability limits described earlier in
this section, but adjusted to reflect the
ozone season data.
Using that approach, the resulting
ozone season 1-year variability limits
are 2,100 tons and 10 percent of a state’s
budget. EPA assigned each state one of
these values–either the tonnage limit or
the percentage limit, whichever was
greater for that state—using the same
approach as for the SO2 and NOX annual
limits described previously. EPA
determined the 3-year variability limits
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as the 1-year limits divided by the
square root of three, the same approach
used for the SO2 and NOX annual limits.
The NOX ozone season limits resulting
from this approach are shown in Table
IV.F–3.
EPA did not explicitly model ozone
season variability limits because it was
assumed that the NOX annual limits
would also serve to limit variability in
the ozone season and that additional
constraints were unnecessary. However,
a comparison of the data revealed that
these variability limits would be lower
than the ozone season emissions shown
in EPA’s modeling for this proposed
rule in seven states, with the difference
ranging from less than 100 tons to about
900 tons. Adding these ozone season
variability limits would, presumably,
change the NOX emissions projections
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in the IPM modeling, but the differences
are expected not to make a noticeable
impact in the overall air quality results.
As with the SO2 and NOX annual
variability limits, EPA also calculated
NOX ozone season limits using the
alternative calculation method
described previously; the alternative
method adds a ceiling based on the
maximum percentage of variability
among covered states as observed in the
historic heat input data. For NOX ozone
season, the percentage limit ceiling
would be 27 percent of a state’s budget.
The NOX ozone season limits resulting
from this approach are also shown in
Table IV.F–3.
EPA requests comments on the NOX
ozone season limits shown in Table
IV.F–3.
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TABLE IV.F–3—VARIABILITY LIMITS ON NOX OZONE EMISSIONS FOR 2014 AND LATER FOR ELECTRIC GENERATING UNITS
[Tons]
NOX ozone
season
emissions
budget
1-year limit
3-year average limit
1-year limit
3-year average limit
Alabama ...................................................................................................
Arkansas ..................................................................................................
Connecticut ..............................................................................................
Delaware ..................................................................................................
District of Columbia ..................................................................................
Florida ......................................................................................................
Georgia ....................................................................................................
Illinois .......................................................................................................
Indiana .....................................................................................................
Kansas .....................................................................................................
Kentucky ..................................................................................................
Louisiana ..................................................................................................
Maryland ..................................................................................................
Michigan ...................................................................................................
Mississippi ................................................................................................
New Jersey ..............................................................................................
New York .................................................................................................
North Carolina ..........................................................................................
Ohio .........................................................................................................
Oklahoma .................................................................................................
Pennsylvania ............................................................................................
South Carolina .........................................................................................
Tennessee ...............................................................................................
Texas .......................................................................................................
Virginia .....................................................................................................
West Virginia ............................................................................................
29,738
16,660
1,315
2,450
105
56,939
32,144
23,570
49,987
21,433
30,908
21,220
7,232
28,253
16,530
5,269
11,090
23,539
40,661
37,087
48,271
15,222
11,575
75,574
12,608
22,234
2,974
2,100
2,100
2,100
2,100
5,694
3,214
2,357
4,999
2,143
3,091
2,122
2,100
2,825
2,100
2,100
2,100
2,354
4,066
3,709
4,827
2,100
2,100
7,557
2,100
2,223
1,717
1,212
1,212
1,212
1,212
3,287
1,856
1,361
2,886
1,237
1,784
1,225
1,212
1,631
1,212
1,212
1,212
1,359
2,348
2,141
2,787
1,212
1,212
4,363
1,212
1,284
2,974
2,100
355
662
28
5,694
3,214
2,357
4,999
2,143
3,091
2,122
1,953
2,825
2,100
1,423
2,100
2,354
4,066
3,709
4,827
2,100
2,100
7,557
2,100
2,223
1,717
1,212
205
382
16
3,287
1,856
1,361
2,886
1,237
1,784
1,225
1,127
1,631
1,212
821
1,212
1,359
2,348
2,141
2,787
1,212
1,212
4,363
1,212
1,284
Total ..................................................................................................
641,614
State
Proposed
Alternative
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Proposed 1-year variability limits are the larger of (1) 2,100 tons or (2) 10 percent of the state’s budget. 3-year limits are the 1-year limits divided by the square root of three.
The alternative 1-year variability limit is 2,100 tons as long as that amount is between 10 and 27 percent of the state’s budget. If 2,100 tons is
greater than 27 percent of the state’s budget, the state’s limit is set at 27 percent of its budget. If 2,100 tons is less than 10 percent of the state’s
budget, the state’s limit is set at 10 percent of its budget.
As discussed in section V.D, the
proposed FIPs would apply the 1-year
variability limits commencing in 2014
and the 3-year variability limits
commencing in 2016, noting that
application of the 3-year average limits
in 2016 would serve to limit each state’s
emissions in 2014 and 2015. The
Agency also requests comment on
whether the remedy in the proposed
FIPs should be modified so that the
limits would apply starting in 2012
instead of 2014. In addition, the direct
control remedy option on which EPA
requests comments includes assurance
provisions based on these variability
limits that would apply starting in 2012.
Thus, EPA also explains later what
variability limits would apply in 2012
and 2013. The 1-year variability limits
for 2012 and 2013 would be the same
as the variability limits for 2014 and
later in Tables IV.F–1, IV.F–2, and IV.F–
3 for all state budgets except for the SO2
budgets for the 15 states comprising the
stringent SO2 tier (‘‘group 1’’), which
have different SO2 budgets in 2012 and
2013 than in 2014 and beyond.
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If EPA finalizes a remedy that uses the
2012 and 2013 variability limits, EPA
would also start applying the 3-year
variability limits in 2014 (for all state
budgets except group 1 SO2 budgets)
which would serve to limit each state’s
emissions in 2012 and 2013, in the same
way that starting the 3-year limits in
2016 would serve to limit emissions in
2014 and 2015 under the proposed
approach. The 3-year variability limits
would be the same as the 3-year limits
for 2014 and later in Tables IV.F–1,
IV.F–2, and IV.F–3.
In this alternative approach, the 15
SO2 group 1 states, which have different
SO2 budgets in 2012 and 2013 than in
2014 and beyond, would be subject to
different 1-year variability limits in
2012 and 2013 than in later years. All
of the group 1 states have sufficiently
large SO2 budgets in 2012 and 2013 that
the tonnage limit of 1,700 tons would
not apply and the 1-year limits would
be 10 percent of the state SO2 budgets.
The 2012 and 2013 1-year limits on SO2
emissions for these 15 states under this
alternative approach are shown later in
Table IV.F–4.
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Additionally, commencing in 2013,
EPA would apply in these 15 states a
distinct 2-year average variability limit
on SO2 emissions for the years 2012 and
2013. Analogous to the 3-year average in
subsequent years, this 2-year average
limit would restrict average variability
in 2012 and 2013 more than the 1-year
average alone. Table IV.F–4 shows, for
this alternative approach, 2-year
variability limits on SO2 emissions for
2012 and 2013 for the 15 group 1 states.
For these states, the 3-year variability
limits for later years would be as shown
in Tables IV.F–1, IV.F–2, and IV.F–3.
For an alternative approach where
variability limits start in 2012 instead of
2014, EPA considered—instead of twoyear average limits on SO2 emissions in
the 15 group 1 states in 2012 and 2013—
applying 3-year average limits in these
states starting in 2014. This would be
the same method as for all other state
budgets under the alternative where
variability limits start in 2012. However,
because the 15 group 1 states have
different SO2 budgets in 2012 and 2013
than in 2014 and beyond, calculation of
the 3-year average limits to apply in
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years spanning the two budget levels is
less straightforward. EPA analyzed this
alternative method for the 15 SO2 group
1 states and compared results to the
results using the 2-year average limits in
2012 and 2013 for these states, and
determined that the 2-year average
approach is reasonable. See the Power
Sector Variability TSD for more
information.
Table IV.F–4 includes 1-year and
2-year variability limits calculated
according to the proposed methodology.
The 2-year limits are the 1-year limits
divided by the square root of two. The
table does not include separate columns
with variability limits calculated
according to the alternative calculation
method (i.e., the method that adds a
ceiling based on the maximum
percentage of variability in historic data,
described previously) because for the
SO2 budgets in Table IV.F–4 the
alternative calculation method would
yield identical results to the proposed
method. The Power Sector Variability
TSD contains more details on the
variability limits.
TABLE IV.F–4—2012–2013 ONE- AND TWO-YEAR VARIABILITY LIMITS ON SO2 EMISSIONS FOR GROUP 1 STATES FOR
ELECTRIC GENERATING UNITS
[Tons]
SO2 annual
emissions
budget
State
Georgia ....................................................................................................................................................
Illinois .......................................................................................................................................................
Indiana .....................................................................................................................................................
Iowa .........................................................................................................................................................
Kentucky ..................................................................................................................................................
Michigan ...................................................................................................................................................
Missouri ....................................................................................................................................................
New York .................................................................................................................................................
North Carolina ..........................................................................................................................................
Ohio .........................................................................................................................................................
Pennsylvania ............................................................................................................................................
Tennessee ...............................................................................................................................................
Virginia .....................................................................................................................................................
West Virginia ............................................................................................................................................
Wisconsin .................................................................................................................................................
1-year limit
233,260
208,957
400,378
94,052
219,549
251,337
203,689
66,542
111,485
464,964
388,612
100,007
72,595
205,422
96,439
23,326
20,896
40,038
9,405
21,955
25,134
20,369
6,654
11,149
46,496
38,861
10,001
7,260
20,542
9,644
Two-year
average
limit
16,494
14,775
28,311
6,650
15,524
17,772
14,403
4,705
7,883
32,878
27,479
7,072
5,133
14,526
6,819
1-year variability limits calculated by the proposed method are the larger of (1) 1,700 tons or (2) 10 percent of the state’s budget. Two-year
limits are the 1-year limits divided by the square root of two.
The alternative 1-year variability limit is 1,700 tons as long as that amount is between 10 and 28 percent of the state’s budget. If 1,700 tons is
greater than 28 percent of the state’s budget, the state’s limit is set at 28 percent of its budget. If 1,700 tons is less than 10 percent of the state’s
budget, the state’s limit is set at 10 percent of its budget. The alternative calculation method would yield identical limits to the limits determined
using the proposed method for the budgets in Table IV.F–4, because for each of these budgets, 1,700 tons is less than 10 percent of the
budget.
3. Summary of Emissions Reductions
Across All Covered States
Table IV.F–5 presents projected
power sector emissions in the base case
(i.e., without the proposed Transport
Rule or CAIR) compared to projected
emissions with the proposed Transport
Rule in 2012 and 2014 for all covered
states. Table IV.F–6 presents 2005
historical power sector emissions
compared to projected emissions with
the Transport Rule in 2012 and 2014.
TABLE IV.F–5—PROJECTED SO2 AND NOX ELECTRIC GENERATING UNIT EMISSIONS REDUCTIONS IN COVERED STATES
WITH THE TRANSPORT RULE COMPARED TO BASE CASE WITHOUT TRANSPORT RULE OR CAIR
[Million tons]
2012 base
case
emissions
SO2 ...................................................................................
Annual NOX .....................................................................
Ozone Season NOX .........................................................
2012
transport
rule emissions
8.4
2.0
0.7
3.4
1.3
0.6
2012
emissions
reductions
2014 base
case
emissions
5.0
0.7
0.1
7.2
2.0
0.7
2014
transport
rule emissions
2.6
1.3
0.6
2014
emissions
reductions
4.6
0.7
0.1
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Note: Emissions differ from emissions budgets due to banking.
TABLE IV.F–6—PROJECTED SO2 AND NOX ELECTRIC GENERATING UNIT EMISSIONS REDUCTIONS IN COVERED STATES
WITH THE TRANSPORT RULE COMPARED TO 2005 ACTUAL EMISSIONS
[Million tons]
2005 actual
emissions
SO2 ..........................................................................................................
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2012
transport
rule emissions
2012
emissions
reductions
from 2005
3.4
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transport
rule emissions
2.6
2014
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from 2005
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TABLE IV.F–6—PROJECTED SO2 AND NOX ELECTRIC GENERATING UNIT EMISSIONS REDUCTIONS IN COVERED STATES
WITH THE TRANSPORT RULE COMPARED TO 2005 ACTUAL EMISSIONS—Continued
[Million tons]
2005 actual
emissions
Annual NOX .............................................................................................
Ozone Season NOX ................................................................................
2012
transport
rule emissions
2.7
0.9
2012
emissions
reductions
from 2005
1.3
0.6
1.4
0.3
2014
transport
rule emissions
1.3
0.6
2014
emissions
reductions
from 2005
1.4
0.3
Note: Emissions differ from emissions budgets due to banking.
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G. How the Proposed Approach Is
Consistent With Judicial Opinions
Interpreting Section 110(a)(2)(D)(i)(I) of
the Clean Air Act
The methodology described
previously quantifies states’ significant
contribution and interference with
maintenance in a manner that is
consistent with the decisions of the DC
Circuit. As discussed in section III
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 v. EPA, 213 F.3d 663 (DC
Cir. 2000), and the second found
significant flaws in the CAIR, North
Carolina v. EPA, 531 F.3d. 896 (DC Cir.
2008). 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 proposed Transport 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 proposed rule relies on statespecific 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 emissions
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.
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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 proposed transport rule, EPA
uses a first step similar to that used in
the CAIR to identify the states with
relatively large contributions. However,
in contrast to the CAIR, it then uses a
state-specific analysis. Instead of
identifying a single emissions level that
could be achieved by the application of
highly cost effective controls in the
region, EPA determines, on a state-bystate basis what reductions could
effectively be achieved by sources in
that 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, emissions 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
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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
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
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‘‘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 IV.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
proposed FIPs are either part of or
constitute the state’s significant
contribution and interference with
maintenance. Thus, elimination of these
emissions will, at a minimum, make
measurable progress towards satisfying
the 110(a)(2)(D)(i)(I) prohibition on
significant contribution and interference
with maintenance.
H. Alternative Approaches Evaluated
But Not Proposed
EPA evaluated a number of alternative
approaches to defining significant
contribution and interference with
maintenance in addition to the
approach proposed in this rule.
Stakeholders suggested a variety of
ideas. EPA considered all suggested
approaches.
EPA evaluated approaches including
those based solely on air quality, based
solely on cost with a uniform cost in all
states, based on cost per air quality
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impact (e.g., $ per μg/m3), and binning
of states based on air quality impact.
Detailed descriptions of the alternative
approaches that EPA evaluated are in a
TSD in the docket titled ‘‘Alternative
Significant Contribution Approaches
Evaluated.’’
EPA is not proposing any of the
alternative approaches listed here.
However, the proposed approach
(described in section IV.D) incorporates
some elements from these approaches.
V. Proposed Emissions Control
Requirements
This section describes the proposed
emissions control requirements in
detail. The section starts with V.A
which discusses the pollutants included
in the proposal, followed by V.B which
discusses the source categories covered.
Section V.C discusses the timing of the
proposed emissions control
requirements. Section V.D describes the
proposed approach to implement the
emission reduction requirements,
starting with a description of the NOX
SIP Call and CAIR approaches to
implementing reductions and the
judicial opinions on those approaches,
then describing in detail the proposed
‘‘remedy’’ (State Budgets/Limited
Trading) for FIPs that would implement
the emissions reductions, and
explaining the structure and key
elements of the proposed Transport
Rule trading program rules for State
Budgets/Limited Trading. Section V.D
also describes two alternative remedies
on which EPA requests comment.
Section V.E presents projected costs and
emissions for each remedy option.
Section V.F discusses the transition
from the CAIR cap and trade programs
to the proposed Transport Rule
programs. Section V.G discusses
interactions of the proposed programs
with the existing Title IV and NOX SIP
Call programs.
A. Pollutants Included in This Proposal
In this action, EPA is proposing FIPs
to directly regulate upwind emissions of
SO2 and NOX because of their impact on
downwind states’ ability to attain and
maintain the PM2.5 NAAQS. EPA is also
proposing to regulate upwind emissions
of NOX because of their impact on
8-hour ozone attainment and
maintenance in downwind states. Our
rationale for regulating these precursor
pollutants is discussed in section IV.B.
In this section, we also explain the
regulatory mechanism we are proposing
to use to regulate these pollutants and
take comment on two alternative
options.
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B. Source Categories
EPA is proposing to require emissions
reductions from the power sector. This
section discusses EPA’s rationale for
proposing to control power sector
emissions, and our rationale for not
proposing to control emissions from
other source categories at this time.
1. Propose To Control Power Sector
Emissions
The proposed Transport Rule FIPs
would require EGUs with capacity
greater than 25 MWe in the covered
states to reduce emissions of SO2, NOX,
and ozone season NOX. See section
V.D.4., later, for a detailed description
of the proposed applicability
requirements.77
Electric generating units are important
sources of SO2 and NOX emissions. In
2012, considering other controls that
will be in place, EPA projects that if a
Transport Rule is not implemented,
EGUs would emit more than 70 percent
of the total man-made SO2 emissions
and about 20 percent of the total manmade NOX emissions in the group of 32
states that would be affected by this rule
(see Table III.A–1 in section III for lists
of states).78
EPA has previously conducted
extensive analyses of the cost and
emissions impacts of SO2 and NOX
reduction policies on the power sector
using the Integrated Planning Model
(IPM). Examples include EPA’s IPM
analyses of a number of multi-pollutant
bills, including the Clean Air Planning
Act (S. 843 in 108th Congress), the
Clean Power Act (S. 150 in 109th
Congress), the Clear Skies Act of 2005
(S. 131 in 109th Congress), the Clear
Skies Act of 2003 (S. 485 in 108th
Congress), and the Clear Skies
Manager’s Mark (of S. 131). EPA also
analyzed several power sector multipollutant scenarios in July 2009 at the
request of Senator Tom Carper. These
analyses are on EPA’s Web site at:
(https://www.epagov/airmarkets/
progsregs/cair/multi.html). EPA’s IPM
analysis for CAIR is another example:
(https://www.epagov/airmarkets/
progsregs/epa-ipm/cair/).
Based on these analyses, EPA believes
that there exist reasonable means for
EGUs to make substantial reductions in
emissions of SO2 and NOX. EPA also
believes that, at this time, EGUs can
77 Certain non-EGUs and smaller EGUs were
included in the CAIR NOX ozone season program
in some CAIR states. EPA proposes that such units
would not be covered by the Transport Rule
requirements; see section V.F in this preamble for
further discussion of these units.
78 Emissions estimates are based on the 2012
baseline projections described in section IV in this
preamble.
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reduce SO2 and NOX emissions more
cost-effectively than other source
categories (see section IV.D for
discussion of control costs for non-EGU
source categories). For these reasons,
EPA has decided to require reductions
in SO2 and NOX emissions from EGUs
in the FIPs in this proposed rule. EPA
requests comments on these proposed
FIPs and its proposal to require
reductions from EGUs.
2. Other Source Categories Are Not
Included
In these proposed FIPs, EPA is not
proposing to include emission reduction
requirements for sources other than
EGUs.79
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a. Why EPA Does Not Require
Reductions From Other Source
Categories To Address Transport
Requirements for PM2.5
In the proposed FIPs to address the
section 110(a)(2)(D)(i)(I) requirements
with respect to the 1997 and 2006 PM2.5
standards, EPA proposes to regulate
only emissions from EGUs. As
discussed previously in section IV.D,
EPA’s review of the costs of EGU and
non-EGU controls resulted in a
conclusion that substantial SO2 and
NOX reductions from EGUs are available
at a cost per ton that is lower than the
cost per ton of non-EGU controls. Other
analyses discussed in section IV.D
demonstrated that these EGU reductions
are sufficient to eliminate the quantity
of emissions identified by EPA as
significantly contributing to or
interfering with maintenance of the
1997 PM2.5 NAAQS in downwind areas.
This same section explains that EGU
reductions substantially address
eliminating the quantity of emissions
identified by EPA as significantly
contributing to or interfering with
maintenance of the 2006 PM2.5 NAAQS,
and this same section explains the need
for EPA to further analyze remaining
winter PM2.5 exceedances. This
conclusion does not, in any way,
address whether a FIP promulgated by
EPA or SIPs promulgated by the states
should include reductions from nonEGU sources in order to eliminate
significant contribution and interference
with maintenance for any other
NAAQS, including the 1997 ozone
NAAQS and future NAAQS for PM2.5.
79 See section IV.D.3 for discussion of non-EGUs
that were included in the CAIR NOX ozone season
trading program.
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b. Why EPA Does Not Propose To
Require Reductions From Other Source
Categories To Address Transport
Requirements for Ozone
In the FIPs for this proposed rule,
EPA is only proposing to require
reductions from EGUs to address
emissions from those source categories
that significantly contribute to or
interfere with maintenance of the 1997
ozone NAAQS. As discussed previously
in section IV.D, EPA’s review of the
costs of EGU and non-EGU controls
resulted in a conclusion that significant
NOX emissions reductions from EGU are
available at a cost per ton that is lower
than the cost per ton of non-EGU NOX
controls. The same section also explains
the need for EPA to further analyze
whether fully addressing upwind state
responsibilities to reduce NOX
emissions that contribute to downwind
nonattainment and maintenance
problems requires additional reductions
at higher cost per ton, which again
would involve analysis of potential EGU
and non-EGU reductions and costs. EPA
will be moving forward to complete its
assessment of pollution transport for the
1997 ozone NAAQS as soon as possible.
For future ozone and PM2.5 NAAQS,
EPA intends to quantify the emissions
reductions needed to satisfy the
requirements of 110(a)(2)(D)(i)(I) with
respect to those NAAQS. EPA has not
made any determinations or
assessments regarding whether
reductions from source categories other
than EGUs will be needed to achieve the
necessary reductions in each state.
C. Timing of Proposed Emissions
Reduction Requirements
EPA is proposing an initial phase of
reductions in 2012 followed by a second
phase in 2014. Sources will be required
to comply with the annual SO2 and NOX
requirements by January 1, 2012 and
January 1, 2014 for the first and second
phases, respectively. Similarly, sources
will be required to comply with the
ozone season NOX requirements by May
1, 2012, and by May 1, 2014. EPA chose
these dates to coordinate with the
NAAQS attainment deadlines and to
assure that reductions are made as
expeditiously as practicable, as
described later in this section. This
section also discusses how the
compliance deadlines address the
Court’s concern about timing.
Additionally, this section explains that
EPA will consider additional reductions
to address the NAAQS in the future.
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1. Date for Prohibiting Emissions That
Significantly Contribute or Interfere
With Maintenance of the PM2.5 NAAQS
For all areas designated as
nonattainment with respect to the 1997
PM2.5 NAAQS, the SIP deadline for
attaining that standard must be as
expeditious as practicable but no later
than April 2010, with a possible
extension to no later than April 2015.
Many areas have already come into
attainment by the April 2010 deadline
due in part to reductions achieved
under CAIR. Because the 2010 deadline
will have passed before the Transport
Rule is finalized, we decided to
coordinate the deadline for eliminating
significant contribution under this rule
with respect to the 1997 PM2.5 NAAQS
with the April 2015 deadline that
applies to areas that will need an
extension of the April 2010 deadline.
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 with a possible extension to as late
as December 2019.80
Upwind emissions reductions
achieved by the 2014 emissions year
will help areas that failed to meet the
April 2010 deadline, to meet the April
2015 deadline for the 1997 PM2.5
NAAQS. These reductions will also
help areas meet the December 2014
attainment deadline with respect to the
2006 PM2.5 NAAQS. Any areas not
meeting that deadline can request a
5-year extension to December 2019.
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 needed for compliance (see
further discussion in section IV.D).
80 Section 172(a)(2) of the Clean Air Act provides
that ‘‘the attainment date for an area designated
nonattainment with respect to a national primary
ambient air quality standard shall be the date by
which attainment can be achieved as expeditiously
as practicable, but no later than 5 years from the
date such area was designated nonattainment under
section 7407(d) of this title, except that the
Administrator may extend the attainment date to
the extent the Administrator 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 2006 24-hour PM2.5
NAAQS became effective on December 14, 2009.
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2. Date for Prohibiting Emissions That
Significantly Contribute or Interfere
With Maintenance of the 1997 Ozone
NAAQS
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
part 51). 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
corresponding to the end of the 2006,
2009, and 2012 ozone seasons. Many
areas have already attained due in part
to CAIR, federal mobile source
standards, and other local, state, and
federal measures. Those that have not
yet attained the standard have
maximum attainment dates ranging
from 2010 (these are the 2009 areas that
have been granted a 1-year extension
due to clean data in 2009) to 2018.
Areas designated ‘‘serious’’
nonattainment areas have a June 2013
maximum attainment deadline. The
proposed 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. The reductions will also
improve air quality in areas with later
deadlines.
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3. Reductions Required by 2012 To
Ensure That Significant Contribution
and Interference With Maintenance Are
Eliminated as Expeditiously as
Practicable
EPA is requiring an initial phase of
reductions by 2012. These reductions
are necessary to ensure that significant
contribution and interference with
maintenance are eliminated as
expeditiously as practicable. This will
in turn assist downwind states to
achieve attainment as expeditiously as
practicable as required by the CAA.
Because the proposed rule, if
finalized, will replace the CAIR, EPA
cannot assume that after this rule is
finalized, EGUs would continue to emit
at the reduced emissions levels
achieved by CAIR. Instead, it is the
emissions reductions requirements in
the proposed FIPs that will determine
the level of EGU emissions in the
eastern United States. For these reasons,
EPA is proposing to require an initial
phase of reductions by 2012 which
would ensure that existing and planned
SO2 and NOX controls operate as
anticipated.
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4. How Compliance Deadlines Address
the Court’s Concern About Timing
practicable and within the applicable
maximum deadlines.
As directed by the Court in North
Carolina v. EPA, 531 F.3d 896 (DC Cir.
2008), and described previously, EPA
has established the compliance
deadlines in the proposed 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 coordinated with the June
2013 maximum attainment deadline for
serious ozone nonattainment areas
(taking into account the need for
reductions by 2012 to demonstrate
attainment by that date). This deadline
is also consistent with the requirement
that states attain the NAAQS as
expeditiously as practicable.
The 2014 deadline for compliance
with the limits on annual NOX and
annual SO2 emissions is coordinated
with the April 2015 maximum
attainment deadline for 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).
This 2014 compliance deadline is also
consistent with December 2014
attainment deadline (5 years from
designation, in the absence of an
extension) for areas designated
nonattainment for the 2006 PM2.5
NAAQS. Areas unable to meet this 2014
deadline may seek a maximum 5-year
extension to 2019.
In addition, the 2012 compliance
deadline for the first-phase of annual
NOX and annual SO2 emissions
reductions will assure the reductions
are achieved as expeditiously as
practicable. EPA established the interim
2012 compliance deadline for annual
NOX and annual SO2 reductions because
a significant number of reductions can
be achieved by 2012. However, 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 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
5. EPA Will Consider Additional
Reductions in Pollution Transport To
Assist in Meeting Any Revised or New
NAAQS
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a. Ozone
As noted, in a January 19, 2010,
notice of proposed rulemaking, EPA
proposed to strengthen the NAAQS for
ozone. In that notice, EPA proposed
levels for the ozone standard to a level
within the range of 0.060 to 0.070 parts
per million. EPA also proposed in this
same notice to establish a distinct
cumulative, seasonal ‘‘secondary’’
standard, designed to protect sensitive
vegetation and ecosystems, including
forests, parks, wildlife refuges and
wilderness areas.81
EPA expects to finalize the revised
NAAQS for ozone in August 2010. After
the NAAQS are finalized, EPA will be
able to identify areas that are expected
to have difficulty attaining and
maintaining those standards and will
evaluate and analyze the impact of
upwind state emissions in those areas
with regard to those standards. EPA has
already begun the technical background
work necessary to allow it to move
quickly, once the revised ozone
standards are promulgated, with a
proposal to address upwind emissions
that significantly contribute to
nonattainment of or interfere with
maintenance of those standards.
Because that analysis will take some
time, and because EPA recognizes the
urgency of responding to the concerns
raised by the Court in North Carolina v.
EPA, EPA intends to address the
requirements of 110(a)(2)(D)(i)(I) with
respect to the revised ozone standards
in a subsequent proposal. Addressing
the 110(a)(2)(D)(i)(I) requirements for
the new NAAQS shortly after
promulgation of those NAAQS would
help clarify the requirements related to
transported emissions before downwind
state nonattainment SIPs are due. In
doing so, the transport rule would aid
downwind states in developing plans
for attaining and maintaining the new
NAAQS.
b. Fine Particles
EPA is also on a schedule to review
and, if necessary update the PM2.5
NAAQS. This review is scheduled for
completion in October 2011. EPA plans
81 This proposed cumulative, seasonal standard is
expressed as an annual index of the sum of
weighted hourly concentrations, cumulated over 12
hours per day (8 a.m. to 8 p.m.) during the
consecutive 3-month period within the O3 season
with the maximum index value, set at a level within
the range of 7 to 15 ppm-hours.
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to conduct background technical
analyses so that EPA will be prepared to
move quickly, if necessary, with a
transport rule related to any revised
PM2.5 NAAQS.
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D. Implementing Emissions Reductions
Requirements
In this rule, EPA is proposing FIPs to
eliminate the significant contribution
and interference with maintenance EPA
has identified in this action. We are
proposing one ‘‘remedy’’ option to
implement the necessary emissions
reductions and taking comment on two
other options. Before presenting these
options we briefly summarize the
approaches used in the NOX SIP Call
and CAIR.
1. Approaches Taken in NOX SIP Call
and CAIR
In the NOX SIP Call and CAIR, EPA
developed emissions trading programs
as possible remedies to 110(a)(2)(D)(i)(I)
SIP deficiencies. States covered by the
rules were given the option of joining
the trading programs and EPA
determined that, by doing so, they
would satisfy the requirements of
110(a)(2)(D)(i)(I) with respect to specific
NAAQS. The NOX SIP Call provided an
ozone-season NOX trading program and
addressed the requirements of the ozone
NAAQS only. The CAIR provided SO2,
annual NOX, and ozone-season NOX
trading programs, and addressed both
the 1997 ozone and the 1997 PM2.5
NAAQS.
NOX SIP Call approach. The NOX SIP
Call proposed a regional cap and trade
program as a way to make cost-effective
NOX reductions. Created after years of
scientific research and air quality data
analyses showed that upwind NOX
emissions can contribute significantly to
ozone nonattainment in downwind
states, the NOX Budget Trading Program
(NBP) followed several other major
efforts to reduce NOX from large,
stationary sources. These initiatives
included the Acid Rain Program, OTC
NOX Budget Program, New Source
Review, New Source Performance
Standards, application of Reasonably
Available Control Technology to
existing sources, and other state efforts.
By notice dated October 27, 1998 (63
FR 57356), EPA took final action to
require states to prohibit specified
amounts of emissions of one of the main
precursors of ground-level ozone, NOX,
in order to reduce ozone transport
across state boundaries in the eastern
half of the United States. EPA found
that sources in 23 states emit NOX in
amounts that significantly contribute to
nonattainment of the 1-hour ozone
NAAQS in downwind states. EPA set
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forth requirements for each of the
affected upwind states to submit SIP
revisions prohibiting those amounts of
NOX emissions that significantly
contribute to downwind air quality
problems. EPA established statewide
NOX emissions budgets for the affected
states. States had the flexibility to adopt
the appropriate mix of controls for their
state to meet the NOX emissions
reductions requirements of the SIP call.
In the final regulation, EPA offered to
administer a multi-state NOX Budget
Trading Program for states affected by
the NOX SIP Call. The NOX Budget
Trading Program was an ozone season
(May 1 to September 30) cap and trade
program for EGUs and large industrial
combustion sources, primarily boilers
and turbines. The program used a
regionwide cap for ozone season NOX
emissions. The cap was the sum of the
state emissions budgets established by
EPA under the NOX SIP Call regulation
to help states meet their SIP obligations.
Authorizations to emit, known as
allowances, were allocated to affected
sources based on state trading budgets.
The NOX allowance market enabled
sources to trade (buy and sell)
allowances throughout the year. Sources
could reduce NOX emissions in any
manner. Options included adding
emissions control technologies,
replacing existing controls with more
advanced technologies, optimizing
existing controls, or switching fuels. At
the end of every ozone season, each
source surrendered sufficient
allowances to cover its ozone season
NOX emissions (each allowance
represents one ton of NOX emissions).
This process is called annual
reconciliation. If a source did not have
enough allowances to cover its
emissions, EPA automatically deducted
allowances from the following year’s
allocation at a 3:1 ratio. If a source had
excess allowances because it reduced
emissions beyond required levels, it
could sell the unused allowances or
bank (save) them for use in a future
ozone season. To accurately monitor
and report emissions, sources use
continuous emission monitoring
systems (CEMS) or other approved
monitoring methods under EPA’s
stringent monitoring requirements (Title
40 of the Code of Federal Regulations
[CFR], Part 75).
The NOX SIP Call cap and trade
program was a way to make costeffective NOX reductions. Under the
NOX SIP Call, states had the flexibility
to determine the mix of controls to meet
their emissions reductions
requirements. However, the rule
provides that if the SIP controls EGUs,
then the SIP must establish a budget, or
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cap, for EGUs. The EPA recommended
that each state authorize a trading
program for NOX emissions from EGUs.
Each of the states required to submit a
NOX SIP under the NOX SIP Call chose
to adopt the cap and trade program
regulating large boilers and turbines.
Each state based its cap and trade
program on a model rule developed by
EPA. Some states essentially adopted
the full model rule as is, while other
states adopted the model rule with
changes to the sections that EPA
specifically identified as areas in which
states may have some flexibility. The
NOX SIP Call cap and trade program,
modeled closely after the OTC NOX
Budget Program, was phased in starting
in 2003 for the OTC states, with the
majority of affected states participating
as of 2004.
CAIR Approach. In May 2005, EPA
promulgated CAIR to address emissions
in 28 states and the District of Columbia
that it found contribute significantly to
nonattainment of the 1997 PM2.5 and
8-hour ozone NAAQS in downwind
states. The EPA required these upwind
states to revise their SIPs to include
control measures to reduce emissions of
SO2 and/or NOX. Reducing upwind
precursor emissions helps the
downwind PM2.5 and 8-hour ozone
nonattainment areas achieve the
NAAQS. Moreover, reducing upwind
emissions makes it possible for
attainment to be achieved in a more
equitable, cost-effective manner than if
each nonattainment area attempted to
achieve the NAAQS by implementing
local emissions reductions alone.
In CAIR, EPA offered states optional
regionwide cap and trade programs,
which were similar to the SO2 trading
program in Title IV of the CAA and the
NOX Budget Trading Program in the
NOX SIP Call. CAIR required
implementation of emissions reductions
requirements for SO2 and NOX in two
phases. The first phase of NOX
reductions started in 2009 (covering
2009–2014) and the first phase of SO2
reductions began in 2010 (covering
2010–2014); the second phase of
reductions for both NOX and SO2 would
start in 2015 (covering 2015 and
thereafter). The required emissions
reductions requirements are based on
controls that are known to be highly
cost effective for EGUs. CAIR also
included model rules for multi-state cap
and trade programs for annual SO2 and
NOX emissions for PM2.5, and seasonal
NOX emissions for ozone, that states
could choose to adopt to meet the
required emissions reductions in a
flexible and cost-effective manner. The
CAIR provided for the NOX SIP Call cap
and trade program to be replaced by the
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CAIR ozone season NOX trading
program.
The U.S. Court of Appeals granted
several petitions for review of the CAIR
and remanded the rule to EPA. Because
the Court decided to remand the rule
without vacatur, however, CAIR
remains in effect. This proposed rule
would replace the CAIR upon final
promulgation.
2. Judicial Opinions
Challenges to both the NOX SIP Call
and the CAIR were brought before the
U.S. Court of Appeals for the DC Circuit.
In Michigan v. EPA, 213 F.3d 663, the
Court largely upheld the NOX SIP Call.
The portion of this opinion most
directly related to the remedy selected
by EPA, discusses EPA’s decision to
utilize a uniform control strategy. The
Court rejected two specific challenges to
the requirement that ‘‘all covered
jurisdictions, regardless of amount of
contribution, reduce their NOX by an
amount achievable with ‘‘highly costeffective controls.’’ Id. at 679. EPA’s
approach, Petitioners first alleged, was
irrational because it did not take into
account differences in individual states’’
respective contributions to downwind
nonattainment. Both small and large
contributors were required to make
reductions achievable by the application
of highly cost effective controls. The
court rejected this challenge finding that
this result ‘‘flows ineluctably from EPA’s
decision to draw the ‘significant
contribution’ line on the basis of cost
differentials.’’ Id.
Petitioners’ second objection to the
use of uniform controls was that it failed
to take into account the fact that the
location of emissions reductions may
affect the impact of those reductions on
downwind nonattainment areas.
Petitioners argued that because
reductions closer to the nonattainment
area have a greater benefit, EPA’s use of
a highly-cost-effective standard and
region-wide emissions trading did not
guarantee that it would have secured the
rule’s health benefits at the lowest cost.
See id. The Court rejected this challenge
also, giving deference to EPA’s
judgment that non-uniform regional
approaches would not ‘‘ ‘provide either
a significant improvement in air quality
or a substantial reduction in cost.’ ’’ Id.
(quoting 63 FR 57423).
Petitioners challenging the CAIR also
raised issues related to EPA’s use of an
interstate trading program to satisfy the
requirements of section
110(a)(2)(D)(i)(I). Petitioners challenged
both the trading program itself and the
state budgets. These budgets were used
to determine the number of emission
allowances allocated to sources in each
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state or, if the state chose not to
participate in the trading programs, the
specific emission reduction
requirements for that state.
The Court concluded, in North
Carolina v. EPA, 531 F.3d 896, that EPA
had not demonstrated that the
110(a)(2)(D)(i)(I) remedy promulgated in
CAIR would effectuate the statutory
mandate of section 110(a)(2)(D)(i)(I) and
promote the goal of prohibiting
contributing sources within one state
from contributing to nonattainment in
another state. In reaching this
conclusion, the Court emphasized that
EPA had not adequately measured each
individual state’s significant
contribution. See id. at 908. (‘‘It is
unclear how EPA can assure that the
trading programs it has designed in
CAIR will achieve section
110(a)(2)(D)(i)(I)’s goals if we do not
know what each upwind state’s
‘‘significant contribution’’ is to another
state.’’)
The Court also emphasized that
section 110(a)(2)(D)(i)(I) ‘‘prohibits
sources ‘within the State’ from
‘contribut[ing] significantly to
nonattainment in * * * any other State
* * *’ ’’ Id. at 907. (quoting section
110(a)(2)(D)(i)(I) and adding emphasis).
While recognizing that it was ‘‘possible
that CAIR would achieve section
110(a)(2)(D)(i)(I)’s goals’’ it concluded
that ‘‘CAIR assures only that the entire
region’s significant contribution will be
eliminated,’’ 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.’’ Id. at
907. Furthermore, since CAIR was
designed as a ‘‘complete remedy to
section 110(a)(2)(D)(i)(I) problems’’ the
Court emphasized that ‘‘it must actually
require elimination of emissions from
sources that contribute significantly and
interfere with maintenance.’’ Id. at 908.
In doing so, however, the Court also
acknowledged that it had accepted in
Michigan v. EPA, 213 F.3d 663 (D.C. Cir.
2000) EPA’s decision to apply uniform
emissions controls and its consideration
of cost in the definition of significant
contribution. See North Carolina, 531
F.3d at 908.
In developing options to eliminate the
emissions identified as constituting all
or part of a state’s significant
contribution and interference with
maintenance, EPA has been mindful of
the direction provided by the Court. As
discussed in greater detail later, EPA
believes that each of the remedy options
presented is consistent with the Court’s
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opinions interpreting the requirements
of section 110(a)(2)(D)(i)(I).
3. Remedy Options Overview
EPA is proposing one ‘‘remedy’’
option to implement the emissions
reductions requirements and taking
comment on two alternatives. This
section provides a brief overview of the
proposed remedy and the two
alternatives. Sections V.D.4, V.D.5, and
V.D.6, later, describe the proposed
remedy and the alternatives in detail.
EPA considered a full range of remedy
options in developing this proposal.
Among other things, EPA considered
variations of direct control options,
intrastate cap and trade, interstate cap
and trade, hybrids of these approaches,
and simple state emissions caps.
Stakeholders have suggested a variety of
remedy options for EPA’s consideration.
A TSD in the docket entitled ‘‘Other
Remedy Options Evaluated’’ describes
other options that EPA evaluated.
Based on its consideration of a range
of options, EPA is proposing one
remedy option and requesting comment
on two alternatives. The proposed
remedy option, discussed later, is a
hybrid approach that combines limited
interstate trading with other
requirements. The alternative remedies
on which EPA requests comment
include an intrastate trading option and
a direct control option. The proposed
and alternative remedy options would
regulate SO2 and NOX emissions from
EGUs through FIPs in the covered states
to eliminate or address the states’’
significant contribution to
nonattainment in, or interference with
maintenance by, downwind areas with
respect to the daily and annual PM2.5
NAAQS and the 8-hour ozone NAAQS.
The remedy option EPA is proposing
would use state-specific control budgets
and allow for intrastate and limited
interstate trading of emissions
allowances allocated to EGUs. This
approach would assure environmental
results while providing some limited
flexibility to covered sources consistent
with the Court decision as described
later. The approach would also help
ease the transition for implementing
agencies and covered sources from CAIR
to the Transport Rule. Based on
consideration of a range of options, EPA
believes that the proposed option is the
best approach, for the reasons discussed
in section V.D.4.
The Agency is also presenting other
alternative remedies for comment. The
first alternative for which EPA requests
comment would use state-specific
control budgets and allow intrastate
trading of emissions allowances
allocated to EGUs, but no interstate
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trading. The second alternative for
which EPA requests comment is a direct
control program in combination with
state-specific control budgets.
EPA recognizes there could be cost
savings from an approach that uses aless
restrictiveinterstate trading option. EPA
also recognizes that unrestricted trading
programs including the NOX SIP Call
Trading Program have been very
successful in addressing regional
pollution problems.
In this action, EPA is not proposing
such an unrestricted trading program,
because EPA does not believe that such
an option could provide assurance that
each state achieves emissions
reductions within the state, as required
by the North Carolina decision. As the
D.C. Circuit emphasized in its opinion,
the statutory requirement in section
110(a)(2)(D)(i)(I) aims to prohibit
‘‘sources ‘‘within the State’’ from
contributing to nonattainment or
interfering with maintenance in ‘‘any
other State.’’ North Carolina, 531 F.3d at
908. The location of emission
reductions is relevant because it can
influence where air quality
improvements occur and whether a
particular state meets its statutory
obligations. See North Carolina, 531
F.3d at 907.
In addition to considering
unrestricted trading, EPA also
considered whether there were other
ways that a trading program could be
structured to address the Court’s
concerns. In particular, EPA reviewed a
methodology that had been investigated
during the development of the NOX SIP
Call regulation that used trading ratios
(‘‘Development and Evaluation of a
Targeted Emission Reduction Scenario
for NOX Point Sources in the Eastern
United States: An Application of the
Regional Economic Model for Air
Quality (REMAQ)’’, Prepared by Stratus
Consulting inc. November 24, 1999) (at
https://www.epagov/airtransport). This
approach would allow interstate
trading, but use trading ratios to take
into account differences in the
cumulative downwind impact of
emissions from different states. Trading
ratios would be developed for each pair
of states using air quality modeling such
that, given the meteorological
assumptions underlying the air quality
modeling, the ratios would represent the
ratio of the benefit to downwind air
quality within a region from controlling
emissions in different upwind areas. For
instance, in its simplest form, if
emission reductions from State A were
twice as effective at reducing
cumulative downwind air quality
impact on a set of downwind receptors
as emission reductions from State B, the
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trading ratio between States A and B
would be 2 to 1.82 In other words, if the
States chose to trade, State A would
have to purchase 2 allocations from
State B to cover 1 ton of State A’s
emissions, since State A’s emissions
have twice the impact on downwind air
quality. Such an approach offers the
very valuable potential to address the
transport problem in an effective (and
potentially less costly) manner, as it
incentivizes reductions from the places
where they have the greatest value in
reducing downwind air quality
problems. While it offers such
opportunities, there are challenges in
developing such a system that is
consistent with the requirement under
section 110(a)(2)(D) that emission
reductions occur in particular
geographic locations. The trading ratio
approach would be designed to assure a
cumulative downwind air quality result,
not to assure specific upwind
reductions. Although it would reduce
the incentive for sources from upwind
states with larger cumulative impacts to
comply by purchasing allowances (since
they would need to purchase a greater
number of allowances per ton emitted
than sources in states with less of an
impact), as currently contemplated it
would not be possible under this
approach 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 requests comment on
whether a ratios trading program could
be designed to provide such a legal
assurance. We also seek comment on
whether such an assurance would be
needed if, for example, in practice
modeling results predicted with
confidence that sufficient state-by-state
reductions would be achieved under
such an approach.
In the SIP Call, EPA did not
ultimately propose this methodology for
several reasons. First, the Stratus
Consulting study (‘‘Development and
Evaluation of a Targeted Emission
Reduction Scenario for NOX Point
82 Note that the report evaluating this alternative
was a theoretical economic and air quality analysis
of the concept. It did not explore how trading ratios
would be incorporated into a workable trading
program. It did however indicates that the
‘‘approach also provides for the possibility that the
emission weights developed by this analysis could
be incorporated into an emission trading program
in which emission weights act like exchange rates
between different subregions and species. However
this adds a significant increase in the complexity
of the market and in practical terms is worth
considering only when the potential cost savings
are large enough to offset the additional complexity
in market structure.’’ P. 1–7, Stratus Consulting Inc.
November 24, 1999.
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Sources in the Eastern United States: An
Application of the Regional Economic
Model for Air Quality (REMAQ)’’)
estimated that the most significant cost
savings occurred from moving from a
uniform direct control approach to a
conventional cap-and-trade approach
(the study suggested that this would
lead to cost savings of approximately 25
percent). Adding trading ratios added
significant complexity while only very
slightly lowering costs (1 percent to 5
percent compared to conventional cap
and trade, where the cost savings
decreased as the problem being
addressed became more widespread
(e.g. cost savings for the more stringent
1997 8 hour ozone NAAQS standard
would be less than cost savings for the
less stringent early 1 hour standard))
(Stratus, page s–2). However, because
the transport rule is a larger program
covering multiple pollutants with a
different set of non-attainment areas and
a broader geographic scope, there is the
potential for greater cost savings.
Second, the trading ratios are dependent
upon the meteorological assumptions
used to develop them; to the extent that
future year meteorology or costs turn
out to be different, the trading ratios
could in fact lead to less than predicted
downwind air quality benefits. Notably
in reality, the ratios would have to
consider that the upwind states that
impact a downwind receptor vary from
receptor to receptor; conversely each
upwind state contributes to different
sets of downwind receptors. It would be
very challenging to develop trading
ratios that account for this myriad of
different relationships. EPA believes
these concerns are also valid in the
context of this Transport Rule.
In addition, in considering this
approach in the original SIP Call, it took
close to a year to perform the underlying
analysis to develop ratios for 1 pollutant
(NOX) and one downwind air quality
problem (ozone). In this context, there
are 3 pollutants (annual NOX, annual
SO2 and ozone season NOX) and two
downwind air quality problems (ozone
and PM2.5) to consider.
EPA requests comment on the trading
ratios approach, including whether: The
trading ratio approach described above
would be consistent with the Court
opinion in North Carolina v. EPA and
satisfy the section 110(a)(2)(D)
requirement that reductions occur
‘‘within the state’’; there are ways the
approach could be modified to be
consistent with the Court opinion and
the statutory requirement; there are
ways that such an approach could
administratively be put in place by 2012
and be modified and adopted if further
reductions are required to address
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future NAAQS; and on whether there
are ways that such a system could be
designed to be transparent and
relatively simple for sources to
understand and comply with.
Analysis from the SIP Call suggests
that the trading ratios approach might
have the potential to slightly reduce
costs. However, the approach, as
envisioned, appears to be in tension
with EPA’s mandate under section
110(a)(2)(D)(i)(I) to assure that
significant contribution is fully
addressed in each upwind state. While
such an approach would ensure
reductions on a region-wide basis, EPA
has not been able to identify a way that
the trading ratio approach could be
modified to assure a specific set of
downwind emissions reductions from
all states. Under such an approach,
there is the potential that some upwind
states might make reductions that are
larger than their significant
contribution, while other states might
make reductions that are less than their
significant contribution. Because the
state budgets have been designed to
achieve all reductions available at a
given cost, trading ratios other than one
to one, although providing equivalent
improvements in downwind air quality
would lead to emissions reductions that
were inconsistent with the initial
budgets.83
Because EPA recognizes the potential
cost savings and potential
improvements in program effectiveness
associated with less restricted trading
options, EPA is also requesting
comment on the appropriateness of the
assurance provisions that have been
proposed, including whether they are
adequate to assure that significant
contribution and interference with
maintenance are addressed in each
state, whether they are overly
restrictive, and whether there are less
restrictive options that would provide
adequate assurance that the statutory
mandate is satisfied while providing
more flexibility. Alternative approaches
could potentially include: Using the
basic methodology proposed with a
higher or lower variability limitation or
using an alternative to the approach to
assure that state emissions budgets are
met (e.g., trading ratios designed to
assure that certain upwind emission
reduction targets are met, rather than
trading ratios designed to assure that
downwind air quality goals are met).
With regards to the variability limits
that EPA has proposed, EPA takes
83 EPA, however, has proposed variability limits
to these budgets, and it is possible a ratios approach
may imply emissions would fall within the
variability limits if the ratios ultimately turned out
to be close to one-to-one.
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comment on alternative approaches to
calculating those limits, such as
considering confidence intervals
different than a 95 percent confidence
interval such as a 99 percent confidence
interval (For more information see TSD,
‘‘Power Sector Variability’’.)
EPA specifically requests that any
commenter suggesting a less restrictive
approach address how the commenter’s
preferred approach would satisfy the
statutory mandate in section
110(a)(2)(D)(i)(I) of the Clean Air Act
and be consistent with the decision of
the DC Circuit in North Carolina v. EPA,
531 F.3d 8906 (2008) (e.g., if
commenters suggest a higher variability
limitation, what would be the rationale
for allowing that amount of variability;
if commenters suggest an alternative
framework, how would that framework
assure that reductions occur ‘‘within the
state’’) as well as how EPA could
develop the approach in a way that
would be workable for sources, states,
and EPA in time to achieve emission
reductions in 2012 (e.g., would an
approach with trading ratios impact
transaction costs or be overly complex
for less sophisticated trading entities,
can the analysis needed to develop the
approach be completed in a timely
way).
As discussed in section IV.E, EPA is
proposing new state budgets developed
on a different basis from the CAIR
budgets. The intrastate and interstate
trading remedy options would use new
allowance allocations, also developed
on a different basis from the CAIR FIP
allowance allocations. See section IV for
the proposed state budget approach and
section V.D.4 for proposed allowance
allocation approaches.
As discussed in section IV.F, EPA
believes that inherent variability in
power system operations affects each
state’s baseline emissions and thus also
affects a state’s emissions after
elimination of all significant
contribution and interference with
maintenance. Thus, emissions may vary
somewhat after implementation of the
remedies under consideration. This
includes the proposed remedy option
(State Budgets/Limited Trading), the
intrastate trading alternative, and the
direct control alternative. Sections
V.D.4, V.D.5, and V.D.6 describe
variability approaches for the proposed
remedy and each of the alternative
remedies.
EPA also considered only establishing
state emissions caps. Such an approach
would define what must be done to
eliminate all (or in some cases part) of
each state’s significant contribution and
interference with maintenance, but it
would not implement specific
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requirements to eliminate those
emissions. As described in section III.C
in this preamble, EPA decided to
implement the emission reduction
requirements through FIPs. To do so,
EPA recognized that it needed to do
more than establish simple state
emissions caps. For this reason, EPA
rejected the simple state emission cap
option.
As with any FIP that EPA issues, a
covered state may submit, for review
and approval, a state implementation
plan (SIP) that replaces the Federal
requirements with state requirements
that would achieve the required
reductions. A state’s SIP submission to
replace the Transport Rule FIP might
propose to use any remedy of the state’s
choosing that actually eliminates the
emissions that significantly contribute
to nonattainment or interfere with
maintenance downwind. Section VII in
this preamble further discusses SIP
submissions.
4. State Budgets/Limited Trading
Proposed Remedy
In this action, EPA is proposing FIPs
that would establish state-specific
emission control requirements using
state budgets starting in 2012 in 32
states.84 This remedy option would
allow unlimited intrastate trading and
limited interstate trading to account for
variability in the electricity sector, but
also includes assurance provisions to
ensure that the necessary emissions
reductions occur within each covered
state. The assurance provisions,
described later in this section, would
restrict EGU emissions within each state
to the state’s budget with the variability
limit and would ensure that every state
is making reductions to eliminate the
portion of significant contribution and
interference with maintenance that EPA
has identified in today’s action. EPA is
proposing to impose these assurance
provisions starting in 2014. Statespecific emissions budgets with
variability limits would be established
as described in section IV in this
preamble. These budgets without the
variability limits would be used to
determine the number of emissions
allowances allocated to sources in each
state: An EGU source would be required
to hold one allowance for every ton of
84 The 32 states are: Alabama, Arkansas,
Connecticut, District of Columbia, Delaware,
Florida, Georgia, Illinois, Indiana, Iowa, Kansas,
Kentucky, Louisiana, Maryland, Massachusetts,
Michigan, Minnesota, Mississippi, Missouri,
Nebraska, New Jersey, New York, North Carolina,
Ohio, Oklahoma, Pennsylvania, South Carolina,
Tennessee, Texas, Virginia, West Virginia, and
Wisconsin. As noted in section III, for purposes of
this rulemaking, when we discuss ‘‘states’’ we are
also including the District of Columbia.
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SO2 and/or NOX emitted during the
compliance period. Banking of
allowances for use in future years would
be allowed under the proposed remedy.
For the 2012–2013 transition period,
EPA is proposing the State Budgets/
Limited Trading remedy without
assurance provisions. EPA is taking
comment on all aspects of, as well as
alternatives to, this option that address
the requirements of 110(a)(2)(D)(i)(I) for
prohibiting emissions that significantly
contribute to or interfere with
maintenance of the NAAQS in
downwind states.
a. Description of the Proposal
The proposed FIPs would address the
elimination of significant contribution
and interference with maintenance by
2014. A first phase of reductions would
be required by 2012 to assure that
significant contribution and interference
with maintenance are eliminated as
expeditiously as practicable.
To directly eliminate the portion of
each state’s significant contribution and
interference with maintenance that EPA
has identified in this action, the
proposed remedy utilizes the state
budgets with variability limits described
in section IV. The budgets without
variability limits are used to determine
the number of allowances issued to
sources in each state. Each affected
source must hold, and surrender to EPA,
allowances equal to its emissions during
the compliance period. In addition,
assurance provisions under the
proposed remedy cap each state’s EGU
emissions at a state-specific budget with
a variability limit to ensure that every
state actually reduces, within the state,
all emissions necessary to eliminate the
portion of its significant contribution
and interference with maintenance that
EPA has identified in today’s proposal.
For the 2012–2013 transition period,
EPA is taking comment on whether the
assurance provisions used to limit
interstate trading are needed, since the
state-specific budgets are based on
known air pollution controls and thus a
high level of certainty exists about
where reductions will occur. As
described later, the proposed FIPs
include penalty provisions that are
adequate to ensure that the budget
including a variability limit will not be
exceeded so that each state eliminates
the portion of its significant
contribution and interference with
maintenance that EPA has identified in
today’s proposed action.
The proposed remedy establishes four
interstate trading programs starting in
2012: Two for annual SO2, one for
annual NOX, and one for ozone season
NOX. One SO2 trading program is for
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sources in states (referred to as the SO2
group 1) that need to make more
aggressive reductions to eliminate the
portion of their significant contribution
that EPA has identified in today’s
proposed action, while the second is for
sources in states (referred to as SO2
group 2) with less stringent reduction
requirements. States within SO2 group 1
can trade SO2 allowances only with
other states in that group. Similarly,
states within SO2 group 2 can trade SO2
allowances only with other states in that
group. Note that all states covered for
annual NOX may trade with each other,
even if they are in different groups for
SO2. Table IV.D.5 in section IV,
previously, summarizes the respective
covered states for the SO2 group 1, SO2
group 2, and annual NOX trading
programs; Table IV.E–2 lists the states
for the ozone season NOX program.
New emissions allowances based on
the new state budgets without
variability would be allocated to
individual sources, as described later.
Four sets of allowances would be
allocated, one for each of the four
trading programs (SO2 group 1, SO2
group 2, NOX annual, and NOX ozone
season). This allocation methodology
neither uses heat input adjusted by fuel
factors, nor relies on the allocation of
allowances under Title IV of the Act.
Sources would be allowed to trade
allowances. However, the assurance
provisions would limit total emissions
from each state, restricting the
variability of emissions from any
particular state to the variability
associated with its baseline emissions
prior to the elimination of all or part of
the state’s significant contribution or
interference with maintenance.
Allowance banking is permitted.
Banking (or saving) allowances for
future use in any given year allows
sources flexibility in compliance
planning. Banking lowers costs and
helps reduce market volatility. Banking
also acts as an incentive to reduce
emissions early and accumulate
allowances that can be used for
compliance in future periods. Because
the early reductions encouraged by the
ability to bank allowances would result
in the reduction of emissions below
allowable levels earlier than required,
the environmental and human health
benefits of the reductions would accrue
sooner.
b. How the Proposal Would Be
Implemented
(1) Applicability
The requirements in the proposed
FIPs would apply to large EGUs.
Specifically, a covered source would be
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any stationary, fossil-fuel-fired boiler or
stationary, fossil-fuel-fired combustion
turbine serving at any time, since the
later of November 15, 1990 or the startup of the unit’s combustion device, a
generator with nameplate capacity of
more than 25 MWe producing electricity
for sale. The term ‘‘fossil fuel’’ is defined
as including natural gas, petroleum,
coal, or any form of fuel derived from
such material. This is the same
definition that was used in CAIR and
would include all material derived from
natural gas, petroleum, or coal,
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 used as fuel, these
materials in the consumer products
would qualify as fossil fuel.
Certain cogeneration units or solid
waste incinerators otherwise covered by
this general category of covered units
would be exempt from the FIP
requirements. These proposed
applicability requirements are
essentially the same as those in the
CAIR model trading rules and CAIR
FIPs (reflecting the revised cogeneration
unit definition promulgated in October
2007 (72 FR 59195; October 19, 2007)),
with some technical corrections to the
exemptions.
Cogeneration unit exemption. In order
to meet the proposed definition of
‘‘cogeneration unit,’’ 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 order to
qualify as a cogeneration unit, a unit
also must meet, on an annual basis,
specified efficiency and operating
standards, e.g., the 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, useful thermal energy must be no
less than a certain percentage of total
energy output, and useful power must
be no less than a certain percentage of
total energy input. Total energy input
includes all energy input except from
biomass.
These proposed elements of the
‘‘cogeneration unit’’ definition are very
similar to the definition used in CAIR.
However, there are two technical
differences. First, under the definition
used in CAIR to qualify as a
‘‘cogeneration unit,’’ a unit had to meet
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the efficiency and operating standards
every year starting with the first 12months during which the unit produced
electricity. In contrast, under the
definition proposed here, a unit can
qualify as a ‘‘cogeneration unit’’ if it
meets the efficiency and operating
standards every year starting the later of
November 15, 1990 or the date on which
the unit first produces electricity. EPA
believes this definition of ‘‘cogeneration
unit’’ is preferable because it may be
problematic to obtain sufficiently
detailed information about unit
efficiency and operations for some units
(e.g., old units that may have started
producing electricity many years ago).
This approach is also more consistent
with the approach taken in the general
applicability criteria. EPA requests
comment on whether it may also be
problematic to obtain sufficiently
detailed information about unit
efficiency and operation back to
November 15, 1990 and whether the
efficiency and operating standards
should be limited to even more recent
years by requiring that the standards be
met every year starting the later of a date
(e.g., January 1) of a more recent year
(e.g., 2000, 2005, or 2009) or the date on
which the unit first produces electricity.
Second, in CAIR, each unit had to meet
individually the efficiency standard
(i.e., the requirement that useful thermal
or electrical output be at least a
specified percentage of energy input). In
contrast, under the ‘‘cogeneration unit’’
definition proposed here, if the
cogeneration system of which a toppingcycle unit (where power is produced
first and then useful thermal energy is
produced using the resulting waste
energy) is a part meets the efficiency
standard on a system-wide basis, then
the unit is also deemed to meet that
efficiency standard. EPA believes this
definition is preferable because it
addresses cases where one unit in a
cogeneration system is operated at a
lower efficiency (e.g., as a ‘‘swing’’ unit
whose use varies with demand) to allow
the rest of the units in the cogeneration
system to operate with higher efficiency.
EPA requests comment on whether this
approach should also be applied to
bottoming-cycle units (where useful
thermal energy is produced first and
then useful power is produced using the
resulting waste energy).
As discussed previously, the
operating and efficiency standards in
the ‘‘cogeneration’’ definition must be
met every year. However, EPA is
concerned whether these annual
standards should be applied to a
calendar year when the unit involved
did not operate at all. For such a year,
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the unit would be unable to meet the
operating and efficiency standards but
also would not have any emissions. EPA
therefore requests comment on whether
it should exclude, from the requirement
to meet the operating and efficiency
standards, calendar years (if any) during
which a unit does not operate at all.
If a unit meets the definition of
cogeneration unit (including the
efficiency and operating standards),
then it may qualify for the proposed
cogeneration unit exemption depending
on whether it meets additional criteria
concerning the amount of electricity
sales from the unit. In order to qualify
for the exemption, a cogeneration unit
would need to supply in any calendar
year—starting the later of November 15,
1990 or the start-up of the unit’s
combustion chamber—no more than
one-third of its potential electric output
capacity or 219,000 MWh, whichever is
greater, to any utility power distribution
system for sale. EPA requests comment
on whether it may be problematic to
obtain sufficiently detailed information
about the disposition of a unit’s
generation (e.g., how much was used on
site or by an industrial host and how
much was supplied to a utility
distribution system for sale) back to
November 15, 1990 and whether the
electricity sales limit should be
restricted to more recent years by
requiring that the limit be met every
year starting the later of a date (e.g.,
January 1) of a more recent year (e.g.,
2000, 2005, or 2009) or the start-up of
a unit’s combustion chamber.
Solid waste incineration unit
exemption. The proposed FIPs also
include an exemption for solid waste
incineration units commencing
operation before January 1, 1985, for
which the average annual fuel
consumption of non-fossil fuels during
1985–1987 exceeded 80 percent and,
during any three consecutive calendar
years after 1990, the average annual fuel
consumption of non-fossil fuels exceeds
80 percent, on a Btu basis. With regard
to a solid waste incineration unit
commencing operation on or after
January 1, 1985, EPA proposes that the
unit would be exempt if its average
annual fuel consumption of non-fossil
fuel for the first 3 calendar years of
operation and for any 3 consecutive
calendar years, thereafter, does not
exceed 80 percent. This is the same as
the solid waste incineration unit
exemption used in CAIR. EPA requests
comment on whether it may 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
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should be limited to more recent years
by requiring that the standard be met
every year starting the later of a date
(e.g., January 1) of a more recent year
(e.g., 2000, 2005, or 2009) or the date on
which the unit first produces electricity.
Further, analogous to the approach
proposed for the cogeneration unit
exemption, the proposed solid waste
incineration unit exemption would
apply to units that qualify as solid waste
incineration units every year starting the
later of November 15, 1990 or the date
the unit first produces electricity. EPA
requests comment on whether it may be
problematic to obtain sufficiently
detailed information about whether a
unit qualified as a solid waste
incineration unit back to November 15,
1990 and whether the qualification
requirement should be restricted to
more recent years by imposing the
qualification requirement every year
starting the later of a date (e.g., January
1) of a more recent year (e.g., 2000,
2005, or 2009) or the date of unit first
produces electricity.
EPA also proposes to make explicit in
the FIPs an interpretation that the
Agency adopted in applying CAIR,
namely that—solely for purposes of
applying the fossil-fuel use limitation in
the solid waste incineration unit
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, this means
that consumer products made from
natural gas, petroleum, or coal are not
fossil fuel, for purposes of determining
qualification under the limitation on
fossil-fuel use, 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).
Opt-in units. EPA proposes to
include, in the trading programs under
the proposed FIP, provisions allowing
non-electric generating (non-covered)
units to opt into one or more of the
proposed trading programs. EPA is
proposing opt-in provisions since they
could encourage emission reductions by
sources that could make lower cost
emissions reductions than electric
generating units. These lower cost
reductions could replace higher cost
reductions that would otherwise be
required by some electric generating
units and could reduce overall program
costs.
Specifically, the proposed opt-in
provisions would allow a non-covered
unit to enter a proposed trading program
voluntarily and obtain an allocation of
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allowances reflecting the unit’s
emissions before opting in. Once in the
program, the unit could make emissions
reductions at a lower cost than other
units in the program and then sell, to
covered sources for use in compliance,
allocated allowances that are in excess
of the unit’s reduced emissions. The
allowances created for and allocated to
the opt-in unit would be in addition to
the allowances issued from the state
budget and would be usable in
compliance by any covered unit (or optin unit) just like the allowances
allocated from the state budget to
covered sources. Replacing higher cost
reductions by covered units by lower
cost reductions by opt-in units could
reduce the overall cost of controlling
emissions. EPA requests comment on
the benefits and concerns of including
opt-in provisions.
The proposed opt-in provisions
would establish the following
procedures, which are similar to those
set forth in the CAIR FIPs. A unit would
be eligible to opt into one of the
proposed trading programs if the unit:
(1) Is an operating boiler, combustion
turbine, or other stationary combustion
device; (2) is in a facility that is located
in a state subject to that proposed
trading program; (3) vents all its
emissions through a stack or duct; and
(4) would be able to meet the
monitoring, reporting, and
recordkeeping requirements for covered
units under the proposed trading
program. The owners and operators,
through a designated representative, of
a source with a unit seeking to opt in
would submit to EPA an opt-in
application, which must include an
emissions monitoring plan for the unit.
If EPA approved the monitoring plan,
the unit would operate, monitor, and
report emissions in accordance with the
monitoring plan and monitoring and
reporting requirements under Part 75,
for at least one or for up to 3 full
calendar years (or full ozone seasons, in
the case of an opt-in unit in the
proposed NOX ozone season trading
program). The unit’s monitored heat
input and emissions rate for that period
would be the baseline heat input and
baseline emissions rate used in
calculating any future opt-in allowance
allocations.
After the monitoring period, EPA
would review the opt-in application and
either approve the application
(including an allowance allocation for
the first year of approved opt-in status),
effective January 1 (May 1 for the NOX
ozone season program) of the year of the
approval, or disapprove the application.
By December 1 (September 1 for the
NOX ozone season program) of the first
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year and each subsequent year, EPA
would calculate and record the opt-in
unit’s allowance allocation for the year.
The allowance allocation for the year
involved would be the product of: The
lesser of the baseline heat input and the
opt-in unit’s actual heat input during
the control period in the immediately
preceding year; and the lesser of the
baseline emissions rate multiplied by 70
percent and the most stringent state or
federal emissions limitation applicable
to the unit (or emissions levels resulting
from the imposition of Clean Air Act
requirements) any time during the
control period in the year involved.
After the opt-in unit was in the
program for at least four years, the
owners and operators could request to
withdraw the opt-in unit at the end of
a control period if the unit met the
requirement to hold allowances
covering emissions for that control
period and if any allowances already
allocated for a subsequent control
period were surrendered. However, the
owners and operators could not submit
a new opt-in application for the
withdrawn unit until at least 4 years
after the last control period before the
withdrawal. An opt-in unit that had a
change in regulatory status during a
control period and would then meet the
general applicability requirements for
covered units would immediately lose
its status as an opt-in unit. Having lost
its opt-in unit status, the unit would
have to surrender to EPA the allocated
opt-in allowances attributable to the
portion of any control period during
which the unit no longer qualified as an
opt-in unit.
In addition to a general request for
comment on all aspects of this opt-in
requirement, EPA requests comment on
three specific aspects of the proposed
opt-in provisions. First, EPA requests
commenters to explain how much
interest they believe owners and
operators of noncovered sources would
have in using these proposed provisions
to opt into one or more of the proposed
trading programs and what types of
sources would be most likely to opt in.
Commenters on this aspect of the
proposed provisions should consider
what effect (if any) future emission
reduction requirements under
upcoming, new regulations (e.g.,
regulations concerning maximum
available control technology (MACT)
standards for sources such as industrial
boilers and cement kilns, best available
retrofit technology (BART) requirements
for certain stationary source categories,
and reasonably available control
technology (RACT)) might have on the
pool of sources that might be interested
in opting into the program. EPA notes
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that, in the Acid Rain Program, opt-in
provisions were established in section
410 of the Act, were implemented in the
Acid Rain Program regulations starting
in 1995, and, to date, have been used by
4 facilities (plus 2 more facilities that
temporarily opted in to obtain
allowances for use in the CAIR SO2
trading program). In the NOX Budget
Trading Program, EPA promulgated optin provisions that states could include
in their SIPs and that were used by
3 facilities.
Second, EPA requests comment on
whether it is necessary to take steps to
identify in this application process
whether emissions reductions identified
by these facilities are reductions units
would not have made for other reasons
unrelated to the opt in. Comments on
this issue would be especially useful if
they discussed how the proposed opt-in
provisions could be revised in order to
ensure that opt-in units would not be
credited for emissions reductions that
the units would make even if they did
not opt in. For example, a unit that, for
business or other reasons, was already
planning to take actions that would
have the effect of reducing emissions
(e.g., fuel switching) may be able to opt
in under this proposed approach and
obtain allowance allocations that could
be sold to covered units. In that case,
emissions reductions that would have
occurred anyway would be offset by the
allocation of new, opt-in allowances
that would be in addition to the state
budget. The net result, in that case,
would be an increase in total
emissions—considering the emissions of
both the covered units and the opt-in
unit—over what total emissions would
have been if the unit had not opted in.
EPA requests comment on whether, in
that circumstance the total emissions
reduction still may be sufficient to
satisfy the interstate transport issue if
such reductions were not anticipated in
state budgets. In other words, even if
emissions reductions would have
happened in the absence of the program,
they may still be reductions that
alleviate attainment or maintenance
issues in downwind states. Third, EPA
requests comment on whether the
baseline emission rate used to
determine the allocations for each optin unit should be multiplied by 70
percent before EPA compares that rate
to the unit’s most stringent applicable
emissions limitation in order to
determine which is lower. The lower
emission rate would then be used in
calculating the opt-in unit’s allocation.
EPA also requests comment on whether
the allocation for an opt-in unit during
Phase II of the proposed SO2 Group 1
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trading program should be reduced by
45 percent, reflecting the average
percent reduction in state SO2 Group 1
budgets from Phase I to Phase II. The
70 percent reduction of the baseline
emission rate for all opt-in units, and
the further 45 percent reduction in
Phase II allocations for SO2 Group 1 optin units, would be meant to ensure that
opt-in facilities install controls in a
similar manner as covered units;
however, all things equal, this may
serve to lower the number of facilities
that would opt into the program. EPA
therefore specifically solicits comment
on whether the proposed 70 percent
reduction (or some other percentage
reduction or no reduction) should
applied to the baseline emission rate for
all opt-in units and on whether any
additional percentage reduction or
45 percent or some other additional
percentage reduction should be applied
to SO2 Group 1 opt-in units on Phase II
in order to strike a reasonable balance
between achieving additional
reductions per opt-in facility and having
more facilities opt in.
Sources equal to or less than 25 MWe
and Non-EGUs. Certain smaller EGUs
and non-EGU sources that were
included in the NOX Budget Trading
Program were brought into the CAIR
NOX ozone season trading program. For
treatment of such sources in the
proposed FIPs, see section V.F in this
preamble.
In the Northeast, a large number of
EGUs serving generators with a
nameplate capacity equal to or less than
25 MWe contribute NOX emissions to
ozone problems on high electric
demand days. There is regional interest
in lowering the 25 MWe applicability
threshold in the ozone season to deal
with this issue and in potentially
requiring these units to operate with
greater controls than a trading program
would necessitate. EPA requests
comment on lowering the greater-than25 MWe applicability threshold for
EGUs during the ozone season, and
whether a trading program offers the
right approach for addressing NOX
emissions from these smaller EGUs.
(2) Allocation of Emissions Allowances
EPA proposes to distribute, to sources
in each state, a number of emissions
allowances equal to the SO2, annual
NOX, and ozone-season emissions
budgets for that state identified in
section IV.E (the state budgets listed in
IV.E are the budgets without accounting
for variability). As discussed later, EPA
proposes to set aside 3 percent of each
state’s emissions budgets for new units.
Tables IV.E.–1 and IV.E.–2 in section
IV.E, referenced previously, show the
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permanent SO2, NOX, and ozone season
NOX budgets for each covered state
(without accounting for variability).
EPA would distribute four discrete
types of emissions allowances for four
separate cap and trade programs: SO2
group 1 allowances, SO2 group 2
allowances, NOX annual allowances,
and NOX ozone season allowances.
In the SO2 group 1 and SO2 group 2
programs, each SO2 allowance would
authorize the emission of one ton of SO2
annually. In the NOX annual program,
each NOX annual allowance would
authorize the emission of one ton of
NOX annually. In the NOX ozone season
program, each NOX ozone season
allowance would authorize the emission
of one ton of NOX during the regulatory
ozone season (May through September
for this proposed rule). Note that, as
explained in section IV.E, EPA is taking
comment on extending the ozone season
for this rule.
In each of the four trading programs,
a covered source would be required to
hold sufficient allowances to cover the
emissions from all covered units at the
source during the control period. EPA
proposes to assess compliance with
these allowance-holding requirements at
the source (i.e., facility) level.
This section explains how EPA
proposes to allocate to two sets of units
in a state, existing units and new units.
This section also describes the new unit
set asides in each state, allocations to
units that are not operating, and the
recording of allowance allocations in
facility accounts.
EPA proposes to base allocations to
existing units on projected emissions
from these units after elimination of
some or all significant contribution and
interference with maintenance (i.e.,
projected emissions after
implementation of the proposed FIPs),
and after deductions for the new unit set
asides. Section IV.E describes how EPA
developed the overall state budgets.
EPA requests comment on all aspects
of the allocation method, such as the
overall state budgets, the need to have
existing unit and new unit allowance
allocations, the proposed allocation
methodology for existing units, and the
proposed allocation methodology for
new units. EPA believes the proposed
approach is consistent at the state
budget and unit level with the Court’s
direction and also addresses the new
unit issue. The proposed methodology
for allocating allowances does not
consider heat input or fuel adjustment
factors. Note that in light of the Court
decision, EPA also is not proposing any
allocation methodologies that rely on
Title IV existing allowances.
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EPA requests comment on whether
there are alternative allocation methods
EPA should consider that are consistent
with the Court decision. EPA asks that
commenters present any such
approaches in detail to enable thorough
evaluation and that they provide a legal
analysis demonstrating how the
approach is consistent with the Court’s
opinions and the statutory mandate of
section 110(a)(2)(D).
Allocations to existing units. Existing
units are units, as described in the
Applicability section, previously (see
4.b), that commenced commercial
operation, or are planned 85 to
commence commercial operation, prior
to January 1, 2012. EPA proposes 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. EPA proposes to use this same
method to allocate allowances for each
of the four trading programs (SO2 group
1, SO2 group 2, NOX annual, and NOX
ozone season). This proposed allocation
method is different from the allocation
method used in the CAIR.
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. This approach is also different
from the allocation method in CAIR.
Further details on the proposed
allocation method for existing units can
be found in the ‘‘State Budgets, Unit
Allocations, and Unit Emissions Rates’’
TSD in the docket for this rule.
The proposed FIPs are designed to
remove emissions from each upwind
state that significantly contributes to
nonattainment or interferes with
maintenance downwind. The allocation
method is consistent with the proposed
approach for determining each upwind
state’s significant contribution and
interference with maintenance
(described in section IV) because the
allocations would be based on the
projected remaining emissions from
each covered source in each upwind
state after removal of the state’s
significant contribution and interference
with maintenance.
EPA proposes to allocate to existing
units one time, before the Transport
85 Planned units, as identified in the EGU
inventory and included in IPM modeling
projections, comprise units that had broken ground
or secured financing and were expected to be online
by the end of 2011.
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Rule cap and trade programs commence
(see discussion of schedule, later). The
allocations generally would be
permanent (with the exception of nonoperating units, discussed later) as base
amounts and would not be updated.
(Note that any unused new source set
aside allowances would be distributed
proportionally to existing units in
addition to the base amount.) By not
updating the allocations, EPA can
allocate for several years at once, which
supports the development of allowance
trading markets.
The proposed unit-level allocations
for existing EGUs for Phases I and II are
set forth in the ‘‘State Budgets, Unit
Allocations, and Unit Emissions Rates’’
TSD in the docket for this rule, but EPA
proposes to include them in the final
rule in an Appendix A to each set of
trading program regulations (i.e., the
SO2 group 1, SO2 group 2, NOX annual,
and NOX ozone season trading
programs). Because the TSD shows the
proposed allocations, Appendices A in
the proposed trading program
regulations do not repeat the allocations
and are simply reserved. The only
circumstances under which allocations
would not be permanent as base
amounts would be if the unit in the
Appendix A table turned out not to be
a covered unit, or turned out not to be
required to hold allowances to cover
emissions, as of the first day of the
control period in 2012,86 or if the unit
stops operating for three consecutive
years.
Allocations to new units. EPA
proposes to allocate emissions
allowances to new units from new unit
set-asides in each state. EPA proposes,
for each of the four trading programs, to
define a new unit as: Any covered EGU
not listed in the table in Appendix A of
the trading rule applicable to that
program; any unit listed in Appendix A
whose allocation is subject to the
requirement that the Administrator not
record the allocation or that the
Administrator deduct the amount of the
allocation (see previous discussion in
footnote), or any unit listed in Appendix
A that stopped operating for three
consecutive years, is no longer allocated
86 If a unit was allocated allowances but turned
out not to be a covered unit or turned out not to
be required to hold allowances as of January 1,
2012, then the treatment of the allocation depends
on when the Administrator determines the unit is
not subject to the trading program or to the
allowance-holding requirement. For instance, if the
allocation has not been recorded, the Administrator
would not record it, and, if the allocation has been
recorded and the Administrator has not completed
the compliance determination process for the unit,
allowances equal to the allocation would be
deducted from the unit’s compliance account.
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allowances as an existing unit, but
resumes operation.
EPA believes it is important to have
a small new unit set-aside in each state
to cover new units within the budget
that was set aside to address the state’s
significant contribution and interference
with maintenance. To create new unit
set-asides, EPA would distribute to
existing EGUs a quantity of allowances
less than the entire state emissions
budgets. EPA would hold back, for the
new unit set-aside for a state, 3 percent
of the state budget. Three percent was
established based on the total amount of
new unit emissions projected for all the
covered states (See ‘‘State Budgets, Unit
Allocations, and Unit Emissions Rates’’
TSD). In this way, new units could be
allocated some allowances for their
emissions, which are part of the the
state’s contribution to downwind
nonattainment or interference with
maintenance.
For every control period after the
control period in which a new unit
commences commercial operation or, in
the case of an existing unit that did not
operate for three consecutive years,
resumes operation, EPA would allocate
to the unit from the new unit set-asides
based on the unit’s reported emissions
from the previous control period. EPA
would not allocate to a new unit for the
control period during which the unit
commences commercial operation
because the unit would have no actual
emissions data on which to base such an
allocation.
EPA proposes that, for the first control
period for which the new unit wants an
allowance allocation from the new unit
set aside (after the first year of
operation), the designated
representative of the source that
includes the new unit would submit to
EPA a request for a new unit allocation.
For each control period, any
allowances remaining in a state’s new
unit set-aside (after allocations are made
to new units that requested allowances)
would be distributed to the existing
units in that state in proportion to the
existing unit’s original allocations. This
ensures that total allocations to units in
the state would equal the state budget.
For each control period, if the size of
the new unit set-aside were insufficient
to provide allocations for all new units
requesting allowances, then allocations
to all new units would be proportionally
reduced.
EPA requests comment on the
proposed allocation approach for new
units. EPA also requests comment on
alternative allocation approaches that
would provide allowances to new units
for the control period during which the
unit commences commercial operation.
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Size of new unit set asides. EPA
proposes new unit set-asides that are
3 percent of the state emissions budgets.
The size of the new unit set-aside would
be 3 percent for the SO2 group 1, SO2
group 2, NOX annual, and NOX ozone
season trading programs, as appropriate,
for each state. EPA based the size of the
proposed new unit set-asides on a
comparison of projected emissions from
new units to projected emissions from
existing units for all covered states
under the proposed State Budgets/
Limited Trading remedy. As noted
previously, EPA proposes that after a
unit is not operating for three
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 setaside for the state in which the retired
unit is located. This approach would
allow the size of the new unit set-asides
to grow over time. Note that in EPA’s
analysis to determine the size of the
new unit set-asides, EPA assumed that
allocations for non-operating units
would be allocated to the new unit setasides after a unit had ceased operating
for 3 consecutive years (see ‘‘State
Budgets, Unit Allocations, and Unit
Emissions Rates’’ TSD). EPA requests
comment on the size of the new unit setasides.
Non-operating units. EPA proposes
that, once an EGU does not operate (i.e.,
does not combust any fuel) for 3
consecutive years, the Agency would no
longer allocate allowances to the unit,
starting in the seventh year after the first
year of non-operation. All allowances
that would otherwise have been
allocated to the unit for that seventh
year and every year thereafter would be
allocated to the new unit set-aside for
the state in which the non-operating
unit is located. This would provide
additional allowances for new units that
may need them (e.g., for new units that
replace non-operating units), and
reflects the fact that new unit emissions
are included in the state’s budget that
eliminates the portion of significant
contribution and interference with
maintenance that EPA has identified in
today’s proposed action (in an average
year).
EPA proposes to continue allocating
allowances to non-operating units
during the 3 consecutive years of nonoperation plus an additional 3-year
period to reduce the incentive for
owners to keep units operating simply
to avoid losing the allowance
allocations for those units. Other
options that EPA considered include
continuing to allocate allowances for an
unlimited period of time, or
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immediately discontinuing allocations
to such units upon the unit ceasing
operation.
Continuing allocations to nonoperating units has the benefit of
reducing the incentive to keep units in
operation that should otherwise be, for
instance, permanently retired due to age
and inefficiency. EPA believes there
will be less incentive to continue
running old, inefficient EGUs if at least
some allowances would still be received
after retirement. On the other hand,
stopping allocations for non-operating
units realigns allowance allocations
with the sources that actually need such
allowances. Non-operating units
obviously are no longer emitting and so
do not need allowances. Moreover,
additional allowances may be needed
for the new unit set-aside to
accommodate new units coming on line
in the future. Allocating allowances for
a specified, but limited, period after the
unit ceases operating for 3 consecutive
years, as EPA proposes to do, would be
a middle ground approach to this issue.
EPA requests comment on the
proposed approach for allocating
allowances to non-operating units. EPA
requests comment on simplifying
allocations by not allocating at all to
non-operating units. EPA also requests
comment on maintaining perpetual
allocations to non-operating units,
similar to the treatment of non-operating
units in the title IV Acid Rain Program.
Schedule for determining and
recording allowances. As discussed
previously, proposed allocations for
existing units are shown in the ‘‘State
Budgets, Unit Allocations, and Unit
Emissions Rates’’ TSD. EPA proposes to
include final allocations for existing
units in the Appendix A for each
proposed trading program in the final
Transport Rule.
EPA proposes to record initial
allowances for existing units in facility
accounts by September 1, 2011, for the
control periods in 2012, 2013, and 2014.
EPA proposes to record allowances for
existing units by July 1, 2012 and July
1 of each year thereafter, for the control
periods in the third year after the year
the allowances are recorded. For
example, EPA would record existing
unit allowances by July 1, 2012 for
control periods in 2015. Recording
allowances several years in advance
supports the development of the
allowance trading markets and provides
time for covered sources to plan for
compliance.
As discussed previously, EPA
proposes to determine allocations to a
new unit based on the unit’s reported
emissions the prior year. Although the
last quarter of emissions data for a year
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must be submitted to EPA in the fourth
quarterly emissions report by January 30
of the next year, the emissions data in
that report may be revised based on
EPA’s review and may not be finalized
until May or June after receipt of that
report. Consequently, EPA proposes to
determine new unit allocations by July
1 of the year for which the allocation is
determined. (Because, for an ozone
season ending September 30, emissions
data may not be finalized until the
following February or March, EPA
proposes to determine new unit
allocations by April 1.) For example,
EPA would determine a new unit’s
allocations for control periods in 2012
by July 1, 2012. EPA proposes to make
the new unit allocation determinations
available to the public through a notice
of data availability. Under the proposal,
objections to the notice could be
submitted, and EPA would issue a
second notice of data availability
referencing any necessary adjustments
of the new unit allocations.
EPA proposes to record allowances
for new units by September 1, 2012 and
September 1 of each year thereafter, for
the control periods in the year that the
allowances are recorded. (For the units
in the NOX ozone season program, the
comparable deadline for recordation of
new units’’ allowances is June 1.) For
example, EPA would record new unit
allocations by September 1, 2012 for
control periods in 2012.
EPA requests comment on the
proposed schedule for determining and
recording emissions allowances,
especially administratively-practical
ways to record allowances as soon as
possible, so facilities have information
useful in compliance planning.
Alternative allocation methods. The
proposed allocation method, described
previously, would determine each unit’s
allocation consistent with the proposed
approach to determine each state’s
significant contribution and interference
with maintenance. EPA considered
other alternative allocation methods.
One is discussed here, but EPA
recognizes that there are many ways that
allowances could be allocated. EPA is
requesting comment on whether the
alternative described here or any other
approach should be used instead of the
proposed allocation method.
As discussed in section IV, the state
emissions budgets are determined based
on EPA’s analysis of significant
contribution and interference with
maintenance in each upwind state. EPA
believes that it is appropriate to develop
individual unit allowances consistent
with this approach. In the proposed
approach, EPA does this by allocating
down to the individual unit level using
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all of the same assumptions used in
developing the proposed budgets. Under
this approach all units are allocated
allowances consistent with their
projected emissions; this means that a
unit that installs control equipment
receives fewer allowances than a similar
unit that did not install control
equipment.
EPA is taking comment on an
alternative methodology that still links
unit allowances directly to the way state
budgets were developed (and thus,
significant contribution was defined). In
the alternative, all units within a state
would be treated as a single group. The
allocation method would distribute
allowances equal to a state’s emissions
budget without variability to each
covered source in the state (in effect,
distributing the responsibility for
eliminating significant contribution and
interference with maintenance) based
on each source’s proportional share of
total state heat input. The state heat
input would be as projected for the
initial year of the program. In other
words, this alternative method for
distributing allowances would have the
effect of distributing the responsibility
for eliminating all or part of a state’s
overall significant contribution and
interference with maintenance to
individual units based on each unit’s
share of projected heat input.
There are other approaches to
allocation. For example, EPA could
identify groups of units in each state
that are capable of having similar
emissions characteristics (e.g., grouped
by size, fuel type, or age). EPA would
distribute a state’s emissions budget
without variability to each group of
units in the state (in effect, distributing
the responsibility for eliminating all or
part of significant contribution) perhaps
based on each group’s proportional
share of the state budget as projected in
the initial year of the program. After
apportioning a state’s budget to the
groups of units, under such an approach
EPA could distribute allocations to
individual sources within each group
based on each source’s proportional
share of projected heat input. Like the
first alternative allocation method
described previously, this approach
distributes each state’s significant
contribution and interference with
maintenance to individual sources in
the state. By determining groups and
then distributing allocations within the
groups based on proportional shares,
this approach would treat units within
the categories equally (i.e., it would not
treat a source that had acted early to
control differently from one that had yet
to take control action).
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EPA requests comment on the
proposed allocation approach, the
alternative approach, and on any other
approaches that are consistent with the
Court decision. EPA asks that
commenters present any such
approaches in detail to enable thorough
evaluation and that they provide a legal
analysis demonstrating how the
approach is consistent with the Court’s
opinions and the statutory mandate of
section 110(a)(2)(D).
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(3) Allowance Management System
EPA proposes that the State Budgets/
Limited Trading remedy include an
allowance management system (AMS)
operated essentially the same as the
existing allowance management systems
that are currently in use for CAIR and
the Acid Rain Program under Title IV.
Under the proposed State Budgets/
Limited Trading remedy, the SO2
programs and the NOX programs would
remain separate trading programs
maintained in EPA’s existing AMS.
AMS would be 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. Specifically,
AMS would track the allocation of all
SO2 and NOX allowances, holdings of
SO2 and NOX allowances in compliance
accounts (i.e., accounts for individual
covered sources) and general accounts
(i.e., accounts for other entities such as
companies and brokers), deduction of
SO2 and NOX allowances for
compliance purposes, and transfers of
allowances between accounts. 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 rate
limitations and other emissions-related
provisions of the cap and trade
programs. AMS also allows the public to
see whether sources are complying. In
addition, AMS provides data to the
allowance market, including a record of
ownership of allowances, dates of
allowance transfers, buyer and seller
information, and the serial numbers of
allowances transferred.
(4) Monitoring and Reporting
EPA proposes to require that
Transport Rule-covered sources monitor
and report SO2 and NOX emissions in
accordance with 40 CFR part 75. Most
sources that would be covered by the
proposed Transport Rule are already
measuring and reporting SO2 mass
emissions year round under CAIR and/
or the Title IV Acid Rain Program.
Similarly, most sources that would be
covered are already measuring and
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reporting NOX mass emissions year
round under CAIR. CAIR and the Acid
Rain Program both require Part 75
monitoring.
Consistent, complete, and accurate
measurement of emissions, as Part 75
requires, ensures that, for a given
pollutant, one ton of reported emissions
from one source is equivalent to one ton
of reported emissions from another
source. Thus, each allowance represents
one ton of emissions, regardless of the
source for which the emissions are
measured and reported. This establishes
the integrity of each allowance, which
instills confidence in the underlying
market mechanisms that are central to
providing sources with flexibility in
achieving compliance.
EPA proposes to require monitoring of
SO2 and NOX emissions by all existing
covered sources by January 1, 2012 for
states covered for the daily and/or
annual PM2.5 NAAQS, and monitoring
of NOX emissions by May 1, 2012 for
sources covered for the 8-hour ozone
NAAQS, using Part 75 certified
monitoring methodologies. New sources
would have separate deadlines based
upon the date of commencement of
commercial operation, consistent with
CAIR and the Acid Rain Program.
Specifically, a new unit must install
and certify its monitoring system within
180 days of the commencement of
commercial operation. While, under the
Acid Rain Program and CAIR, the
deadline was the earlier of 90 operating
days or 180 calendar days after
commencement of commercial
operation, EPA intends to propose that
part 75 be revised to use only the 180day deadline. EPA believes that using
only the 180-day deadline would ensure
that new units have sufficient time to
complete installation and certification
of monitoring systems without having to
request extensions of time and would
facilitate compliance by making the
monitoring deadline clearer for owners
and operators and easier for EPA to
apply. See a discussion on units
transitioning from CAIR and units
previously not covered by Part 75
requirements in section V.F, later.
EPA also proposes to require
designated representatives to submit
quarterly reports that would include
emissions and related data and proposes
to establish a procedure for
resubmission of quarterly reports where
appropriate. Specifically, the proposed
reporting provisions would include the
same requirement to submit quarterly
reports as the requirement in Part 75. In
addition, the proposed provisions
would include language that would
make explicit a process that is implicit
under, and has been in continuous use
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in, the Acid Rain, NOX Budget, and
CAIR trading programs. The
resubmission process would be as
follows. The Administrator could
review and audit any quarterly report to
determine whether the report met the
monitoring, reporting, and
recordkeeping requirements in the
proposed rule and Part 75. The
Administrator would provide
notification to the designated
representative stating whether any of
these requirements was not met and
specifying any corrections that the
Administrator believed were necessary
to make through resubmission of the
report and a reasonable deadline for a
response. The Administrator could
provide reasonable extensions of such
deadline. The designated representative
would be required, within the deadline
(including any extensions), to resubmit
the report with the identified
corrections, except to the extent the
designated representative would submit
information showing that a correction
was not necessary because the report
already met the monitoring, reporting,
and recordkeeping requirements
relevant to the correction. Any
resubmission of a quarterly report
would have to meet the requirements for
quarterly report submission, except for
the deadline for initial submission of
quarterly reports.
(5) Assurance Provisions
To ensure that the proposed FIPs
require the elimination of all emissions
that EPA has identified that
significantly contribute to
nonattainment or interfere with
maintenance within each individual
state, we are proposing to establish
assurance provisions, as described later,
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
budget with the variability limit for state
budgets, discussed in section IV. As
described therein, 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 is 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.
Starting in 2014, EPA is proposing as
part of the FIPs to establish limits on the
total emissions that may be emitted
from EGUs at sources in each state. For
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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 addition, the
3-year rolling average of the state’s
emissions must not exceed the state
budget with the variability limit allowed
on average for any consecutive 3 years
for that state (i.e., the state’s 3-year
variability limit). Note that in 2014 and
2015, EPA would apply only the 1-year
variability limit, and not the 3-year
variability limit. Because emissions
would be evaluated against the 3-year
variability limit on a 3-year rolling
average basis, the application of the
3-year variability limit in 2016 would
serve to limit emissions in 2014 and
2015.
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 one year,
and the state’s annual average emissions
for any 3-year period can not exceed, on
average, the state budget with the state’s
3-year variability limit. The fact of the
3-year variability limit would further
assure that emissions are constrained
during the two preceding years.
For example, a hypothetical state has
a budget of 100,000 tons, a 1-year
variability limit of 10,000 tons, and a
3-year variability limit of 5,800 tons.
• In the first year, collective
emissions from covered EGUs in the
state are 120,000 tons, 10,000 tons over
the budget with 1-year variability limit
of 110,000 tons, triggering the assurance
provisions in that year.
• In the second year, collective
emissions from covered EGUs in the
state are 97,500 tons, below the state
budget with 1-year variability limit of
110,000 tons. Assurance provisions are
not triggered.
• In the third year, collective
emissions from covered EGUs in the
state are 109,000 tons, below the state
budget with 1-year variability limit of
110,000 tons. Assurance provisions are
not triggered for the 1-year variability
limit. But after three years, the state
emissions are computed against the
3-year variability limit. The 3-year
rolling average (adding the last 3 years
of emissions and dividing that by three)
computes to 108,833 and determines
that the 3-year variability limit of
105,800 tons is exceeded, even though
in any one year, the 1-year variability
limit may not have been exceeded.
• In the fourth year, collective
emissions from covered EGUs in the
state are 99,000 tons, below the state
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budget with 1-year variability limit of
110,000 tons. Assurance provisions are
not triggered for the 1-year variability
limit. The 3-year rolling average of the
last 3 years is 101,833, which is less
than the 3-year variability limit of
105,800. Assurance provisions are not
triggered for the 3-year variability limit.
The variability limits for each state
are shown in Tables IV.F–1 through
IV.F–3 in section IV. The basis for the
variability limits is also described in
section IV.F. Additional details may be
found in the ‘‘Power Sector Variability’’
TSD in the docket to this rule.
To implement this requirement, EPA
would first evaluate whether any state’s
total EGU emissions in a control period
exceeded the state’s budget with 1-year
variability limit. Next, EPA would
evaluate whether any state’s total EGU
emissions in a control period exceeded
the state’s budget with the 3-year
variability limit (once the program is in
effect for 3 years, and each year
thereafter). If any state’s EGU emissions
in a control period exceeded either of
these limits, then EPA would apply
additional criteria to determine which
source owners in the state would be
subject to an allowance surrender
requirement. The proposed allowance
surrender requirement that owners
surrender allowances under the
assurance provisions would be triggered
only for owners of units in a state where
the total state EGU emissions for a
control period exceed the applicable
state budget with the variability limit.
Moreover, only an owner whose units’’
emissions exceed the owner’s share of
the state budget with the variability
limit would be subject to the allowance
surrender requirement.
In applying the additional criteria,
EPA would evaluate which source
owners in the state had emissions
exceeding the respective owner’s share
of the state budget with the variability
limit (regardless of whether the source
had enough allowances to cover its
emissions). An owner’s share would
equal the sum of the allocations of its
EGUs in the state, plus its proportional
share of the amount of the variability
limit that, when included with the state
budget, was exceeded by the state’s EGU
emissions during the year involved. If
the state emissions exceeded both the
state budget with the 1-year and with
the 3-year variability limit, then the 3year variability limit would be used in
determining the owner’s share of the
state budget.
On the other hand, if the state’s total
EGU emissions for a control period in a
given year did not exceed the state
budget with the state’s 1-year variability
limit and did not exceed, on a 3-year
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rolling average basis, the state budget
with the state’s 3-year variability limit,
then the additional criteria concerning
the emissions of each owner’s sources in
the state would not apply. For more
details see subsection V.D.4.i, later, and
the rule text at the end of this preamble
(§§ 97.425, 97.525, 97.625, and 97.725—
Compliance with assurance provisions).
As discussed previously, EPA would
not allocate emissions allowances to a
new unit for the control period during
which the unit commences commercial
operation. In the case where assurance
provisions for a state are triggered in the
year that a new unit first operates, the
owner’s share—if calculated as the sum
of the allocations of its EGUs plus its
proportional share of the variability
limit—would necessarily be zero
because the new unit would have no
allocation for that year. Instead, EPA
would use a specific surrogate
emissions number to calculate the
maximum amount the unit could emit
in that year before being required to
surrender allowances under the
assurance provisions. The surrogate
emissions number would apply only if
the state’s assurance provisions were
triggered and only in the first year of the
new unit’s operation.
The surrogate emissions number
would be calculated by multiplying the
unit’s allowable emissions rate (in lbs/
MWe) by the unit’s maximum hourly
load (in MWe/hr) and a default capacity
factor specific to the unit type. The
default capacity factors would be: 84
percent for coal-fired units, 66 percent
for gas-fired combined cycle units, and
15 percent for combustion turbines in
the NOX annual and SO2 trading
programs; and 89 percent for coal-fired
units, 72 percent for gas-fired combined
cycle units, and 22 percent for
combustion turbines in the NOX ozone
season trading program. These
percentages are based on the 95th
percentile capacity factors for these unit
types in quarterly data that have been
reported to EPA for coal-fired units
commencing operation since 2000 and
combustion turbines since 2004. EPA
believes that this approach would cover
a range of operating conditions for new
units and thus avoid attributing to each
new unit a share of the state budget with
variability reflecting the maximum
amount of emissions possible for the
unit in its first operating year, in the
case where the state’s assurance
provisions were triggered. (See
‘‘Capacity Factors Analysis for New
Units’’ TSD in the docket for further
information on the proposed default
capacity factors for new units).
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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 later.
EPA believes the likelihood of
triggering assurance provisions is low.
The State Budgets/Limited Trading
programs have a regional cap that limits
overall emissions; state-specific budgets
that are the basis for allocating
emissions allowances in each state;
assurance provisions that each state
eliminates the excess emissions leading
to significant contribution and
interference with maintenance that EPA
has identified in this proposed action;
and additional allowance surrender
requirements for not meeting emissions
reductions requirements. As discussed
in section e, later, the underlying
mechanism of cap and trade, even
without assurance provisions, has
succeeded in reducing emissions below
allowance levels. The accumulated data,
history, and experience from these
programs underscore that emissions
reductions requirements and
environmental and public health goals
of the programs were met. However,
unlike earlier cap and trade programs
(e.g., the Acid Rain, CAIR, and NOX
Budget Trading Programs), where
allocations were made based on the
same average emissions rates for classes
of units, in this proposed rule EPA
specifically designed budgets that were
intended to match up with reductions at
certain cost levels used to determine the
respective state’s significant
contribution and interference with
maintenance. This means more units are
likely to have allocations close to their
emissions when the state is eliminating
its significant contribution and
interference with maintenance and there
is likely to be less need for trading in
order for sources to comply with the
requirement to hold allowances
covering emissions. Additionally, EPA
has now added assurance provisions to
ensure that emissions within a state do
not exceed the state budget with the
variability limitation.
The existence of these assurance
provisions will limit incentives to trade
and ensure that state emissions will stay
below the level of the budget with the
variability limit. An example of a
circumstance that might result in
emissions approaching the variability
limit is an extended nuclear unit outage
that causes a company to run its fossil
units harder to meet demand. Increased
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emissions under such a scenario would
not result from the ability to trade across
state boundaries, or because the fossil
units were not controlled, but because
the units were operated more. In this
type of scenario, emissions would also
be higher in a rate-based program that
did not allow interstate trading.
EPA is setting two criteria to
determine if a state has exceeded its
budget using the state budget with the
1-year variability limit on an annual
basis, and the state budget with the
3-year variability limit on a 3-year
rolling average basis. EPA proposes that
emissions from an owner’s EGUs in
excess of the owner’s share of the state
budget with the variability limit would
not be a violation of the regulation or
the CAA. But the owner would be
required to make an allowance
surrender of one allowance for each ton
emitted over the owner’s proportional
share of the amount by which state
emissions exceed the state budget with
the variability limit.
This allowance surrender requirement
is significant, and EPA believes
sufficient, to ensure that the state
emissions will not exceed the budgets
plus the variability limit. The allowance
surrender requirement, however, is less
severe than the penalties (discussed
later) that apply if a source fails to
comply with the requirement to hold an
allowance for each ton emitted by EGUs
at the source. However, failing to hold
sufficient allowances to meet the
allowance surrender requirement would
be a violation of the regulations and the
CAA.
EPA requests comment on whether
the allowance surrender requirement
should be different (either more or less)
than one allowance per ton emitted over
the owner’s proportional share of the
state budget with the variability limit. In
addition, EPA requests comment on
whether the exceedance of total
emissions by an owner’s sources over
the owner’s share of the state budget
with the variability limit should be a
violation of the CAA and thus subject to
discretionary penalties. Finally, EPA
requests comment on all aspects of the
proposed assurance provisions in the
proposed FIPs.
(6) Penalties
All covered sources must hold an
allowance for each ton of SO2 or NOX
emitted and are subject to penalties if
they fail to comply with this allowanceholding requirement.
Each source must hold in its
compliance account in the AMS enough
allowances issued for the respective
annual trading program (SO2 group 1,
SO2 group 2, or NOX annual programs)
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to cover the annual emissions of the
relevant pollutant from all the EGUs at
the source. The source owner must
provide, for deduction by the
Administrator, one allowance as an
offset and one allowance as an excess
emissions penalty for each ton of excess
emissions. These are automatic
penalties-they are required, 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., a calendar
year), is a violation of the CAA, for
which the maximum discretionary
penalty is $25,000 (inflation-adjusted to
$37,500 for 2009) per violation under
CAA Section 113.
For the ozone season control program,
the same provisions apply as for an
annual program, except that the control
period (and averaging period) is the
ozone season, not a calendar year.
Consequently, the relevant allowances
and emissions are for an ozone season.
EPA requests comment on the amount
of allowances required for the automatic
penalties.
c. 2012 and 2013 Transition Period
For the 2012–2013 transition period,
EPA is proposing the State Budgets/
Limited Trading remedy without the
previously-described assurance
provisions (penalty provisions would
remain in effect), but taking comment
on whether the assurance provisions
should be in force during that period.
New state-specific control budgets
(developed as described in section IV)
and new allowances would be allocated
to sources in the Transport Rule region.
These state budgets would reflect the
operation of all existing and planned
emission control devices. Under EPA’s
proposed approach, for 2012 and 2013,
intrastate and interstate trading, without
the assurance provisions, would be
allowed.
The locations of existing and planned
air pollution control retrofits on EGUs
are known, and this knowledge provides
greater certainty of where reductions
will occur and how these reductions
should impact air quality in downwind
areas. There would not be sufficient
time to complete construction of
additional control retrofits or entirely
new, controlled EGUs before 2014.87
Consequently, EPA believes that there
is a high level of certainty that
emissions reductions projected for
87 U.S. Environmental Protection Agency (U.S.
EPA). 2002. Engineering and Economic Factors
Affecting the Installation of Control Technologies
for Multipollutant Strategies. Washington, DC.
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2012–2013 with interstate trading
would be achieved within the states
where they are projected to occur,
making imposition of the assurance
provisions during 2012–2013
unnecessary. In addition, EPA believes
that the two alternative options
discussed later present greater
implementation challenges than this
proposed interim remedy for 2012–
2013. See sections V.D.5 and V.D.6.
Except for the absence of the assurance
provisions, the remedy for 2012–2013
would be the same as the State Budgets/
Limited Trading option, including
compliance and penalty provisions
described previously.
The 2012–2013 transition period
would provide time for sources to
migrate to the new rule requirements in
2014, such as preparing for the
imposition of the assurance provisions
and, for some states, tighter SO2
budgets. EPA is requesting comment on
the proposed approach of locking in
emissions reductions for 2012 and 2013
by allocating new state-specific budgets
based on significant contribution and
interference with maintenance and
ensuring that pollution control devices
operate, while allowing for interstate
trading in 2012 and 2013 without the
assurance provisions. Assurance
provisions would provide sources less
flexibility and therefore likely increase
compliance costs, but would be required
starting in 2014. EPA requests comment
on the pros and cons of including
assurance provisions or other
limitations on trading during the 2012–
2013 period. Section IV.F presents
variability limits for the alternative
where assurance provisions would
apply during 2012 and 2013 (see Tables
IV.F–1 through IV.F–4).
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d. Electric Reliability
The State Budgets/Limited Trading
remedy is not a risk to electric
reliability. The option for sources to
trade across state borders and to emit up
to the specified state budget with
variability limit gives ISOs
(Independent System Operators) the
flexibility to manage regional electricity
generation so that reliability is
maintained. For example, the operations
of the electricity generation sector under
the State Budgets/Limited Trading
remedy, as compared to the option
allowing only intrastate trading, would
be less constrained by state borders and
have greater flexibility to handle
unexpected events such as extreme
weather or the loss of generating
capacity for extended periods of time.
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e. How Emissions Cap and Trade
Programs Have Worked Under Title IV,
the NOX SIP Call, and CAIR
Even absent assurance provisions, cap
and trade programs have resulted in
broad-based emissions reductions
distributed across the entire covered
area, with the reductions coming where
emissions were highest and most cost
effective. The national SO2 emissions
cap and trade program that EPA
implemented under Title IV of the CAA
Amendments (the Acid Rain Program)
and the regional SO2 and NOX programs
established under CAA section
110(a)(2)(D)(i), in the form of the NOX
Budget Trading Program and the three
CAIR trading programs, all have several
key components in common:
• Phases and reductions.
Æ An emissions cap is established
and the programs are phased in, with
increasing stringency to lower
emissions.
• Allowance allocation.
Æ Authorizations to emit, i.e.,
allowances, are allocated to affected
sources and are limited by each state’s
trading budget.
• Allowance trading.
Æ Markets enable sources to trade
allowances.
• Flexible compliance.
Æ Sources have the flexibility to
choose the most efficient way to comply
including adding emission control
technologies, updating control
technologies, optimizing existing
controls, switching fuels, and buying
allowances.
• Annual reconciliation.
Æ At the end of every compliance
period, each source must surrender
sufficient allowances to cover its
emissions. Excess allowances may be
sold or banked for future use.
• Penalties and enforcement.
Æ There are automatic penalties and
potentially discretionary civil penalties
for program noncompliance.
• Stringent monitoring and reporting.
Æ Sources must use approved
monitoring methods under EPA’s
stringent monitoring requirements (40
CFR part 75) to monitor and report
emissions.
• Data transparency.
Æ The data on key program elements,
such as emissions, allocations, and
allowance trades, are publicly available
on EPA’s web site and in annual
progress reports.
About 50 government staff operate
these cap and trade programs. They
have been successful in achieving the
emissions reductions goals at reasonable
costs with virtually 100 percent program
compliance. In the following
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paragraphs, specific results from the
programs are described. These results
are documented in program progress
reports that are available on EPA’s Web
site (https://www.epagov/airmarkets/
progress/progress-reports.html) and in
the docket to this rule, as referenced at
the end of each program section later.
Title IV Acid Rain Program—Emissions
Reductions
Since program implementation in
1995, the ARP has reduced SO2 and
NOX emissions from the power sector
across the nation. In 2008, the ARP SO2
program covered 3,572 electric
generating units (including 1,055 coalfired units, which account for almost 99
percent of total ARP unit SO2
emissions). Verified data submitted to
EPA from 2008 show that:
• SO2 emissions from power sector
sources were 7.6 million tons, which is
52 percent less than 1990 levels and
already below the statutory annual
emission cap of 8.95 million tons set for
compliance in 2010.
• NOX emissions from power sector
sources were 3.0 million tons, which is
51 percent less than 1995 levels and
more than double the Title IV NOX
program emission reduction objective,
but also reflects reductions achieved
under the NOX Budget and CAIR NOX
trading programs.
The largest reductions have occurred
in the states with the highest power
plant emissions. These high emitting
areas were upwind of major populations
centers and areas of environmental and
ecological concern. Emissions
reductions have led to improvements in
air quality with significant benefits to
sensitive ecosystems and human health.
• Between the 1989 to 1991 and 2006
to 2008 observation periods, decreases
in wet sulfate deposition averaged more
than 30 percent for the eastern U.S.
• Acid Neutralizing Capacity (ANC),
the ability of water bodies to neutralize
acid deposition, increased significantly
from 1990 to 2008 in lake and stream
long-term monitoring sites in New
England, the Adirondacks, and the
Northern Appalachian Plateau.
• Recently updated assessments of
U.S. PM2.5 and ozone health-related
benefits estimate that PM2.5 benefits due
to ARP implementation in 2010 are
valued at $170–$410 billion annually
and ground-level ozone benefits from
ARP implementation in 2010 are valued
at $4.1–$17 billion (estimates are in
2008 dollars). The benefits are primarily
from reduced premature mortality.
See EPA’s docket for this rule and
https://www.epagov/airmarkets/progress/
ARP_4.html.
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NOX SIP Call NOX Budget Trading
Program—Emissions Reductions. From
2003–2008, the NBP reduced ozone
season NOX emissions throughout the
NOX SIP Call region each year. Results
of the program include:
• In 2008, NBP ozone season NOX
emissions totaled 481,420 tons, which is
62 percent below 2000 levels and 9
percent below the 2008 NOX emissions
cap. Emissions were also below the caps
in 2006 and 2007.
• The average NOX emissions rate for
the 10 highest electric demand days (as
measured by megawatt hours of
generation) consistently fell every year
of the NBP.
• The largest NOX emissions
reductions and 8-hour ozone
concentrations reductions took place
along the Ohio River Valley, as was
projected by EPA air quality models of
the NOX SIP Call.
• Noticeable improvements in
ambient concentrations of ozone have
been measured across the region.
• Of the 104 areas in the eastern
United States designated to be in
nonattainment for the 1997 8-hour
ozone NAAQS in 2004, 88 areas (85
percent) had ozone air quality better
than the level of the 1997 standard in
2008. 8-hour ozone concentrations were
10 percent lower in 2008 than in 2001.
This decline is largely due to reductions
in NOX emissions required by the NOX
SIP Call rule.88
Over the past several years a series of
studies 89 90 91 have evaluated the NOX
SIP Call and the link between
decreasing NOX emissions and
decreasing ozone concentrations. These
studies demonstrate that the NOX SIP
Call has been effective in improving
ozone air quality in the eastern U.S.
EPA stopped administering the NBP
at the conclusion of 2008 control period.
States still have the emissions
reductions requirements under the NOX
SIP Call and can use the CAIR NOX
ozone season trading program to meet
these.
88 U.S. EPA, Our Nation’s Air Status and Trends
through 2008, Office of Air Quality Planning and
Standards, EPA–454/R–09–002, Research Triangle
Park, NC, pp. 1, 17.
89 Gego, E., P.S. Porter, A. Gilliland, and S.T. Rao,
´
2007: Observation-Based Assessment of the Impact
of Nitrogen Oxides Emissions Reductions on Ozone
Air Quality over the Eastern United States. J. Appl.
Meteor. Climatol., 46, 994–1008.
90 Godowitch, J.M., Hogfrefe, C., & Rao, S.T. 2008.
Diagnostic analyses of a regional air quality model:
Changes in modeled processes affecting ozone and
chemical-transport indicators from NOX point
source emission reductions. Journal of Geophysical
Research, 113, D19303, doi:10.1029/2007JD009537.
91 Godowitch, J.M., Gilliland, A.B., Draxler, R.R.,
and Rao, S.T. 2008. Modeling assessment of point
source NOX emission reductions on ozone air
quality in the eastern United States. Atmospheric
Environment, 42 (1), 87–100.
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See EPA’s docket for this rule for
more details on the results of the NOX
Budget Trading Program, or see https://
www.epagov/airmarkets/progress/
NBP_4.html.
CAIR—Emissions Reductions.
Anticipation of the CAIR regional
program in 2008 resulted in an
additional 2.8 million tons of SO2
reductions from 2005 levels in the
eastern United States, bringing
emissions well under the 2010 Title IV
cap. The NOX annual and ozone season
programs began on January 1 and May
1, 2009, respectively. The SO2 program
began on January 1, 2010. The CAIR cap
and trade programs remain in effect,
consistent with the Court’s remand, in
order to benefit public health and the
environment, until EPA replaces the
rule.
Allowance trading. Because of the
ease with which allowances can be
banked, bought and sold, and
transferred in the trading programs,
robust allowance trading markets have
developed over the past fifteen years,
along with considerable banking of
allowances.
Allowance prices and trading activity
under the trading programs were
reduced in 2008 in response to the
Court’s July 2008 decision in North
Carolina v. EPA granting petitions for
review of CAIR. However, the allowance
markets remained active. For a recent
assessment on allowance markets, see
https://www.epagov/airmarkets/
resource/docs/marketassessmnt.pdf.
Transaction Costs. The cap and trade
program results described previously
are real, measurable, and very
significant. These results demonstrate
that cap and trade is a policy tool that
can achieve cost-effective, broad
reductions quickly to improve human
health and the environment and help
states meet their obligations to attain the
NAAQS. While some have suggested
that transaction costs associated with
cap and trade programs were high or
problematic, EPA has found no
indication that this is the case.
Transaction costs are important because
they can diminish the incentive to trade
or the amount traded.
In fact, few empirical studies on
transaction costs have been done. EPA
has searched the literature and
compiled a list of anecdotal discussions
on transaction costs, including a study
of the ARP’s SO2 cap and trade program
by Ellerman 92 of MIT, published in
2004. Ellerman suggests that, while no
92 Ellerman, A. Denny. 2004. ‘‘The U.S. SO Cap2
and-Trade Programme,’’ Tradeable Permits: Policy
Evaluation, Design and Reform, chapter 3, pp. 71–
97, OECD.
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comprehensive study has been
conducted on the subject, ‘‘* * * the
creation of a standard unit of account in
allowances and the lack of any review
requirement for trading has avoided the
very large transactions costs that limited
* * * earlier experiments with
emissions trading.’’ Other studies (see
Schennach, 2000 93) suggest transaction
costs are about one percent of the
allowance price. An industry expert,
Gary Hart,94 suggested that a typical fee
charged by a brokerage firm is $0.50 for
each SO2 allowance.
Tietenberg, in his book, Emissions
Trading Principles and Practice,95
explains the role of transaction costs
and their impact on trading. Note that
Tietenberg and many economists use
the word, ‘‘permits,’’ in the same way
EPA uses the word, ‘‘allowances.’’
Tietenberg defines transactions costs
as ‘‘the costs, other than price, incurred
in the process of exchanging goods and
services. These include the costs of
researching the market, finding buyers
or sellers, negotiating and enforcing
contracts for permit transfers,
completing all the regulatory
paperwork, and making and collecting
payments.’’ 96 He also describes how to
lower transaction costs, as follows:
‘‘Transaction costs can be lowered by
making permit transactions transparent,
by the availability of exchanges and
knowledgeable brokers, and by the
sharing of information on the
availability of cost-effective abatement
technologies, while administrative costs
can be lowered by continuous emissions
monitoring and by software that
streamlines monitoring and
reporting.’’ 97 He goes on to say, ‘‘Price
transparency (making prices public) can
reduce the uncertainty associated with
trading and facilitate negotiations about
price and quantity. One good example is
[the] public auctions held each spring
for the Sulfur Allowance Program
[ARP].’’ 98
Tietenberg contrasts EPA’s earlier
credit-based trading programs in the
93 Schennach, S.M. 2000. The Economics of
Pollution Permit Banking in the Context of Title IV
of the 1990 Clean Air Act Amendments. Journal of
Environmental Economics and Management 40(3):
189–210.
94 Personal communication with Gary Hart, ICAPUnited, June 25, 2007 as quoted in Napolitano, S.,
J. Schreifels, G. Stevens, M. Witt, M. LaCount, R.
Forte, & K. Smith. 2007. ‘‘The U.S. Acid Rain
Program: Key Insights from the Design, Operation,
and Assessment of a Cap-and-Trade Program.’’
Electricity Journal. Aug/Sept. 2007, Vol. 20, Issue
7. doi:10.1016/j.tej.2007.07.001.
95 Tietenberg, T.H. 2006. Emissions Trading
Principles and Practice. Washington, DC. Published
by Resources for the Future.
96 Ibid., p. 41.
97 Ibid., p. 73.
98 Ibid., pp. 70–71.
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1970s and 1980s (U.S. Emissions
Trading Program (ETP)) with cap and
trade programs, such as the Acid Rain
Program for SO2. He says that while
credit-based programs ‘‘typically
involved a considerable amount of
regulatory oversight at each step of the
process (e.g., certification of credits and
approval of each trade),’’ cap and trade
programs use instead a system ‘‘that
compares actual and authorized
emissions at the end of the year, which
can lower transactions costs’’ compared
to a credit program.
All the features Tietenberg highlights
comprise fundamental aspects of EPA’s
cap and trade program design. Program
design remains one of the principle
ways to ensure lower transaction costs.
Over the last 15 years, EPA’s state-ofthe-art information management system
has evolved in parallel with the
advancement of technology in order to
offer platforms for reporting and
receiving data and for public access.
EPA provides dedicated assistance for
sources, states, and regions around the
country on program operations and
monitoring and reporting, specifically.
With limited oversight of transactions,
EPA focuses on recording data and
information accurately, including
allowance transfers, as well as ‘‘true-up’’,
where actual emissions are reconciled
with allowances held in accounts for
compliance.
These features of EPA’s program
management lead to low transaction
costs. EPA is attuned to trying to keep
requirements as simple and
straightforward as possible, and offers
substantial and routine training to
ensure successful program
implementation and regulatory
compliance. While some have equated
the length of EPA’s trading program
rules with higher transaction costs, in
fact, the detailed regulatory sections,
such as for allocations and the stringent
monitoring requirements, form the basis
of what actually allows the programs to
function with limited oversight,
virtually 100 percent compliance,
public transparency, and nominal
transaction costs.
For the ARP, NOX Budget Trading
Program, and CAIR trading programs,
EPA records all allowance allocations in
accounts in an electronic allowance
tracking system (currently called the
AMS). In addition, EPA records in the
AMS all allowance transfers that are
submitted by parties for official
recordation. These allowance accounts
are searchable and visible to the public.
The trading program regulations that
directly govern allowance trading, i.e.,
the regulations governing the
establishment of allowance accounts
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and the submission of allowance
transfers, are relatively simple and
establish requirements that are easy to
meet. See, e.g., 40 CFR 96.151(a)
(requiring establishment of source
compliance accounts). Allowances may
be held in an allowance account (i.e.,
banked) for use or trading in any future
year in which the trading program
involved is in effect. See, e.g., 40 CFR
96.155 (allowing banking). Further,
allowances may be transferred from one
account to another with no restrictions
except the requirements that the
authorized account representative of the
transferor account submit to EPA a
simple (generally electronic) allowance
transfer form identifying the allowances
to be transferred and the account to
receive them, and that the allowances
must be currently recorded in the
transferor account. See, e.g., 40 CFR
96.160 (requiring submission of
specified allowance transfer form) and
96.161(a)(2) (requiring that allowance be
in transferor account). This
transparency of data and availability of
information allows the allowance
market to function smoothly.
EPA research found no indications
that transaction costs have been a
problem. From discussions with a
leading industry consultant we learned
that there is enough competition among
the approximately fifteen brokerage
houses that any attempt at charging fees
in excess of market standards will be
bid down through competition.99 In
many instances, clients can negotiate
fees even lower than market averages.
Financial exchanges, such as the
Chicago Climate Exchange and New
York Mercantile Exchange, added SO2
and NOX allowances to their list of
commodities. Prior to the vacatur of
CAIR, transaction costs (broker fee as a
percent of allowance price) were
estimated at less than 0.2 percent for
SO2, less than 1.8 percent for seasonal
NOX, and less than 0.5 percent for
annual NOX.100 These transaction costs
are low and not expected to affect
program outcome.
In summary, EPA believes its cap and
trade programs functioned efficiently
and did not result in high transaction
costs for several reasons. First, in
developing the regulations for the
trading programs, EPA strove to make
the programs as transparent as possible
in order to ensure that relevant data
were available to the market, to
minimize regulatory oversight of trading
activity, and to let the market work
99 Memo from ICF International to EPA Clean air
Markets Division, September 17, 2008. Transaction
Costs in Allowance Trading Markets.
100 Ibid.
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unhampered. Strong markets exist that
have seen upwards of 273 million SO2
allowances transferred to date.
Educational and professional
associations that hold regular
conferences for members, regulated
entities, government agents, and the
public have existed to increase
transparency of information and
exchange ideas on cap and trade
programs for more than a decade.
Further, EPA is not aware of any
source participating in the trading
programs over the past 15 years that
expressed concern about the costs of
making allowance transfers. For
example, EPA has received no comment
in the rulemaking proceedings for the
trading programs raising concern about
the level of transactions costs for
allowance transfers under these
programs, and no party challenged the
allowance transfer provisions on appeal
of any of the trading program rules.
In addition, all available information
indicates that actual transactions costs
are very low. For a list of some articles
written by scholars and economists over
the past 15 years on transaction costs,
see the docket for this rule.
f. How the Remedy in the Proposed FIPs
Is Consistent With the Court’s Opinions
The proposed remedy discussed in
this section effectuates the statutory goal
of prohibiting sources within the state
from contributing to nonattainment or
interfering with maintenance in any
other state. See North Carolina, 531 F.3d
at 908. The proposed FIPs eliminate all
or the emissions that EPA has identified
as significantly contributing to
downwind nonattainment or
interference with maintenance in
today’s proposed action by requiring
sources to participate in emissions
trading programs that allow intrastate
trading and limited interstate trading,
and that also 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 emissions allowances sufficient to
cover their emissions, effectuate the
requirement that emissions reductions
occur ‘‘within the State.’’
A state’s ‘‘significant contribution’’ is
the portion of emissions that must be
eliminated.101 State budgets represent
EPA’s estimate of the remaining
emissions after elimination of
significant contribution, but in actuality
101 Note that in cases where EPA has not fully
identified the quantity of emissions that represent
significant contribution or interference with
maintenance, state budgets define the emissions
that remain after the part that has been identified
is eliminated.
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the amount of remaining emissions may
vary. As explained in greater detail
previously, both the budgets and the
assurance provisions recognize the
inherent variability in state EGU
emissions. 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
states’ baseline emissions are variable,
their remaining emissions after all
significant contribution is eliminated
are 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, could in fact
exceed the state budget without
variability. For this reason, the
assurance provisions limit a state’s
emissions to the state’s budget with
variability limit.
In addition, the requirement that all
sources hold emissions allowances (and
the fact that the total number of
emissions 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) 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
emissions levels, are more likely to vary
significantly within the region so that
resulting emissions 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
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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
proposed use of state budgets with the
variability limit may allow limited
shifting of emissions between states is
not inconsistent with the Court’s
holding that emissions reductions must
occur ‘‘within the state.’’ North Carolina,
531 F.3d at 907. Under the proposed
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. It is thus consistent with
the statutory mandate of section
110(a)(2)(D)(i)(I) as interpreted by the
Court.
g. Why EPA Is Proposing the State
Budgets/Limited Trading Option
The FIPs that EPA is proposing use
the State Budgets/Limited Trading
remedy to eliminate all of the significant
contribution and interference with
maintenance that EPA has identified.
This remedy—which would use state
budgets (see section IV) and allow full
trading within each state and limited
trading outside of each state—would be
a cost-effective method for eliminating
all or part of each state’s emissions that
constitute a significant contribution and
interfere with maintenance, would be
consistent with the Court’s decision in
North Carolina v. EPA, and would
address the issues raised by the Court.
In the first phase (2012 and 2013), the
proposed remedy would provide a new
interstate trading program that would
ensure existing and planned pollution
controls operate. Units would be
required to run their existing, or already
planned, pollution control devices
when the units are operating. The State
Budgets/Limited Trading remedy would
use the new state budgets described in
section IV and allocate allowances to
individual sources using a methodology
directly related to the methodology used
to identify emissions that significantly
contribute to nonattainment or interfere
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with maintenance in downwind areas.
EPA believes that because the location
of existing and already planned
pollution controls for 2012 and 2013 is
known, the use of these budgets, even
without the added assurance provisions,
would assure that the necessary
emissions reductions would occur in
each state under the trading programs
during those years. The impact of the
resulting emissions reductions on
atmospheric concentrations of
particulate matter and other pollution,
and subsequent benefits for the
environment and human health, would
be significant and are described in
sections III.B and IX. The proposed
remedy would offer the most
expeditious approach practicable for
compliance in 2012–2013, given the
short time available for sources, states,
and EPA to implement a transition from
CAIR. While there is some uncertainty
about how quickly units potentially
capable of switching fuels would
actually be able to implement such fuel
switching, the banking provisions of the
State Budgets/Limited Trading approach
would provide incentives to reduce
emissions as quickly and early as
possible. The trading provisions would
provide flexibility for sources to
purchase allowances in the meantime,
without the risks of unexpected high
costs, non-compliance, or the inability
to operate if unable to switch fuels. The
remedy would be relatively easy for
sources and states to understand and
follow as they transition from prior
trading programs to a new regime,
beginning in 2014, that would include
limits on interstate trading.
The second phase would begin in
2014 with tighter state-specific SO2 caps
for states in the more stringent group 1
tier to address significant contribution
and interference with maintenance. In
addition, assurance provisions limiting
interstate trading would become
effective in each state. This approach in
the proposed remedy, which is modeled
in several ways after the approaches of
the ARP and NBP programs, is likely to
lead to virtually 100 percent
compliance. The approach ensures that,
as we see economic growth, future air
quality is not compromised and states
can depend on emissions reductions in
meeting local air quality goals.
The limited interstate trading
permitted in this proposed remedy
would address some of the problematic
issues identified in the alternative
options discussed later, such as, under
the intrastate trading option, concerns
about the administrative burden and
needed resources associated with
administering 82 new trading programs
(with 82 new sets of allowances),
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conducting 82 annual auctions,
concentrated allowance market power
within individual states, and regional
electricity reliability. In particular, the
interstate trading component with
assurance provisions would mean that
allowances issued for one state for a
trading program could be used in any of
the states included in the respective
trading program. This feature of the
proposed remedy would create a
regionwide allowance market, rather
than single-state allowance markets
where individual owners of sources
would be much more likely to have
market power (see discussion later in
section V.D.5). Further, the interstate
trading component with assurance
provisions would provide source
owners with much more flexibility to
ensure electric reliability in the event of
future variability in electricity demand
(e.g., due to weather or economic
changes) or in the availability of specific
individual electricity generation
facilities.
In addition, the proposed State
Budgets/Limited Trading remedy
provides reductions at a lower cost than
the direct control option described later
and is flexible enough to accommodate
unit-specific circumstances. In contrast,
the direct control option described later
would involve a complex process of
determining unit-by-unit emissions
limits that might need to take account
of unit-specific circumstances.
Moreover, this option would be roughly
$600 million (2006$) more expensive
than the proposed remedy in 2012. See
section V.E for more details on projected
costs and emissions.
In summary, EPA believes that
interstate trading, although limited by
the assurance provisions, would allow
source owners to choose among several
compliance options to achieve required
emissions reductions in the most costeffective manner, such as installing
controls, changing fuels, reducing
utilization, buying allowances, or any
combination of these actions. Interstate
trading with assurance provisions
would also allow the electricity sector to
continue to operate as an integrated,
interstate system able to provide electric
reliability. Compared to the alternative
options, EPA believes the State Budgets/
Limited Trading remedy would provide
the greatest flexibility to companies
complying with the rules and is the
approach most likely to achieve the
goals and principles outlined in section
III.C.
The proposed remedy provides
intrastate and interstate trading
components that simplify
implementation for EPA (and, where
applicable, states) and sources and
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results in cost-effective achievement of
required emissions reductions. Resource
needs for EPA and sources to implement
the proposed remedy are expected to be
comparable to the resources necessary
to implement CAIR.
EPA believes the State Budgets/
Limited Trading proposed remedy
provides more assurance that the
emissions levels necessary to address
NAAQS nonattainment are not
exceeded than most previous regulatory
programs such as rate-based direct
control programs and even
nonattainment plans, none of which
places an absolute cap on emissions.
EPA has pointed out, in contrast, that
the results from cap and trade programs
such as the Acid Rain and NOX Budget
Trading programs demonstrate how
substantial emissions reductions have
been delivered throughout the
respective covered region with high
levels of compliance, at low costs, and
with significant health and ecological
benefits. The proposed State Budgets/
Limited Trading remedy provides added
assurance that emissions reductions
now will occur on a state-by-state basis,
not just overall at a regional level. These
assurance provisions would prohibit
states from exceeding their state-level
budgets with variability limits and
impose stringent and costly allowance
surrender requirements that are known
upfront to deter exceedances. EPA is
confident that the proposed program is
both reasonable to implement and
stronger than the alternative options.
Additionally, this remedy approach
and the method EPA proposes for
determining significant contribution
together provide a workable regulatory
structure for not only dealing with the
transport problem for the existing
NAAQS, but also would be usable in the
years ahead when EPA considers further
revisions of the NAAQS, notably for
ozone and fine particles. EPA requests
comment on the State Budgets/Limited
Trading proposed remedy. EPA is also
requesting comment on the two options
described later in sections V.D.5 and
V.D.6.
h. Other Limited Interstate Trading
Options Evaluated
EPA considered a range of ways to
create an interstate-trading-withlimitations option consistent with the
direction provided by the Court. One
option considered was to put in place
simultaneously intrastate trading with
direct control requirements and
interstate trading with direct control
requirements. The challenges associated
with developing direct control
requirements are discussed in section
V.D.6 later.
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45319
EPA also considered interstate trading
with backstop provisions, which were
rejected as not workable. EPA
considered a backstop provision that
prohibited the units in a state from
future participation in the interstate
trading program if the state’s emissions
in a control period in any year exceeded
the state’s budget with variability. In
that event, the units would be limited to
intrastate trading only in the control
period of the next year. This is not
EPA’s proposed option because data on
annual emissions are not final until
several months into the next year,
making it hard for the units in a state
to know early enough whether they
would be in the interstate trading
program or an intrastate trading program
for that next year. This would make
compliance planning and
implementation of compliance plans
extremely difficult and adversely affect
allowance markets.
In summary, EPA rejected these
alternatives as more complicated and
perhaps problematic to implement.
Instead, EPA is proposing the State
Budgets/Limited Trading remedy,
which is similar in many ways to the
approaches implemented in the past
that have succeeded in reducing
emissions. However, in order to address
the Court’s concerns about trading, the
proposed remedy includes assurance
provisions to ensure that the remedy
removes each upwind state’s significant
contribution and interference with
maintenance. The ‘‘Other Remedy
Options Evaluated’’ TSD in the docket
contains greater detail on the
deliberations undertaken to evaluate
other options for this rulemaking.
i. Structure and Key Elements of
Proposed Transport Rule Trading
Program Rules for State Budgets/
Limited Trading
This preamble section describes the
structure and key elements of the
proposed Transport Rule trading
program rules for the State Budgets/
Limited Trading remedy in the
proposed FIPs. Proposed regulatory text
that would be added to the Code of
Federal Regulations if this option is
finalized appears at the end of this
notice. EPA requests comment on the
structure and key elements of the
program as well as on the proposed
regulatory text.
In order to make the proposed FIP
trading program rules as simple and
consistent as possible, EPA designed
them so that the proposed rules for each
of the trading programs (i.e., the
Transport Rule NOX Annual trading
program, Transport Rule NOX Ozone
Season trading program, Transport Rule
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SO2 Group 1 trading program, and
Transport Rule SO2 Group 2 trading
program) would be parallel in structure
and contain the same basic elements.
For example, the proposed rules for the
Transport Rule NOX Annual, NOX
Ozone Season, SO2 Group 1, and SO2
Group 2 trading programs would be
located, respectively, in subparts
AAAAA, BBBBB, CCCCC, and DDDDD
of Part 97. Moreover, the order of the
specific provisions for each trading
program would be same, and the
provisions would have parallel
numbering. The key elements of the
proposed Transport Rule trading
program rules are discussed later.
(1) General Provisions
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(i) §§ 97.402 and 97.403, 97.502 and
97.503, 97.602 and 97.603, and 97.702
and 97.703—Definitions and
Abbreviations
The definitions and measurements,
abbreviations, and acronyms would be
the same in all four proposed Transport
Rule trading programs, except where
necessary to reflect the different
pollutants (NOX and SO2), control
periods (for NOX, annual and ozone
season), and geographic coverage (for
SO2, Group 1 and Group 2) involved.
Moreover, many of the definitions
would be essentially the same as those
used in prior EPA-administered trading
programs, in some cases with
modifications to reflect the specific,
proposed Transport Rule trading
program involved. For example, the
definitions of ‘‘unit’’ and ‘‘source’’ would
be the same as in prior trading
programs. As a further example, the
definitions of ‘‘allowance transfer
deadline,’’ ‘‘owner,’’ and ‘‘operator’’
would be the same as in prior trading
programs, except for references to
Transport Rule NOX Annual allowances,
Transport Rule NOX Ozone Season
allowances, Transport Rule SO2 Group 1
allowances, or Transport Rule SO2
Group 2 allowances or Transport Rule
NOX Annual units and sources,
Transport Rule NOX Ozone Season units
and sources, Transport Rule SO2 Group
1 units and sources, or Transport Rule
SO2 Group 2 units and sources, as
appropriate. As a further example, the
term ‘‘Allowance Management System’’
would be used instead of the term
‘‘Allowance Tracking System’’ but
would have essentially the same
definition, while referencing the type of
allowances appropriate for the proposed
Transport Rule trading program
involved. As a further example,
‘‘continuous emission monitoring
system’’ is essentially the same as in
prior trading programs, except for
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references to the proposed Transport
Rule trading program rules.
Some definitions would be similar to
those used in prior EPA-administered
trading programs but with some
substantive differences. For example,
the definitions of ‘‘cogeneration unit’’
and ‘‘fossil-fuel-fired,’’ used in the
applicability provisions and discussed
in this section of the preamble, would
be 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.
A few new definitions would be
included to reflect unique provisions of
the proposed Transport Rule trading
programs. For example, the terms,
‘‘owner’s assurance level’’ and ‘‘owner’s
share’’, would be used in the Transport
Rule assurance provisions and defined
in the proposed Transport Rule trading
program rules. The assurance provisions
are discussed previously in section
V.D.4.b.
(ii) §§ 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 would be
the same for each of the proposed
Transport Rule trading programs, except
that the provisions would reflect
(through the definition of ‘‘state’’)
differences in the specific states whose
EGUs are covered by the respective
Transport Rule trading programs (as
discussed in section IV.D of this
preamble). In general, the proposed
Transport Rule trading programs would
cover fossil fuel-fired boilers and
combustion turbines serving 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. The
applicability provisions are discussed
previously in section V.D.4.b.
The provisions exempting
permanently retired units from most of
the requirements of the Transport Rule
trading programs would be the same for
each of the trading programs. The
purpose of the retired units’’ exemption
would be to avoid requiring units that
are permanently retired to continue to
operate and maintain emission
monitoring systems, to report quarterly
emissions, and to hold allowances, as of
the allowance transfer deadline,
sufficient to cover their emissions
determined in accordance with the
monitoring and reporting requirements.
Consequently, the retired unit
provisions would exempt these units
from the rule sections imposing the
relevant monitoring, recordkeeping, and
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reporting requirements and allowanceholding requirements. However, an
owner would include each of these
permanently retired units that it owns
in determining whether and, if so, how
many allowances the owner would be
required to surrender in compliance
with the assurance provisions. As
discussed earlier in this section, while
these units would have zero emissions
once they are permanently retired, the
units could continue to receive
allowance allocations for several years
thereafter. Consequently, an owner
would include these units in
determining whether the owner’s share
of total emissions of covered units in a
state exceeded its share (generally based
on the allowances allocated to its units)
of the state budget with the variability
limit and thus whether the owner would
have to surrender allowances under the
assurance provisions.
The exemption for a retired unit
would begin on the day the unit is
permanently retired. The unit’s
designated representative (i.e., the
person authorized by the owners and
operators to make submissions and
handle other matters) would be required
to submit notification to the
Administrator within 30 days of the
unit’s permanent retirement.
The retired unit exemption provisions
would not directly address any permitrelated matters concerning these units.
This would be consistent with the
general approach under the Transport
Rule trading program rules of leaving
permitting matters largely to be
addressed by the existing, applicable
state and federal title V permit
programs. Permitting is discussed in
section VIII of this preamble.
(iii) §§ 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 proposed
Transport Rule trading programs and
presented as standard requirements
would 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 Act provisions.
The paragraphs, in the standard
requirements section, that would
address designated representative
requirements and emissions monitoring,
reporting, and recordkeeping
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requirements would reference the
details of these requirements in other
sections of the proposed Transport Rule
trading program rules.
The paragraphs addressing emissions
requirements would describe these
requirements in detail and reference
other sections that would set forth the
procedures for determining compliance
with the emissions limitations and
assurance provisions. These paragraphs
would also explain that: Transport Rule
NOX Annual allowances, Transport Rule
NOX Ozone Season allowances,
Transport Rule SO2 Group 1 allowances,
or Transport Rule SO2 Group 2
allowances would each authorize
emission of one ton of emissions under
the applicable Transport Rule trading
program; such authorizations could be
terminated or limited by the
Administrator to the extent necessary or
appropriate to implement any provision
of the CAA; and such allowances would
not constitute a property right. The
proposed Transport Rule SO2 trading
programs use new SO2 allowances and
not CAA Title IV allowances, thus the
provisions allowing the Administrator
to terminate or limit the Transport Rule
trading program allowances under this
rule would not be contrary to the
Court’s North Carolina decision, which
addressed the Administrator’s authority
to terminate or limit Title IV SO2
allowances through the CAIR.
The remaining paragraphs in the
standard requirements section concern
permitting, recordkeeping and
reporting, liability provisions, and the
effect on other CAA provisions. As
discussed in section VIII of this
preamble, the paragraphs concerning
permitting requirements would be
limited to stating that no title V permit
revisions would be necessary to account
for allowance allocation, holding,
deduction, or transfer and that the
minor permit modification procedures
could 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. The paragraphs on
recordkeeping and reporting would
generally require owners and operators
to keep on site for 5 years copies (which
could be electronic) of certificates of
representation, emissions monitoring
information (including quarterly
emissions data), and submissions and
records demonstrating compliance with
the proposed Transport Rule trading
programs. The paragraphs on liability
would state that each covered source
and covered unit would be required to
meet the Transport Rule trading
program requirements, any provision
applicable to a source or designated
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(iv) §§ 96.407, 97.507, 97.607, and
97.707—Computation of Time
These sections would clarify how to
determine the deadlines referenced in
the proposed Transport Rule trading
program rules. For example, deadlines
falling on a weekend or holiday are
extended to the next business day.
These are the same computation-of-time
provisions used in prior EPAadministered trading programs.
appealable under Part 78, any person
who—in connection with the
Administrator’s process of making that
decision—submitted comments,
testified at a public hearing, submitted
objections, or submitted their name to
be included by the Administrator in an
interested persons list.
In addition, § 78.3 would be revised to
allow for petitions for administrative
appeal of decisions of the Administrator
under the proposed Transport Rule
trading programs. Further, § 78.4 would
be expanded to state that filings on
behalf of owners and operators of a
covered source or unit under the
proposed Transport Rule trading
programs would have to be signed by
the designated representative of the
source or unit. Filings on behalf of
persons with an interest in allowances
in an account in the proposed programs
would have to be signed by the
authorized account representative of the
account.
(v) §§ 97.408, 97.508, 97.608, 97.708 and
Part 78—Administrative Appeal
Procedures
Final decisions of the Administrator
under the proposed Transport Rule
trading program rules would be
appealable to EPA’s Environmental
Appeals Board under the regulations
that are set forth in part 78 (40 CFR part
78) and are proposed to be revised to
accommodate such appeals.
Specifically, the list in § 78.1 of the
types of final decisions that could be
appealed under Part 78 would be
expanded to include specific types of
decisions under the proposed Transport
Rule trading program rules.
Further, under the approach in the
existing part 78, an ‘‘interested person’’
(in addition to the official representative
of owners and operators or an allowance
account involved in a matter) may
petition for an administrative appeal of
a final decision of the Administrator. In
order to expand the ‘‘interested person’’
definition (which is currently in part 72
of the ARP regulations) and make the
definition more readily accessible to
readers of part 78, the definition would
be removed from § 72.2, added in § 78.2,
and expanded in a way that would
cover the proposed trading program
rules. Provisions concerning public
availability of information, and
provisions concerning computation of
time (revised to be consistent with the
requirements for computation of time
used by the Environmental Appeals
Board in other types of administrative
proceedings), would also be moved to
§ 78.2. In particular, the revised
‘‘interested person’’ definition would
include, with regard to a decision
(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
would 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
would include tables providing, for each
state covered by the particular proposed
Transport Rule trading program and for
each year, the state trading budget
(without the variability limit), new unit
set-aside, and one-year and three-year
variability limits. With regard to
existing units, these sections would also
state that existing units would be
allocated the allowances set forth in
appendix A of the relevant Transport
Rule trading program rules. These
allocations would be permanent (taking
into account the reductions in
allocations, for the Transport Rule SO2
Group 1 trading program, from Phase I
to Phase II) with one exception. A unit
that does not operate (i.e., has no heat
input) for three consecutive years
starting in 2012 would continue to
receive its Appendix A allocation for
those years plus only three more years.
Starting in the seventh year, the
Administrator would stop recording the
allocations for the unit and would
instead add to the new unit set-aside the
allowances that would otherwise have
been recorded for the non-operating
unit. Because the proposed unit-by-unit
allocations are set forth in the ‘‘State
Budgets, Unit Allocations, and Unit
Emissions Rates’’ TSD cited previously,
representative would be applicable to
the source and unit owners and
operators, and any provision applicable
to a unit or designated representative
would be applicable to the unit owners
and operators. The paragraph on the
effect on other CAA provisions would
state that the Transport Rule trading
programs do not exempt or exclude
owners and operators from any other
requirements under the CAA, an
approved SIP, or a federally enforceable
permit.
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the proposed Transport Rule trading
program rules do not repeat these
allocations in Appendix A to each rule.
Instead, each Appendix A is reserved,
and EPA proposes to include the unitby-unit allocations, for each Transport
Rule trading program, in Appendix A to
the respective final Transport Rule
trading program rules.
With regard to new units (as well as
units whose allocations are subject to
the requirement that the Administrator
not record them or that the
Administrator deduct the amount of the
allocation and units that lost their
allocations after not operating and that
subsequently began operating again), the
owner and operator of such units could
request, by a specified deadline each
year, an allocation from the new unit
set-aside for that year and each year
thereafter. The allocation would equal
that unit’s emissions—as determined in
accordance with 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. The
Administrator would determine
whether the total number of properly
requested allowance allocations for all
units in a state for a control period
would exceed the amount in the new
unit set-aside for the state for the control
period. If not, the Administrator would
allocate consistent with all proper
requests. If the total number would
exceed the new unit set-aside, the
Administrator would allocate to each
properly requesting unit its
proportionate share of the new unit setaside. The Administrator would provide
notice of these determinations (which
would reflect these calculations rather
than any exercise of discretion on the
part of the Administrator) through
issuance of a notice of data availability
to which parties could submit
objections and a second notice
addressing any objections. Any
unallocated allowances in the new unit
set-aside would be allocated to existing
units in proportion to their current
allocations.
If a unit that was not really a covered
unit or a unit that was not subject to the
allowance-holding requirement were
allocated allowances, the proposed
provisions set forth a process under
which the allocation would not be
recorded or the amount of the recorded
allocation would be deducted, with one
exception. The exception would be if
the process of determining compliance
with the emission limitation for the
source that includes the unit were
already completed, in which case no
action would be taken to account for the
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erroneous allocation for the control
period involved.
(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
would 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 would also describe the
designated representative’s and
alternate designated representative’s
responsibilities and the process through
which he or she could delegate to an
agent the authority to make electronic
submissions to the Administrator. These
provisions would be patterned after the
provisions concerning designated
representatives and alternates in prior
EPA-administered trading programs.
The designated representative would
be the individual 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. This approach would ensure
that one individual was required to be
knowledgeable about the requirements
of, and responsible for compliance with,
all Transport Rule trading programs.
One alternate designated representative
could 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
would legally bind the owners and
operators, the designated representative
and alternate would have to submit a
certificate of representation certifying
that each was selected by an agreement
binding on all such owners and
operators and was authorized to act on
their behalf.
The designated representative and
alternate would be authorized upon
receipt by the Administrator of the
certificate of representation. This
document, in a format prescribed by the
Administrator, would include: Specified
identifying information for the covered
source and 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. All
submissions (e.g., monitoring plans,
monitoring system certifications, and
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allowance transfers) for a covered
source or covered unit would have to be
submitted, signed, and certified by the
designated representative or alternate.
Further, upon receipt of a complete
certificate of representation, the
Administrator would establish a
compliance account in the Allowance
Management System for the source
involved.
In order to change the designated
representative or alternate, a new
certificate of representation would have
to be received by the Administrator. A
new certificate of representation would
also have to be submitted to reflect
changes in the owners and operators of
the source and units involved. However,
new owners and operators would be
bound by the existing certificate of
representation even in the absence of
such a submission.
In addition to the flexibility provided
by allowing an alternate to act for the
designated representative (e.g., in
circumstances where the designated
representative might be unavailable),
additional flexibility would be provided
by allowing the designated
representative or alternate to delegate
authority to make electronic
submissions on his or her behalf. The
designated representative or alternate
could designate agents to submit
electronically certain specified
documents. The previously-described
requirements for designated
representatives and alternates would
provide regulated entities with
flexibility in assigning responsibilities
under the Transport Rule trading
programs, while ensuring accountability
by owners and operators and
simplifying the administration of the
proposed Transport Rule trading
programs.
(4) Allowance Management System
The Transport Rule trading program
rules listed later would establish the
procedures and requirements for using
and operating the Allowance
Management System (which is the
electronic data system through which
the Administrator would handle
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
would also provide 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. Consistent with the
approach in prior EPA-administered
trading program, allowance price
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information would not be included in
the Allowance Management System.
EPA’s experience is that private parties
(e.g., brokers) are in a better position to
obtain and disseminate timely, accurate
allowance price information than is
EPA. For example, because not all
allowance transfers are immediately
reported to the Administrator for
recordation, the Administrator would
not be able to ensure that any reported
price information associated with the
transfers would reflect current market
prices.
(vi) §§ 97.420, 97.520, 97.620, and
97.720—Compliance and General
Accounts
The Allowance Management System
would contain two types of accounts:
compliance accounts, one of which the
Administrator would establish for each
covered source upon receipt of the
certificate of representation for the
source; and general accounts, which
could be established by any entity upon
receipt by the Administrator of an
application for a general account. A
compliance account would be the
account in which any allowances used
by the covered source for compliance
with the emissions limitations and
assurance provisions would have to be
held. The designated representative and
alternate for the source would also be
the authorized account representative
and alternate for the compliance
account. Using source-level, rather than
unit-level accounts, would provide
owners and operators more flexibility in
managing their allowances for
compliance, without jeopardizing the
environmental goals of the Transport
Rule trading programs, because the
source-level approach would avoid
situations where a unit would hold
insufficient allowances and would be in
violation of allowance-holding
requirements even though units at the
same source had more than enough
allowances to meet these requirements
for the entire source.
General accounts could be used by
any person or group for holding or
trading allowances. However,
allowances could not be used for
compliance with emissions limitations
or assurance provisions so long as the
allowances were held in, and not
properly and timely transferred out of,
a general account. To open a general
account, a person or group would have
to submit an application for a general
account, which would be similar in
many ways to a certificate of
representation. The application would
include, in a format prescribed by the
Administrator: The name and
identifying information of the
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individual who would be the authorized
account representative and of any
individual who would be the alternate
authorized account representative; an
identifying name for the account; the
names of all persons with an ownership
interest with the respect to allowances
held in the account; and certification
language and signatures of the
authorized account representative and
alternate. The authorized account
representative and alternate would be
authorized upon receipt of the
application by the Administrator. The
provisions for changing the authorized
account representative and alternate, for
changing the 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 would
be analogous to those applicable to
comparable matters for designated
representatives and alternates.
(vii) §§ 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
By September 1, 2011, the
Administrator would record allowance
allocations for existing units, based on
Appendix A to each proposed Transport
Rule trading program rule, for 2012
through 2014. By June 1, 2012 and June
1 of each year thereafter, the
Administrator would record such
allowance allocations for each proposed
Transport Rule trading program for the
third year after the year of the
recordation deadline, e.g., for 2015 in
2012. Recording these allowance
allocations about 3 years in advance of
the first year for which they could be
used for compliance would facilitate
compliance planning by owners and
operators and promote robust allowance
markets, including futures markets for
allowances. By September 1 (for the
Transport Rule NOX and SO2 annual
trading programs and June 1, for the
Transport Rule NOX Ozone Season
program) of each year starting with
2012, the Administrator would record
allowance allocations for that year from
the new unit set-aside. Because this
would occur before the allowance
transfer deadline for each proposed
Transport Rule trading program
involved, this would still allow for
trading and thereby promote robust
allowance markets.
The process for transferring
allowances from one account to another
would be quite simple. A transfer would
be submitted providing, in a format
prescribed by the Administrator, the
account numbers of the accounts
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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 were submitted to
the Administrator and, when the
Administrator attempted to record the
transfer, the transferor account included
the allowances identified in the form,
the Administrator would record 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.
(viii) §§ 97.424, 97.524, 97.624, and
97.724—Compliance With Emissions
Limitations
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 NOX ozone
season trading program), covered
sources would have a window of
opportunity (i.e., 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 might
need to cover their emissions during the
control period. Each allowance issued
in each proposed Transport Rule trading
program would authorize emission of
one ton of the pollutant, and so would
be usable for compliance, for a control
period in the year for which the
allowance was allocated or a later year.
Consequently, each source would
need—as of the allowance transfer
deadline—to have in its compliance
account, or have a properly submitted
transfer that would move into its
compliance account, enough allowances
usable for compliance to authorize the
source’s total emissions for the control
period. The authorized account
representative could identify specific
allowances to be deducted, but, in the
absence of such identification or in the
case of a partial identification, the
Administrator would deduct on a firstin, first-out basis.
If a source were to fail to hold
sufficient allowances for compliance,
then the owners and operators would
have to provide, for deduction by the
Administrator, 2 allowances allocated
for the control period in the next year
for every allowance that the owners and
operators failed to hold as required to
cover emissions. In addition, the owners
and operators would be subject to
discretionary civil penalties for each
violation, with each ton of unauthorized
emissions and each day of the control
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period involved constituting a violation
of the Clean Air Act.
EPA believes that it is important to
include a requirement for an automatic
deduction of allowances. The deduction
of one allowance per allowance that the
owners and operators failed to hold
would offset this failure. The deduction
of another allowance per allowance that
the owners and operators failed to hold
would provide an automatic penalty
that could not be avoided, regardless of
any explanation provided by the owners
and operators for their failure, and
would therefore provide a strong
incentive for compliance with the
allowance-holding requirement by
ensuring that non-compliance would be
a significantly more expensive option
than compliance.
(ix) §§ 97.425, 97.525, 97.625, and
97.725—Compliance With Assurance
Provisions
EPA proposes to include assurance
provisions in the Transport Rule trading
programs in order to ensure that each
state would eliminate that part of its
significant contribution and interference
with maintenance that EPA has
identified in today’s proposed action
(see section V.D.4.b previously). As
previously discussed, a requirement that
owners surrender allowances under the
assurance provisions would be triggered
only for owners of units in a state where
the total state EGU emissions for a
control period would exceed the
applicable state budget with the
variability limit. Moreover, only an
owner whose units’ emissions would
exceed the owner’s share of the state
budget with the variability limit would
be subject to the allowance surrender.
The process of determining, for a
given control period, which states
would have total EGU emissions
sufficient to trigger the allowance
surrender requirement, which owners
would be subject to the allowance
surrender, and whether those owners
were in compliance would be
implemented in a series of steps. (The
dates summarized later apply to the
proposed annual programs; the dates for
the proposed ozone season program
would be earlier.)
First, the Administrator would
perform the calculations necessary to
determine whether any states had total
state EGU emissions for a control period
greater than the state budget with the
variability limit, applying both the
1-year and the 3-year variability limits
discussed earlier. By June 1 (starting in
2015), the Administrator would
promulgate a notice of availability of the
results of these calculations and provide
an opportunity for submission of
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objections. By August 1, the
Administrator would promulgate a
second notice of availability of any
necessary adjustments to the
calculations and the reasons for
accepting or rejecting any properly
submitted objections.
Second, by August 15, the designated
representative of every Transport Rule
source in a state identified in the August
1 notice as having control period
emissions in excess of the budget with
the variability limit would make a
submission to the Administrator that
would identify: Each person having (as
of the last day of the control period) a
legal, equitable, leasehold, or
contractual reservation or entitlement in
the Transport Rule units at the source;
and the percentage of each such
person’s reservation or entitlement.
Third, by September 15, the
Administrator would calculate, for each
state identified in the August 1 notice
and for each owner of covered units in
the state, the owner’s share of
emissions, the owner’s share of the state
budget with the variability limit, and
the amount (if any) that the owner
would be required to hold for surrender
under the assurance provisions (i.e., the
owner’s proportionate share of the
excess of state emissions over the state
budget with the variability limit). The
Administrator would promulgate a
notice of availability of the results of
these calculations, provide an
opportunity for submission of
objections, and promulgate by
November 15 a second notice of
availability of any necessary
adjustments to the calculations and the
reasons for accepting or rejecting any
properly submitted objections.
By December 1, each owner identified
in the November 15 notice as being
required to hold allowances for
surrender under the assurance
provisions would designate a
compliance account of one of its
covered units in the state, and the
authorized account representative of the
compliance account would submit to
the Administrator a statement
designating the compliance account, as
the account in which the required
allowances would be held.
As of midnight of December 15, the
owner would have to have in its
designated compliance account, or have
a properly submitted transfer that would
move into that compliance account, the
amount of allowances (usable for
compliance) that the Administrator
determined (in the calculations
referenced in the November 15 notice)
were required to be held by the owner
for surrender. The authorized account
representative could identify specific
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allowances to be deducted but, in the
absence of such identification or in the
case of a partial identification, the
Administrator would deduct allowances
on a first-in, first-out basis.
The potential effect of subsequent
data revisions that would otherwise
change the data used in and the results
of the Administrator’s calculations
referenced in the August 1 or November
15 notices discussed previously would
be limited. If data used in a notice
applying the assurance provisions to a
given year were revised as a result of a
decision in, or settlement of, litigation
(such as an administrative appeal
resulting in such decision or settlement
or an administrative appeal whose
results were in turn appealed in a
judicial proceeding resulting in such
decision or settlement) initiated within
30 days of the promulgation of the
notice involved, then the Administrator
would use the revised data for the
calculations in the respective notice.
Any other data revisions would not be
used to revise the calculations. The
revised data could be used, if relevant,
in the Administrator’s calculations in
future notices promulgated for a later
year. If the revised calculations
increased the amount of allowances that
an owner was required to hold for
surrender, the Administrator would set
a new, reasonable deadline for the
owner to hold the additional allowances
in the owner’s designated compliance
account. The Administrator believes
that this limitation on the effect of data
revisions on the calculation of the
amount of allowances owners would
have to surrender under the assurance
provisions is necessary. Because an
owner’s surrender obligation would be
calculated using large amounts of data
involving all the covered units in a state
(including potentially many units
owned by other owners), each owner
would face the potential that changes in
data outside of the owner’s
responsibility and control could
change—after the December 15
allowance-holding deadline—in a way
that would increase his surrender
obligation after that deadline and put
him in violation of the regulations and
the Act. EPA believes that this potential
risk would be significant enough that it
could make many owners reluctant to
consider any compliance options
involving even the limited interstate
trading allowed under the proposed
remedy. The proposal would limit this
risk by having the Administrator only
take account of data revisions resulting
from decisions in, or settlement of,
litigation initiated soon after
promulgation of the notice involved.
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Owners’ potential allowance surrender
obligations as of the December 15
allowance-holding deadline under the
assurance provisions would still be
significant even with this limitation on
the potential for the surrender
obligations to increase after December
15 due to data revisions.
As discussed previously, it would not
be a violation of the CAA for total state
EGU emissions to exceed the state
budget with the variability limit or for
an owner to become subject to
allowance surrender under the
assurance provisions. However, the
failure of an owner to hold in the
designated compliance account a
sufficient amount of allowances to
satisfy this allowance surrender would
violate the CAA and be subject to
discretionary penalties, with each
required allowance that was not held
and each day of the control period
involved constituting a violation. EPA
believes that the allowance surrender
requirement alone—and certainly when
coupled with the potential for large
discretionary penalties—would ensure
that owners would take actions to avoid
having total state EGU emissions exceed
the level that would trigger the
allowance surrender.
(x) §§ 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 would allow 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. Banking would allow
sources to make emissions reductions
beyond required levels and bank the
unused allowances for use or trading
later. This would encourage
development of emissions reductions
techniques and technologies and
implementation of early reductions,
stimulate the allowance markets, and
provide flexibility to owners and
operators. While this could also
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 would
limit such emissions in a way that
would ensure that the part of each
state’s significant contribution and
interference with maintenance that EPA
has identified in today’s proposed
action would be eliminated.
These sections also would provide
that the Administrator could, at his or
her discretion and on his or her own
motion, correct any type of error that he
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or she finds in an account in the
Allowance Management System. In
addition, the Administrator could
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
would establish emissions monitoring,
recordkeeping, and reporting
requirements for Transport Rule units
that would result in clear, consistent,
rigorous, and transparent monitoring
and reporting of all emissions. Such
monitoring and reporting would be the
basis for holding sources accountable
for their emissions and would be
essential to the success of the Transport
Rule trading programs. This is because
consistent and accurate measurement of
emissions would be necessary to ensure
that each allowance would actually
represent one ton of emissions and that
one ton of reported emissions from one
source would be equivalent to one ton
of reported emissions from another
source. This would establish the
integrity of each allowance and instill
confidence in the underlying market
mechanisms that would be central to
providing sources with flexibility in
achieving compliance. Moreover, given
the variation in the type, operation, and
fuel mix of sources covered by the
proposed Transport Rule trading
programs, EPA believes that emissions
would need to be monitored
continuously in order to ensure the
precision, reliability, accuracy, and
timeliness of emissions data supporting
the trading programs.
In §§ 97.430 through 97.435, 97.530
through 97.535, 97.630 through 97.635,
and 97.730 through 97.735, EPA
proposes the monitoring, recordkeeping,
and reporting requirements for the
Transport Rule NOX annual, NOX ozone
season, SO2 Group 1, and SO2 Group 2
trading programs, respectively. 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 found. The proposed provisions are
virtually the same as the monitoring,
recordkeeping, and reporting
requirements under previous EPAadministered trading programs, e.g., the
ARP and NOX Budget and CAIR trading
programs.
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Part 75 was originally developed for
the ARP and addressed SO2 mass
emissions and NOX emissions rate. The
ARP, as established by Congress in CAA
Title IV, requires the use of continuous
emission monitoring systems (CEMS) or
an alternative monitoring system that is
demonstrated to provide information
with the same precision, reliability,
accuracy, and timeliness as a CEMS.
Subsequently, Part 75 was expanded, for
purposes of the NOX Budget Trading
Program under the NOX SIP Call, to
address monitoring and reporting of
NOX mass emissions. 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,
under Part 75, the Administrator can
approve petitions for alternatives to Part
75 requirements.
The proposed monitoring and
reporting provisions for the Transport
Rule trading programs would allow use
of these same options and petition
procedures and would reference the
applicable provisions in Part 75.
Existing Transport Rule units would be
required to install and certify
monitoring systems by the beginning of
the relevant Transport Rule trading
program. New Transport Rule units
have separate deadlines based upon the
date of commencement of commercial
operation. Recognizing that many of the
Transport Rule units are already
monitoring NOX and/or SO2 under Part
75 through existing trading programs,
continued use of previously certified
monitoring systems would be allowed
when appropriate rather than
automatically requiring recertification.
The quality assurance (QA)
requirements for the ARP that were
mandated by Congress under CAA Title
IV are codified in Appendices A and B
of Part 75. Part 75 specifies 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 daily calibrations. A
standard set of data validation rules
apply to all of the monitoring
methodologies. These stringent
requirements result in an accurate
accounting of the mass emissions from
each unit, and EPA provides prompt
feedback if the monitoring system is not
operating properly. In addition, when
the monitoring system is not operating
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properly, standard substitute data
procedures are applied and result in a
conservative estimate of emissions for
the period involved. This ensures a
level playing field among the regulated
units, with consistent accounting for
every ton of emissions, and also
provides an incentive to properly
maintain, and meet the QA
requirements for, each monitoring
system. The monitoring and reporting
provisions in the proposed Transport
Rule trading program regulations would
contain the same QA requirements and
substitute data procedures as in Part 75
and would reference the applicable
provisions in Part 75.
Part 75 requires electronic
submission, to the Administrator and in
a format prescribed by the
Administrator, of a quarterly emissions
report containing all of the emissions
data specified in the recordkeeping
provisions of Part 75. EPA has found
that centralized, electronic reporting
using a consistent format is necessary to
ensure consistent review and public
posting of the emissions data for
covered units, which contribute to the
integrity, efficiency, and transparency of
trading programs. Further, the inclusion
of all emissions data in a single
quarterly report for each unit means
that, if the same data are needed for
multiple trading programs, the unit only
needs to report it once in the form of
one comprehensive report. The
reporting provisions in the proposed
Transport Rule trading program
regulations would contain the same
requirements for submission to the
Administrator of electronic,
comprehensive quarterly reports as in
Part 75. As discussed above, the
reporting provisions would also include
a process for resubmission of quarterly
reports where appropriate.
5. State Budgets/Intrastate Trading
Remedy Option
As noted earlier in this preamble, in
addition to the remedy option included
in the proposed FIPs, EPA is taking
comment on two alternative options for
eliminating all or part of the emissions
in upwind states that significantly
contribute to nonattainment or interfere
with maintenance in downwind states.
The first of these alternative options is
the State Budgets/Intrastate Trading
option described below. EPA is
considering the relative merits of this
option and requests comment on
whether it should be included in the
final FIPs. EPA also identifies below a
number of disadvantages that raise
concerns for EPA and are explained
later in this section. EPA requests
comment on these issues and their
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impacts on and significance for any
final rule.
a. Description of Option
The State Budgets/Intrastate Trading
option would set state-specific caps for
SO2, NOX annual, and NOX ozone
season emissions from EGUs and create
separate allowance trading programs
within each state in the respective
regions starting in 2012. The statespecific caps would ensure that all
required reductions occur within the
state and thus would address the Court’s
concerns about abating each individual
upwind state’s unlawful emissions
under CAA section 110(a)(2)(D)(i)(I).
Similar to other trading programs, the
owners and operators of each source
would be required to surrender to EPA
one allowance for every ton of
emissions after the end of every control
period. However, a source could only
use, for compliance with this
requirement, an allowance issued for
the state where the source was located.
For purposes of obtaining allowances
usable in compliance, sources within
each state could trade allowances
amongst themselves, but not with
sources located in other states. Total
emissions in each state could not exceed
that state’s budget and there would be
no shifting of emissions to other states
thus ensuring that each state’s
contribution to nonattainment and
interference with maintenance with
regard to downwind states would be
adequately addressed. Banking of
allowances for use in a later period
would be permitted under this remedy
option.
Under this option, EPA would
allocate allowances to the covered
sources within each state, and sources
in the state could use for compliance
only allowances issued for the same
state. Even a company that operates
EGUs in multiple states would not be
permitted to use for compliance for one
of its sources allowances issued to
another of its sources in a different state.
In essence, this approach, if
implemented, would result in 28
separate trading programs for NOX
annual, 26 trading programs for NOX
ozone season, and 28 trading programs
for SO2 for a total of 82 new trading
programs to be administered by EPA.
These 82 trading programs would
require 82 separate sets of allowances.
Companies that own EGUs in more than
one state would also be responsible for
managing their allowances for each
program in each state separately.
Unlike the remedy option in the
proposed FIPs or the other alternative
remedy option, this option does not
include assurance provisions based on
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the variability limits described in
section IV. This option includes a
‘‘hard’’ cap for each state equal to its
budget, which provides assurance that
reductions will occur in each state and
which EPA believes makes additional
assurance provisions unnecessary. The
State Budgets/Intrastate Trading option
does allow banking and the use of
banked allowances to provide sources
with some degree of operational
flexibility in complying with the
program. Because this option includes
provisions for banking emissions
allowances (as does the proposed State
Budgets/Limited Trading remedy),
limited year-to-year (temporal)
emissions variability is allowed. EPA
requests comment on this approach to
providing for emissions variability. EPA
also requests comment on whether
assurance provisions based on
variability limits should be included in
this option.
b. How the Option Would Be
Implemented
(1) Applicability
Applicability would be the same for
the proposed remedy and for the two
alternative options, including this one.
Refer to section V.D.4 above for detailed
discussion on applicability.
(2) Allocation of Emissions Allowances
While the general approach for
calculating allowance allocations would
be the same as described above for State
Budgets/Limited Trading, EPA would
not distribute all of the allowances into
the source accounts each period. The
distribution of allowances would be
modified because of the concentrated
nature of numerous state power
markets, which would be reflected in
the state allowance markets if all
allowances were distributed in each
state based on factors reflecting
generation in that state. The electric
power sector tends to be highly
concentrated, and, within a state, the
majority of generation is often owned by
a relatively small number of companies.
This assessment of state electricity
markets is supported by analysis using
the Herfindahl-Hirschman Index, a way
to measure the size of firms in relation
to the industry and an indicator of the
amount of competition among them (see
Electric Generation Ownership, Market
Concentration and Auction Size
Technical Support Document). To
address this potential issue concerning
the allowance markets in many states,
under this option some allowances
would be withheld from certain sources
in each state that control a large share
of fossil-fueled power generation and
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would be made available for companies
with a small share of generation in the
state.
The reason for including this
provision is that the dominant power
generation companies in each state
would likely receive a large share of the
allocated allowances and as a result
might be able to exert control over
allowance prices in the state’s
allowance market. This market power
and potential for allowance price
manipulation could pose a threat to the
transparency and liquidity of allowance
markets and put small owners of fossilfuel fired generation at a disadvantage
regarding their compliance costs unless
the owners were given sufficient access
to allowances other than through direct
purchase from the state’s dominant
companies. Some of these owners of a
small share of generation might already
face higher control costs, higher
transaction costs, and less flexibility
regarding compliance options.
Moreover, the use of allowance
market power to manipulate prices
could have wider impacts on electricity
markets as a whole, electricity prices,
and electricity reliability both within
and across state borders. Therefore, the
State Budgets/Intrastate Trading
approach needs to address the potential
for excessive market power and ensure
that allowances would be available to
all covered sources at reasonable market
prices.
In order to address the potential
market power issue, under this option,
not all allowances would be allocated
using the allocation method described
above in section V.D.4. Rather, a small
portion of allowances would be
withheld from companies with a large
share of a state’s total fossil-fuel fired
electricity generation. These allowances
would be made available for purchase
by companies with a small share of
generation through an annual auction.
EPA is soliciting comments on
whether a potential market power
problem could arise or reasons why
market manipulation would not be a
concern under this alternative remedy.
EPA is also soliciting comments on
whether the approach of using an
annual auction to make allowances
available to small generators would
satisfactorily address this potential
issue. This approach is detailed in
subsection (3) below.
The approach described for new unit
set-asides and allocations to nonoperating units above for State Budgets/
Limited Trading in section V.D.4 would
remain the same for this option.
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(3) Auction of Emissions Allowances
The use of an annual allowance
auction would ensure that companies
with a small market share in a state
would have access to additional
allowances, if needed, other than
through direct purchase from a large
owner of generation and would reduce
the opportunity for market price
manipulation by dominant companies.
This means that EPA would hold a total
of 82 auctions every year to separately
auction SO2 and NOX ozone season and
NOX annual allowances in each of the
82 intrastate trading programs. The
auction format would be single-round,
uniform-price, sealed bid with an initial
reserve price of 70 to 80 percent of the
modeled allowance price. Reserve
prices would be updated at regular
intervals to reflect changes in average
market prices over time. Any unsold
allowances would be returned to the
sources from which they were withheld
on a proportional basis. Revenues from
the auctions would be deposited in the
U.S. Treasury, in accordance with 31
U.S.C. 3302.
EPA would use auctions to address
market power concerns rather than
other options it considered. The Agency
considered using a different allowance
allocation method that would take into
account an owner’s share of total
generation and distribute proportionally
more allowances to owners of a small
share of the total generation in each
state. This would also ensure that small
owners had sufficient allowances
without relying on the open markets.
However, EPA opted to use an
allocation methodology based directly
on the approach used to quantify each
state’s significant contribution to ensure
that a direct link exists between
allocations and significant contribution
to nonattainment or interference with
maintenance. EPA also considered
direct sales of allowances withheld from
dominant sources but believes that
auctions would be better suited for
determining the appropriate prices for
allowances than EPA would be at
setting fixed allowance prices for all
trading programs in all states. For these
reasons, EPA believes the use of
auctions would be the best method to
address the issue of potential allowance
market manipulation.
EPA prefers to use the single-round,
uniform-price, sealed bid format
because it is simple for all participants
to understand, relatively simple to
implement and administer, and deters
collusion among bidders. In addition,
the utility sector already is familiar with
this type of format, and EPA has several
years of experience running single-
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round, sealed-bid auctions for Title IV
SO2 allowances. Other formats
considered such as multi-round
auctions are believed to be more
complicated for participants to
understand and more complex to
administer and do not discourage
collusion.
Entities that meet the following
criteria would be eligible to participate
in the allowance auction: (1) They are
required to hold allowances in the state
for compliance; and (2) they own no
more than 10 percent of the total fossilfuel fired generation within the state
based on EPA’s modeled generation for
2014. EPA considered a range from 5 to
20 percent share of ownership for all
states and believes that 10 percent
ownership is appropriate for
determining what constitutes a small
market share for this rule. EPA believes
that by limiting the auction to entities
that own no more than 10 percent of the
fossil-fuel fired generation in a state, it
would ensure that each auction has
enough participants to make auctions
viable and competitive and also ensure
that the allowances are available only to
those companies that may be at a
disadvantage in the open markets.
Companies with more than a 10 percent
share of generation tend to operate
several units, have more flexibility,
receive a significant share of
allowances, and face lower control and
transaction costs. EPA is requesting
comment on the share of electric
generation used as a threshold for
determining participation in auctions
and also the percentage of allowances
available through auctions.
To implement this option, EPA would
withhold 2 to 5 percent of the
allowances that would be allocated to
companies with more than 10 percent of
the generation in order to supply
allowances for auction each period. This
amount is small enough not to have a
significant impact on those EGUs from
which the allowances are withheld and
large enough to provide a sufficient
number of allowances for auction. In
more highly concentrated states where
few companies control much of the
generation, a relatively greater number
of allowances would be available
through the auction to the smaller,
potentially disadvantaged companies.
Conversely, in states where the
electricity sector is less concentrated,
there is less threat of market
manipulation and greater likelihood of
liquid markets. Thus, in these states
relatively fewer allowances would be
withheld for auction.
Another variation on this alternative
option would be to divide companies in
each state into three groups, instead of
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just two. The first group would be the
companies that own no more than 10
percent of the total fossil-fuel generation
within the state and would be able to
participate in EPA’s allowance auctions.
The second group would be companies
that own a medium amount of fossilfuel fired generation (for example,
between 10 to 20 percent of the total).
These companies would not be allowed
to participate in auctions but also would
not have to contribute any allowances to
the auctions. Finally, the third group
would be those remaining companies
that own a large share of fossil-fuel
generation (for example, more than 20
percent of the total). A small percentage
of the allowances allocated to these
companies would be withheld to supply
the auctions. EPA is asking for
comments on this variation on the
alternative option and other ways to
address potential market power
problems and on this alternative option.
(4) Allowance Management System
The allowance management system
for the State Budgets/Intrastate Trading
option would be consistent with the
allowance management system for the
State Budgets/Limited Trading programs
described above, and with the data
system structure EPA has developed for
allowance management under its
existing cap and trade programs such as
the CAIR and the Acid Rain Program.
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(5) Monitoring and Reporting
Monitoring and reporting provisions
would require complete, quality-assured
monitoring, and timely reporting of
emissions to assure accountability and
provide public access to data, and
would be the same for EPA’s proposed
remedy and the State Budgets/Intrastate
Trading option. Refer to section V.D.4
above for detailed discussion on
monitoring and reporting requirements.
(6) Penalties
Under the State Budgets/Intrastate
Trading option for an annual control
program (i.e., any of the 28 SO2 or 28
NOX annual programs), the requirement
that each source hold in its compliance
account one allowance for each ton of
emissions, and the penalties for failure
to meet this requirement, would be the
same as described previously in the
Penalties section for the State Budgets/
Limited Trading remedy option.
However, because sources in a given
state can only use allowances issued for
that state, the penalties associated with
failure to hold one allowance for each
ton of emissions are adequate to ensure
that emissions from the state do not
exceed the state budget (except for some
temporal variability due to banking). For
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this reason, EPA does not believe that
any other penalties or assurance
provisions (such as the assurance
provisions used in the State Budgets/
Limited Trading remedy) are necessary
to ensure that each state eliminates the
portion of significant contribution and
interference with maintenance that EPA
has identified in today’s action. EPA
requests comment on this conclusion.
c. How the State Budgets/Intrastate
Trading Remedy is Consistent With the
Court’s Opinions
The state budgets/intrastate trading
remedy, by establishing state-specific
caps on annual or ozone-season EGU
emissions, directly implements the
section 110(a)(2)(D)(i)(I) requirement
that emissions from sources that
contribute significantly to
nonattainment in, or interfere with
maintenance by, any other state with
respect to any such national primary or
secondary ambient air quality standard
be prohibited. Of the three remedy
options considered, this option provides
the most certainty regarding total annual
or ozone-season emissions from each
state. For this reason, it most directly
addresses the statutory mandate that the
emissions reductions occur ‘‘within the
State.’’
To implement this remedy option,
EPA would use the state budgets
without variability limits, developed in
accordance with the procedures
described in sections IV.D and IV.E.
These budgets represent EPA’s
projection of each affected state’s EGU
emissions in an average year (before
accounting for the inherent variability
in power system operations) after the
elimination of all emissions that EPA
has identified as significantly
contributing to nonattainment or
interference with maintenance.
The number of allowances in each
state budget would be distributed or
made available (through an auction or
otherwise) to sources in that state. Only
allowances distributed or made
available to sources in a particular state
could be used by sources in that state to
satisfy the requirement to hold one
allowance for every ton of emissions.
Thus, annual (or ozone season)
emissions in the state would be capped
at the level of the state budget. The
limited variability due to banking of
emissions could allow limited temporal
shifting of emissions, but would not
alter the requirement that reductions
occur within the state. This remedy is
thus sufficient to ensure that all
significant contribution and interference
with maintenance identified by EPA in
today’s action is eliminated.
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d. Electric Reliability Issues
EPA requests comments about
whether the State Budgets/Intrastate
Trading alternative option could have
adverse consequences for electric
reliability. The grid regions, and the
movement of electricity within each
grid region, do not correspond with, and
are not limited by, state borders. For
example, an increase in electricity
demand (e.g., due to a hot summer), or
a decrease in electricity supply (e.g.,
due to a major generation capacity
outage), in a given state will not
necessarily be met, or offset, through
increased electricity generation in that
same state. Instead, the increased
demand or reduced supply may well
result in increased generation outside
that state. The sources of the increased
generation will be determined by
availability and economics and will not
necessarily be confined to generation
sources in that state. In fact, the ability
to obtain additional or replacement
supply from sources in another part of
the state or from another state enhances
electric reliability.
Although companies in one state
obtain electricity from sources in
multiple states, the State Budgets/
Intrastate Trading option would
establish emissions budgets on a state
basis and would not allow sources in
one state to use allowances issued to
sources in other states. A source could
use, in covering emissions for the
current year, both allowances allocated
for the current year and banked
allowances issued by its state for a past
year. However, this option would
provide sources less trading flexibility
than the proposed State Budgets/
Limited Trading remedy. The other
remedy options allow for emissions
variability, which should largely
address electric reliability concerns.
EPA requests comment on whether
the State Budgets/Intrastate Trading
alternative would provide sufficient
flexibility for reliable operation of the
integrated grid and, if not, whether there
would be ways of preventing or
reducing adverse effects such as
including additional emissions
variability provisions in this option or
other approaches. EPA requests
comment on approaches to provide
additional emissions variability, or
other approaches to increasing
flexibility, in this option that would be
consistent with eliminating all or part of
the significant contribution and
interference with maintenance that EPA
has identified.
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e. How Smaller Market Trading
Programs Have Worked
These examples of small trading
programs below are relevant to further
understanding of the State Budgets/
Intrastate Trading remedy option. While
small trading programs can succeed,
they can also have serious consequences
for allowance and electricity markets.
Budgets and caps, allowance
availability, and prices all can have a
profound impact on generation and
energy prices for consumers in addition
to any air quality benefits. In addition,
states range in size and number of
potential program participants making
each state’s circumstances unique and
more challenging for EPA to monitor.
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(1) Texas Mass Emissions Cap and
Trade (MECT)
EPA has approved a NOX cap and
trade program as part of an ozone
attainment SIP for the Houston
Galveston Brazoria (HGB)
nonattainment area in Texas. The
program knows as the Mass Emissions
Cap and Trade (MECT) program
establishes a mandatory NOX annual
emissions cap for stationary facilities in
the HGB area located at sites with a
collective uncontrolled design capacity
to emit 10 tons per year or more of NOX.
The MECT program source population
is relatively small but very diverse and
covers, among others, EGUs, refineries,
chemical plants, and industrial and
commercial boilers. The diverse source
population allows the MECT program to
be a viable means of reducing NOX
emissions without impacting electric
reliability. Overall, the MECT program
has not encountered major problems
caused by its small size and has resulted
in environmental benefits for the HGB
area.
The MECT program establishes a hard
cap for NOX emissions at a level
modeled as necessary for the area to
reach ozone attainment. The MECT
program started January 1, 2002 and the
NOX cap stepped down each subsequent
year until reaching the final cap level of
80 percent of the baseline NOX
emissions in January 2007. In the MECT
program one allowance is equivalent to
one ton of NOX emissions. Allowances
are allocated to existing facilities on
January 1 of each control period, which
spans the calendar year. Facilities that
do not receive allowances as ‘‘existing
facilities’’ (those in operation at the time
of program inception) must purchase
excess allowances from other covered
sources to operate and demonstrate
compliance. All covered sources are
required to hold sufficient allowances at
the end of each control period to equal
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NOX emissions during the same time
period. Allowances can be used in the
control period of allocation, traded to
another covered source in the MECT for
use in the same time period, or banked
for use in the following control period.
Allowances can be traded in one of
four ways: Vintage trades, current year
trades, individual future year trades, or
stream trades. Vintage trades involve the
immediate transfer of vintage
allowances. Current year trades involve
the immediate transfer of current
allowances. Individual future year and
stream trades involve the transfer of
future allowances, with stream trades
involving a transfer of allowances in
perpetuity. Analysis conducted by the
Texas Commission on Environmental
Quality of the MECT program trading
history shows that approximately 20
percent of the allowances allocated each
year are traded and that nearly 50
percent of all program participants have
participated in allowance trading.
Allowance prices are set by market
demand. Prices of individual year
allowances have steadily increased as
the program has progressed, showing
that the value of the allowances
increases as the cap tightens. Stream
trade prices have fluctuated throughout
the program, but have steadily increased
as the final cap level has been reached.
(2) Regional Clean Air Incentives Market
(RECLAIM)
In comparison to MECT, RECLAIM is
a small trading program that has faced
a number of challenges due to initial
program design decisions. In 1994,
RECLAIM established a cap and trade
program for NOX and SO2 emissions as
part of an effort to improve air quality
in the Los Angeles area. Every year the
caps decline to meet the objective of
getting the area into compliance with
ozone and particulate matter NAAQS.
One noteworthy feature of the RECLAIM
trading programs is the two overlapping
cycles. Roughly equal numbers of
facilities were assigned to each of the
two compliance cycles. Facilities in
compliance cycle 1 complete their
twelve month cycle at the end of the
calendar year (December 31), while
facilities in compliance cycle 2
complete their twelve-month cycle at
the end of the fiscal year (June 30).
Around 300 facilities have participated
annually in the RECLAIM NOX trading
program. Every facility then complied
using valid credits of either cycle, but
banking of allowances for use in a later
period was not allowed.
RECLAIM Trading Credits (RTC)
prices for NOX rose from about $3,000
per ton early in 2000 to nearly $20,000
per ton in June and up to about $70,000
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per ton in August of that year. Prices of
RTCs during the California energy crisis
during 2000 and 2001 averaged in the
$50,000 per ton range.102 While the
California crisis was the result of several
malfunctions in the market, the RTC
price spike was exacerbated by a
number of factors starting with the fact
that few emissions reductions had been
made in earlier years. Prior to the
California crisis, RTCs had been overallocated, RTC prices had remained low,
and utilities had taken little action to
install costly controls. When emissions
increased and exceeded the level of
allocated RTCs, prices shot up to very
high levels. In addition, there has been
speculation that high RTC prices at the
time were partly caused by the high
demand for credits resulting directly
from the manipulation of the power
market by generators.103
The operation of the RECLAIM market
also contributed to the high prices in the
overall power markets. During this
period, generators would pay
excessively high prices for RTCs in
order to raise the price of southern
California generation needed to meet
demand in the California Independent
System Operator (CAISO).
Subsequently, generation with high RTC
costs in the RECLAIM area would be
used to set the electricity price for all of
California. The result was that
generators could then collect excessive
profits on their generation located
outside the RECLAIM area. In addition,
RECLAIM’s overlapping compliance
cycles and assignment of facilities to
one of two compliance cycles appears to
have contributed to some confusion
among the participants in the
markets.104 Since that time, significant
changes have been adopted to improve
the program.
According to the audit report for the
2007 compliance period, total aggregate
NOX emissions were below total
allocations by 21 percent and total
aggregate SOX emissions were below
total allocations by 13 percent. Since
January 2008, NOX RTCs prices have
been declining and have not exceeded
$15,000 per ton.
102 Joskow, Paul and Edward Kahn, 2002. A
Quantitative Analysis of Pricing Behavior In
California’s Wholesale Electricity Market During
Summer 2000: The Final Word.
103 Kolstad, Jonathan T. and Frank A. Wolak,
2003. Using Environmental Emissions Permit Prices
to Raise Electricity Prices: Evidence from the
California Electricity Market. Published by
University of California Energy Institute.
104 Holland, Stephen P. and Michael Moore, 2008.
When to Pollute, When to Abate? Intertemporal
Permit Use in the Los Angeles NOX Market.
Published by University of California Energy
Institute.
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f. Why This Is Not the Preferred Option
As explained above, EPA is requesting
comment on a State Budgets/Intrastate
Trading remedy as an alternative option
because this option would provide
certainty regarding emissions from each
state. However, this option would be
more resource intensive, more complex,
less flexible, and potentially more
susceptible to market manipulation than
the other options on which EPA is
taking comment.
Although this remedy may be
perceived as relatively easy to
understand and follow, it would
actually be more burdensome to
administer due to the number of trading
programs that would be required to
operate simultaneously and annual
auctions that would be held every year
to address the issues of market power
within states. It would also result in a
greater burden for participants operating
EGUs in several states. Finally, EPA is
asking for comment on whether this
option raises electric reliability issues
since sources would have less flexibility
and fewer options for compliance. EPA
is requesting comments on this
approach, specifically on alterations
that could address the drawbacks
identified above or on any other
weaknesses of this option not identified
by EPA. EPA also welcomes comments
regarding the validity of the concerns
with this approach identified above.
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6. Direct Control Remedy Option
The second alternative option on
which EPA is requesting comment is the
direct control option described in this
section. EPA is considering the relative
merits of this option and requests
comment on whether a direct control
remedy option should be included in
the final FIPs.
There are a variety of ways to
construct a direct control option. The
approach that EPA is presenting as an
alternative to the remedy in the
proposed FIPs would assign emissions
rate limits to individual sources.
Emissions limits would take the form of
input-based emissions rate limits (lb/
mmBtu).
EPA requests comments on the direct
control remedy summarized later and
the approach for determining emissions
rate limits, which is described in greater
detail in the ‘‘State Budgets, Unit
Allocations, and Unit Emissions Rates’’
TSD in the docket for this rulemaking.
Specifically, EPA requests comment on
the general use of a direct control
remedy as well as the specific rate-based
direct control approach described later.
EPA also requests comment on the
potential weakness of this remedy
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option identified in the discussion later.
In addition, EPA requests comment on
alternate methodologies which could be
used to implement a direct control
remedy.
See section V.E. later for projected
costs and emissions associated with this
option.
a. Description of Option
Unlike the proposed remedy option
(State Budgets/Limited Trading) and the
other alternative remedy option
(Intrastate Trading) discussed
previously, which both use flexible capand-trade approaches, a direct control
remedy would directly regulate
individual sources. Under this direct
control remedy alternative, each owner
of EGUs would be required to meet
specified average emissions rate limits
covering all of its EGUs in each covered
state. In a state covered for the 24-hour
and/or annual PM2.5 NAAQS, the direct
control remedy option would require
each company within the state to meet
specified EGU annual emissions rate
limits for SO2 and NOX. In a state
covered for the 8-hour ozone NAAQS,
this remedy would require each
company within the state to meet
specified EGU ozone season emissions
rate limits for NOX. EPA would set
emissions rates on a unit-by-unit basis
in all covered states (see approach to
determine emissions rate limits, later).
While emissions rates in all states
would be set on a unit-by-unit level, a
company would be allowed to average
the emissions at its units within each
state to meet the specified within-thestate rate limits. Company-level average
rates would be calculated as companylevel total emissions divided by
company-level total heat input in each
state. Analogously, allowable companylevel average rates would be calculated
using unit-specific rate limits and the
heat inputs used to determine those
allowable rates (as discussed in 6.b.1). A
company that exceeded the applicable
average rate limits would be subject to
penalties (described later).
In addition, to address the potential
variability in annual emissions
associated with emissions rate limits
(i.e., not all years are average), starting
in 2012, each state’s total annual (or
ozone season, as applicable) EGU
emissions would also be capped.
Emissions from EGUs in each state
would be limited to the state’s
emissions budget with the variability
limit. Each state’s EGU emissions would
be capped in the following two ways.
First, the state’s EGU emissions would
not be permitted to exceed the state
budget with the state’s 1-year variability
limit in any year (or ozone season, as
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applicable). Second, on average, the
state’s EGU emissions would not be
permitted to exceed the budget with the
state’s 3-year variability limit, evaluated
as a 3-year rolling annual (or ozone
season) average (or, in SO2 group 1
states during 2012 and 2013, a 2-year
rolling average). See section IV.E for
lists of each state’s emissions budgets.
Section IV.F describes EPA’s proposed
approach to variability. Tables IV.F–1
through IV.F–3 present 1-year and
3-year variability limits. Table IV.F–4
presents 1-year and 2-year variability
limits for SO2 group 1 states during
2012 and 2013.
If total EGU emissions in a state
exceed either of these limits (i.e., budget
with 1-year variability limit in any year,
or budget with 2-or 3-year variability
limit on average), then each company
with units in the state whose emissions
in the state exceeded the company’s
share of the state budget with variability
limit would be subject to a penalty.
These assurance provisions are designed
to assure that emissions in each covered
state do not exceed the state’s budget
with variability limit. They are
described later. EPA also believes the
penalty provisions described later are
sufficient to ensure that these caps
would not be exceeded.
To implement this remedy option,
EPA would determine unit-level
emissions rate limits for SO2, NOX
annual, and NOX ozone season at levels
such that, if the units operated at the
levels assumed in determining the state
budgets, total emissions of each
pollutant from these units would sum to
each state’s emissions budget for the
pollutant without the variability limit.
The method for determining these rate
limits is described later.
An alternative direct control approach
would be to create individual unit-level
annual emissions caps (e.g., tons/year)
in order to cap emissions in each state.
However, this approach would greatly
limit operational flexibility and increase
risk to electric reliability. For example,
a unit-level annual emissions cap
approach could prevent a peaking unit
from running at a time when the unit is
necessary for electric reliability. EPA
does not believe that a unit-level annual
emissions cap approach is workable.
b. How the Option Would Be
Implemented
(1) Approach To Determine Emissions
Rate Limits
To implement this remedy option,
EPA would determine unit-level
emissions rate limits for SO2, NOX
annual, and NOX ozone season, for
covered EGUs in the covered states.
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Emissions rate limits would be set at
levels such that, if the units operated at
the levels assumed in determining the
state budgets, total emissions from these
units would sum to the state budgets. In
a state covered for purposes of the PM2.5
NAAQS, EPA would determine SO2 and
NOX annual emissions rate limits for
each covered EGU. In a state covered for
purposes of the 8-hour ozone NAAQS,
EPA would determine NOX ozone
season emissions rate limits for each
covered EGU.
Emissions rate limits for Phase I (2012
and 2013). State budgets were derived
from the lower of available 2007–2009
quarterly emissions or IPM base case
projections for 2012, at the state level.
Analogous to state budget calculation,
EPA would base the Phase I annual
emissions rate limit on either the unit’s
reported annual emissions rate or the
IPM projected rate. Rates based on
reported data would be calculated using
the most recent first, second, third, and
fourth quarters of emissions data
reported to EPA, between the first
quarter of 2007 and the third quarter of
2009, where four such quarters of
reported data are available. EPA would
determine ozone season rates based on
a unit’s most recent ozone season
emissions reported to EPA during the
period of 2007–2009, if available, and
projections or source-specific judgments
otherwise.
For units where EPA is aware that
SO2 or NOX controls will be installed by
2012 and such controls were not
reflected in the unit’s reported
emissions rate as determined previously
(i.e., the control was not in operation
during the period of time on which
emissions limits were based), EPA
would determine the Phase I emissions
rate limit as the historic rate adjusted
(reduced) to reflect operation of the
planned control equipment at an
emissions rate consistent with operation
of that equipment. Emissions rate limits
would be determined based on the
assumption that units operate all
existing SO2 and NOX control
equipment, and the assumption that the
type of fuel used does not change from
that used in determining the unadjusted
rate limit.
For those EGUs which did not report
a first, second, third, and fourth quarter
of SO2, NOX, and/or a complete ozone
season of NOX emissions data to EPA
during the 2007–2009 period, or for
those units located in states where
budgets are based on IPM projections,
EPA would determine emissions rate
limits based on modeling projections.
Based on the analysis conducted for this
proposed rule, EPA would use modeling
projections to determine SO2 rates for
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approximately 1,600 units, annual NOX
rates for 1,800 units, and ozone season
NOX rates for 1,900 units. EPA seeks
comment on the ability of all such units
to achieve these limits based on IPM
projections. See table entitled ‘‘Phase I
and Phase II unit-level emission rate
limits’’ located in the ‘‘State Budgets,
Unit Allocations, and Unit Emissions
Rates’’ TSD in the docket for this
rulemaking.
For those units that did not report
data for a given pollutant and time
frame combination and also were not
included in IPM modeling, EPA would
need to determine permissible rates
based on unit characteristics (e.g., types
and sizes of units, fuel type). The
approach would also need to take into
account the variety of controls and
measures that can be used to limit
emissions, including available fuels.
While EPA does not believe that such
units exist, EPA is taking comment on
the existence of units that did not report
first, second, third, and fourth quarter
data to EPA between the first quarter of
2007 and the third quarter of 2009, and
are not included in IPM modeling. If
EPA is made aware of such units, the
unit-level analysis required to establish
such limits would be extremely
complex, and could impact the ability of
EPA to require the reductions as quickly
as under other remedy approaches.
EPA is also taking comment on an
alternative approach for setting
emissions rate limits for those units
which did not report a first, second,
third, and fourth quarter of SO2, NOX,
and/or a complete ozone season of NOX
emissions data to EPA during the 2007–
2009 period. In this alternative
approach, EPA could develop specific
limits that would apply to a large group
of units with varying characteristics.
The numerous variables that contribute
to differences in units’’ emissions rates
complicate development of limits for a
large group of units. Therefore, to
ensure that all units in a broadlydefined group could achieve their rate
limits, it would be necessary to either
establish limits that are fairly weak so
that the poorest-performing units could
meet the requirements (‘‘lowestcommon-denominator’’ effect), or,
design more stringent requirements but
include provisions for exceptions to the
requirements. At this time, EPA believes
using IPM projections and sourcespecific judgments is preferable to the
alternative of group-based limits, and
seeks comments on this alternative.
Emissions rate limits for Phase II
(2014 and onward). For EGUs in states
that are in SO2 group 1 (i.e., the more
stringent SO2 group), EPA would further
adjust (reduce) SO2 emissions rates for
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certain EGUs that EPA projects would
install FGD in modeling of the proposed
remedy option (at less than $2000 per
ton); for such units EPA would
determine emissions rate limits at rates
consistent with FGD operation. For
other covered units, Phase II emissions
rate limits would be the same as Phase
I limits. Again, emissions rate limits
would be determined based on the
assumption that units operate all
existing SO2 and NOX control
equipment, and that the type of fuel
used does not change from that used in
determining the unadjusted rate limit.
Note that for ozone season NOX there is
only one phase.
Emissions rate limits for new units.
The emissions rate limits for covered
new units would be set equal to the
permit rates for these units.
EPA has calculated specific emissions
rate limits for each existing unit that
would be covered under this direct
control remedy option. These unit-level
emissions rate limits appear in a table
entitled ‘‘Phase I and Phase II unit-level
emissions rate limits’’ located in the
‘‘State Budgets, Unit Allocations, and
Unit Emissions Rates’’ TSD in the docket
for this rulemaking. More detailed
description of the approach is also
provided in the TSD. EPA is requesting
comment on this approach for
determining the emissions rate limits
described in the TSD and on the limits
themselves.
(2) Applicability
Applicability would be the same for
all three remedies. Refer to section
V.D.4 previously for detailed discussion
on applicability.
(3) Monitoring and Reporting
Monitoring provisions would be the
same for all three remedies. The direct
control option would require minor
changes to the reporting and record
keeping requirements due to the need to
collect information on both emissions
rates and mass. The provisions would
require complete, accurate measurement
and timely reporting of emissions to
assure accountability and provide
public access to data. Refer to section
V.D.4 previously for detailed discussion
on monitoring and reporting
requirements.
(4) Assurance Provisions
As discussed previously, starting in
2012, the direct control remedy
alternative would include assurance
provisions designed to assure that
emissions in each covered state do not
exceed the state’s emissions budget with
variability limit. The state’s EGU
emissions would not be permitted to
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exceed the state budget with 1-year
variability limit in any year (or ozone
season, as applicable). Additionally, on
a 3-year rolling average basis, the state’s
EGU emissions would not be permitted
to exceed the budget with the 3-year
variability limit (evaluated on an annual
or ozone season basis, as appropriate).
Furthermore, during 2012 and 2013,
SO2 emissions from EGUs in group 1
states (i.e., the more stringent SO2
group) would not be permitted to
exceed the budget with the state’s 2-year
variability limit, evaluated as a 2-year
rolling annual average. Section IV.E in
this preamble lists each state’s
emissions budget, and section IV.F lists
the 1-, 2-, and 3-year variability limits,
as applicable.
Note that for EGUs in states that are
in SO2 group 2 (i.e., the less stringent
SO2 group) and/or states required to
reduce NOX emissions, EPA would
apply only the 1-year variability limit in
2012 and 2013, and not a 2-year
variability limit. Because emissions
would be evaluated against the 3-year
variability limit on a 3-year rolling
average basis, the application of the 3year variability limit in 2014 would also
serve to limit emissions in 2012 and
2013. For EGUs in SO2 group 1 states
(i.e., the more stringent SO2 group) EPA
would apply a different 1-year SO2
variability limit in 2012 and 2013 than
for 2014 and later. Furthermore, in these
group 1 states, EPA would apply a 2year SO2 variability limit in 2012 and
2013, and a 3-year limit for later years
(section IV.F discusses why variability
limits for the group 1 states would differ
in 2012 and 2013).
If total EGU emissions in a state
exceed either the state’s budget with
1-year variability limit in any year, or
budget with 3-year variability limit (or
2-year limit, as appropriate) on average,
then each company with units in the
state whose emissions in the state
exceeded its share of the state budget
with variability limit would be subject
to a penalty for its share of emissions
above the budget with variability limit.
In the State Budgets/Limited Trading
remedy described previously, the
proposed assurance provisions include
an allowance surrender requirement.
Those assurance provisions would
require a company to surrender one
allowance for each ton of the company’s
proportional share of the amount the
state’s EGU emissions exceed the budget
with variability limit. This allowance
surrender requirement is in addition to
the trading program requirement to
surrender one allowance for every ton
emitted.
In the direct control alternative,
however, allowances are not allocated to
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units therefore an allowance surrender
requirement is not feasible. Instead, for
this alternative, a company with
emissions over its share of the budget
with variability limit would be in
violation of the CAA and subject to
discretionary penalties. The tonnage
amount of the company’s violation, i.e.,
the company’s excess emissions under
the assurance provisions, would be its
proportional share of the amount that
the state’s EGU emissions exceed the
budget with the variability limit. Each
ton of the company’s excess emissions,
as well as each day in the averaging
period, would be a violation.
In this direct control remedy
alternative, a company’s share of the
state budget with variability limit would
be determined using the same approach
described in the State Budgets/Limited
Trading option, previously. That
approach is based on allowance
allocations; although the direct control
remedy would not allocate allowances
to sources, this remedy would use the
allocation method described in State
Budgets/Limited Trading in determining
a company’s share of the state budget.
The assurance provisions would
commence in 2012 for this direct
control option. In contrast and for the
reasons explained in section V.D.4, for
the proposed State Budgets/Limited
Trading remedy, EPA is proposing to
start applying the assurance provisions
in 2014. The combination of
circumstances for State Budgets/Limited
Trading—known locations of controls
and a price on each ton emitted—
provides greater certainty of where
reductions will occur during 2012 and
2013 than would be provided by the
direct control program. In contrast to the
State Budgets/Limited Trading remedy,
the direct control program does not put
a price on emitting SO2 or NOX so does
not provide that incentive to reduce
emissions. Sources can increase
generation, while meeting the emissions
rate limits, and increase their emissions.
For these reasons, the direct control
program provides less certainty
regarding the location of emissions in
the short term. For this reason, EPA
believes that it would be appropriate to
apply the assurance provisions under
this remedy option beginning in 2012.
EPA requests comment on these
assurance provisions.
(5) Penalties
As explained previously, under this
direct control remedy approach, each
owner of EGUs within a covered state
would be required to meet specified
average emissions rate limits for SO2
and/or NOX emission for all of its EGUs.
For the annual SO2 or NOX control
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programs, if a company were to exceed
the applicable company-wide annual
average rate limit, the company would
be in violation of the CAA and subject
to discretionary civil penalties.
The excess emissions of the owner’s
EGUs would be calculated as the EGUs’’
actual annual average emissions rate
minus the applicable annual average
emissions rate limit, with the difference
multiplied by the EGUs’’ total actual
annual heat input. Each ton of excess
emissions, as well as each day in the
averaging period (e.g., 365 days for an
annual program), would be a violation
of the CAA. The maximum
discretionary penalty under CAA
Section 113 is $25,000 (inflationadjusted to $37,500 for 2009) per
violation.
For the ozone season NOX program,
the penalty provisions would work in
the same manner described herein
except on an ozone season basis rather
than annual.
In addition, any company with EGU
emissions exceeding its share of the
state budget with variability limit for
SO2, NOX annual or NOX ozone season
would also be in violation of the CAA
and subject to discretionary civil
penalties explained earlier in this
section if, in any year (or ozone season,
as applicable), the state as a whole
exceeds its budget with variability limit
(see description of assurance provisions,
previously).
EPA requests comment on the penalty
provisions.
c. How the Direct Control Remedy Is
Consistent With the Court’s Opinions
The direct control remedy option
would implement the section
110(a)(2)(D)(i)(I) requirement that
‘‘emissions from sources that contribute
significantly and interfere with
maintenance in downwind
nonattainment areas’’ be prohibited. It
would do so by establishing for covered
EGUs specific emissions rate limits,
with company-wide within state
averaging. Emissions rates in all states
would be set on a unit-by-unit basis at
levels such that, if the units operated at
the levels assumed in determining the
state budgets, total emissions from these
units would sum to each state’s
emissions budgets without the
variability limits. A company could
average the emissions at its units within
each state to meet specified within-thestate rate limits. This approach would
directly limit emissions from EGUs in
each covered state, providing assurance
that emissions reductions would occur
within each state consistent with the
mandate of section 110(a)(2)(D)(i)(I).
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Because individual EGUs would be
required to meet specific emissions rate
limits (with within-state company-wide
averaging), this option would ensure
that required controls and measures are
installed and implemented within the
state. The fact that emissions, after
implementation of all controls required
to meet the emissions rate limits, may
vary based on the amount of generation
in each state is not inconsistent with the
section 110(a)(2)(D)(i)(I) requirement
that all significant contribution and
interference with maintenance be
eliminated. As noted previously,
changes in generation due to changing
meteorology, demand growth, or
disruptions in electricity supply from
other units can all affect the amount of
generation needed in a specific state and
thus the baseline emissions from that
state. Because baseline emissions are
variable, emissions after the elimination
of all significant contribution are also
somewhat variable.
Further, any such variation in
emissions would be limited. As with the
State Budgets/Limited Trading option
described previously, no state’s EGU
emissions would be permitted to exceed
the state budget with variability limit in
any year (or ozone season, as
applicable). Nor would any state’s EGU
emissions be permitted, on average, to
exceed the budget plus a specified
portion of the state’s variability limit,
evaluated as a 3-year rolling annual (or
ozone season) average (or, in SO2 group
1 states during 2012–2013, a 2-year
rolling annual average). Section IV in
this preamble lists each state’s
emissions budget, and 1-, 2-, and 3-year
variability limit, as applicable.
d. Electric Reliability Issues
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The risk to electric reliability is
considered low under the direct control
remedy option. Specifically, the
provisions for the variability limits and
company averaging within each state
help to alleviate electric reliability
concerns. Therefore, EGUs are expected
to be able to both comply with their
emissions rate limits and reliably
provide electricity to customers. EPA
requests comment on electric reliability
issues.
e. Why This Is Not the Preferred Option
As explained previously, EPA is
requesting comment on the merits and
weaknesses of this direct control
remedy option. EPA did not include this
remedy option in the proposed FIPs;
however, we continue to consider this
option and are taking comment on
whether this option should be included
in the FIPs. This option would provide
assurance that companies in each state
are meeting specific emissions rate
limits and would also ensure that
annual emissions from each state are
capped. Additionally, the direct control
option may be perceived as easy to
understand and follow. Nonetheless, at
this time, EPA believes the direct
control option is inferior to the
preferred approach. EPA requests
comments on the validity of EPA’s
concerns regarding this option and
alternative methods for addressing those
concerns.
EPA modeling projects fewer
emissions reductions under the direct
control alternative than the proposed
State Budgets/Limited Trading remedy.
Additionally, the reductions would be
achieved at a higher cost than the
proposed remedy. See section V.E. for
projected costs and emissions.
A direct control program must
account for outliers, e.g., units that can
not install controls due to space
limitations. EPA believes that the
within-the-state company-wide
averaging in the direct control
alternative on which EPA is taking
comment likely mitigates this concern.
However, this averaging approach may
put an owner with a small number of
units within a state at a disadvantage
compared to an owner with a larger
number of units. EPA requests comment
on this issue.
Within the direct control approach on
which EPA is taking comment, the
assurance provisions (which limit a
company’s emissions within a state to
its share of the budget with the
variability limit if the state’s budget
with variability limit is exceeded) may
also put an owner with a small number
of units at a disadvantage compared to
an owner with a larger number of units
within a state. EPA seeks comment on
this issue.
A direct control program based on
emissions rate limits does not cap
annual emissions; if there is growth in
fossil generation within a state, a ratebased approach alone could allow
emissions increases. In the direct
control approach on which EPA
requests comment, the assurance
provisions provide some assurance of
achieving required reductions.
Notably, the direct control approach
described herein restricts compliance
options more than a trading approach.
EPA generally believes that granting
more flexibility to companies in meeting
an emissions reductions goal results in
the ability of those companies to meet
that goal at a lower cost and decreases
reliability risks in the electric power
system. While some portion of this
effect is captured in IPM modeling (see
section V.E. for projected costs and
emissions), some types of unforeseen
innovations in technology, fuel
switching, and management cannot be
captured by modeling. Any potential
innovations and resulting cost savings
are more likely to be found and utilized
in the presence of regulatory flexibility.
Based on historical experience, EPA
believes that the benefits offered by a
flexible trading approach are large and
should be considered qualitatively, even
if they cannot be quantified. Many of
these benefits would be foregone under
the direct control approach.
E. Projected Costs and Emissions for
Each Remedy Option
Emission and cost projections for the
three remedies discussed previously
come from the Integrated Planning
Model (IPM), a dynamic linear
programming model of electric
generation in the contiguous U.S. For
each remedy, projected costs relative to
the base case appear in Table V.E–1.
The following section explains these
projections in light of how the remedies
differ and how they were represented in
the model. The emissions projections
below comprise fossil generation above
25 megawatts of capacity, the units that
would be subject to the rule. More detail
on the modeling of costs and emissions
can be found in the Regulatory Impact
Analysis for the proposed Transport
Rule and in the IPM Documentation.
TABLE V.E–1—PROJECTED INCREMENTAL COSTS DUE TO TRANSPORT RULE REMEDIES COMPARED TO BASELINE
WITHOUT TRANSPORT RULE OR CAIR
[Billion 2006 dollars]
2012
Limited Interstate Trading (proposed) .....................................................................................................................
Intrastate Trading .....................................................................................................................................................
Direct Control ...........................................................................................................................................................
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4.2
4.3
2.8
2.7
3.4
2.0
2.2
2.5
2.0
2.2
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1. State Budgets/Limited Trading
The proposed remedy of State
Budgets/Limited Trading was modeled
with regional emissions caps beginning
in 2012 and state-specific emissions
limits beginning in 2014. The statespecific emissions limits represent state
budgets plus 3-year average variability
limits. Because banking early reductions
beyond the budget levels is allowed,
2012 SO2 reductions are greater overall
than state budgets alone would require
in that year. Table V.E–2 shows the
projected emissions reductions from
this remedy.
TABLE V.E–2—PROJECTED SO2 AND NOX ELECTRIC GENERATING UNIT EMISSIONS REDUCTIONS IN COVERED STATES
WITH THE TRANSPORT RULE COMPARED TO BASELINE WITHOUT TRANSPORT RULE OR CAIR
[Million tons]
2012 base case
emissions
SO2 ...................................
Annual NOX .....................
Ozone Season NOX .........
2012 transport
rule emissions
8.4
2.0
0.7
2. State Budgets/Intrastate Trading
Though based on the same state
budgets as State Budgets/Limited
trading, the alternative remedy of State
Budgets/Intrastate Trading costs
approximately 0.5 billion 2006 dollars
more in 2012 and achieves slightly more
2012 emissions
reductions
3.4
1.3
0.6
2014 base case
emissions
5.0
0.7
0.1
2014 transport
rule emissions
7.2
2.0
0.7
SO2 reduction in 2012 (and slightly less
in 2014), as Table V.E–3 shows. In
modeling this remedy, each state’s
emissions were restricted to the state
budget without variability. Without the
opportunity for even limited trading of
allowances across state borders, more
banking was projected in some states. In
2.6
1.3
0.6
2014 emissions
reductions
4.6
0.7
0.1
other states, more immediate emissions
reductions (relative to the base case) are
projected so that state budgets are met
exactly. Both of these factors drive 2012
costs higher than those of limited
interstate trading and lead to slightly
greater SO2 reductions in 2012.
TABLE V.E–3—PROJECTED SO2 AND NOX ELECTRIC GENERATING UNIT EMISSIONS REDUCTIONS IN COVERED STATES
WITH THE INTRASTATE TRADING ALTERNATIVE REMEDY COMPARED TO BASELINE WITHOUT TRANSPORT RULE OR CAIR
[Million tons]
2012 base case
emissions
SO2 ...................................
Annual NOX .....................
Ozone Season NOX .........
2012 transport
rule emissions
8.4
2.0
0.7
3. Direct Control
The direct control alternative remedy
consists of source-specific emissions
rate limits commensurate with those
used in the derivation of state budgets
(see sections IV.D and IV.E). To
represent assurance provisions, the
emissions from each state were also
constrained to the state’s budget plus
3-year average variability limit
2012 emissions
reductions
3.2
1.3
0.6
2014 base case
emissions
5.2
0.7
0.1
2014 transport
rule emissions
7.2
2.0
0.7
beginning in 2012. For states with more
stringent SO2 budgets in 2014, FGD
retrofits were required on units shown
to have cost-effective retrofit
opportunities at $2,000 per ton.
Compared to the proposed remedy of
State Budgets/Limited Trading, the
direct control alternative costs
approximately 0.6 billion 2006 dollars
more and results in less SO2 reduction
2.7
1.2
0.6
2014 emissions
reductions
4.5
0.8
0.1
in 2012, as shown in Table V.E–4.
Unlike remedies allowing banking for
early reductions, the direct control
alternative does not result in reductions
below state budgets in 2012. At the
same time, meeting specific rate
requirements for every source means
there is little incentive to achieve
additional reductions with fuel
switching.
TABLE V.E–4—PROJECTED SO2 AND NOX ELECTRIC GENERATING UNIT EMISSIONS REDUCTIONS IN COVERED STATES
WITH THE DIRECT CONTROL ALTERNATIVE REMEDY COMPARED TO BASELINE WITHOUT TRANSPORT RULE OR CAIR
[Million tons]
2012 base case
emissions
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SO2 ...................................
Annual NOX .....................
Ozone Season NOX .........
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8.4
2.0
0.7
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3.8
1.3
0.6
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0.7
0.1
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emissions
2014 transport
rule emissions
7.2
2.0
0.7
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0.6
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4.6
0.8
0.1
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4. State-Level Emissions Projections
Tables V.E–5, V.E–6, and V.E–7 show
projected emissions at the state level
from all EGUs in 2014.
TABLE V.E–5—PROJECTED STATE-LEVEL 105 SO2 EMISSIONS FROM ELECTRIC GENERATING UNITS IN 2014
[Tons]
State budgets/
limited trading
Base case
Alabama ...........................................................................................
Connecticut ......................................................................................
Delaware ..........................................................................................
District of Columbia .........................................................................
Florida ..............................................................................................
Georgia ............................................................................................
Illinois ...............................................................................................
Indiana .............................................................................................
Iowa .................................................................................................
Kansas .............................................................................................
Kentucky ..........................................................................................
Louisiana ..........................................................................................
Maryland ..........................................................................................
Massachusetts .................................................................................
Michigan ...........................................................................................
Minnesota ........................................................................................
Missouri ............................................................................................
Nebraska ..........................................................................................
New Jersey ......................................................................................
New York .........................................................................................
North Carolina ..................................................................................
Ohio .................................................................................................
Pennsylvania ....................................................................................
South Carolina .................................................................................
Tennessee .......................................................................................
Virginia .............................................................................................
West Virginia ....................................................................................
Wisconsin .........................................................................................
322,362
6,160
8,079
176
194,723
173,257
200,484
804,425
163,966
65,125
739,595
94,866
45,294
17,265
275,961
62,033
500,649
115,695
39,721
142,762
140,924
841,199
974,644
156,200
600,071
136,573
496,307
117,397
State budgets/
intrastate trading
172,430
3,234
9,185
179
139,805
92,375
164,741
240,730
102,419
51,248
123,837
94,933
45,449
10,306
173,828
49,413
192,645
75,095
16,562
58,455
97,262
232,964
154,852
131,232
106,767
58,329
127,646
85,933
162,103
3,208
8,974
180
159,120
89,706
156,049
267,564
102,096
52,501
128,318
92,647
45,304
8,595
188,796
49,836
190,815
73,219
14,935
53,373
109,385
269,547
183,276
123,525
100,012
51,633
147,580
87,328
Direct control
172,430
3,208
9,110
180
135,366
92,375
163,902
239,852
106,569
53,275
123,833
96,390
45,752
8,909
172,986
58,925
190,532
75,061
16,569
58,455
97,262
228,514
154,855
131,232
94,078
58,330
127,646
83,709
TABLE V.E–6—PROJECTED STATE-LEVEL ANNUAL NOX EMISSIONS FROM ELECTRIC GENERATING UNITS IN 2014
[Tons]
State budgets/
limited trading
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Base case
Alabama ...........................................................................................
Connecticut ......................................................................................
Delaware ..........................................................................................
District of Columbia .........................................................................
Florida ..............................................................................................
Georgia ............................................................................................
Illinois ...............................................................................................
Indiana .............................................................................................
Iowa .................................................................................................
Kansas .............................................................................................
Kentucky ..........................................................................................
Louisiana ..........................................................................................
Maryland ..........................................................................................
Massachusetts .................................................................................
Michigan ...........................................................................................
Minnesota ........................................................................................
Missouri ............................................................................................
Nebraska ..........................................................................................
New Jersey ......................................................................................
New York .........................................................................................
North Carolina ..................................................................................
Ohio .................................................................................................
Pennsylvania ....................................................................................
105 The modeling presented in Tables V.E–5,
V.E–6, and V.E–7 differs from the proposed
Transport Rule because the District of Columbia
(DC) is included neither in the annual SO2 and NOX
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118,955
7,991
5,790
933
196,373
48,267
80,451
201,027
68,259
79,018
148,551
45,551
36,089
12,650
98,941
55,283
83,019
53,029
27,127
36,352
62,608
164,947
204,950
requirements nor in the ozone season NOX
requirement. Modeled units in DC include two
small facilities, one of which has only units below
25 MW capacity. EPA believes the addition of
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State budgets/
intrastate trading
61,793
8,003
6,176
946
126,155
44,461
57,589
112,502
53,072
40,020
71,371
37,255
36,326
13,047
65,066
38,969
67,475
35,101
23,377
36,592
60,516
99,358
123,629
61,618
7,986
6,126
948
126,065
44,462
54,773
112,721
50,146
40,074
71,692
36,594
33,778
12,219
65,973
39,114
61,679
34,105
23,358
34,538
54,639
95,997
123,095
Direct control
61,865
8,004
6,074
948
94,646
44,611
57,949
108,675
52,069
39,558
69,882
37,164
36,532
13,064
67,525
38,039
67,648
35,457
23,338
36,597
60,517
100,886
123,409
emissions limits in DC would have little to no effect
on the modeling results.
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TABLE V.E–6—PROJECTED STATE-LEVEL ANNUAL NOX EMISSIONS FROM ELECTRIC GENERATING UNITS IN 2014—
Continued
[Tons]
State budgets/
limited trading
Base case
South Carolina .................................................................................
Tennessee .......................................................................................
Virginia .............................................................................................
West Virginia ....................................................................................
Wisconsin .........................................................................................
47,742
68,914
37,485
100,095
54,515
State budgets/
intrastate trading
34,735
28,212
35,805
48,180
41,875
33,781
26,874
35,745
48,987
42,498
Direct control
34,616
28,873
37,004
50,555
42,450
TABLE V.E–7—PROJECTED STATE-LEVEL OZONE-SEASON NOX EMISSIONS FROM ELECTRIC GENERATING UNITS IN 2014
[Tons]
State budgets/
limited trading
Base case
Alabama ...........................................................................................
Arkansas ..........................................................................................
Connecticut ......................................................................................
Delaware ..........................................................................................
District of Columbia .........................................................................
Florida ..............................................................................................
Georgia ............................................................................................
Illinois ...............................................................................................
Indiana .............................................................................................
Kansas .............................................................................................
Kentucky ..........................................................................................
Louisiana ..........................................................................................
Maryland ..........................................................................................
Michigan ...........................................................................................
Mississippi ........................................................................................
New Jersey ......................................................................................
New York .........................................................................................
North Carolina ..................................................................................
Ohio .................................................................................................
Oklahoma .........................................................................................
Pennsylvania ....................................................................................
South Carolina .................................................................................
Tennessee .......................................................................................
Texas ...............................................................................................
Virginia .............................................................................................
West Virginia ....................................................................................
F. Transition From the CAIR Cap and
Trade Programs To Proposed Programs
This proposed Transport Rule would
replace the CAIR rule and its associated
trading programs. This section
elaborates on some of the areas of the
CAIR program that would need to be
addressed in the transition to the new
program. EPA is taking comment on
how the transition would occur.
erowe on DSK5CLS3C1PROD with PROPOSALS2
1. Sunsetting of CAIR, CAIR SIPs, and
CAIR FIPs
The CAIR, CAIR SIPs, and CAIR FIPs
would be replaced entirely by the
Transport Rule provisions. If this
proposed Transport Rule is finalized in
2011, the CAIR, CAIR SIPs, and CAIR
FIPs would sunset at the completion of
all 2011 control period activities.
In order to implement the sunsetting
of the CAIR and CAIR FIPs, the
proposed rule includes several revisions
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26,995
21,667
3,446
2,367
391
94,686
21,947
24,167
49,023
34,537
29,927
21,443
15,307
29,934
16,955
10,470
17,257
27,018
44,753
38,546
53,263
15,730
12,021
79,572
16,264
24,339
of the CAIR, §§ 51.123 and 51.124, and
the CAIR FIPs, §§ 52.35 and 52.36. First,
sunsetting the CAIR and CAIR FIPs in
2011 would mean that the requirements
of the CAIR and CAIR FIPs would not
apply to control periods after 2011.
Specifically, the CAIR would be revised
to rescind, with regard to any control
period beginning after December 31,
2011, the findings that states must
revise their SIPs to meet CAIR
requirements. Similarly, the CAIR FIPs
would be revised to state that, with
regard to any post-December 31, 2011
control period, CAIR FIP requirements
would not be applicable.
Second, the sunsetting in 2011 would
mean that the CAIR trading programs
would not continue past 2011.
Consequently, the proposed revisions of
the CAIR and CAIR FIPs would state
that, with regard to any post-December
31, 2011 control period, the
Administrator would not carry out any
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State budgets/
intrastate trading
26,727
12,080
3,453
2,669
397
62,221
19,686
24,930
47,477
17,470
29,376
17,388
15,454
27,778
8,524
10,324
17,493
26,117
41,141
24,471
53,102
14,818
11,868
68,769
15,397
20,249
26,552
12,095
3,446
2,671
397
62,037
19,688
22,833
47,813
17,590
29,671
17,106
14,275
28,052
8,526
10,295
16,518
23,459
40,051
24,471
52,692
14,666
10,955
68,874
15,289
21,466
Direct control
26,823
12,077
3,446
2,613
398
48,170
19,749
24,701
45,589
17,282
29,107
17,308
15,512
29,415
8,522
10,260
17,491
26,004
42,789
24,426
52,586
14,753
12,007
67,832
16,093
21,500
of the functions established for the
Administrator in the CAIR model
trading rule, the CAIR FIPs, or any state
trading programs approved under the
CAIR.
Third, the sunsetting in 2011 would
mean that CAIR allowances allocated for
control periods after 2011—which have
already been recorded by the
Administrator in the Allowance
Management System compliance
accounts of sources in many states—
would not be usable in the CAIR trading
programs for control periods ending
before 2012. Specifically, under the
existing CAIR trading programs, a
source that fails to hold sufficient
allowances to cover emissions for the
2011 control period (whether annual or
ozone season) must provide for
surrender to the Administrator three
allowances (one as an offset and two as
an automatic penalty) allocated for the
2012 control period for every one
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allowance that was not held as required.
However, consistent with the proposed
termination of the CAIR trading
programs for control periods after 2011,
EPA believes that allowances allocated
for such control periods (e.g., 2012
allowances) should not be usable for
any purpose. In any event, because such
allowances would have little or no
market value, their deduction would
impose little or no cost on the party
holding them. Consequently, the
proposed revisions of the CAIR and
CAIR FIPs would state that the
Administrator would not deduct, for
excess emissions, any CAIR allowances
allocated for control periods in 2012 or
any year thereafter. These revisions
would ensure that no CAIR allowances
allocated for post-2011 control periods
would be used as an offset of, or an
automatic penalty for, excess emissions.
As a result of these proposed
revisions of the CAIR and CAIR FIP
rules, there would be no offset or
automatic penalty deducted for a source
that failed to hold sufficient allowances
to cover its 2011 control period
emissions unless the state SIPs are
revised. In order to preserve the
deductions for offsets and automatic
penalties for 2011 control periods, the
CAIR SIPs for most states (i.e., 20 out of
the 28 states subject to at least one CAIR
trading program) would need to be
modified and the modified CAIR SIPs
would need to be approved by the EPA
—-before EPA conducts the process of
determining source compliance after the
allowance transfer deadline for the 2011
control periods —in order to change the
allocation year of the allowances
required to be deducted (e.g., from
allowances allocated for 2012 to
allowances allocated for 2011).
Although EPA’s past experience with
trading programs strongly suggests that
few sources would be out of compliance
with the requirement to hold allowances
covering 2011 emissions, all of these
CAIR SIPs would have to be revised
because there is no way to predict
which few sources in which few states
might be out of compliance in 2011 and
the process of revising SIPs is too long
to be started while EPA is still
determining compliance. In fact, when
states needed to revise their SIPs to
include the existing requirements of
CAIR and submit the revised SIPS to the
Administrator, EPA found that states
needed up to 3 years to develop and
submit SIP revisions, and EPA needed
about 6 months to act on the SIP
revisions. In light of this experience
with SIP revisions under CAIR, EPA
believes that it would highly unlikely
that all, or even most, state CAIR SIPs
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could be revised, submitted, and
approved in time—even if the SIP
revision process were started when a
final Transport Rule is promulgated—to
change what allowances were to be used
for offsets and automatic penalties for
excess emissions for the 2011 control
periods.
Moreover, any excess emissions for
the 2011 control periods would be
violations of the state SIPs (or of CAIR
FIPs in those states with CAIR FIPs) and
of the Clean Air Act and, therefore
would be subject to discretionary civil
penalties under CAA Section 113. Each
ton of excess emissions, and each day in
the control period involved (i.e., 365
days for annual control periods and 153
days for the ozone season control
period), would be a violation, with a
maximum penalty of $25,000 (inflation
adjusted to $37,500) per violation. In
determining what level of discretionary
civil penalties to impose on a source
that has excess emissions violations,
EPA routinely considers, among other
things, whether, and if so what level of,
other penalties (e.g., automatic excess
emissions penalties) have already been
imposed for the same violations, as well
as any economic benefit of
noncompliance (e.g., the avoidance of
the cost of surrendering allowances to
cover emissions). See, e.g., 42 U.S.C.
7413(e)(1) (including, as penalty
assessment criteria, ‘‘payment by the
violator of penalties previously assessed
for the same violation’’ and ‘‘the
economic benefit of noncompliance’’).
Consequently, EPA believes that,
regarding the CAIR 2011 control periods
(both annual and ozone season) for
which it is not feasible to change the
offset and automatic penalty provisions
to make them workable, the potential for
assessment of significant, discretionary
civil penalties would provide a strong
incentive for compliance with the
allowance-holding requirement and
avoidance of excess emissions.
In addition to the previouslydescribed, proposed revisions to
§§ 51.123, 51.124, 52.35, and 52.36,
certain provisions in part 52 that reflect,
state by state, the CAIR SIP revisions
and CAIR FIP requirements applicable
to each state would need to be revised
to implement the sunsetting of the
CAIR, CAIR SIPs, and CAIR FIPs.
However, the timing for proposal and
adoption of revisions to part 52 is
necessarily different for the part 52
provisions addressing CAIR SIP
revisions and those addressing revisions
of the CAIR and the CAIR FIPs
themselves.
The part 52 provisions addressing
CAIR SIP revisions for the individual
states reflect EPA’s approval of CAIR
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45337
SIP revisions adopted and submitted to
EPA by the respective states. The first
step toward sunsetting those part 52
provisions would be that, if and after
the proposed Transport Rule was
finalized, the respective states would
change their SIPs in order to, among
other things, make the CAIR provisions
in the SIPs inapplicable to any control
period that starts after December 31,
2011. After the submittal by the
respective states of these SIP revisions,
EPA would review and approve such
changes. Consequently, the rule text
approving such CAIR SIP revisions
would not be included in either the
proposed Transport Rule or any final
rule based on the proposed Transport
Rule, but rather would be proposed and
adopted only after the respective states
revised their SIPs. As EPA did when
transitioning from the NOX Budget
Trading Program to the CAIR NOX
ozone season trading program, EPA will
work with states to transition from state
CAIR programs to their replacement
FIPs or state SIPs. This assistance will
be provided through meetings or
workshops, web-based references, oneon-one assistance through the EPA
regions, etc.
In contrast, the part 52 provisions
adopting CAIR FIPs for individual states
could be revised, as part of the proposed
Transport Rule, to sunset these CAIR
FIPs because no state action would be
required to accomplish this sunsetting.
EPA proposes to revise each statespecific part 52 provision adopting a
CAIR FIP—whether for NOX annual or
ozone season emissions or SO2
emissions—to add a paragraph stating
that: with regard to any control period
starting after December 31, 2011, the
respective CAIR FIP would not apply
and the Administrator would not carry
out any of the functions set forth for the
Administrator in the trading program
rules under the CAIR FIP; and the
Administrator would not deduct for
excess emissions any CAIR allowances
allocated for 2012 or any year thereafter.
The new, added rule text would be very
similar to the proposed rule text
revisions to §§ 52.35 and 52.36 and
would be essentially the same for each
of these state-specific Part 52
provisions. EPA has included in the
proposed Transport Rule the proposed
rule text making these state-by-state
revisions for Delaware, District of
Columbia, Indiana, Louisiana,
Michigan, New Jersey, Tennessee,
Texas, and Wisconsin. These provisions
revise all of the state-specific Part 52
provisions adopting CAIR FIPs
provisions to make the CAIR FIPs
inapplicable to any control period that
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starts after December 31, 2011 and state
that the Administrator would not carry
out any functions under the CAIR
trading programs during any such
control period and would not use any
CAIR allowances allocated for any such
control period.
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2. Change in States Covered
The states covered by the proposed
Transport Rule differ slightly from states
covered by the CAIR. Namely, as
compared with the states covered by the
CAIR NOX ozone season trading
program, the states covered by the
proposed Transport Rule NOX ozone
season trading program would include
Georgia, Kansas, Oklahoma, and Texas
and would not include Iowa,
Massachusetts, Missouri, and
Wisconsin. Further, as compared with
the states covered by the CAIR NOX
annual and SO2 trading programs, the
states covered by the proposed
Transport Rule NOX Annual and SO2
trading programs would include
Connecticut, Kansas, Massachusetts,
Minnesota, and Nebraska and would not
include Mississippi and Texas. (See also
the discussion in section IV.D. regarding
the possibility that the states to which
this rule would apply could expand.)
Consequently, sources in some states
that would be covered by the proposed
Transport Rule would have new
allowance holding requirements
beginning in 2012, but would not have
been subject to the CAIR trading
programs. Conversely, sources in some
states covered by the CAIR or CAIR FIPs
would not be subject to the proposed
Transport Rule. To the extent that the
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 will work with individual
states to identify state-specific options
to ensure that necessary reductions
needed for other SIP requirements can
continue.
3. Applicability, CAIR Opt-ins and NOX
SIP Call Units
Except for the changes in the states
covered, the general applicability
provisions of the proposed Transport
Rule would be essentially the same as
the CAIR general applicability
provisions, with a few exceptions. First,
the proposed Transport Rule does not
allow any units to opt into the trading
programs. In contrast, under CAIR,
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, and a
number of states adopted these opt-in
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provisions. However, currently no units
have opted into the CAIR trading
programs, and, even in the Acid Rain
Program, where opt-in provisions have
been in place since 1995, very few units
have actually opted in.
Second, under the CAIR trading
programs, a state subject to the NOX SIP
Call was allowed to expand the
applicability of the CAIR NOX ozone
season trading program in the state in
order to include all units subject to the
NOX Budget Trading Program (NBP)
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 NOX ozone season
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.
In expanding the applicability of the
CAIR NOX ozone season trading
program, the fourteen states brought
into the program large industrial boilers
and turbines (with maximum design
heat input greater than 250 mmBtu/ hr)
and, in some cases, smaller electric
generating units (serving generators
with nameplate capacity of 15 through
25 MWe), and generally the CAIR NOX
ozone season budgets in these states
were increased to account for these
additional sources. In contrast, the
proposed Transport Rule NOX ozone
season trading program would not allow
for expansion of applicability to include
these units currently covered only by
the NBP.
There are several factors underlying
this difference between the proposed
Transport Rule and the CAIR. First, in
determining which states are
contributing significantly or interfering
with maintenance of the ozone NAAQS,
the Transport Rule does not cover some
states subject to the NOX SIP Call (i.e.,
Massachusetts, Missouri, and Rhode
Island). Further, the six states that chose
under the CAIR to require the necessary
NOX SIP Call reductions through
provisions other than the CAIR NOX
ozone season program would not likely
be interested in expanding applicability
under the Transport Rule NOX ozone
season trading program to cover these
units. In addition, EPA has determined
that these units as a group did not
actually reduce emissions as a result of
the NBP or through their inclusion in
the CAIR NOX ozone season trading
program. In fact, their current emissions
rates are nearly identical to what they
were before the NBP started. Moreover,
these units as a group had allowances
that they did not need for compliance
and that were available for trading to
other affected units. The Transport Rule,
as proposed, does not include these
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units and does not include provisions
for allowing states expand applicability
to include them. EPA is taking comment
on this approach.
4. Early Reduction Provisions
Substantial emissions reductions have
occurred as a result of the CAIR
programs. These reductions are greater
than were expected when the rule was
promulgated. This is evidenced in the
banks of allowances that exist in each of
the CAIR programs.
a. 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
emissions reductions for Title IV where
allowances are used for compliance
with the requirement to hold allowances
covering emissions and early reductions
for the CAIR SO2 trading program. EPA
believes that it is advantageous to
minimize sources’’ use of the Title IV
allowance bank if possible and
recognizes that, if the bank has minimal
future market value, there may be
incentive to use as many banked
allowances as possible. EPA tracks the
SO2 emissions on a quarterly basis and
makes the information available to the
public at https://epa.gov/airmarkets/
quarterlytracking.html.
EPA evaluated whether the Title IV
allowance bank could be used in the
proposed Transport Rule SO2 program
in any way. One idea presented to EPA
was to distribute Transport Rule SO2
allowances based on the number of Title
IV allowances a source has in its bank
at the completion of compliance in the
last year of the CAIR SO2 program,
thereby incentivizing minimal use, by
sources, of Title IV allowance banks and
encouraging continued emission
control. EPA is concerned that the
approach would have significant legal
risk for two reasons. First, the Court is
likely to view the approach as imposing
a significant burden on the use of Title
IV allowances and therefore as
modifying the authorization provided
by such allowances. Second, the Court
is likely to view the approach as not
related to, much less necessary for,
implementation of the section
110(a)(2)(D)(i)(I) mandate to eliminate
significant contribution and interference
with maintenance. EPA chose instead,
under the proposed Transport Rule, to
distribute Transport Rule SO2
allowances in a manner directly linked
to its calculation of each state’s
significant contribution and interference
with maintenance and not to use Title
IV allowances as a basis for distributing
the new Transport Rule allowances.
EPA is confident that the approach
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selected is consistent with the Court’s
opinion in North Carolina v. EPA, 531
F.3d 896, 922 (D.C. Cir. 2008).
(Additional information on this
approach can be found in the docket.)
EPA requests comment on whether or
not an allowance distribution approach
based on the number of Title IV
allowances in a given source’s account
would be consistent with the Court
opinion.
EPA proposes that the Transport Rule
provisions 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.
Thus, there would be no SO2 allowances
carried over into the new SO2 program.
Title IV allowances continue, of course,
to be used for compliance with the Acid
Rain Program.
b. NOX Allowance Banks
Assuming that NOX emissions in 2010
and 2011 are equal to what they were
in 2009, the CAIR NOX ozone season
bank would contain over 600,000
allowances (which would equal more
than 100 percent of the total of the state
budgets under the proposed Transport
Rule NOX ozone season program for
2012), and the CAIR NOX annual bank
would contain about 720,000
allowances (which would equal nearly
50 percent of the total of the state
budgets under the proposed Transport
Rule NOX annual program for 2012),
after completion of true-up of allowance
holdings and emissions for 2011.
Estimates of the size of the banks have
only recently been made based on
reported 2009 emissions data, and the
impacts of different approaches to
handling the banks have not yet been
modeled. However, EPA is concerned
about the potential impacts of these
approaches. On one hand, allowing pre2012 CAIR NOX allowances and CAIR
NOX ozone season allowances to be
used in the proposed Transport Rule
NOX programs, and thereby ensuring
that the allowances would continue to
have some market value in the future,
would promote the continuation—in
2010 and 2011—of the reductions that
occurred in 2009 under the CAIR NOX
programs. On the other hand, the
amounts of the banks are so large that
they might significantly reduce the
amount of emissions reductions that
would otherwise be achieved in the
proposed Transport Rule NOX programs,
particularly in the earlier years (e.g.,
2012 and 2013).
EPA has identified several possible
approaches for handling banked pre2012 CAIR NOX allowances in the
Transport Rule NOX programs. The first
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approach might be to 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 the
significant contribution and interference
with maintenance that EPA has
identified in today’s proposal. The
banked CAIR allowances would be
usable, and the assurance provisions
would apply, in all states in the
Transport Rule NOX programs.
However, EPA is concerned that some
parties may view this approach as
having the effect of allowing sources
that were advantaged by the
development of state budgets using fuel
adjustment factors—the use of which
was reversed by the Court in North
Carolina, 531 F.3d at 918–21—and that
still hold part of their allocated
allowances to continue have an
advantage in the Transport Rule NOX
trading programs. These concerns may
be mitigated somewhat by the fact that
even though the methodology used to
divide the regional budget into state
budgets used fuel factors, states had the
flexibility to allocate allowances
however they wished. EPA takes
comment on the extent to which states
have allocated differently and the extent
to which this may mitigate concerns
about allowing the use of banked CAIR
NOX allowances in the Transport Rule
annual NOX and ozone season NOX
trading programs.
The second approach might be to
allow only a limited amount of banked
pre-2012 CAIR allowances to be brought
into the Transport Rule programs. This
could be accomplished by allowing all
such banked allowances to be used, but
at a tonnage authorization level
significantly lower than one ton per
allowance, in the Transport Rule NOX
programs. However, while severely
limiting the tonnage authorization of
banked allowances that is allowed into
the new programs would limit any
advantage realized by sources that
received fuel-adjustment-factor-based
CAIR allowance allocations, this would
also limit any beneficial impact that
bringing CAIR allowances into the new
programs might have on preserving
emissions reductions in 2010 and 2011.
The third option might be to try to
factor the bank into the calculation of
state budgets by reducing the state
budgets to take account of the banked
pre-2012 CAIR allowances. This might
allow these allowances to be used in the
Transport Rule NOX programs without
adversely affecting the states’
elimination of the part of significant
contribution and interference with
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maintenance that EPA has identified.
However, this approach would not be
feasible because EPA cannot determine
in advance in which states banked pre2012 CAIR allowances might be used
and so would not know which state
budgets should be adjusted and what
amount of adjustment would be
necessary.
A final approach would simply be to
not allow the use of any banked pre2012 CAIR allowances in the Transport
Rule NOX programs. This approach
would avoid the potential legal and
practical problems raised by the other
approaches and is the approach
proposed by EPA. EPA requests
comment on the proposed approach, the
previously-discussed alternative
approaches, and any other possible
approaches for handling banked pre2012 CAIR allowances in the Transport
Rule NOX programs.
5. Source Monitoring and Reporting
Monitoring and reporting using 40
CFR part 75 provisions is required for
all units subject to the CAIR programs
and would also be required for all units
subject to the proposed Transport Rule
programs. In states covered by both the
CAIR and the proposed Transport Rule,
units would generally have no changes
to their monitoring and reporting
requirements and would continue to
monitor and submit reports as they have
under the CAIR. The exceptions are
units in: CAIR states subject to CAIR
NOX ozone season requirements but
NOX and SO2 annual requirements
under the proposed Transport Rule; or
CAIR states subject to CAIR NOX annual
and ozone season and SO2 requirements
but only to NOX ozone season
requirements under the proposed
Transport Rule. These exceptions could
arise, in part, because under Part 75
some units (i.e., non-Acid Rain units)
that are in NOX ozone season, and not
NOX annual, programs have the option
of monitoring and reporting NOX
emissions for just the ozone season.
Units in the following states monitor
and report both SO2 and NOX yearround under the CAIR and would
continue to do so under the Transport
Rule: Alabama, Delaware, the District of
Columbia, Florida, Georgia, Illinois,
Indiana, Iowa, Kentucky, Louisiana,
Maryland, Michigan, Missouri, New
Jersey, New York, North Carolina, Ohio,
Pennsylvania, South Carolina,
Tennessee, Virginia, West Virginia, and
Wisconsin. Non-Acid Rain units in
Arkansas are currently required to
monitor and report NOX in the ozone
season under the CAIR and would
continue to be required to do so under
the proposed Transport Rule.
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Non-Acid Rain units in Connecticut
and Massachusetts (about 15 units total)
that currently monitor and report NOX
in the ozone season would need to
monitor and report NOX and SO2 on an
annual basis under the proposed
Transport Rule.
Non-Acid Rain units in Mississippi
(about 4 units) and Texas (about 52
units) are currently monitoring and
reporting NOX and SO2 year-round and
under the proposed Transport Rule
would be required to monitor and report
NOX in the ozone season. (All of these
units burn natural gas and emitted
approximately 12 tons of SO2 in 2009.)
In states not covered by the CAIR but
covered by the proposed Transport
Rule, some units would have to meet
new monitoring and reporting
requirements under part 75. Kansas,
Minnesota, and Nebraska are not
covered by the CAIR and are covered by
the Transport Rule, and units there
would need to monitor and report NOX
and SO2 emissions year-round.
Oklahoma is not covered by the CAIR
and is covered by the Transport Rule,
and units there would need to monitor
and report NOX in the ozone season.
There are about 34 non-Acid Rain units
total in Kansas, Nebraska and Oklahoma
not monitoring and reporting under Part
75 that would need to begin to do so.
Most of these units are simple-cycle
combustion turbines used in the ozone
season as peaking units and would
likely be able to utilize the Low Mass
Emissions or Appendix D and E
methodologies in 40 CFR part 75, which
do not require a continuous emissions
monitoring system (CEMS). The
circulating fluidized bed (CFB) units in
Oklahoma (about 4 units) that burn coal
are already monitoring and reporting
under 40 CFR part 60, subpart Da,
which requires an SO2, NOX and CO2/
O2 (diluent) CEMS. These boilers would
only have to add a flow monitor and
upgrade the automated data acquisition
and handling system. Non-Acid Rain
units in Minnesota (about 20 units)
would also need to monitor and report,
but were already doing so under the
CAIR before the CAIR was stayed in
Minnesota (74 FR 56721, November 3,
2009); therefore, they would simply
have to reactivate those monitoring
systems.
Units that have not been covered by
part 75 monitoring and reporting in the
past would likely have less than one
year to install, certify, and operate the
required monitoring systems. EPA
believes that these units would
reasonably be able to comply with this
requirement because the monitoring
equipment needed is not extensive or is
largely in place already for the purpose
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of meeting other requirements. Quality
assurance and reporting provisions and
data system upgrades may be necessary,
but there would be sufficient time to
accomplish this.
G. Interactions With Existing Title IV
Program and NOX SIP Call
1. Title IV Interactions
Promulgation of a Transport Rule
would not affect any Acid Rain Program
requirements. Any Title IV sources that
are subject to final Transport Rule
provisions would still need to continue
to comply with all Acid Rain
provisions. Acid Rain requirements are
established independently in Title IV of
the Clean Air Act and would not be
replaced by the Transport Rule. In
contrast with the CAIR, the proposed
Transport Rule would not allow Title IV
SO2 allowances to be used in the
Transport Rule program. Similarly,
Transport Rule SO2 allowances would
not be useable in the Acid Rain
Program. Title IV SO2 and NOX
requirements will continue to apply
independently of the Transport Rule
provisions. The Transport Rule program
as proposed has no opt-in provisions, so
no sources, including any that have
opted into the Acid Rain Program would
be able to opt-in to the Transport Rule
program.
Compliance with the Transport Rule
would reduce SO2 emissions in the
Transport Rule states below the 2010
Title IV cap. So, as sources complied
with the Transport Rule, emissions
would go down and with them so would
the demand for Title IV allowances.
Therefore, the Title IV allowance prices
are expected to be very low once the
Transport Rule is finalized; some
analysts suggest a price of nearly zero.
Acid Rain sources will still be required
to comply with Title IV requirements,
including the requirement to hold Title
IV allowances to cover emissions at the
end of a compliance year.
There would likely be changes to
emissions at some Acid Rain sources
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
sources may increase because of the
change in the Title IV allowance price.
This would be expected to occur mainly
in the states that border the Transport
Rule states. Overall, SO2 emissions from
these non-Transport Rule Acid Rain
sources would be expected to increase
approximately 237,000 tons each year if
the Transport Rule is implemented
compared to what they would have been
in the absence of the Transport Rule.
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There is more discussion of this effect
in section IV.D.
2. NOX SIP Call Interactions
States affected by both the NOX SIP
Call and any final Transport Rule will
be required to comply with the
requirements of both rules. The
Transport Rule does not preempt or
replace the requirements of the NOX SIP
Call. However, the proposed Transport
Rule ozone season program would
achieve the emissions reductions
required by the NOX SIP Call from EGUs
greater than 25 MW in nearly all NOX
SIP Call states. The NOX SIP Call states
used the NOX Budget Trading Program
(NBP) 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/hr.
(In some states, EGUs smaller than 25
MW were also part of the NBP as a
carryover from the Ozone Transport
Commission NOX Budget Trading
Program.) EPA stopped administering
the NBP after the 2008 ozone season
control period activities, and states used
another mechanism to comply with the
NOX SIP Call requirements.
Many of the states using the NBP used
the CAIR NOX ozone season trading
program to replace the NBP. To address
NOX SIP Call requirements, fourteen
NOX SIP Call states chose to expand the
CAIR NOX ozone season applicability to
include all NBP-affected units. EPA has
analyzed the effect of allowing states to
expand their CAIR NOX ozone season
applicability and consequently their
CAIR NOX ozone season budgets to
include the additional non-CAIR
affected NBP units. In 2009, the
additional units emitted about half of
the amount of allowances added to the
CAIR NOX ozone season budgets for
them. The remaining allowances are
available for the sources to trade to
other affected units. As a group, these
units did not reduce their NOX
emissions or their NOX emissions rates
as a result of their inclusion in the CAIR
NOX ozone season program. If EPA were
to allow them to be part of the Transport
Rule NOX Ozone Season Program, and
if states were allowed to increase the
Transport Rule NOX Ozone Season
Budgets by the amounts allowed under
the NBP and CAIR for these units, a
state’s ability to eliminate the part of
significant contribution and interference
with maintenance that EPA has
identified in today’s proposal could be
jeopardized. One option considered that
could possibly address concerns about
still being able to address significant
contribution and interference with
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maintenance would be to require the
budget increase to be much less than
allowed under the NBP and CAIR. For
example, the units’ 2009 emissions (or
2012 projected emissions if they are
required to install controls for another
program) could be used to determine the
budget increase and the elimination of
emissions causing significant
contribution and interference with
maintenance might be able to be
preserved. It is likely the budget
changes would not be consistent across
states as each state’s impact would have
to be considered individually. EPA is
proposing to not allow the expansion of
the applicability of the Transport Rule.
Therefore, the NBP states would need
to achieve their NOX SIP Call emissions
reductions another way in order to
continue to comply with the NOX SIP
Call. If EPA promulgates a final rule that
does not allow the expansion of the
Transport Rule to NBP units, any state
that allowed these units to participate in
the CAIR NOX Ozone Season Program
would need to submit a SIP revision to
address their NOX SIP Call requirement
for the reductions.
States that were part of the CAIR NOX
ozone season program or the NBP that
are not part of a final Transport Rule
ozone season program would need to
submit SIP revisions that address the
NOX SIP Call requirements for any
emissions reductions that were part of
either the CAIR NOX ozone season
program or the NBP and would not
continue to be addressed some other
way. EPA will work with states to
ensure that NOX SIP Call obligations
continue to be met.
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VI. Stakeholder Outreach
In early 2009, EPA began its efforts to
coordinate activities with state
regulatory partners and other
stakeholders on the new transport rule
to replace CAIR. To establish open lines
of communication and ensure
transparency in the regulatory process,
EPA participated in a series of ‘‘listening
sessions’’ in March and April, 2009 with
states, nongovernmental organizations,
and industry. EPA also participated in
tribal teleconferences. The same agenda
was set for each of the ten meetings.
Meeting notes were developed and
distributed for concurrence and to
ensure accuracy. Subsequent to these
sessions, EPA received post-meeting
comments and additional detailed
suggestions and analyses on ways to
address some of the issues that the court
cited, most notably from state regional
organizations in the eastern U.S. All the
stakeholder-related materials may be
found in the EPA docket for the
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transport rule (EPA–HQ–OAR–2009–
0491).
Following the remand of CAIR to EPA
in December 2008, 17 states in the East
and Midwest, under the umbrellas of
the OTC and Lake Michigan Air
Directors Consortium (LADCO) with
support from southeastern states,
worked to develop recommendations for
EPA to consider in crafting a new
transport rule to replace CAIR. The
comprehensive framework presented
the consensus approach the states
reached but noted that certain regional
differences would be addressed in
separate letters with additional
recommendations and supporting
materials.
EPA has considered and appreciates
all the ideas and recommendations
provided by the states. We are
employing the technical work that they
submitted as part of the data set we are
using in this and later transport rules.
Topics addressed in the listening
sessions, where EPA asked stakeholders
and regulatory partners for their
thoughts on particular issues, included:
• Analysis and baselines.
• Linkages between a state’s
significant contribution and downwind
nonattainment/interference with
maintenance.
• Remedies.
• Attainment planning.
• Other areas.
EPA continued to provide updates to
regulatory partners and stakeholders
through monthly conference calls with
states, hosted by, e.g., NACAA, as well
as industry and NGO conferences where
EPA directors often made presentations.
Several of the options presented in
this proposal were influenced by
feedback received from stakeholders
and regulatory partners, including:
• 2012 baseline used in the
calculation of each state’s significant
contribution and interference with
maintenance.
• The ‘‘tiered’’ approach to SO2
emissions reductions requirements.
• Threshold (1 percent of the
NAAQS) used for linking upwind areas
to downwind nonattainment and
maintenance receptors.
• Approach used to give independent
meaning to the interfere with
maintenance prong of section
110(a)(2)(D)(i)(I).
• Level of reductions required.
• Use of limited interstate trading.
• Correlated and coordinated
requirements and timing for the power
industry.
EPA looks forward to the public
comment period of this rulemaking and
is committed to establishing and
maintaining close working relationships
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45341
with a broad range of public and private
sector organizations.
VII. State Implementation Plan
Submissions
A. Section 110(a)(2)(D)(i) SIPs for the
1997 Ozone and PM2.5 NAAQS
All states have an obligation to submit
SIPs that address the requirements of
CAA section 110(a)(2) within 3 years of
promulgation or revision of a NAAQS.
With respect to the 1997 ozone and
PM2.5 NAAQS, EPA found in 2005 that
states had failed to make submissions
that address the requirements of section
110(a)(2)(D)(i) related to interstate
transport of pollution. See 70 FR 21147
(April 25, 2005). Also in 2005, EPA
promulgated the CAIR, which was
intended to provide states covered by
the rule with a mechanism to satisfy
their section 110(a)(2)(D)(i)(I)
obligations. In the CAIR, EPA concluded
that the states in the CAIR region would
meet their section 110(a)(2)(D)(i)
obligations to address ‘‘significant
contribution’’ and ‘‘ interference with
maintenance’’ requirements by
complying with the CAIR requirements.
Consequently, states within the CAIR
region did not need to submit a separate
SIP revision to satisfy the section
110(a)(2)(D)(i) requirements provided
they submitted a SIP revision to satisfy
CAIR. Most of the CAIR states
participated in the CAIR trading
programs and submitted SIP revisions
that EPA subsequently approved. In
2008, the Court granted several petitions
for the review of the CAIR and found,
among other things, that EPA had not
demonstrated that the CAIR effectuates
the statutory mandate of section
110(a)(2)(D)(i)(I). The EPA approvals of
the CAIR SIPS preceded the remand of
the CAIR by the Court. Therefore,
because the D.C. Circuit Court found
CAIR and the CAIR FIPs unlawful,
EPA’s approval of the provisions of a
state’s SIP submittal as addressing the
requirements of the CAIR could not
satisfy that state’s section
110(a)(2)(D)(i)(I) obligation. In other
words, a CAIR SIP submission can no
longer be considered an adequate
section 110(a)(2)(D)(i)(I) SIP submission.
For this reason, EPA’s 2005 findings
that states had failed to submit SIPs that
satisfy section 110(a)(2)(D)(i)(I) 106
remain in force regardless of whether a
state covered by the CAIR submitted
106 The 2005 findings of failure to submit related
to states’ obligations pursuant to section
110(a)(2)(D)(i). The CAIR, however, addressed only
the requirements of 110(a)(2)(D)(i)(I). The remand of
CAIR, therefore, had no impact on state SIP
submissions or EPA approval of state SIP
submissions pursuant to section 110(a)(2)(D)(i)(II).
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and/or had an approved SIP stating that
compliance with the CAIR satisfied
their 110(a)(2)(D)(i) obligations.
The 2005 findings of failure to submit
also remain in force for many states not
covered by the original CAIR. Some of
these states have not yet submitted
110(a)(2)(D)(i)(I) SIPs and thus the
findings remain in force. However,
several states that were not covered by
the CAIR have since 2005 submitted SIP
revisions to satisfy the requirements of
section 110(a)(2)(D)(i) for the 1997 8hour ozone and PM2.5 NAAQS. Some of
these SIPs have been approved and
some are pending approval.
For the states that have now been
identified to be contributing
significantly to nonattainment or
interfering with maintenance under this
proposed rule and whose
110(a)(2)(D)(i)(I) SIPs with respect to the
1997 ozone and PM2.5 NAAQS are
pending approval, EPA will finalize the
FIP included in this proposed rule only
if EPA either determines that the SIP
submission is incomplete or
disapproves the SIP submission.
(Alternatively, if a state withdraws its
SIP submission, EPA will finalize the
FIP.)
For states which are not included in
a final FIP under this proposed
transport rule and that have not
submitted a 110(a)(2)(D)(i)(I) SIP to
address the 1997 ozone and PM2.5
NAAQS, a SIP submittal is required.
EPA has approved the 110(a)(2)(D)(i)
submission from the state of Kansas for
the 1997 ozone and PM2.5 NAAQS. The
updated modeling done for this
proposed rule demonstrates that
emissions from Kansas significantly
contribute to nonattainment or interfere
with maintenance of the 1997 8-hour
ozone NAAQS in downwind areas.
Because Kansas’ current SIP does not
prohibit these emissions, it is not
adequate to satisfy the requirements of
110(a)(2)(D)(i)(I) at this time. For
Kansas, under a separate action, EPA
plans to propose a finding under CAA
110(k)(5) (known as a SIP Call) that the
state’s existing SIP is substantially
inadequate to meet the requirements of
110(a)(2)(D)(i)(I) with respect to the
1997 ozone NAAQS. That SIP call, if
finalized, would also establish a
deadline for submission of a new
110(a)(2)(D)(i)(I) SIP which EPA would
review for completeness. Therefore, in
today’s notice EPA is proposing to
finalize the FIP for Kansas for ozone
only if the state fails to submit a
complete and approvable SIP by the
deadline established in any final SIP
Call.
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B. Section 110 (a)(2)(D)(i) SIPs for the
2006 24-Hour PM2.5 NAAQS
With respect to the 2006 24-hour
PM2.5 NAAQS, EPA has issued a
separate Federal Register notice finding
that a number of states failed to make
the required 110(a)(2)(D)(i)(I) SIP
submissions. None of the SIP submittals
in the states that have submitted section
110(a)(2)(D)(i)(I) transport SIPs for the
2006 24-hour PM2.5 NAAQS have been
acted on yet by EPA. For the states with
SIPs that are pending approval, EPA is
proposing to finalize the FIP with
respect to the 2006 PM2.5 NAAQS only
if EPA finds the previously submitted
SIP incomplete or disapproves the SIP
submission. Alternatively, if any of
these states withdraws its 2006 24-hour
PM2.5 SIP submittal, EPA plans to issue
a separate notice of finding for such
states.
C. Transport Rule SIPs
EPA also notes that, by promulgating
these Transport Rule FIPs, EPA would
in no way affect the right of states to
submit, for review and approval, a SIP
that replaces the federal requirements of
the FIP with state requirements. In order
to replace the FIP in a state, the state’s
SIP must provide adequate provisions to
prohibit NOX and SO2 emissions that
contribute significantly to
nonattainment or interfere with
maintenance in another state or states.
The Transport Rule FIPs would be in
place in each covered state until a
state’s SIP was submitted and approved
by EPA to replace a FIP.
For each upwind state covered by the
proposed Transport Rule, EPA proposes
state-specific emissions reductions
requirements with respect to one or
more of three air quality standards—the
1997 annual PM2.5 NAAQS, the 2006 24hour 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.
Again EPA wants to offer states
substantial flexibility for addressing the
Section 110(a)(2)(D)(i)(I) transport issues
through a SIP should they choose to do
so. The EPA’s intent is to provide states
with substantial flexibility in
implementing these emissions
reductions requirements. EPA will
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. The
specific quantity of emissions
reductions necessary for a state’s SIP
would be determined based on the state
emissions budgets provided in the final
transport rule. (See Tables IV.E–1 for
proposed SO2 and annual NOX budgets,
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and IV.E–2 for proposed ozone season
NOX budgets, in section IV.E).
In the states for which EPA is
proposing to require reductions with
respect to both the 24-hour PM2.5
NAAQS and the annual PM2.5 NAAQS,
there is no case where the annual
standard drives the reduction
requirements deeper than would the 24hour standard alone. Thus, emissions
reduction requirements for a SIP to
address significant contribution and
interference with maintenance with
respect to the 24-hour PM2.5 NAAQS
would be based on the SO2 and NOX
emissions budgets in Table IV.E–1. For
such a state, a SIP that addresses the
requirements with respect to the 24hour PM2.5 NAAQS would also by
definition address the requirements
with respect to the annual PM2.5
NAAQS.
EPA is taking comment on all aspects
of how a state could replace the
Transport Rule FIP with a SIP and on
what the SIP approval criteria should
be.
VIII. Permitting
A. Title V Permitting
EPA’s proposed FIPs would 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 71.107 Title V requires that sources
meeting certain criteria have permits
meeting the requirements specified in
Title V and the Title V regulations. For
example, for sources required to have
Title V permits, such permits must
include, among other things, all
‘‘applicable requirements,’’ as defined in
the Title V regulations (40 CFR 70.2 and
71.2 (definition of ‘‘applicable
requirement’’)).
EPA anticipates that, given the nature
of the units covered by the proposed
FIPs, most of the sources at which they
are located would be subject to Title V
permitting requirements. For sources
subject to Title V, the requirements
applicable to them under the proposed
FIPs would be ‘‘applicable
requirements’’ under Title V and
therefore would need to be included in
the Title V permits. For example,
requirements under the proposed FIPs
concerning designated representatives,
monitoring, reporting, and
recordkeeping, the requirement to hold
allowances covering emissions, the
assurance provisions, and liability
would be ‘‘applicable requirements’’ and
necessary to include in the permits.
107 Part 70 governs approved state Title V
programs, and part 71 governs the federal Title V
program.
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The Title V permits program includes,
among other things, provisions for
permit applications, permit content, and
permit revisions that would address the
applicable requirements under the
proposed FIPs in a manner that would
provide the flexibility necessary to
implement a market-based program
such as the one that EPA is proposing.
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). The trading program
regulations for the proposed FIPs would
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
would also be included in each Title V
permit for a covered source. As a result,
allowances could be traded (or
allocated, held, or deducted) under the
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
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 trading
program regulations for the proposed
FIPs would include provisions requiring
unit owners and operators to submit
monitoring system certification
applications (or, for alternative
monitoring systems, petitions) to EPA
establishing the monitoring and
reporting approach to be used by the
unit. These applications and petitions
are subject to EPA review and approval
to ensure consistency in monitoring and
reporting among all trading program
participants. As provided in the
proposed regulations, EPA would only
allow use of approaches that would
result in emissions data with an
appropriate level of precision,
reliability, accessibility, and timeliness.
The proposed regulations would also
include a provision stating that a
description of the general approach that
each covered unit is required to use for
monitoring and reporting emissions
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(i.e., an approach using a continuous
emissions monitoring system, an
excepted monitoring system under
appendices D and E to part 75, a low
mass emissions excepted monitoring
methodology under § 75.19, or an
alternative monitoring system under
subpart E of part 75) could be added to
or changed in a Title V permit using
minor permit modification procedures,
provided that the requirements
applicable to the monitoring and
reporting addition or change were
already incorporated elsewhere in the
permit. As a result, minor permit
modification procedures could be used
to revise a unit’s Title V permit to be
consistent with any changes in the
monitoring and reporting approach
allowed for the unit by EPA through the
monitoring system certification or
petition process in the proposed trading
program regulations. However, if the
permit did not already incorporate the
monitoring and reporting requirements
applicable to the change, the permit
would also have to be revised to
incorporate these requirements, and this
change would not qualify as a minor
permit modification pursuant to 40 CFR
70.7(e)(2)(i)(B) and 40 CFR
71.7(e)(1)(i)(B).
As new applicable requirements
under Title V, the requirements for
covered units under the final FIPs
would 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)).108 For
sources newly subject to title V that
would also be covered sources under
the proposed FIPs, the initial Title V
permit issued pursuant to 40 CFR
70.7(a) would include the final FIP
requirements. In order to ensure that
covered sources’ Title V permit
provisions concerning the FIPs would
reflect, properly and in a manner
consistent from permit to permit, the
trading program requirements and
flexibilities, EPA intends to issue
guidance, after promulgation of the final
FIPs, to assist permitting authorities.
This guidance would include
information on permit issuance and
permit modification requirements, as
well as a permit content template that
would identify the applicable
requirements under the trading program
108 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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and thereby ensure that they would be
correctly and comprehensively reflected
in each permit in a manner that would
reduce the need for frequent permit
revisions. Use of a permit content
template would also reduce the burden
on sources in obtaining, on permitting
authorities in issuing, and on EPA in
reviewing, permits or permit revisions.
B. New Source Review
EPA recognizes that pollution control
projects, including pollution control
projects constructed to comply with the
proposed rule, have the potential to
trigger new source review (NSR)
permitting.
On December 20, 2005, the EPA
agreed to reconsider one specific aspect
of the CAIR. In that notice, EPA granted
reconsideration and sought comment on
the potential impact of a judicial
opinion, New York v. EPA, 413 F.3d 3
(D.C. Cir. 2005). This decision vacated
the pollution control project exclusion
in EPA’s NSR regulations. (The
exclusion allowed for certain
environmentally beneficial pollution
control projects to be excluded from
certain NSR requirements.) For this
reconsideration, EPA conducted an
analysis which showed that the court
decision did not impact the CAIR
analyses. The EPA believes this
analysis, which remains current and
relevant for all pollutants except for
greenhouse gas (GHG), shows that New
Source Review (NSR) requirements
would not significantly impact the
construction of controls that are
installed to comply with the proposed
transport rule. Details of this analysis
can be found in a Technical Support
document which is available on EPA’s
Web site at: https://epa.gov/cair/pdfs/
0053–2263.pdf.
Because GHG was not considered by
EPA to be a ‘‘pollutant’’, let alone a
‘‘regulated pollutant,’’ at the time of
CAIR, GHG was not addressed in the
previous analysis. GHG requirements
related to the component of new source
review concerning the Prevention of
Significant Deterioration (‘‘PSD’’)
program have recently been 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, once the PSD requirements for
GHG take effect on January 2, 2011,
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
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IX. What benefits are projected for the
proposed rule?
In this section, we present the results
of EPA’s analysis of the benefits of the
emissions reductions in this proposal on
PM2.5 and ozone air quality, public
health, welfare, and the environment.
These improvements were determined
based upon air quality modeling of the
2014 base case and the ‘‘State Budgets/
Limited Trading’’ remedy proposed in
this rule, as described in section V,
above.
Implementation of this rule will very
substantially lower the extent of
nonattainment and maintenance
problems for the annual and 24-hour
PM2.5 NAAQS and 8-hour ozone
NAAQS in the eastern U.S. (see section
IX.A, below). The improvements in air
quality will annually prevent thousands
of premature deaths and other serious
health effects (see section IX.B, below).
We estimate the total monetized annual
benefits to be approximately $120
billion to $290 billion or $110 billion to
$270 billion in 2014 (at a 3 percent and
a 7 percent discount rate, respectively)
for the proposed ‘‘State Budgets/Limited
Trading’’ remedy. There will be
significant benefits that are not
quantified. Notably, in 2012 the benefits
are actually larger since greater
emissions reductions are occurring from
the baseline in that timeframe, as
indicated in Table V.E–2, above.
Because the magnitude of the PM2.5 cobenefits is largely driven by the
concentration-response function for
premature mortality, we examined
alternate relationships between PM2.5
and premature mortality supplied by
experts. Higher and lower co-benefits
estimates are plausible, but most of the
expert-based estimates fall between
these two estimates above.109 All
monetized estimates are stated in 2006
dollars. Also note that the analytic
baseline presents a unique situation.
EPA has been directed to replace the
CAIR; yet the CAIR remains in place
and has led to significant emissions
reductions in many states.
A key step in the process of
developing a 110(a)(2)(D)(i)(I) rule
involves analyzing existing (base case)
emissions to determine which states
significantly contribute to downwind
nonattainment and maintenance areas.
EPA cannot prejudge at this stage which
states will be affected by the rule. For
example, a state affected by CAIR may
not be affected by the new rule and after
the new rule goes into effect, the CAIR
requirements will no longer apply. For
a state covered by CAIR but not covered
by the new rule, the CAIR requirements
would not be replaced with new
requirements, and therefore an increase
in emissions relative to present levels
could occur in that state. More
fundamentally, the court has made clear
that, due to legal flaws, the CAIR rule
cannot remain in place and must be
replaced. If EPA’s base case analysis
were to ignore this fact and assume that
reductions from CAIR would continue
indefinitely, areas that are in attainment
solely due to controls required by CAIR
would again face nonattainment
problems because the existing
protection from upwind pollution
would not be replaced. For these
reasons, EPA cannot assume in its base
case analysis, that the reductions
required by CAIR will continue to be
achieved.
Following this logic, the 2012 base
case shows emissions higher than
current levels in some states. Because
EPA has been directed to replace CAIR,
EPA believes that for many states, the
absence of the CAIR NOX program will
lead to the status quo of the NOX Budget
Program, which limits ozone-season
NOX emissions and ensures the
operation of NOX controls in those
states. Also, without the CAIR SO2
program, emission requirements in
many areas would revert to the
comparatively less stringent
requirements of the Title IV Acid Rain
109 Roman et al., 2008. Expert Judgment
Assessment of the Mortality Impact of Changes in
Ambient Fine Particulate Matter in the U.S.
Environ. Sci. Technol., 42, 7, 2268–2274.
110 As described in the AQMTSD, the eastern U.S.
was modeled at a horizontal resolution of 12 x 12
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program. As a result, SO2 emissions in
many states would increase markedly in
the 2012 base case relative to the
present. Efforts to comply with ARP
rules at the least-cost would occur in
many cases without the operation of
existing scrubbers through use of readily
available, inexpensive Title IV
allowances. Notably, all known controls
that are required under state laws,
NSPS, consent decrees, and other
enforceable binding commitments
through 2014 are accounted for in the
base case. It is against this backdrop that
the Transport Rule is analyzed and that
significant contribution to
nonattainment and interference with
maintenance must be addressed.
km. The remainder of the U.S. was modeled at a
resolution of 36 x 36 km.
111 To provide a point of reference, Table IX–1
also includes the number of nonattainment and/
maintenance sites based on ambient design values
for the period 2003 through 2007.
exceed the thresholds in the Tailoring
Rule. Once the PSD requirements take
effect, 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 tons per year of CO2
equivalent. EPA believes it is very
unlikely that pollution control projects
would cause GHG increases that would
exceed the 75,000 tons per year
threshold.
Consistent with EPA’s previous
analysis and EPA’s conclusions for
GHG, EPA does not believe that there
are significant impacts from NSR for any
pollution control projects resulting from
the proposed rule such as low-NOX
burners, SO2 scrubbers, or SCR. EPA
requests comment on this issue.
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A. The Impacts on PM2.5 and Ozone of
the Proposed SO2 and NOX Strategy
The air quality modeling platform
described in section IV.C. was used by
EPA to model the impacts of the
proposed SO2 and NOX emissions
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.110
Modeling was performed for the 2014
base case and the 2014 ‘‘State Budgets/
Limited Trading’’ scenario to assess the
expected effects of the proposed
regional strategy 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
IV.C. The aggregate emissions in 2012
and 2014 for SO2 and NOX are provided
in Table V.E–2 in section V.E. The
emissions by state are provided in
Tables V.E–5 through V.E–7 in section
V.E, and also in the Air Quality
Modeling TSD.
The projected 2014 concentrations of
annual PM2.5, daily PM2.5, and ozone at
each monitoring site in the East for
which projections were made are
provided in the AQMTSD. 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, daily PM2.5, and ozone are
provided in Table IX–1.111 The average
and peak reductions in annual PM2.5,
daily PM2.5, and ozone predicted at 2012
nonattainment and/or maintenance sites
due to the emissions reductions
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between 2012 and the 2014 remedy are
provided in Table IX–2.
TABLE IX–1—PROJECTED REDUCTION IN NONATTAINMENT AND/OR MAINTENANCE PROBLEMS FOR PM2.5 AND OZONE IN
THE EASTERN U.S.
Ambient
(2003–2007)
Annual PM2.5 Nonattainment Sites 112 .....
Annual PM2.5 Maintenance-Only Sites ....
Daily PM2.5 Nonattainment Sites .............
Daily PM2.5 Maintenance-Only Sites ........
Ozone Nonattainment Sites .....................
Ozone Maintenance-Only Sites ...............
2012 base
case
102
21
151
48
103
67
2014 base
case
32
16
92
38
11
16
2014 proposed
remedy
Percent reduction: 2012
base case vs.
2014 remedy
(percent)
Percent reduction: 2014
base case vs.
2014 remedy
(percent)
1
1
17
11
7
5
97
94
82
71
36
69
93
86
69
61
0
17
15
7
54
28
7
6
TABLE IX–2—AVERAGE AND PEAK REDUCTION IN ANNUAL PM2.5, DAILY 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 to 2014 remedy
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Annual PM2.5 Nonattainment Sites .........................................................
Annual PM2.5 Maintenance-Only Sites ....................................................
Daily PM2.5 Nonattainment Sites .............................................................
Daily PM2.5 Maintenance-Only Sites .......................................................
Ozone Nonattainment Sites ....................................................................
Ozone Maintenance-Only Sites ..............................................................
The information in Table IX–1 shows
that there will be significant reductions
in the extent of nonattainment and
maintenance problems for annual PM2.5,
daily PM2.5, and ozone between 2012
and 2014 as a result of the emissions
budgets in this proposal coupled with
emissions reductions during this time
period from other existing control
programs. Specifically, the results of the
air quality modeling indicate that all but
1 site is projected to be in attainment
and only 1 site is projected to have a
maintenance problem for annual PM2.5
in 2014 with the emissions reductions
expected from this proposal. As
indicated in Table IX–2, the average
reduction in annual PM2.5 across the 32
2012 nonattainment sites is 1.9 μg/m3
and the peak reduction at an individual
nonattainment site is 3.2 μg/m3.
Comparable reductions are projected at
annual PM2.5 maintenance-only sites.
For 24-hour PM2.5, we project that the
number of nonattainment sites will be
reduced by 82 percent and the number
of maintenance-only sites by 71 percent
in 2014 compared to the 2012 base case.
The average reduction in 24-hour PM2.5
across the 92 2012 nonattainment sites
is 5.8 μg/m3 and the peak reduction at
2.8
2.6
5.8
5.1
1.9
2.3
μg/m3 .......................................
μg/m3 .......................................
μg/m3 .......................................
μg/m3 .......................................
ppb ...........................................
ppb ...........................................
an individual nonattainment site is 15.3
μg/m3. Comparable reductions are
projected at 24-hour PM2.5 maintenanceonly sites.
The emissions reductions in this
proposal will result in considerable
progress toward attainment and
maintenance at the 28 sites that remain
as nonattainment and/or maintenance
for the 24-hour PM2.5 standard. On
average for these 28 sites, the predicted
amount of PM2.5 reduction in 2014 is
more than half of what is needed for
these sites to attain and/or maintain the
24-hour standard.
Thus, the SO2 and NOX emissions
reductions which will result from
today’s proposal will greatly reduce the
extent of PM2.5 nonattainment and
maintenance problems by 2014 and
beyond. As described previously, these
emissions 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
emissions reductions will also help
Peak reduction: 2012 base case to
2014 remedy
3.9 μg/m3
4.2 μg/m3
15.3 μg/m3
13.5 μg/m3
3.9 ppb
4.2 ppb
those locations that may have
maintenance problems.
Based on the 2012 base air quality
modeling for ozone, 27 sites in the East
are projected to be nonattainment or
have problems maintaining the 1997
ozone standard. The initial phase of
summer NOX reductions in today’s
proposal are projected to lower 8-hour
ozone concentration by 2.8 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
36 percent and the number of
maintenance-only sites by 69 percent in
2014 compared to the 2012 base case.
For the 12 sites expected to have
residual nonattainment/maintenance
problems in 2014, the predicted ozone
reductions provide nearly 10 percent of
the amount needed for these sites to
attain and/or maintain the ozone
standard. Thus, our modeling indicates
that by 2014 the initial phase of summer
NOX emissions reductions in this
proposal will lower ozone
concentrations in the East and help
bring areas closer to attainment for the
8-hour ozone NAAQS.
112 ‘‘Nonattainment’’ is used to denote sites that
are projected to have both nonattainment and
maintenance problems.
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B. Human Health Benefit Analysis
To estimate the human health benefits
of the proposed Transport Rule, we 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. We
provide such estimates for the proposed
remedy option. Notably, EPA expects
that in 2014 the other two alternatives
that the Agency considered have the
same general level of benefits that will
result from their implementation. The
results of the analysis for the alternate
SO2 reduction scenarios are found in the
RIA. 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
concentrations and premature mortality.
For this proposed rule we cite two key
empirical studies, one based on the
American Cancer Society cohort
study 113 and the other based on the
extended Six Cities cohort study.114
Table IX–3 presents the primary
estimates of reduced incidence of PM2.5
and ozone-related health effects in 2014
for the proposed and alternative
remedies. In 2014, we estimate that PMrelated annual benefits of the proposed
remedy include approximately 14,000 to
36,000 fewer premature mortalities,
9,200 fewer cases of chronic bronchitis,
22,000 fewer non-fatal heart attacks,
11,000 fewer hospitalizations (for
respiratory and cardiovascular disease
combined), 10 million fewer days of
restricted activity due to respiratory
illness and approximately 1.8 million
fewer work-loss days. We also estimate
substantial health improvements for
children from fewer cases of upper and
lower respiratory illness, acute
bronchitis, and asthma attacks. As
mentioned earlier, the reduced
incidences of various effects would be
greater in 2012 due to the larger
emissions reductions that occur from
the baseline. The lower reductions in
emissions in 2014 result from further
SO2 controls in the proposed remedy
because the baseline has much greater
controls resulting from state actions and
consent decrees.
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 50 and 230 fewer
premature mortalities, 690 fewer
hospital admissions for respiratory
illnesses, 230 fewer emergency room
admissions for asthma, 300,000 fewer
days with restricted activity levels, and
110,000 fewer days where children are
absent from school due to illnesses.
When adding the PM and ozone-related
mortalities together, we find that the
proposed Transport Rule will yield
between 14,000 and 36,000 fewer
premature mortalities. The following
references are used in providing our
estimates of ozone health-related
benefits:
Bell, M.L., et al. 2004. Ozone and shortterm mortality in 95 U.S. urban communities,
1987–2000. Journal of the American Medical
Association. 292 (19): p. 2372–8.
Laden, F., J. Schwartz, F.E. Speizer, and
D.W. Dockery. 2006. Reduction in Fine
Particulate Air Pollution and Mortality.
American Journal of Respiratory and Critical
Care Medicine 173:667–672. Estimating the
Public Health Benefits of Proposed Air
Pollution Regulations. Washington, DC: The
National Academies Press.
Levy JI, Baxter LK, Schwartz J. 2009.
Uncertainty and variability in health-related
damages from coal-fired power plants in the
United States. Risk Anal. doi: 10.1111/
j.1539–6924.2009.01227.x [Online 9 Apr
2009]
Pope, C.A., III, R.T. Burnett, M.J. Thun,
E.E. Calle, D. Krewski, K. Ito, and G.D.
Thurston. 2002. Lung Cancer,
Cardiopulmonary Mortality, and Long-term
Exposure to Fine Particulate Air Pollution.
Journal of the American Medical Association
287:1132–1141.
TABLE IX–3—ESTIMATED ANNUAL REDUCTIONS IN INCIDENCE OF HEALTH EFFECTS A
Health effect
Proposed remedy
PM-Related endpoints
Premature Mortality
Pope et al. (2002) (age >30) ..............................................................................................................................
Laden et al. (2006) (age >25) ............................................................................................................................
Infant (< 1 year) ..................................................................................................................................................
Chronic Bronchitis ..............................................................................................................................................
Non-fatal heart attacks (age > 18) .....................................................................................................................
Hospital admissions—respiratory (all ages) .......................................................................................................
Hospital admissions—cardiovascular (age > 18) ...............................................................................................
Emergency room visits for asthma (age < 18) ..................................................................................................
Acute bronchitis (age 8–12) ...............................................................................................................................
Lower respiratory symptoms (age 7–14) ...........................................................................................................
Upper respiratory symptoms (asthmatics age 9–18) .........................................................................................
Asthma exacerbation (asthmatics 6–18) ............................................................................................................
Lost work days (ages 18–65) .............................................................................................................................
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Minor restricted-activity days (ages 18–65) .......................................................................................................
Ozone-related endpoints
Premature mortality
Bell et al. (2004) (all ages) .................................................................................................................................
Levy et al. (2005) (all ages) ...............................................................................................................................
Hospital admissions—respiratory causes (ages > 65) ......................................................................................
Hospital admissions—respiratory causes (ages < 2) ........................................................................................
Emergency room visits for asthma (all ages) ....................................................................................................
Minor restricted-activity days (ages 18–65) .......................................................................................................
113 Pope et al., 2002. ‘‘Lung Cancer,
Cardiopulmonary Mortality, and Long-term
Exposure to Fine Particulate Air Pollution.’’ Journal
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of the American Medical Association. 287:1132–
1141.
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14,000 (4,000–25,000)
36,000 (17,000–56,000)
59 (¥66–180)
9,200 (320–18,000)
22,000 (5,800–39,000)
3,500 (1,400–5,500)
7,500 (5,200–8,900)
14,000 (7,200–21,000)
21,000 (¥4,800–46,000)
250,000 (98,000–400,000)
190,000 (36,000–350,000)
240,000 (8,300–800,000)
1,800,000 (1,500,000–
2,000,000)
10,000,000 (8,600,000–
12,000,000)
50 (17–84)
230 (160–300)
390 (¥18–740)
300 (130–460)
230 (¥30–730)
300,000 (130,000–480,000)
114 Laden et al., 2006. ‘‘Reduction in Fine
Particulate Air Pollution and Mortality.’’ American
Journal of Respiratory and Critical Care Medicine.
173:667–672.
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TABLE IX–3—ESTIMATED ANNUAL REDUCTIONS IN INCIDENCE OF HEALTH EFFECTS A—Continued
Health effect
Proposed remedy
School absence days .........................................................................................................................................
110,000 (38,000–160,000)
A Values
rounded to two significant figures. Benefits from reducing other criteria pollutants and hazardous air pollutants and ecosystem effects
are not included here.
C. Quantified and Monetized Visibility
Benefits
Only a subset of the expected
visibility benefits—those for Class I
areas—are included in the monetary
benefits 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 $3.4 billion
beginning in 2014 for visibility
improvements. Methodological
limitations prevented us from
quantifying the visibility benefits of the
alternate remedies. The value of
visibility benefits in areas where we
were unable to monetize benefits could
also be substantial.
D. Benefits of Reducing GHG Emissions
When fully implemented in 2014, the
proposed Transport Rule would reduce
emissions of CO2 from electrical
generating units by about 15 million
metric tons annually. Using a ‘‘social
cost of carbon’’ (SCC) estimate that
accounts for the marginal dollar value
(i.e., cost) of climate-related damages
resulting from CO2 emissions, previous
analyses including the RIA for the Final
Rulemaking to Establish Light-Duty
Vehicle Greenhouse Gas Emissions
Standards and Corporate Average Fuel
Efficiency Standards have found the
total benefit of CO2 reductions is
substantial. The monetary value of these
avoided damages also grows over time.
Readers interested in learning more
about the calculation of the SCC metric
should refer to the SCC TSD, Social Cost
of Carbon for Regulatory Impact
Analysis Under Executive Order 12866
[Docket No. EPA–HQ–OAR–2009–
0472].
E. Total Monetized Benefits
Table IX–4 presents the estimated
monetary value of reductions in the
incidence of health and welfare effects.
These estimates account for increases in
the value of risk reduction over time. As
the table indicates, total benefits are
driven primarily by the reduction in
premature fatalities each year, which
account for over 90 percent of total
benefits.
Table IX–5 presents the total
monetized net benefits for 2014. A
listing of the benefit categories that
could not be quantified or monetized in
our benefit estimates are provided in
Table IX–6.
TABLE IX–4—ESTIMATED ANNUAL MONETARY VALUE OF REDUCTIONS IN INCIDENCE OF HEALTH AND WELFARE EFFECTS
(Billions Of 2006$) A
Health effect
Pollutant
Proposed remedy
Premature mortality (Pope et al. 2002 PM mortality and Bell et al. 2004 ozone mortality estimates)
3% discount rate .........................................................................................
7% discount rate .........................................................................................
PM2.5 & O3 .......................................
PM2.5 & O3 .......................................
$110 ($8.8–$340)
$100 ($7.9–$300)
Premature mortality (Laden et al. 2006 PM mortality and Levy et al. 2005 ozone mortality estimates)
3% discount rate .........................................................................................
7% discount rate .........................................................................................
Chronic bronchitis ........................................................................................
Non-fatal heart attacks.
3% discount rate .........................................................................................
7% discount rate .........................................................................................
Hospital admissions—respiratory ................................................................
Hospital admissions—cardiovascular ..........................................................
Emergency room visits for asthma .............................................................
Acute bronchitis ...........................................................................................
Lower respiratory symptoms .......................................................................
Upper respiratory symptoms .......................................................................
Asthma exacerbation ...................................................................................
Lost work days ............................................................................................
School loss days .........................................................................................
Minor restricted-activity days .......................................................................
Recreational visibility, Class I areas ...........................................................
PM2.5 & O3 .......................................
PM2.5 & O3 .......................................
PM2.5 ................................................
$280 ($25–$820)
$260 ($22–$310)
$4.3 $0.2–$20)
PM2.5 ................................................
PM2.5 ................................................
PM2.5 & O3 .......................................
PM2.5 ................................................
PM2.5 & O3 .......................................
PM2.5 ................................................
PM2.5 ................................................
PM2.5 ................................................
PM2.5 ................................................
PM2.5 ................................................
.....................................................
PM2.5 & O3 .......................................
PM2.5 ................................................
$2.5 ($0.4–$6)
$2.4 ($0.4–$5.9)
$0.06 ($0.03–$0.1)
$0.2 ($0.1–$0.3)
$0.005 ($0.002–$0.008)
$0.009 (¥$0.0004–$0.03)
$0.005 ($0.002–$0.009)
$0.006 ($0.001–$0.014)
$0.012 ($0.001–$0.046)
$0.2 ($0.19–$0.24)
$0.01 ($0.004–$0.013)
$0.64 ($0.34–$0.97)
$3.6
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Total benefits based on Pope et al. 2002 PM mortality and Bell et al. 2004 ozone mortality estimates
3% discount rate .........................................................................................
7% discount rate .........................................................................................
PM2.5 & O3 .......................................
PM2.5 & O3 .......................................
$120 ($10–$360)
$110 ($9–$330)
Total benefits based on Laden et al. 2006 PM mortality and Levy et al. 2005 ozone mortality estimates
3% discount rate .........................................................................................
7% discount rate .........................................................................................
A Estimates
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PM2.5 & O3 .......................................
rounded to two significant figures.
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$270 ($24–$760)
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E. How do the benefits compare to the
costs of this proposed rule?
The estimated annual private costs to
implement the emission reduction
requirements of the proposed rule for
the Transport Rule region are $3.7
billion in 2012 and $2.8 billion in 2014
(2006$) for the proposed remedy option,
$4.2 billion in 2012 and $2.7 billion in
2014 for the State Budgets/Intrastate
Trading remedy option, and $4.3 billion
in 2012 and $3.4 billion in 2014 for the
direct control remedy option. 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 (thus reflecting the
proposed remedy option) are estimated
to be approximately $2.0 billion in 2014
assuming a 3 percent discount rate.
These costs become $2.2 billion in 2014,
if one assumes a 7 percent discount rate.
Thus, the net benefit (social benefits
minus social costs) as will be shown in
Table IX–5 for the proposed remedy
option is approximately $120 to 292
billion or $109 to 264 billion (3 percent
and 7 percent discount rates) in 2014.
Implementation of the rule is expected
to provide society with a substantial net
gain in social welfare based on
economic efficiency criteria.
The annualized regional cost of the
proposed rule, as quantified here, is
EPA’s best assessment of the cost of
implementing the proposed option.
These costs are generated from rigorous
economic modeling of changes in the
power sector expected from the
proposed 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 proposed
option 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 less than $28
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 to the quantified costs of the
program on 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 section X of
this preamble and in the RIA for this
proposed rule.
TABLE IX–5—SUMMARY OF ANNUAL BENEFITS, COSTS, AND NET BENEFITS OF THE TRANSPORT RULE IN 2014
[Billions of 2006 dollars]
Description
Proposed remedy
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Social costs:
3 percent discount rate ............................................................................................................................................
7 percent discount rate ............................................................................................................................................
Social benefits:
3 percent discount rate ............................................................................................................................................
7 percent discount rate ............................................................................................................................................
Health-related benefits:
3 percent discount rate ............................................................................................................................................
7 percent discount rate ............................................................................................................................................
Visibility benefits:
3 percent discount rate ............................................................................................................................................
7 percent discount rate ............................................................................................................................................
Annual net benefits (benefits-costs)
3 percent discount rate ............................................................................................................................................
7 percent discount rate ............................................................................................................................................
$2.0.
$2.2.
$122 to 294 + B.
$111 to 266 + B.
$118 to 290.
$107 to 262.
$3.6.
$3.6.
$120 to 292.
$109 to 264.
a All estimates are rounded to three significant digits and represent annualized benefits and costs anticipated for 2014. Estimates relate to the
complete Transport Rule program.
b Note that costs are the annual total costs of reducing pollutants including NO and SO in the Transport Rule region.
X
2
c As this table indicates, total benefits are driven primarily by PM -related health benefits. The reduction in premature fatalities each year ac2.5
counts for over 90 percent of total monetized benefits 2014. Benefits in this table are nationwide (with the exception of visibility) and are associated with NOX and SO2 reductions for the EGU source category. Ozone benefits represent benefits in the eastern United States. Visibility benefits represent benefits in Class I areas in the southeastern United States.
d Not all possible benefits or disbenefits are quantified and monetized in this analysis. Potential benefit categories that have not been quantified
and monetized are listed in Table IX–6. We represent the value of unquantified benefits and disbenefits with a ‘‘B.’’
e Valuation assumes discounting over the SAB-recommended 20 year segmented lag structure described in chapter 4 of the Regulatory Impact
Analysis for the Clean Air Interstate Rule (March 2005). Results reflect 3 percent and 7 percent discount rates consistent with EPA and OMB
guidelines for preparing economic analyses (U.S. EPA, 2000 and OMB, 2003).174
f Net benefits are rounded to the nearest $1 billion. Columnar totals may not sum due to rounding.
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Federal Register / Vol. 75, No. 147 / Monday, August 2, 2010 / Proposed Rules
Every benefit-cost analysis examining
the potential effects of a change in
environmental protection requirements
is limited to some extent by data gaps,
limitations in 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. Gaps in the
economics literature often result in the
inability 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
emissions 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
VSL estimates derived from 26 labor
market and contingent valuation studies
published between 1974 and 1991. The
mean VSL across these studies is $6.3
million (2000$).115 The benefits
estimates generated for this rule are
subject to a number of assumptions and
uncertainties, which are discussed
throughout the RIA document.
As Table IX–4 indicates, total benefits
are driven primarily by the reduction in
115 In this analysis, we adjust the VSL to account
for a different currency year (2006$) and to account
for income growth to 2014. After applying these
adjustments to the $6.3 million value, the VSL is
$8.5 million.
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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 daily 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.
(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 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 IX–6.
F. What are the unquantified and
unmonetized benefits of the Transport
Rule emissions reductions?
Important benefits beyond the human
health and welfare benefits resulting
from reductions in ambient levels of
PM2.5 and ozone in the eastern United
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States are expected to occur from this
rule. These other benefits occur both
directly from NOX and SO2 emissions
reductions. These benefits are listed in
Table IX–6. Some of the more important
examples include: Reductions in NOX
and SO2 emissions required by the
Transport Rule will reduce acidification
and, in the case of NOX, eutrophication
of water bodies. Reduced nitrate
contamination of drinking water is
another possible benefit of the rule. This
proposed rule will also reduce 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 we are 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, and reduced vegetation
impairment from ozone.
1. 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.
Together these emissions are deposited
onto terrestrial and aquatic ecosystems
across the U.S., contributing to the
problems of acidification, nutrient
enrichment, and methylmercury
production. In addition, NOX is a
precursor to ozone, which can impair
vegetation.
a. 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 [key
indicator is termed Acid Neutralizing
Capacity (ANC)] depends largely on the
watershed’s physical characteristics,
such as geology, soils, and size. 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
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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 midAppalachian highlands) and
southeastern streams. This regulatory
action will decrease acid deposition in
the transport region and is likely to have
positive effects on the health and
productivity of aquatic ecosystems in
the region.
b. 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 (U.S. EPA, 2008f). 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
(Joslin et al., 1992), leading to increased
mortality of canopy trees.
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 for 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., and acidifying
deposition has been implicated as a
causal factor (DeHayes et al., 1999).
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This regulatory action will decrease
acid deposition in the transport region
and is likely to have positive effects on
the health and productivity of forest
systems in the region.
c. 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 N and phosphorus, and a
majority of these estuaries are located in
the coastal area from North Carolina to
Massachusetts (NOAA, 2007). For
estuaries in the Mid-Atlantic region, the
contribution of atmospheric distribution
to total N loads is estimated to range
between 10 percent and 58 percent
(Valigura et al., 2001).
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
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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 in the Transport
Rule region. 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.
d. Mercury Methylation and Deposition
Mercury is a highly neurotoxic
contaminant that enters the food web as
a methylated compound,
methylmercury (U.S. EPA, 2008d). 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 (Drevnick et al., 2007; Munthe et
al., 2007). The SO2 ISA (U.S. EPA, 2008)
concluded that evidence is sufficient to
infer a casual relationship between
sulfur deposition and increased mercury
methylation in wetlands and aquatic
environments.
2. Ozone Vegetation Effects
Ozone causes discernible injury to a
wide array of vegetation (U.S. EPA,
2006; Fox and Mickler, 1996). In terms
of forest productivity and ecosystem
diversity, ozone may be the pollutant
with the greatest potential for regionalscale forest impacts (U.S. EPA, 2006).
Studies have demonstrated repeatedly
that ozone concentrations commonly
observed in polluted areas can have
substantial impacts on plant function
(De Steiguer et al., 1990; Pye, 1988).
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
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ozone, scientists have developed ozoneexposure/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 (Chappelka and Samuelson,
1998). In areas where certain ozonesensitive 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 longterm forest health (Heck, 1997).
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 (U.S.
EPA, 2007). 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 (U.S. EPA, 2007). 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 (Abt Associates,
1995).
3. Other Health or Welfare Disbenefits of
the Transport Rule That Have Not Been
Quantified
In contrast to the additional benefits
of the proposed rule discussed above, it
is also possible that this rule will result
in disbenefits in some areas of the
region. Current levels of nitrogen
deposition in these areas may provide
passive fertilization for forest and
terrestrial ecosystems where nutrients
are a limiting factor and for some
croplands. The effects of ozone and PM
on radiative transfer in the atmosphere
can also lead to effects of uncertain
magnitude and direction on the
penetration of ultraviolet light and
climate. Ground level ozone makes up
a small percentage of total atmospheric
ozone (including the stratospheric layer)
that attenuates penetration of
ultraviolet-b (UVb) radiation to the
ground. The EPA’s past evaluation of
the information indicates that potential
disbenefits would be small, variable,
and with too many uncertainties to
attempt quantification of relatively
small changes in average ozone levels
over the course of a year (EPA, 2005a).
The EPA’s most recent provisional
assessment of the currently available
information indicates that potential but
unquantifiable benefits may also arise
from ozone-related attenuation of UVb
radiation (EPA, 2005b). Sulfate and
nitrate particles also scatter UVb, which
can decrease exposure of horizontal
surfaces to UVb, but increase exposure
of vertical surfaces. In this case as well,
both the magnitude and direction of the
effect of reductions in sulfate and nitrate
particles are too uncertain to quantify
(EPA, 2004). Ozone is a greenhouse gas,
and sulfates and nitrates can reduce the
amount of solar radiation reaching the
earth, but EPA believes that we are
unable to quantify any net climaterelated disbenefit or benefit associated
with the combined ozone and PM
reductions in this rule.
Additionally, from analyses of the
benefits of the Acid Rain Program, EPA
has seen that substantial health and
environmental benefits that are likely to
occur for Canadians because 80 percent
of the Canadian population lives within
40 miles of the US-Canada border.
TABLE IX–6—UNQUANTIFIED AND NON-MONETIZED EFFECTS OF THE TRANSPORT RULE
Pollutant/effect
Endpoint
PM: health a ......................................................
PM: welfare .......................................................
Ozone: health ...................................................
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Ozone: welfare .................................................
NO2: health .......................................................
NO2: welfare .....................................................
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Low birth weight.
Pulmonary function.
Chronic respiratory diseases other than chronic bronchitis.
Non-asthma respiratory emergency room visits.
UVb exposure (+/¥) c.
Household soiling.
Visibility in residential and non-class I areas.
UVb exposure (+/¥) c.
Global climate impacts c.
Chronic respiratory damage.
Premature aging of the lungs.
Non-asthma respiratory emergency room visits.
Increased exposure to UVb (+/¥) c.
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 (+/¥) c.
Respiratory hospital admissions.
Respiratory emergency department visits.
Asthma exacerbation.
Acute respiratory symptoms.
Premature mortality.
Pulmonary function.
Commercial fishing and forestry from acidic deposition.
Commercial fishing, agriculture and forestry from nutrient deposition.
Recreation in terrestrial and estuarine ecosystems from nutrient deposition.
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Federal Register / Vol. 75, No. 147 / Monday, August 2, 2010 / Proposed Rules
TABLE IX–6—UNQUANTIFIED AND NON-MONETIZED EFFECTS OF THE TRANSPORT RULE—Continued
Pollutant/effect
Endpoint
SO2: health .......................................................
SO2: welfare .....................................................
Other ecosystem services and existence values for currently healthy ecosystems.
Respiratory hospital admissions.
Asthma emergency room visits.
Asthma exacerbation.
Acute respiratory symptoms.
Premature mortality.
Pulmonary function.
Commercial fishing and forestry from acidic deposition.
Recreation in terrestrial and aquatic ecosystems from acid deposition.
Increased mercury methylation.
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 Cohort estimates are designed to examine the effects of long term exposures to ambient pollution, but relative risk estimates may also incorporate some effects due to shorter term exposures (see Kunzli et al. (2001) for a discussion of this issue). While some of the effects of short
term exposure are likely to be captured by the cohort estimates, there may be additional premature mortality from short term PM exposure not
captured in the cohort estimates included in the primary analysis.
c May result in benefits or disbenefits.
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X. Economic Impacts
For the affected region, the projected
annual private incremental costs of the
proposed remedy option to the power
industry are $3.7 billion in 2012 and
$2.8 billion in 2014. For the State
Budgets/Intrastate Trading remedy,
projected annual private incremental
costs are $4.2 billion in 2012 and $2.7
billion in 2014. Finally, for the direct
control remedy, the projected annual
private incremental costs are $4.3
billion in 2012 and $3.4 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 2006 dollars.
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 for the proposed
remedy option are estimated to be
approximately $2.0 billion in 2014
assuming a 3 percent discount rate.
These costs become $2.2 billion in 2014
assuming a 7 percent discount rate. For
the State Budgets/Intrastate Trading
remedy, social costs are estimated to be
approximately $2.5 billion in 2014
assuming a 3 percent discount rate and
$2.7 billion in 2014 assuming a 7
percent discount rate. Finally, for the
direct control remedy, social costs are
estimated to be approximately $2.7
billion in 2014 assuming a 3 percent
discount rate and $2.9 billion in 2014
assuming a 7 percent discount rate.
Overall, the economic impacts of the
Transport Rule proposal are modest in
2014, particularly in light of the large
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benefits ($122 to $294 billion annually
at a 3 percent discount rate and $111 to
$266 billion annually at a 7 percent
discount rate) we expect as shown
earlier in this preamble (see section IX
for more details). 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 proposal, please refer to section
XII.H (Statement of Energy Effects) later
in this preamble.
For this proposed 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
https://www.epa.gov/airmarkets/
progsregs/epa-ipm/. Analysis
of impacts on affected industries outside
of the electric power generating sector
are estimated by the Economic Model
for Policy Analysis (EMPAX), a dynamic
model that can generate price and
output changes for output affected by
electricity price changes due to air
pollution control policies and also
estimates of social costs associated with
such policies. Documentation for
EMPAX can be found in the docket for
this rulemaking or at https://
www.epa.gov/ttn/ecas/EMPAX.htm.
Also note that as explained in section
IV.A.3, the baseline used in this analysis
assumes no CAIR. If EPA’s base case
analysis were to assume that reductions
from CAIR would continue indefinitely,
areas that are in attainment solely due
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to controls required by CAIR would
again face nonattainment problems
because the existing protection from
upwind pollution would not be
replaced. 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).
XI. Incorporating End-Use Energy
Efficiency Into the Proposed Transport
Rule
A. Background
EPA believes that achievement of
energy efficiency improvements in
homes, buildings, and industry is an
important component of achieving
emissions 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 rule. While all remedy
options considered—including the
proposed remedy (State Budgets/
Limited Trading)—will lead to a modest
increase in the relative costeffectiveness of energy efficiency
investments by internalizing
environmental costs associated with
these pollutants, EPA is interested in
considering additional means by which
energy efficiency can be encouraged
through this proposed rule.
1. What is end-use energy efficiency?
End-use energy efficiency (hereafter,
‘‘energy efficiency’’) in the context of
this proposed rule refers to activities
that reduce the demand for electricity
from EGUs in affected states. Energy
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efficiency improvements are pursued
through the efforts of state agencies,
independent program administrators
(e.g. Vermont Energy Investment
Corporation), electric utilities, energy
service companies, and other
commercial entities. Examples of
common energy efficiency projects
include re-commissioning of
commercial buildings, rebates for energy
efficient appliances, and home energy
audits.
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2. How does energy efficiency
contribute to cost-effective reductions of
air emissions from EGUs?
EPA recognizes that significant
opportunity remains for energy
efficiency improvements in businesses,
homes, and industry. However, there are
several informational and market
barriers that limit investment in costeffective energy efficient practices.
Several federal programs authorized
under the Act, including ENERGY
STAR, are designed to address these
barriers.
By reducing the demand for
electricity energy efficiency reduces the
need for investments in EGU emissions
control technologies in order to meet the
limits of an established state emissions
budget and can often be implemented at
a lower cost than traditional control
technologies. Section III.E in this
preamble further discusses the
importance of electricity demand
reductions as a component of EPA’s
broader air quality improvement
strategy for the power sector.
EPA is available to assist states in
quantifying the reduction in compliance
costs of air regulatory programs,
including the proposed rule, that can be
realized through effective energy
efficiency policies and programs.
3. How does the proposed rule support
greater investment in energy efficiency?
By requiring reductions in the
emissions of NOX and SO2 from power
plants in affected states, a transport rule
will lead to the internalization of costs
associated with reducing the
environmental effects of these
pollutants. Since the economics of
energy efficiency investments are
directly related to power generation
costs, this will improve the relative costeffectiveness of these investments. Over
time, this effect is expected to lead to
increases in energy efficiency
investments and associated benefits.
4. How have EPA and states previously
integrated energy efficiency into air
regulatory programs?
Congress, EPA, and states have all
recognized the value of incorporating
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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 projects
through either the award of emissions
allowances, typically through the use of
a fixed set-aside pool, or the use of
revenues obtained through the auction
of emissions allowances. The emissions
caps established by these programs are
unaffected by this approach, however,
compliance costs are reduced (to the
extent electricity demand reductions are
realized) as are the emissions of noncapped pollutants from affected EGUs.
In addition to these allowance-based
programs, EPA has also established,
through Guidance,116 a means for
recognizing the emissions benefits of
energy efficiency in SIPs and has
approved their use in individual state
plans.
B. Incorporating End-Use Energy
Efficiency Into the Transport Rule
As discussed previously, EPA
believes that increasing end-use energy
efficiency can be an effective approach
for reducing compliance costs of the
proposed rule, as well as for reducing
EGU emissions that are not the target of
this rule including mercury, other
toxics, and carbon dioxide. While EPA
believes the proposed rule will make
energy efficiency investments more
competitive, the Agency is seeking
comments on additional ways in which
this rule could further encourage these
investments.
1. Options that Could Be Used To
Incorporate Energy Efficiency Into
Allowance Based Programs
As discussed previously, allowancebased programs (such as the proposed
State Budgets/Limited Trading remedy
and the alternative State Budgets/
Intrastate Trading remedy) of EPA and
states have supported energy efficiency
projects through the use of auction
revenues or the award of allowances.
EPA considered these options in
developing this proposal but, for the
reasons described later, decided not to
include either option in this proposal.
116 U.S. EPA. 2004. Guidance on State
Implementation Plan (SIP) Credits for Emission
Reductions From Electric-Sector Energy Efficiency
and Renewable Energy Measures. August. https://
www.epa.gov/ttn/oarpg/t1/memoranda/
ereseerem_gd.pdf.
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2. Why did EPA not propose these
options?
The emissions reductions
requirements of the proposed rule are
implemented through proposed FIPs.
This means, among other things, that
EPA allocates the emission allowances
directly to individual sources. In
contrast, when allowance based
programs are implemented through
SIPs, states may have significant
flexibility to determine the methodology
used to allocate or auction allowances
in their budgets. Under the proposed
FIPs, EPA would allocate allowances to
sources in a manner consistent with the
methodology used to determine each
state’s budget. EPA believes this
approach is appropriate because of the
link between the allowance allocation
methodology and the significant
contribution determinations. EPA
requests comment on whether EPA has
authority to and whether it would be
appropriate for EPA to consider energy
efficiency considerations in developing
the allowance allocation methodology.
In addition, because the emission
reduction requirements are
implemented through FIPs, any auction
of allowances would be conducted by
EPA. As discussed previously in section
V.D.5.b, pursuant to the Miscellaneous
Receipts Act, any revenues from a
federal auction of allowances must go to
the U.S. Treasury. This precludes the
use of proceeds from such an auction to
reward energy efficiency projects.
In addition, and as also discussed
previously in sections III.A and III.B.3,
EPA anticipates further revisions to the
PM2.5 and ozone NAAQS and intends to
issue subsequent proposals to address
the interstate transport requirements of
section 110(a)(2)(D)(i)(I) with respect to
those new NAAQS. The emissions
reductions requirements identified in
any such rules could be implemented
through SIPs. The SIP process could
give states significant flexibility in
regards to allocation and auctioning of
allowances. This flexibility could be
used by states to support energy
efficiency projects through the use of
auction revenues or the award of
allowances.
EPA is seeking comment on the
discussion within this section and the
use of these and other approaches for
encouraging energy efficiency within
the proposed rule.
XII. Statutory and Executive Order
Reviews
A. Executive Order 12866: Regulatory
Planning and Review
Under section 3(f)(1) of Executive
Order 12866 (58 FR 51735, October 4,
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1993), this action is an ‘‘economically
significant regulatory action’’ because it
is likely to have an annual effect on the
economy of $100 million. Accordingly,
EPA submitted this action to the Office
of Management and Budget (OMB) for
review under EO 12866 and any
changes made in response to OMB
recommendations have been
documented in the docket for this
action. In addition, EPA prepared a
Regulatory Impact Analysis (RIA) of the
potential costs and benefits associated
with this action.
When estimating the PM2.5- and
ozone-related human health benefits
and compliance costs in Table 1 below,
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 the
preferred and alternate Transport Rule
remedies considered by the Agency. The
Regulatory Impacts Analysis (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.
When characterizing uncertainty in
the PM-mortality relationship, EPA has
historically presented a sensitivity
analysis applying alternate assumed
thresholds in the PM concentrationresponse relationship. In its synthesis of
the current state of the PM science,
EPA’s 2009 Integrated Science
Assessment (ISA) for Particulate Matter
concluded that a no-threshold log-linear
model most adequately portrays the PMmortality concentration-response
relationship. In the RIA accompanying
this rule, rather than segmenting out
impacts predicted to be associated
levels above and below a ‘bright line’
threshold, EPA includes a ‘‘lowestmeasured-level (LML)’’ that illustrates
the increasing uncertainty that
characterizes impacts attributed to
levels of PM2.5 below the LML for each
study. Figure 5–19 shows the
distribution of avoided PM mortality
impacts predicted relative to the
baseline (i.e. pre-Transport Rule) PM2.5
levels experienced by the population
receiving the PM2.5 mortality benefit in
2014 (Figure 5–19). This figure also
shows the lowest air quality levels
measured in each of the two primary
epidemiological studies EPA uses to
quantify PM-related mortality. This
information allows readers to determine
the 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 decreases in areas where
annual mean PM2.5 levels are further
below the LML in the two
epidemiological studies. In this
analysis, we see that about 80% of the
estimated benefits accrue among
populations exposed to annual mean
PM2.5 levels above 10ug/m3 (the LML in
the Six Cities study) and 97% of the
estimated benefits are associated with
PM levels above 7.5 mg/m3 (the LML in
the American Cancer Society study used
for this analysis). While 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.
Table XII.A–1 shows the results of the
cost and benefits analysis for the
proposed and alternate remedies.
TABLE XII.A–1—SUMMARY OF ANNUAL BENEFITS, COSTS, AND NET BENEFITS OF VERSIONS OF THE PROPOSED REMEDY
OPTION IN 2014 a
[Billions of 2006$]
Preferred remedy-State budgets/
limited trading
Description
Social costs b
3% discount rate .....................
7% discount rate .....................
Health-related benefits c,d
3% discount rate .....................
7% discount rate .....................
Net benefits (benefits-costs)
3% discount rate .....................
7% discount rate .....................
Direct control
$2.03 .............................................
$2.23 .............................................
$2.68 .............................................
$2.91 .............................................
$2.49.
$2.70.
$118 to $288 + B ..........................
$108 to $260 + B ..........................
$117 to $286 + B ..........................
$108 to $262 + B ..........................
$113 to $276 + B.
$104 to $252 + B.
$116 to $286 ................................
$105 to $258 ................................
$115 to $283 ................................
$105 to $259 ................................
$110 to $273.
$101 to $249.
Intrastate trading
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Notes: (a) All estimates are rounded to three significant digits and represent annualized benefits and costs anticipated for the year 2014. For
notational purposes, unquantified benefits are indicated with a ‘‘B’’ to represent the sum of additional monetary benefits and disbenefits. Data limitations prevented us from quantifying these endpoints, and as such, these benefits are inherently more uncertain than those benefits that we
were able to quantify. A listing of health and welfare effects is provided in RIA Table 1–6. Estimates here are subject to uncertainties discussed
further in the body of the document. (b) The social costs are the loss of household utility as measured in Hicksian equivalent variation. (c) The
reduction in premature mortalities account for over 90% of total monetized benefits. Benefit estimates are national. Valuation assumes discounting over the SAB-recommended 20-year segmented lag structure described in Chapter 5. Results reflect 3 percent and 7 percent discount
rates consistent with EPA and OMB guidelines for preparing economic analyses (U.S. EPA, 2000; OMB, 2003). The estimate of social benefits
also includes CO2-related benefits calculated using the social cost of carbon, discussed further in chapter 5. Benefits are shown as a range from
Pope et al. (2002) to Laden et al. (2006). Monetized benefits do not include unquantified benefits, such as other health effects, reduced sulfur
deposition or visibility. These models assume that all fine particles, 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. (d) Not all possible benefits or disbenefits are quantified and monetized in this analysis. B is the sum of all unquantified benefits and
disbenefits. Potential benefit categories that have not been quantified and monetized are listed in RIA Table 1–4.
B. Paperwork Reduction Act
The information collection
requirements in the proposed rule have
been submitted for approval to OMB
under the Paperwork Reduction Act, 44
U.S.C. 3501 et seq. The information
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collection requirements are not
enforceable until OMB approves them.
The information collection activities
in this proposed rule include
monitoring and the maintenance of
records. The information generated by
these activities will be used by EPA to
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ensure that affected facilities comply
with the emission limits and other
requirements. Records and reports are
necessary to enable EPA or states to
identify affected facilities that may not
be in compliance with the requirements.
Based on reported information, EPA
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will decide which units and what
records or processes should be
inspected. 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. These recordkeeping and
reporting requirements are 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.
The record-keeping and reporting
burden to sources resulting from states
choosing to participate in a regional
cap-and-trade program is approximately
$28 million annually. This estimate
includes the annualized cost of
installing and operating appropriate SO2
and NOX emissions monitoring
equipment to measure and report the
total emissions of these pollutants from
affected EGUs (serving generators
greater than 25 megawatt electrical). The
burden to state and local air agencies
includes any necessary SIP revisions,
performance of monitoring certification,
and fulfilling of audit responsibilities.
More information on the ICR analysis is
included in the proposed Transport
Rule docket. Burden is defined at 5 CFR
1320.3(b).
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
45355
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 proposed 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 (MW-hr) 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
NAICS
Code b
Category
Industry .................................................................
Federal Government ............................................
221112
c 221112
State/Local ...........................................................
Tribal Government ...............................................
c 221112
921150
Examples of potentially regulated entities
Fossil fuel-fired electric utility steam generating units.
Fossil fuel-fired electric utility steam generating units owned by the federal government.
Fossil fuel-fired electric utility steam generating units owned by municipalities.
Fossil fuel-fired electric utility steam generating units in Indian Country.
a Include
b North
NAICS categories for source categories that own and operate electric generating units only.
American Industry Classification System.
state, or local government-owned and operated establishments are classified according to the activity in which they are engaged.
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c Federal,
After considering the economic
impacts of this proposed rule on small
entities, EPA is certifying that this
action will not have a significant
economic impact on a substantial
number of small entities. This
certification is based on the economic
impact of this proposed action to all
affected small entities across all
industries affected. EPA has assessed
the potential impact of this action on
small entities and found that
approximately 550 of the estimated
4,700 EGUs potentially affected by
today’s proposal are owned by the 81
potentially affected small entities
identified by EPA’s analysis. EPA
estimates that 30 of the 81 identified
small entities will have annualized costs
greater than 1 percent of their revenues,
and the other 51 are projected to incur
costs less than 1 percent of revenues.
While there are costs greater than 1
percent of revenues for a number of
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small entities, EPA is certifying No
SISNOSE for several reasons. First, of
the 30 entities projected to have costs
greater than 1 percent of revenues,
around 75 percent of them operate in
cost of service regions and would
generally be able to pass any increased
costs along to rate-payers. This is one of
the primary reasons given in the
Regulatory Impact Assessment for the
Final Clean Air Interstate Rule (EPA–
452/R–05–002 March 2005) that
supported EPA’s ‘‘No SISNOSE’’
certification in the final CAIR FIP rule
on April 28, 2006 (71 FR 25366).
Furthermore, of the approximately 550
units identified by EPA as being
potentially owned by small entities,
approximately two-thirds of the units
that have higher costs are not expected
to make operational changes as a result
of this rule (e.g., install control
equipment or switch fuels). Their
increased costs are largely due to
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increased cost of the fuel they would be
expected to use whether or not they had
to comply with the proposed rule.
Further, increased fuel costs are often
passed through to rate-payers as
common practice in many areas of the
United States due to fuel adder
arrangements instituted by state public
utility commissions. In addition, EPA’s
decision to exclude units smaller than
25 MWe has already significantly
reduced the burden on small entities.
Hence, EPA has concluded that there is
no SISNOSE for this rule.
For more information on the small
entity impacts associated with the
proposed rule, please refer to the
Economic Impact and Small Business
Analyses in the public docket. These
analyses can be found in the Regulatory
Impact Analysis for this proposed rule.
Finally, although EPA believes that the
proposed rule would not have a
significant economic impact on a
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substantial number of small entities,
EPA plans to take steps to conduct
meetings with industry trade
associations to discuss regulatory
options and ensure that the burdens
imposed on small entities are minimal.
We continue to be interested in the
potential impacts of the proposed rule
on small entities and welcome
comments on issues related to such
impacts.
D. Unfunded Mandates Reform Act of
1995
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 one year.
Accordingly, EPA has prepared under
section 202 of the UMRA a written
statement which is summarized later.
Consistent with section 205, EPA has
identified and considered a reasonable
number of regulatory alternatives. In
today’s action, EPA has included three
remedy options that it considered when
developing this proposed rule: (1) The
proposed remedy of State Budgets/
Limited Trading, (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 municipalityowned entities associated with this
rulemaking based on assumptions of
how the affected states will implement
control measures to meet their
emissions. 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.
According to EPA’s analysis, of the 84
government entities considered in this
analysis and the 482 government
entities in the Transport Rule region
that are included in EPA’s modeling, 27
may experience compliance costs in
excess of 1 percent of revenues in 2014,
based on our assumptions of how the
affected states implement control
measures to meet their emissions
budgets as set forth in this rulemaking.
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Government entities projected to
experience compliance costs in excess
of 1 percent of revenues have some
potential for significant impact resulting
from implementation of the Transport
Rule. However, as noted previously, it is
EPA’s position that because these
government entities can pass on their
costs of compliance to rate-payers, they
will not be significantly affected.
Furthermore, the decision to include
only units greater than 25 MW in size
exempts 380 government entities that
would otherwise be potentially affected
by the Transport Rule. For more
information on the impacts estimated
for this analysis, please refer to the RIA
for this proposed rule.
In addition, before EPA establishes
any regulatory requirements that may
significantly or uniquely affect small
governments, including tribal
governments, it must have developed
under section 203 of the UMRA, a small
government agency plan. The plan must
provide for notifying potentially
affected small governments, enabling
officials of affected small governments
to have meaningful and timely input in
the development of EPA regulatory
proposals with significant Federal
intergovernmental mandates, and
informing, educating, and advising
small governments on compliance with
the regulatory requirements. Consistent
with the intergovernmental consultation
provisions of section 204 of the UMRA,
EPA has initiated consultations with
governmental entities affected by this
rule.
The 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.
E. Executive Order 13132: Federalism
This proposed rule does not have
federalism implications. It will not have
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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 proposed
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 proposed
rule.
In the spirit of Executive Order 13132,
and consistent with EPA policy to
promote communications between EPA
and state and local governments, EPA
will specifically solicit comment on the
proposed rule from state and local
officials.
F. Executive Order 13175: Consultation
and Coordination With Indian Tribal
Governments
This action does not have tribal
implications, as specified in Executive
Order 13175 (65 FR 67249, November 9,
2000). It will not have substantial direct
effects on tribal governments, on the
relationship between the Federal
government and Indian tribes, or on the
distribution of power and
responsibilities between the federal
government and Indian tribes, as
specified in Executive Order 13175.
Thus, Executive Order 13175 does not
apply to the final rule.
G. Executive Order 13045: Protection of
Children From Environmental Health
and Safety Risks
EPA interprets Executive Order 13045
(62 FR 19885, April 23, 1997) as
applying to those regulatory actions that
concern health or safety risks, such that
the analysis required under section
5–501 of the Order has the potential to
influence the regulation. 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.
The EPA believes that the emissions
reductions from the strategies in this
rule will further improve air quality and
will further improve children’s health.
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
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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 proposed rule is a significant
regulatory action under Executive Order
12866, and this proposed rule may have
a significant adverse effect on the
supply, distribution, or use of energy.
Under the provisions of this proposed
rule, EPA projects that approximately
1.2 GW of 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.
Assumptions of higher natural gas
prices or electricity demand would
create a greater incentive to keep these
units operational. The EPA projects that
the average retail electricity price could
increase nationally by less than 2.5
percent in 2012 and 1.5 percent in 2014.
This is generally less of an increase than
often occurs with fluctuating fuel prices
and other market factors. Related to this,
delivered coal prices increase by about
7 percent in 2012 and 4 percent in 2014
as a result of higher demand for lowersulfur coals. The EPA also projects that
natural gas prices will increase by less
than 1.7 percent in 2012 and 0.5 percent
in 2014 and that natural gas use for
electricity generation will increase by
less than 73 million mcf by 2014. The
price increase is also within the range
we regularly see in delivered natural gas
prices. Finally, the EPA projects coal
production for use by the power sector,
a large component of total coal
production, will decrease by 3 million
tons in 2012 and 9 million tons in 2014.
The EPA does not believe that this rule
will have any other impacts that exceed
the significance criteria.
The EPA believes that a number of
features of the proposed rulemaking
serve to reduce its impact on energy
supply. First, the trading programs in
State Budgets/Limited Trading provide
considerable flexibility to the power
sector and enable industry to comply
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with the emission reduction
requirements in the most cost-effective
manner, 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 proposed Transport Rule.
I. National Technology Transfer and
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 proposed rule would 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 costeffective 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
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45357
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, lowincome, and Tribal populations in the
United States.
1. Consideration of Environmental
Justice Issues in the Rule Development
Process
In the rulemaking process, EPA
considers whether there are positive or
negative impacts of the action that
appear to affect low-income, minority,
or Tribal communities
disproportionately, and, regardless of
whether a disproportionate effect exists,
whether there is a chance for these
communities to meaningfully
participate in the rulemaking process.
EPA expects that this rule, ‘‘Federal
Implementation Plans to Reduce
Interstate Transport of Fine Particulate
Matter and Ozone,’’ will provide
significant health and environmental
benefits to, among others, people with
asthma, people with heart disease, and
people living in ozone or fine particle
(PM2.5) nonattainment areas. This rule
also has the potential to affect the cost
structure of the utility industry and
could lead to regional shifts in
electricity generation and/or emissions
of various pollutants. Therefore we
expect this rule to be of interest to many
environmental justice communities.
EPA’s analysis of the effects of this
proposed rule, including information on
air quality changes and the resulting
health benefits, is presented both in
section IX of this preamble and in more
detail in the air quality modeling
Technical Support Document and 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 Web page for the rule https://
www.epagov/airtransport. This section
summarizes the legal basis for this rule,
and provides background information
on how this rule fits into the larger
regulatory strategy for controlling
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pollution from the power sector. A
summary of the emissions, air quality,
and health benefit estimates for this rule
then follows.
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. CAIR was vacated by the U.S.
Court of Appeals for the District of
Columbia Circuit in July 2008 in a case
known as North Carolina v. EPA. In
December 2008, the vacatur was altered
to a remand based on the likely
environmental harms of vacating the
rule and EPA’s stated intent to replace
the rule promptly. At the time of the
2008 court ruling, many sources had
already begun to install and run
emissions control devices or otherwise
alter their operations and had
successfully begun reducing their
emissions. The court decision has led to
significant uncertainty among affected
sources as to what emissions reductions
will be required and among states and
communities as to what air quality
benefits will be achieved. By proposing
this aggressive replacement rule that
meets the legal requirements of the CAA
as interpreted by the Court in the North
Carolina decision promptly, EPA is both
maximizing the likelihood that the goals
of the CAA will be met, and helping
communities receive the air quality
benefits they need as quickly as possible
by minimizing the chance that any
emissions reductions achieved under
CAIR would be lost.
It is important to note that CAA
section 110(a)(2)(d), which addresses
transport of criteria pollutants between
states and is the authority for this rule,
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 environmental justice
communities, and provide substantial
health benefits to both the general
public and sensitive sub-populations.
This proposed rule is one of a group
of regulatory actions that EPA will take
over the next several years to respond to
statutory and judicial mandates that will
reduce exposure to ozone and PM2.5, as
well as to other pollutants, from power
plants and other sources. To the extent
that EPA has the legal authority to do so
while fulfilling its obligations under the
CAA and other relevant statutes, we will
also coordinate these utility-related air
pollution rules with upcoming
regulations for the power sector from
EPA’s Office of Water (OW) and its
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Office of Resource Conservation and
Recovery (ORCR). The primary actions
are outlined below and presented in
more detail in section III.E of this
preamble.
Beyond this action and any additional
efforts undertaken in response to
comment, other rules that will drive the
creation of a clean, efficient and
completely modern power sector
include: CAA section 112(d) standards
(one of which is often referred to as a
Maximum Achievable Control
Technology (MACT) standard) to reduce
emissions of air toxics, including
mercury, and particles from coal- and
oil-fired power plants; new National
Ambient Air Quality Standards
(NAAQS) for ozone, PM2.5, sulfur
dioxide, and nitrogen oxides;
potentially one or more additional rules
eliminating interstate transport of
emissions that contribute significantly
to nonattainment and maintenance areas
for the new ozone and PM2.5 NAAQS as
necessary; revisions to the New Source
Performance Standards (NSPS) for
steam electric generating units; and best
available retrofit technology (BART)
requirements and other requirements
that address visibility and regional haze.
Within the planning and investment
horizon for compliance with these rules,
EPA very likely will be compelled to
respond to a pending petition to set
standards for the emissions of
greenhouse gases (GHGs) from steam
electric generating units under the New
Source Performance Standard program.
Furthermore, as set forth in the recently
promulgated reinterpretation of the
Johnson Memo, beginning in 2011 new
and modified sources of GHG emissions,
including EGUs, will be subject to
permits under the Prevention of
Significant Deterioration program
requiring them to adopt Best Available
Control Technology for their GHGs.
Finally, 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 that the Agency
wants to provide while lowering the
costs of realizing those improvements.
Together, these rules and actions 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
intends to provide multiple
opportunities for comment on these
actions, including during the comment
process for this rule, and encourages
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environmental justice communities to
review and comment on them.
2. Potential Environmental and Public
Health Impacts to Vulnerable
Populations
There are several considerations to
take into account when assessing the
effects of this proposed rule on
minority, low-income, and tribal
populations. These include: Amount of
emissions reductions and where they
take place (including any potential for
areas of increased emissions); the
changes in ambient concentrations
across the affected area; and the health
benefits expected from the rules.
Emissions reductions. This proposed
rule will reduce exposure to PM2.5 and
ozone pollution in most eastern states
by reducing interstate transport of these
pollutants and their chemical precursors
(sulfur dioxide (SO2) and nitrogen
oxides (NOX)). This rule has the effect
of reducing emissions of these
pollutants that affect the mostcontaminated areas (i.e. areas that are
not meeting the 1997 and 2006 ozone
and PM2.5 National Ambient Air Quality
Standards (NAAQS)). This rule
separately identifies both nonattainment
areas and maintenance areas
(maintenance areas are those that
currently meet the NAAQS but that,
based on past data, are in danger of
exceeding the standards in the future).
This approach of requiring emissions
reductions to protect maintenance areas
as well as nonattainment areas reduces
the likelihood that any areas close to the
level of the standard will exceed the
current health-based standards in the
future.
Ozone and PM2.5 concentrations in
both nonattainment and maintenance
areas identified in this rule are the
result of both local emissions and longrange transport of pollution. This rule
requires upwind states to reduce or
eliminate their significant contribution
to nonattainment or maintenance
problems in downwind states. Even
when the significant contributions of
upwind states are fully eliminated,
additional emissions reductions within
the nonattainment area and/or the
downwind state will be needed for some
areas to attain and maintain the
NAAQS.
The proposed remedy option for this
rule would use a limited emissions
trading mechanism among power plants
to achieve significant emissions
reductions in states covered by the rule.
EPA recognizes that many
environmental justice communities
have voiced concerns about emissions
trading and any resulting potential for
any emissions increases in any location.
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This proposed rule uses EPA’s
authority in CAA § 110(a)(2)(d) to
require states to eliminate emissions
from power plants in their state that
contribute significantly to downwind
PM2.5 or ozone nonattainment or
maintenance areas. EPA’s proposed
mechanism for achieving these
emissions reductions is to use a tightly
constrained trading program that
requires a strict emission ceiling in each
state while allowing a limited ability to
shift emissions between facilities or
states. This approach ensures that
emissions in each state that significantly
contribute to downwind nonattainment
or maintenance areas are controlled,
while allowing power companies to
adjust generation based on fluctuations
in electricity demand, weather,
availability of low-emitting power
sources (e.g. temporary shut-down of a
nuclear power plant for maintenance or
repairs), or other unanticipated factors
affecting the interconnected electricity
grid.
Any emissions above the state’s
allocated level must be offset by
emissions reductions from another state
in the region below that state’s budget
or by using extra ‘‘banked’’ allowances
from earlier years. All sources must
hold enough allowances to cover their
emissions; therefore, if they emit more
than their allocation they must buy
allowances from another source that
emitted less than its allocation. 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
emissions 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 recognize that the
section of the Clean Air Act providing
authority for this rule, 110(a)(2)(D),
unlike some other provisions, does not
dictate levels of control for particular
facilities. None of EPA’s alternatives
within this proposal can ensure there
will be no emission increases at any
facility. Under the direct control
alternative, the emissions rate for each
facility is reduced 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, state
emissions must stay constant but
individual facilities within each state
could increase their emissions as long as
another facility in the state had
decreased theirs. By strictly setting state
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budgets to eliminate significant
contributions to non-attainment and
maintenance areas that EPA has
identified in this action, by limiting the
amount of interstate trading possible
and by requiring any emissions above
the level of the allocations to be offset
by emission decreases elsewhere in the
region, the proposed remedy options
reduce ambient concentrations where
they are most needed.
EPA’s emissions modeling data
indicate that nationwide SO2 emissions
from electric generating units (EGUs)
will be approximately 6.4 million tons
(60 percent) lower in 2014 than they
were in 2005 (which is the year that the
Clean Air Interstate Rule was finalized).
Emissions would also decrease when
compared to the base case (the base case
estimates of SO2 emissions in 2014 in
the absence of this proposed rule or the
Clean Air Interstate Rule it is replacing).
SO2 emissions under this proposed rule
are projected to be approximately 4.4
million tons (50%) lower than they
would have been in 2014 in the base
case (i.e. without this rule).
EPA’s modeling does project that
some states not covered by one or more
aspects of the program may experience
increases of SO2 emissions (i.e., their
emissions are greater in the control case
modeling than in the base case
modeling). These emission increases are
the result of forecasted changes in
operation of units outside of the
controlled region (due to the
interconnected nature of the utility grid
or influence of the rule on the market
for lower sulfur coal). As shown in
Table IV.D.6, Arkansas, Mississippi,
North Dakota, South Dakota, and Texas
all exhibit 2012 SO2 emissions increases
over the base case of more than 5,000
tons. Texas is projected to have by far
the largest increase (136,000 tons),
while the other states’ increases ranges
from 6,000 to 32,000 tons. Further
analysis with the simplified air quality
assessment tool indicates that these
projected increases in the Texas SO2
emissions would increase Texas’s
contribution to an amount that would
exceed the 0.15 μg/m3 threshold for
annual PM2.5. For this reason, EPA
requests comment on whether Texas
should be included in the program as a
group 2 state. For additional details, see
section IV.D of this preamble.
With the exception noted above, EPA
is not proposing for the SO2 portion of
this rule to cover the states where SO2
emissions are projected to increase
because EPA has not found, at this time,
that they contribute significantly to
nonattainment or interfere with
maintenance of the PM2.5 NAAQS in
downwind areas. EPA’s authority under
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§ 110(a)(2)(d)(i)(I) is limited to
addressing any such significant
contribution and interference with
maintenance. EPA anticipates that
additional rulemakings affecting
utilities that will be proposed soon,
such as the CAA Section 112(d)
standards, would apply nationwide and
result in significant additional SO2
reductions.
EPA’s emissions modeling data
indicates that nationwide ozone season
NOX emissions from EGUs will be
approximately 400,000 tons (30%)
lower in 2014 than they were in 2005
(before implementation of the Clean Air
Interstate Rule). Emissions would also
decrease compared to the base case.
Ozone season NOX emissions from
EGUs under this proposed rule are
projected to be approximately 150,000
tons (15%) lower than they would have
been in 2014 in the base case (i.e.
without this rule). EPA anticipates that
additional upcoming actions, and likely
additional interstate transport
reductions to help states attain the
proposed 2010 ozone NAAQS, will
result in significant additional NOX
reductions.
EPA anticipates that this proposed
action will significantly reduce, but not
eliminate, the number of nonattainment
and maintenance areas for the 1997
ozone and PM2.5 and 2006 PM2.5
NAAQS. Table IX–1 lists the changes in
number of nonattainment sites. Most of
these sites are located in urban areas. A
single nonattainment area usually
contains multiple monitoring sites;
therefore there are more nonattainment
sites than nonattainment counties or
areas. As discussed in detail in section
IV.D of this preamble, where this
proposal does not fully quantify all of
the significant contribution and
interference with maintenance, EPA
intends to address these additional
requirements quickly. To the extent
possible, EPA will supplement this
proposed notice with additional
information so that we can provide
downwind states with all the certainty
about upwind emissions reductions
they need to address their own local
nonattainment concerns. In addition, as
stated above, elimination of these
nonattainment areas may require both
local and regional emissions reductions
and this proposed action seeks only to
address the regional transport
component.
As a result of these SO2 and NOX
reductions, EPA’s air quality modeling
indicates that concentrations of fine
particles will decline throughout the
eastern U.S. and in all the states affected
by this rule. These reductions are largest
in the area of the Ohio River valley and
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neighboring states and extend east
through New England, west to Texas,
south to Florida, and north through the
Great Lakes states. ‘‘Border’’ states
immediately outside the transport
region are also predicted to see
reductions in air concentrations, even
though emissions increase in some of
these states. This is because
concentrations of fine particles in most
locations are composed of both local
emissions and those transported over
hundreds of miles and emissions
reductions far away can cause
significant improvements in local air
quality.
The modeling suggests also that there
may be some small increases in PM2.5
near locations in the western U.S. where
SO2 emissions are forecast to increase.
These increases are small compared to
the reductions predicted to take place in
the eastern U.S. The increases are due
to the regional nature of this rule (i.e.
these states are not covered because
sources in these states have not been
found to contribute significantly to
downwind nonattainment or
maintenance areas) and the national
nature of both coal markets and the
Acid Rain Program allowance market.
They are not the result of any particular
type of remedy option (e.g. trading).
EPA anticipates that future rulemakings,
such as CAA section 112(d) standards
and anticipated revisions to the 2006
fine particulate standards, are likely to
reduce emissions in the areas not
covered by this rule.
EPA’s air quality modeling also
indicates that concentrations of ozone
will decline in much of the eastern U.S.
These reductions are largest along much
of the Gulf Coast and in Florida and in
a region encompassing western
Wisconsin, Iowa, Kansas, Missouri,
Arkansas, and northeastern Oklahoma.
These areas with the largest reductions
are roughly the area immediately
outside the boundaries of the NOX SIP
Call region. States in the SIP Call region
were required to make significant
reductions in NOX beginning in 2003
and these emissions reductions are
included in the baseline modeling for
this proposed Transport Rule and
therefore not captured as additional
benefits of this rulemaking.
As is common when modeling many
NOX control strategies, the air quality
modeling for this proposed rule also
suggests there may be a few small,
localized areas in the eastern U.S. where
there are small increases in ozone
concentrations. These generally small
increases are a result of reductions in
NOX emissions in these local areas; they
do not appear to represent a lack of NOX
emissions reductions or be the result of
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any specific emission control strategy
(e.g. any type of trading). Rather, this
phenomenon can result from complex
atmospheric chemistry reactions taking
place among chemical constituents of
air pollution in these areas. Due to the
complex photochemistry of ozone
production, NOX emissions lead to both
the formation and destruction of ozone,
depending on the relative quantities of
NOX, volatile organic compounds, and
ozone formation catalysts. In the 2014
base case, NOX emissions from sources
in a few locations act to ‘‘quench’’ (i.e.,
lower) ozone compared to ozone
concentrations in surrounding areas.
The application of NOX controls in
these areas reduces this quenching
effect, thereby increasing ozone to levels
generally on par with those of the
surrounding area. In this case it is
uncertain whether the structure of the
model itself is potentially exacerbating
the spatial extent or magnitude of any
ozone increases which might actually
occur as a result of this rule. It should
be noted that these same NOX emissions
reductions that might be causing
extremely localized ozone increases are
certainly causing larger, more
widespread improvements in ozone
concentrations in downwind areas.
Finally, as stated above, it is important
to note that EPA intends to promulgate
additional rules over the next few years
that will further reduce concentrations
of ozone and PM2.5 and that the federal
government and the states can and do
use many different legal authorities to
limit exposure to ozone.
Health benefits. This rule reduces
concentrations of PM2.5 and ozone
pollution, exposure to which can cause,
or contribute to, adverse health effects
including premature mortality and
many types of heart and lung diseases
that affect many minority and lowincome individuals, and Tribal
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 both heart disease
and asthma are a cause for concern in
many environmental justice
communities, making these populations
more susceptible to air pollution health
impacts. In addition, many individuals
in these communities also lack access to
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high quality health care to treat these
illnesses.
We estimate that in 2014 the PMrelated annual benefits of the proposed
remedy option include approximately
14,000 to 36,000 fewer premature
mortalities, 9,200 fewer cases of chronic
bronchitis, 22,000 fewer non-fatal heart
attacks, 11,000 fewer hospitalizations
(for respiratory and cardiovascular
disease combined), 10 million fewer
days of restricted activity due to
respiratory illness and approximately
1.8 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 between 50 and 230 fewer
premature mortalities, 690 fewer
hospital admissions for respiratory
illnesses, 230 fewer emergency room
admissions for asthma, 300,000 fewer
days with restricted activity levels, and
110,000 fewer days where children are
absent from school due to illnesses.
When adding the PM and ozone-related
mortalities together, we find that the
proposed remedy option for this rule
will yield between 14,000 and 36,000
fewer premature mortalities. EPA has
also estimated the benefits of the
alternate remedies in this proposal
using a benefit-per-ton estimation
approach and found they would provide
similar benefits.
It should be noted that, as discussed
in the RIA for this action, there are other
benefits to the emissions reductions
discussed here, such as improved
visibility and, indirectly, reduced
mercury deposition. Additional benefits
of reducing emissions of SO2 include
reduced acidification of lakes and
streams, and reduced mercury
methylation; additional benefits of NOX
reductions include reduced
acidification of lakes and streams and
reduced coastal eutrophication.
Conversely, it is possible that the
modest increases in emissions modeled
for this rule in some western areas could
result in limited increases of one or
more of these effects in these locations.
3. Meaningful Public Participation
As EPA began considering approaches
to address the court remand of the 2005
Clean Air Interstate Rule, the agency
also began gathering input from a larger
range of stakeholders. In the spring of
2009, EPA held a series of listening
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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 entitled ‘‘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 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 this
proposal, as they took place prior to the
development of this proposal, but they
provided valuable information that EPA
used in developing this proposal.
Upon proposal of this action, the
Agency will begin an outreach effort
with environmental justice
communities, the public, the regulated
community, state air regulators, and
others to (1) describe the Transport Rule
proposal, (2) provide information on the
2011 CAA Section 112 (d) and other
upcoming EPA rulemakings affecting
the power sector, and (3) listen to
comments from stakeholders. The intent
will be to inform all stakeholders of the
industry’s obligations and opportunities
for the industry to use investments in
SO2 and NOX reductions to help smooth
transition to the CAA Section 112(d)
standards compliance in late 2014. EPA
intends to continue these efforts over
time as more information becomes
available in the development of the
various rulemakings under development
for the power sector.
During the comment period for this
proposed rule, EPA intends to reach out
specifically to environmental justice
communities and organizations to notify
them of the opportunity to provide
comments on this rule and to solicit
their comments on both this rule and
the upcoming actions described above
and in section III.E. EPA will hold
public hearings on this rule; see the
information at the very beginning of this
preamble for locations, times and dates.
Comments can also be submitted in
writing or electronically by following
the instructions at the beginning of this
preamble.
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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 communities in both rural areas
and inner cities in the East, will see
significant improvements in air quality
and resulting improvements in health.
EPA also recognizes that there is the
potential for a number of communities
or individuals outside the region
covered by this rule to experience
slightly worse air quality as an indirect
result of emissions reductions required
under this proposal. EPA requests
comment on the impacts of this
proposed action on low income,
minority, and Tribal communities. EPA
will further analyze environmental
justice issues related to the impacts of
the rule on those communities based
both on additional data that may be
developed and on comments on those
issues prior to final action on this rule.
List of Subjects
40 CFR Part 51
Administrative practice and
procedure, Air pollution control,
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,
Intergovernmental relations, Nitrogen
oxides, Ozone, Particulate matter,
Regional haze, Reporting and
recordkeeping requirements, Sulfur
dioxide.
40 CFR Parts 72
Acid rain, Administrative practice
and procedure, Air pollution control,
Electric utilities, 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.
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Dated: July 6, 2010.
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 proposed to be
amended as follows:
PART 51—[AMENDED]
1. The authority citation for Part 51
continues to read as follows:
Authority: 23 U.S.C. 101; 42 U.S.C. 7401–
7671q.
§ 51.121
[Amended]
2. Section 51.121 is amended by
revising paragraph (r)(2) by removing
the words ‘‘§ 51.123(bb)’’ and adding, in
their place, the words ‘‘§ 51.123(bb) with
regard to an ozone season that occurs
before January 1, 2012’’.
§ 51.123
[Amended]
3. Section 51.123 is amended by
adding a new paragraph (ff) to read as
follows:
§ 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
AAA through III 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; 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.
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[Amended]
4. Section 51.124 is amended by
adding a new paragraph (s) to read as
follows:
§ 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.
§ 51.125
[Reserved]
5. Section 51.125 is removed and
reserved.
PART 52—[AMENDED]
6. The authority citation for Part 52
continues to read as follows:
Authority: 42 U.S.C. 7401, et seq.
Subpart A—General Provisions
§ 52.35
[Amended]
7. Section 52.35 is amended by
adding a new paragraph (f) to read as
follows:
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§ 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,
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(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; 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.
§ 52.36
[Amended]
8. Section 52.36 is amended by
adding a new paragraph (e) to read as
follows:
§ 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.
9. Subpart A is amended by adding
§§ 52.37 and 52.38 to read as follows:
§ 52.37 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 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, regarding the
TR NOX Annual Trading Program, apply
to the sources in the following States:
Alabama, Connecticut, Delaware,
District of Columbia, Florida, Georgia,
Illinois, Indiana, Iowa, Kansas,
Kentucky, Louisiana, Maryland,
Massachusetts, Michigan, Minnesota,
Missouri, Nebraska, New Jersey, New
York, North Carolina, Ohio,
Pennsylvania, South Carolina,
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Tennessee, Virginia, West Virginia, and
Wisconsin.
(3) Following promulgation of an
approval by the Administrator of a
State’s SIP as correcting the SIP’s
deficiency that is the basis for this
Federal Implementation Plan, 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 is
partial or conditional.
(4) Notwithstanding the provisions of
paragraph (a)(3) of this section, if, at the
time of such approval of the State’s SIP,
the Administrator has already allocated
any TR NOX Annual allowances to
sources in the State for any years, the
provisions of part 97 of this chapter
authorizing the Administrator to
complete the allocation of TR NOX
Annual allowances for those years shall
continue to apply, unless provided
otherwise by such approval of the
State’s SIP.
(b)(1) The TR NOX Ozone Season
Trading Program provisions of 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, regarding the
TR NOX Ozone Season Trading
Program, apply to sources in each of the
following States: Alabama, Arkansas,
Connecticut, Delaware, District of
Columbia, Florida, Georgia, Illinois,
Indiana, Kansas, Kentucky, Louisiana,
Maryland, Michigan, Mississippi, New
Jersey, New York, North Carolina, Ohio,
Oklahoma, Pennsylvania, South
Carolina, Tennessee, Texas, Virginia,
and West Virginia.
(3) Following promulgation of an
approval by the Administrator of a
State’s SIP as correcting the SIP’s
deficiency that is the basis for this
Federal Implementation Plan, 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 is partial or
conditional.
(4) Notwithstanding the provisions of
paragraph (b)(3) of this section, if, at the
time of such approval of the State’s SIP,
the Administrator has already allocated
any TR NOX Ozone Season allowances
to sources in the State for any years, the
provisions of part 97 of this chapter
authorizing the Administrator to
complete the allocation of TR NOX
Ozone Season allowances for those
years shall continue to apply, unless
provided otherwise by such approval of
the State’s SIP.
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§ 52.38 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 and TR SO2 Group 2 Trading
Program provisions 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, regarding the
TR SO2 Group 1 Trading Program, apply
to sources in each of the following
States: Georgia, Illinois, Indiana, Iowa,
Kentucky, Michigan, Missouri, New
York, North Carolina, Ohio,
Pennsylvania, Tennessee, Virginia, West
Virginia, and Wisconsin.
(c) The provisions of subpart DDDDD
of part 97 of this chapter, regarding the
TR SO2 Group 2 Trading Program, apply
to sources in each of the following
States: Alabama, Connecticut, Delaware,
District of Columbia, Florida, Kansas,
Louisiana, Maryland, Massachusetts,
Minnesota, Nebraska, New Jersey, and
South Carolina.
(d) Following promulgation of an
approval by the Administrator of a
State’s SIP as correcting the SIP’s
deficiency that is the basis for this
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 is partial or conditional.
(e) Notwithstanding the provisions of
paragraph (d) of this section, if, at the
time of such approval of the State’s SIP,
the Administrator has already allocated
any TR SO2 Group 1 allowances or any
TR SO2 Group 2 allowances (as
applicable) to sources in the State for
any years, the provisions of part 97 of
this chapter authorizing the
Administrator to complete the
allocation of TR SO2 Group 1
allowances or TR SO2 Group 2
allowances (as applicable) for those
years shall continue to apply, unless
provided otherwise by such approval of
the State’s SIP.
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10. Section 52.440 is amended by
adding a new paragraph (c) to read as
follows:
§ 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
15:19 Jul 30, 2010
§ 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
12. Section 52.484 is amended by
adding a new paragraph (c) to read as
follows:
§ 52.484 Interstate pollutant transport
provisions; What are the FIP requirements
for decreases in emissions of nitrogen
oxides?
*
Subpart I—Delaware
VerDate Mar<15>2010
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.
11. Section 52.441 is amended by
designating the introductory text as
paragraph (a) and adding a new
paragraph (b) to read as follows:
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*
*
*
*
(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
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45363
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.
13. Section 52.485 is amended by
designating the introductory text as
paragraph (a) and adding a new
paragraph (b) to read as follows:
§ 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 P—Indiana
14. Section 52.789 is amended by
adding a new paragraph (c) to read as
follows:
§ 52.789 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.
15. Section 52.790 is amended by
designating the introductory text as
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paragraph (a) and adding a new
paragraph (b) to read as follows:
§ 52.790 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 T—Louisiana
16. Section 52.984 is amended by
adding a new paragraph (c) to read as
follows:
§ 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; 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.
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Subpart X—Michigan
§ 52.1186 Interstate pollutant transport
provisions; What are the FIP requirements
for decreases in emissions of nitrogen
oxides?
*
*
VerDate Mar<15>2010
*
§ 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.
Subpart FF—New Jersey
*
15:19 Jul 30, 2010
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§ 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
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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.
20. Section 52.1185 is amended by
designating the introductory text as
paragraph (a) and adding a new
paragraph (b) to read as follows:
§ 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.
Subpart RR—Tennessee
21. Section 52.2240 is amended by
adding a new paragraph (c) to read as
follows:
§ 52.2240 Interstate pollutant transport
provisions; What are the FIP requirements
for decreases in emissions of nitrogen
oxides?
*
19. Section 52.1584 is amended by
adding a new paragraph (c) to read as
follows:
*
17. Section 52.1186 is amended by
adding a new paragraph (c) to read as
follows:
*
(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.
18. Section 52.1187 is amended by
designating the introductory text as
paragraph (a) and adding a new
paragraph (b) to read as follows:
*
*
*
*
(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
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allowances or CAIR NOX Ozone Season
allowances allocated for 2012 or any
year thereafter.
22. Section 52.2241 is amended by
designating the introductory text as
paragraph (a) and adding a new
paragraph (b) to read as follows:
§ 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.
Subpart SS—Texas
23. Section 52.2283 is amended by
adding a new paragraph (c) to read as
follows:
§ 52.2283 Interstate pollutant transport
provisions; What are the FIP requirements
for decreases in emissions of nitrogen
oxides?
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*
*
*
*
*
(c) Notwithstanding any provisions of
paragraphs (a) and (b) 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; and
(2) The Administrator will not deduct
for excess emissions any CAIR NOX
allowances allocated for 2012 or any
year thereafter.
24. Section 52.2284 is amended by
designating the introductory text as
paragraph (a) and adding a new
paragraph (b) to read as follows:
§ 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
VerDate Mar<15>2010
15:19 Jul 30, 2010
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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 YY—Wisconsin
45365
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.
PART 72—[AMENDED]
27. 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.
§ 72.2
[Amended]
28. Section 72.2 is amended by
removing the definition of ‘‘interested
person’’.
25. Section 52.8587 is amended by
adding a new paragraph (c) to read as
follows:
PART 78—[AMENDED]
§ 52.8587 Interstate pollutant transport
provisions; What are the FIP requirements
for decreases in emissions of nitrogen
oxides?
Authority: 42 U.S.C. 7401, 7403, 7410,
7411, 7426, 7601, et seq.
*
30. Section 78.1 is amended by
adding paragraphs (b)(13) through
(b)(16) to read as follows:
*
*
*
*
(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.
26. Section 52.8588 is amended by
designating the introductory text as
paragraph (a) and adding a new
paragraph (b) to read as follows:
§ 52.8588 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
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29. The authority citation for Part 78
continues to read as follows:
§ 78.1
§ 78.1
[Amended]
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
§ 97.411(a)(2) and (b) of this chapter.
(ii) The decision on the transfer of TR
NOX Annual allowances under § 97.423
of this chapter.
(iii) The decision on the deduction of
TR NOX Annual allowances under
§§ 97.424 and 97.425 of this chapter.
(iv) The correction of an error in an
Allowance Management System account
under § 97.427 of this chapter.
(iv) 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 § 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 § 97.435 of this chapter.
(viii) The approval or disapproval of
a TR opt-in application, the approval or
disapproval of a request to withdraw,
the decision on allocation of TR NOX
Annual allowances, and the decision on
the deduction of TR NOX Annual
allowances under §§ 97.441 through
97.444.
(14) Under subpart BBBBB of part 97
of this chapter, (i) The decision on
allocation of TR NOX Ozone Season
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allowances under § 97.511(a)(2) and (b)
of this chapter.
(ii) The decision on the transfer of TR
NOX Ozone Season allowances under
§ 97.523 of this chapter.
(iii) The decision on the deduction of
TR NOX Ozone Season allowances
under §§ 97.524 and 97.525 of this
chapter.
(iv) The correction of an error in an
Allowance Management System account
under § 97.527 of this chapter.
(iv) 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 § 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 § 97.535 of this chapter.
(viii) The approval or disapproval of
a TR opt-in application, the approval or
disapproval of a request to withdraw,
the decision on allocation of TR NOX
Ozone Season allowances, and the
decision on the deduction of TR NOX
Ozone Season allowances under
§§ 97.541 through 97.544.
(15) Under subpart CCCCC of part 97
of this chapter,
(i) The decision on allocation of TR
SO2 Group 1 allowances under
§ 97.611(a)(2) and (b) of this chapter.
(ii) The decision on the transfer of TR
SO2 Group 1 allowances under § 97.623
of this chapter.
(iii) The decision on the deduction of
TR SO2 Group 1 allowances under
§§ 97.624 and 97.625 of this chapter.
(iv) The correction of an error in an
Allowance Management System account
under § 97.627 of this chapter.
(iv) 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 § 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 § 97.635 of this chapter.
(viii) The approval or disapproval of
a TR opt-in application, the approval or
disapproval of a request to withdraw,
the decision on allocation of TR SO2
Group 1 allowances, and the decision
on the deduction of TR SO2 Group 1
allowances under §§ 97.641 through
97.644.
(16) Under subpart DDDDD of part 97
of this chapter,
(i) The decision on allocation of TR
SO2 Group 2 allowances under
§ 97.711(a)(2) and (b) of this chapter.
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15:19 Jul 30, 2010
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(ii) The decision on the transfer of TR
SO2 Group 1 allowances under § 97.723
of this chapter.
(iii) The decision on the deduction of
TR SO2 Group 1 allowances under
§§ 97.724 and 97.725 of this chapter.
(iv) The correction of an error in an
Allowance Management System account
under § 97.727 of this chapter.
(iv) 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 § 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 § 97.735 of this chapter.
(viii) The approval or disapproval of
a TR opt-in application, the approval or
disapproval of a request to withdraw,
the decision on allocation of TR SO2
Group 2 allowances, and the decision
on the deduction of TR SO2 Group 2
allowances under §§ 97.741 through
97.744.
*
*
*
*
*
§ 78.2
[Amended]
31. Section 78.2 is revised to read as
follows:
§ 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, 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, who submitted
objections pursuant to an opportunity
for objections provided by the
Administrator as part of the process of
making such decision, or who submitted
his or her name to the Administrator to
be placed on a list of persons interested
in such decision. 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
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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 sameday 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.
§ 78.3
[Amended]
32. Section 78.3 is amended by:
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’’.
b. Adding paragraph (a)(10);
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
d. Adding paragraph (d)(11) to read as
follows:
§ 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 § 97.406, § 97.506, § 97.606, or
§ 97.706 of this chapter and any
emission monitoring or reporting
requirements.
§ 78.4
[Amended]
33. Section 78.4 is amended by:
a. Revising paragraph (a) by:
i. Removing the first, second, third,
fourth, fifth, and last sentences;
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ii. In the sixth and seventh sentences,
removing the words ‘‘interest in’’ and
adding, in their place, the words
‘‘ownership interest with respect to’’;
and
iii. Redesignating the paragraph as
paragraph (a)(1)(iii); and
b. Adding paragraphs (a)(1)
introductory text, (a)(1)(i), (a)(1)(ii) and
(a)(2) to read as follows:
§ 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.
*
*
*
*
*
PART 97—[AMENDED]
34. The authority citation for part 97
continues to read as follows:
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Authority: 42 U.S.C. 7401, 7403, 7410,
7426, 7601, and 7651, et seq.
35. Part 97 is amended by adding
subpart AAAAA to read as follows:
Subpart AAAAA TR NOX Annual Trading
Program
Sec.
97.401 Purpose.
97.402 Definitions.
97.403 Measurements, abbreviations, and
acronyms.
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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, and variability
limits.
97.411 Timing requirements for TR NOX
Annual allowance allocations.
97.412 TR NOX Annual allowance
allocations for 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 Allowance
Management System 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.
97.440 General requirements for TR NOX
Annual opt-in units.
97.441 Opt-in process.
97.442 Withdrawal of TR NOX Annual optin unit from TR NOX Annual Trading
Program.
97.443 Change in regulatory status.
97.444 TR NOX Annual allowance
allocations to TR NOX Annual opt-in
units.
Subpart AAAAA—TR NOX Annual
Trading Program
§ 97.401
Purpose.
This subpart sets forth the general,
designated representative, allowance,
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and monitoring provisions for the
Transport Rule (TR) NOX Annual
Trading Program, under section 110 of
the Clean Air Act and § 52.37(a) of this
chapter, as a means of mitigating
interstate transport of fine particulates
and nitrogen oxides.
§ 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 multistate 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) 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
of the amount of such TR NOX Annual
allowances to be initially credited to a
TR NOX Annual source or a new unit
set-aside.
Allowable NOX emission rate means,
with regard to a unit, the NOX emission
rate limit 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, held,
deducted, or transferred only as whole
allowances. The Allowance
Management System is a component of
the CAMD Business System, which is
the system used by the Administrator to
handle TR NOX Annual allowances and
data related to NOX emissions.
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, 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
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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
§ 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 § 72.2 of
this chapter, § 97.502, § 97.602, or
§ 97.702 respectively.
Authorized account representative
means, with regard to 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, with regard to 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
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
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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.
Certifying official means a natural
person who is:
(1) For a corporation, a president,
secretary, treasurer, or vice-president or
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 any solid fuel classified as
anthracite, bituminous, subbituminous,
or lignite.
Coal-derived fuel means any fuel
(whether in a solid, liquid, or gaseous
state) produced by the mechanical,
thermal, or chemical processing of coal.
Coal-fired means combusting any
amount of coal or coal-derived fuel,
alone or in combination with any
amount of any other fuel, during 1990
or any year thereafter.
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—
(1) Operating as part of a cogeneration
system; and
(2) Producing during the later of 1990
or the 12-month period starting on the
date that the unit first produces
electricity and during each calendar
year after the later of 1990 or the
calendar year in which the unit first
produces electricity—
(i) For a topping-cycle unit,
(A) Useful thermal energy not less
than 5 percent of total energy output;
and
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(B) Useful power that, when added to
one-half of useful thermal energy
produced, is not less then 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 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
(4) Provided that, if a topping-cycle
unit is operated as part of a cogeneration
system during a calendar year and the
cogeneration system meets on a systemwide basis the requirement in paragraph
(2)(i)(B) of this definition, the toppingcycle unit shall be deemed to meet such
requirement during that 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 § 97.405.
(i) For a unit that is a TR NOX Annual
unit under § 97.404 on the later of
November 15, 1990 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 (other than replacement of the
unit by a unit at the same 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 § 97.404 on the later
of November 15, 1990 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 source, such date shall remain the
replaced unit’s date of commencement
of commercial operation, and the
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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 § 97.405, for a unit that is not a TR
NOX Annual unit under § 97.404 on the
later of November 15, 1990 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 § 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 (other than replacement
of the unit by a unit at the same 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 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.
Commence operation means, with
regard to a unit:
(1) To have begun any mechanical,
chemical, or electronic process,
including start-up of the unit’s
combustion chamber.
(2) For a unit that undergoes a
physical change (other than replacement
of the unit by a unit at the same source)
after the date the unit commences
operation as defined in paragraph (1) of
this definition, such date shall remain
the date of commencement of operation
of the unit, which shall continue to be
treated as the same unit.
(3) For a unit that is replaced by a unit
at the same source after the date the unit
commences operation as defined in
paragraph (1) of this definition, such
date shall remain the replaced unit’s
date of commencement of operation,
and the replacement unit shall be
treated as a separate unit with a separate
date for commencement of operation as
defined in paragraph (1), (2), or (3) of
this definition as appropriate.
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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
for 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
complying with the source’s TR NOX
Annual emissions limitation in
accordance with § 97.424 and the TR
NOX Annual assurance provisions in
accordance with § 97.425.
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 §§ 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 NOXdiluent) 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 § 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
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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 § 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 § 72.2 of this chapter,
§ 97.502, § 97.602, or § 97.702
respectively.
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 in
accordance with this subpart.
Excess emissions means any ton of
NOX emitted from the TR NOX Annual
units at a TR NOX Annual source during
a control period that exceeds the TR
NOX Annual emissions limitation for
the source.
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
§§ 97.404(b)(2)(i)(B), 97.404(b)(2)(ii)(B),
and 97.404(b)(2)(iii), 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 1990 or any calendar year
thereafter.
Fuel oil means any petroleum-based
fuel (including diesel fuel or petroleum
derivatives such as oil tar) and any
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recycled or blended petroleum products
or petroleum by-products used as a fuel
whether in a liquid, solid, or gaseous
state.
General account means an Allowance
Management System account,
established under this subpart, that is
not a compliance account.
Generator means a device that
produces electricity.
Gross electrical output means, with
regard to 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, with regard to a
unit for a specified period of time, the
product (in mmBtu/time) of the gross
calorific value of the fuel (in mmBtu/lb)
multiplied by the fuel feed rate into a
combustion device (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 the amount of
heat input (in mmBtu) divided by unit
operating time (in hr) or, with regard to
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.
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
the maximum amount of fuel per hour
(in Btu/hr) that a unit is capable of
combusting on a steady state basis as of
the initial installation of the unit as
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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) 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
(in MWe) 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 as of such completion as
specified by the person conducting the
physical change.
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 any person who
operates, controls, or supervises a TR
NOX Annual unit or a TR NOX Annual
source and shall include, but not be
limited to, any holding company, utility
system, or plant manager of such a unit
or source.
Owner means, with regard to 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;
(3) Any purchaser of power from a TR
NOX Annual unit at the source or the TR
NOX Annual unit under a life-of-theunit, firm power contractual
arrangement;
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(4) Provided that, for purposes of
applying the TR NOX Annual assurance
provisions in §§ 97.406(c)(2) and 97.425,
if one or more owners (as defined in
paragraphs (1) through (3) of this
definition) of one or more TR NOX
Annual units in a State are wholly
owned by another, common owner, all
such owners shall be treated collectively
as a single owner in the State.
Owner’s assurance level means:
(1) With regard to a State and control
period for which the State assurance
level is exceeded as described in
§ 97.406(c)(2)(iii)(A) and not as
described in § 97.406(c)(2)(iii)(B), the
owner’s share of the State NOX Annual
trading budget with the one-year
variability limit for the State for such
control period; or
(2) With regard to a State and control
period for which the State assurance
level is exceeded as described in
§ 97.406(c)(2)(iii)(B), the owner’s share
of the State NOX Annual trading budget
with the three-year variability limit for
the State for such control period.
Owner’s share means:
(1) With regard to a total amount of
NOX emissions from all TR NOX Annual
units in a State during a control period,
the total tonnage of NOX emissions
during such control period from all of
the owner’s TR NOX Annual units in the
State;
(2) With regard to a State NOX Annual
trading budget with a one-year
variability limit for a control period, the
amount (rounded to the nearest
allowance) equal to the total amount of
TR NOX Annual allowances allocated
for such control period to all of the
owner’s TR NOX Annual units in the
State, multiplied by the sum of the State
NOX Annual trading budget under
§ 97.410(a) and the State’s one-year
variability limit under § 97.410(b) and
divided by such State NOX Annual
trading budget;
(3) With regard to a State NOX Annual
trading budget with a three-year
variability limit for a control period, the
amount (rounded to the nearest
allowance) equal to the total amount of
TR NOX Annual allowances allocated
for such control period to all of the
owner’s TR NOX Annual units in the
State, multiplied by the sum of the State
NOX Annual trading budget under
§ 97.410(a) and the State’s three-year
variability limit under § 97.410(b) and
divided by such State NOX Annual
trading budget;
(4) Provided that, in the case of a unit
with more than one owner, the amount
of tonnage of NOX emissions and of TR
NOX Annual allowances allocated for a
control period, with regard to such unit,
used in determining each owner’s share
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shall be the amount (rounded to the
nearest ton and the nearest allowance)
equal to the unit’s NOX emissions and
allocation of such allowances,
respectively, for such control period
multiplied by the percentage of
ownership in the unit that the owner’s
legal, equitable, leasehold, or
contractual reservation or entitlement in
the unit comprises as of December 31 of
such control period;
(5) Provided that, where two or more
units emit through a common stack that
is the monitoring location from which
NOX mass emissions are reported for a
control period for a year, the amount of
tonnage of each unit’s NOX emissions
used in determining each owner’s share
for such control period shall be:
(i) The amount (rounded to the
nearest ton) of NOX emissions reported
at the common stack multiplied by the
quotient of such unit’s heat input for
such control period divided by the total
heat input reported from the common
stack for such control period;
(ii) An amount determined in
accordance with a methodology that the
Administrator determines is consistent
with the purposes of this definition and
whose adverse effect (if any) the
Administrator determines will be de
minimis; or
(iii) An amount approved by the
Administrator in response to a petition
for an alternative requirement submitted
in accordance with § 97.435; and
(6) Provided that, in the case of a unit
that operates during, but is allocated no
TR NOX Annual allowances for, a
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 lesser of—
(i) The unit’s allowable NOX emission
rate (in lb per MWe) applicable to such
control period, multiplied by a capacity
factor of 0.84 (if the unit is a coal-fired
boiler), 0.15 (if the unit is a simple
combustion turbine), or 0.66 (if the unit
is a combined cycle turbine), 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; or
(ii) For a unit listed in appendix A to
this subpart, the sum of the unit’s NOX
emissions in the control period in the
last three years during which the unit
operated during the control period,
divided by three.
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.
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Permitting authority means
‘‘permitting authority’’ as defined in
§§ 70.2 and 71.2 of this chapter.
Potential electrical output capacity
means 33 percent of a 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
Annual allowances by the
Administrator into, out of, or between
Allowance Management System
accounts, for purposes of allocation,
transfer, or deduction.
Reference method means any direct
test method of sampling and analyzing
for an air pollutant as specified in
§ 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) For a topping-cycle unit, the use
of reject heat from electricity production
in a useful thermal energy application
or process; or
(2) For a bottoming-cycle unit, 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
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permit program or any other program
under the Clean Air Act.
State means one of the States or the
District of Columbia that is subject to
the TR NOX Annual Trading Program
pursuant to § 52.37(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 total energy
of all forms supplied to a 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 the sum of
useful power and useful thermal energy
produced by the unit.
TR NOX Annual allowance means a
limited authorization issued and
allocated by the Administrator under
this subpart to emit one ton of NOX
during a control period of the specified
calendar year for which the
authorization is allocated or of any
calendar year thereafter under the TR
NOX Annual 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 assurance
provisions.
TR NOX Annual allowances held or
hold TR NOX Annual allowances means
the TR NOX Annual allowances treated
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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 Trading Program
means a multi-state NOX air pollution
control and emission reduction program
established by the Administrator in
accordance with this subpart and
52.37(a) of this chapter, as a means of
mitigating interstate transport of fine
particulates and NOX.
TR NOX Annual emissions limitation
means, for a TR NOX Annual source, the
tonnage of NOX emissions authorized in
a control period by the TR NOX Annual
allowances available for deduction for
the source under § 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 unit means a unit
that is subject to the TR NOX Annual
Trading Program under § 97.404.
TR NOX Ozone Season Trading
Program means a multi-state NOX air
pollution control and emission
reduction program established by the
Administrator in accordance with
subpart BBBBB of this part and 52.37(b)
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 by the Administrator in
accordance with subpart CCCCC of this
part and 52.38(b) 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 by the Administrator in
accordance with subpart DDDDD of this
part and 52.38(c) of this chapter, as a
means of mitigating interstate transport
of fine particulates and SO2.
Unit means a stationary, fossil-fuelfired boiler, stationary, fossil-fuel-fired
combustion turbine, or other stationary,
fossil-fuel-fired combustion device.
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Unit operating day means a calendar
day in which a unit combusts any fuel.
Unit operating hour or hour of unit
operation means an hour in which a
unit combusts any fuel.
Useful power means electricity or
mechanical energy that a 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.
§ 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
§ 97.404
Applicability.
(a) Except as provided in paragraph
(b) of this section:
(1) The following units in a 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,
since the later of November 15, 1990 or
the start-up of the unit’s combustion
chamber, a generator with nameplate
capacity of more than 25 MWe
producing electricity for sale.
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(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 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), (b)(2)(i), or (b)(2)(ii)
of this section shall not be a TR NOX
Annual unit:
(1)(i) Any unit:
(A) Qualifying as a cogeneration unit
during the later of 1990 or the 12-month
period starting on the date the unit first
produces electricity and continuing to
qualify as a cogeneration unit; and
(B) Not serving at any time, since the
later of November 15, 1990 or the startup of the unit’s combustion chamber, a
generator with nameplate capacity of
more than 25 MWe supplying in any
calendar year 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 a unit qualifies as a cogeneration
unit during the later of 1990 or the 12month period starting on the date the
unit first produces electricity and meets
the requirements of paragraphs (b)(1)(i)
of this section for at least one calendar
year, but subsequently no longer meets
such qualification and requirements, 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.
(2)(i) Any unit commencing operation
before January 1, 1985:
(A) Qualifying as a solid waste
incineration unit during the later of
1990 or the 12-month period starting on
the date the unit first produces
electricity and continuing to qualify as
a solid waste incineration unit; and
(B) With an average annual fuel
consumption of fossil fuel for 1985–
1987 less than 20 percent (on a Btu
basis) and an average annual fuel
consumption of fossil fuel for any 3
consecutive calendar years after 1990
less than 20 percent (on a Btu basis).
(ii) Any unit commencing operation
on or after January 1, 1985:
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(A) Qualifying as a solid waste
incineration unit during the later of
1990 or the 12-month period starting on
the date the unit first produces
electricity and continuing to qualify as
a solid waste incineration unit; and
(B) With an average annual fuel
consumption of fossil fuel for the first
3 calendar years of operation less than
20 percent (on a Btu basis) and an
average annual fuel consumption of
fossil fuel for any 3 consecutive
calendar years after 1990 less than 20
percent (on a Btu basis).
(iii) If a unit qualifies as a solid waste
incineration unit during the later of
1990 or the 12-month period starting on
the date the unit first produces
electricity and meets the requirements
of paragraph (b)(2)(i) or (ii) of this
section for at least 3 consecutive
calendar years, but subsequently no
longer meets such qualification and
requirements, 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
1990 for which the unit has an average
annual fuel consumption of fossil fuel of
20 percent or more.
(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, 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
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
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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
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.
§ 97.405
Retired unit exemption.
(a)(1) Any TR NOX Annual unit that
is permanently retired and is not a TR
NOX Annual opt-in unit shall be exempt
from § 97.406(b) and (c)(1), § 97.424,
and §§ 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.
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(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.
§ 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
§§ 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 §§ 97.430
through 97.435.
(2) The emissions data determined in
accordance with §§ 97.430 through
97.435 shall be used to calculate
allocations of TR NOX Annual
allowances under §§ 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
§§ 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, 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 § 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 a TR NOX Annual source emits
NOX during any control period in excess
of the TR NOX Annual emissions
limitation set forth in paragraph (c)(1)(i)
of this section, then:
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(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 § 97.424(d) and pay
any fine, penalty, or assessment or
comply with any other remedy imposed,
for the same violations, under the Clean
Air Act; and
(B) 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 the total amount of
NOX emissions from all TR NOX Annual
units in a State during a control period
in 2014 or any year thereafter exceeds
the State assurance level as described in
paragraph (c)(2)(iii) of this section, then
each owner whose share of such NOX
emissions during such control period
exceeds the owner’s assurance level for
the State and such control period shall
hold, in a compliance account
designated by the owner in accordance
with § 97.425(b)(4)(ii), TR NOX Annual
allowances available for deduction for
such control period under § 97.425(a) in
an amount equal to the product, as
determined by the Administrator in
accordance with § 97.425(b), of
multiplying—
(A) The quotient (rounded to the
nearest whole number) of the amount by
which the owner’s share of such NOX
emissions exceeds the owner’s
assurance level divided by the sum of
the amounts, determined for all such
owners, by which each owner’s share of
such NOX emissions exceeds that
owner’s assurance level; and
(B) The amount by which total NOX
emissions for all TR NOX Annual units
in the State for such control period
exceed the State assurance level as
determined in accordance with
paragraph (c)(2)(iii) of this section.
(ii) The owner 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) The total amount of NOX
emissions from all TR NOX Annual
units in a State during a control period
in 2014 or any year thereafter exceeds
the State assurance level:
(A) If such total amount of NOX
emissions exceeds the sum, for such
control period, of the State NOX Annual
trading budget and the State’s one-year
variability limit under § 97.410(b); or
(B) If, with regard to a control period
in 2016 or any year thereafter, the sum,
divided by three, of such total amount
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of NOX emissions and the total amounts
of NOX emissions from all TR NOX
Annual units in the State during the
control periods in the immediately
preceding two years exceeds the sum,
for such control period, of the State NOX
Annual trading budget and the State’s
three-year variability limit under
§ 97.410(b);
(C) Provided that the amount by
which such total amount of NOX
emissions exceeds the State assurance
level shall be the greater of the amounts
of the exceedance calculated under
paragraph (c)(2)(iii)(A) of this section
and under paragraph (c)(2)(iii)(B) of this
section.
(iv) It shall not be a violation of this
subpart or of the Clean Air Act if the
total amount of NOX emissions from all
TR NOX Annual units in a State during
a control period exceeds the State
assurance level or if an owner’s share of
total NOX emissions from the TR NOX
Annual units in a State during a control
period exceeds the owner’s assurance
level.
(v) To the extent an owner fails to
hold TR NOX Annual allowances for a
control period in accordance with
paragraphs (c)(2)(i) and (ii) of this
section,
(A) The owner 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 owner fails to hold for a control
period in accordance with paragraphs
(c)(2)(i) and (ii) 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:
(i) Under paragraph (c)(1) 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
§ 97.430(b) and for each control period
thereafter; and
(ii) Under paragraph (c)(2) of this
section for the control period starting on
the later of January 1, 2014 or the
deadline for meeting the unit’s monitor
certification requirements under
§ 97.430(b) and for each control period
thereafter.
(4) Vintage of deducted allowances. A
TR NOX Annual allowance shall not be
deducted, for compliance with the
requirements under paragraphs (c)(1)
and (2) of this section, for a control
period in a calendar year before the year
for which the TR NOX Annual
allowance was allocated.
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(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. (i) A TR
NOX Annual allowance is a limited
authorization to emit one ton of NOX in
accordance with the TR NOX Annual
Trading Program.
(ii) Notwithstanding any other
provision of this subpart, the
Administrator has the authority to
terminate or limit 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 § 75.19 of this
chapter), or an alternative monitoring
system (under subpart E of part 75 of
this chapter) in accordance with
§§ 97.430 through 97.435 may be added
to, or changed in, a title V permit using
minor permit modification procedures
in accordance with §§ 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 §§ 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
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before the end of 5 years, in writing by
the Administrator.
(i) The certificate of representation
under § 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
documents are superseded because of
the submission of a new certificate of
representation under § 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, including any
monitoring plans and monitoring
system certification and recertification
applications.
(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,
including any submissions required for
compliance with the TR NOX Annual
assurance provisions. 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
§ 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.
§ 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, falls on
a weekend or a State or Federal holiday,
the time period shall be extended to the
next business day.
§ 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.
§ 97.409
[Reserved]
§ 97.410 State NOX Annual trading
budgets, new-unit set-asides, and variability
limits.
(a) The State NOX Annual trading
budgets and new-unit set-asides for
allocations of TR NOX Annual
allowances for the control periods in
2012 and thereafter are as follows:
NOX annual
trading budget
(tons) *
For 2012 and
thereafter
erowe on DSK5CLS3C1PROD with PROPOSALS2
State
Alabama ...................................................................................................................................................................
Connecticut ..............................................................................................................................................................
Delaware ..................................................................................................................................................................
District of Columbia .................................................................................................................................................
Florida ......................................................................................................................................................................
Georgia ....................................................................................................................................................................
Illinois .......................................................................................................................................................................
Indiana .....................................................................................................................................................................
Iowa .........................................................................................................................................................................
Kansas .....................................................................................................................................................................
Kentucky ..................................................................................................................................................................
Louisiana ..................................................................................................................................................................
Maryland ..................................................................................................................................................................
Massachusetts .........................................................................................................................................................
Michigan ...................................................................................................................................................................
Minnesota ................................................................................................................................................................
Missouri ....................................................................................................................................................................
Nebraska ..................................................................................................................................................................
New Jersey ..............................................................................................................................................................
New York .................................................................................................................................................................
North Carolina ..........................................................................................................................................................
Ohio .........................................................................................................................................................................
Pennsylvania ............................................................................................................................................................
South Carolina .........................................................................................................................................................
Tennessee ...............................................................................................................................................................
Virginia .....................................................................................................................................................................
West Virginia ............................................................................................................................................................
Wisconsin .................................................................................................................................................................
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E:\FR\FM\02AUP2.SGM
02AUP2
New-unit
set-aside
(tons)
For 2012 and
thereafter
69,169
2,775
6,206
170
120,001
73,801
56,040
115,687
46,068
51,321
74,117
43,946
17,044
5,960
64,932
41,322
57,681
43,228
11,826
23,341
51,800
97,313
113,903
33,882
28,362
29,581
51,990
44,846
2,075
83
186
5
3,600
2,214
1,681
3,471
1,382
1,540
2,224
1,318
511
179
1,948
1,240
1,730
1,297
355
700
1,554
2,919
3,417
1,016
851
887
1,560
1,345
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NOX annual
trading budget
(tons) *
For 2012 and
thereafter
State
Total ..................................................................................................................................................................
New-unit
set-aside
(tons)
For 2012 and
thereafter
1,376,312
41,288
* Without variability limits.
(b) The States’ one-year and three-year
variability limits for the State NOX
Annual trading budgets for the control
periods in 2014 and thereafter are as
follows:
One-year
variability
limits
Three-year
variability
limits
2014 and
thereafter
(tons)
2016 and
thereafter
(tons)
State
Alabama ...................................................................................................................................................................
Connecticut ..............................................................................................................................................................
Delaware ..................................................................................................................................................................
District of Columbia .................................................................................................................................................
Florida ......................................................................................................................................................................
Georgia ....................................................................................................................................................................
Illinois .......................................................................................................................................................................
Indiana .....................................................................................................................................................................
Iowa .........................................................................................................................................................................
Kansas .....................................................................................................................................................................
Kentucky ..................................................................................................................................................................
Louisiana ..................................................................................................................................................................
Maryland ..................................................................................................................................................................
Massachusetts .........................................................................................................................................................
Michigan ...................................................................................................................................................................
Minnesota ................................................................................................................................................................
Missouri ....................................................................................................................................................................
Nebraska ..................................................................................................................................................................
New Jersey ..............................................................................................................................................................
New York .................................................................................................................................................................
North Carolina ..........................................................................................................................................................
Ohio .........................................................................................................................................................................
Pennsylvania ............................................................................................................................................................
South Carolina .........................................................................................................................................................
Tennessee ...............................................................................................................................................................
Virginia .....................................................................................................................................................................
West Virginia ............................................................................................................................................................
Wisconsin .................................................................................................................................................................
erowe on DSK5CLS3C1PROD with PROPOSALS2
§ 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 set forth in appendix A to
this subpart. Listing a unit in such
appendix does not constitute a
determination that the unit is a TR NOX
Annual unit, and not listing a unit in
such appendix 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 listed in
appendix A to this subpart as being
allocated TR NOX Annual allowances
does not operate, starting after 2011,
during the control period in three
consecutive years, such unit will not be
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15:19 Jul 30, 2010
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allocated the TR NOX Annual
allowances set forth in appendix A to
this subpart for the unit for the control
periods in the seventh year after the first
such year and in each year after that
seventh 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 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) By July 1, 2012 and
July 1 of each year thereafter, the
Administrator will calculate the TR
NOX Annual allowance allocation for
each TR NOX Annual unit, in
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6,917
5,000
5,000
5,000
12,000
7,380
5,604
11,569
5,000
5,132
7,412
5,000
5,000
5,000
6,493
5,000
5,768
5,000
5,000
5,000
5,180
9,731
11,390
5,000
5,000
5,000
5,199
5,000
3,993
2,887
2,887
2,887
6,928
4,261
3,235
6,679
2,887
2,963
4,279
2,887
2,887
2,887
3,749
2,887
3,330
2,887
2,887
2,887
2,991
5,618
6,576
2,887
2,887
2,887
3,002
2,887
accordance with § 97.412, for the
control period in the year of the
applicable calculation deadline under
this paragraph and will promulgate a
notice of availability of the results of the
calculations.
(2) For each notice of data availability
required in paragraph (b)(1) of this
section, the Administrator will provide
an opportunity for submission of
objections to the calculations referenced
in such notice.
(i) Objections shall be submitted by
the deadline specified in such notice
and shall be limited to addressing
whether the calculations are in
accordance with § 97.412 and
§§ 97.406(b)(2) and 97.430 through
97.435.
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(ii) 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)(i) of this section. By September 1
immediately after the promulgation of
such notice, the Administrator will
promulgate a notice of 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)(i) of this section.
(c) Units that are not TR NOX Annual
units. 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 for the
control period to a recipient that is not
actually a TR NOX Annual unit under
§ 97.404 as of January 1, 2012 or whose
deadline for meeting monitor
certification requirements under
§ 97.430(b)(1) and (2) is after January 1,
2012 or if the Administrator determines
that TR NOX Annual allowances were
allocated under paragraph (b) of this
section and § 97.412 for the control
period to a recipient that is not actually
a TR NOX Annual unit under § 97.404
as of January 1 of the control period,
then the Administrator will notify the
designated representative and will act in
accordance with the following
procedures:
(1) Except as provided in paragraph
(c)(2) or (3) of this section, the
Administrator will not record such TR
NOX Annual allowances under § 97.421.
(2) If the Administrator already
recorded such TR NOX Annual
allowances under § 97.421 and if the
Administrator makes such
determination before making deductions
for the source that includes such
recipient under § 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.
(3) If the Administrator already
recorded such TR NOX Annual
allowances under § 97.421 and if the
Administrator makes such
determination after making deductions
for the source that includes such
recipient under § 97.424(b) for such
control period, then the Administrator
will not make any deduction to take
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15:19 Jul 30, 2010
Jkt 220001
account of such already recorded TR
NOX Annual allowances.
(4) The Administrator will transfer the
TR NOX Annual allowances that are not
recorded, or that are deducted, in
accordance with paragraphs (c)(1) and
(2) of this section to the new unit setaside, for the State in which such
recipient is located, for the control
period in the year of such transfer if the
notice required in paragraph (b)(1) of
this section for the control period in that
year has not been promulgated or, if
such notice has been promulgated, in
the next year.
§ 97.412 TR NOX Annual allowance
allocations for new units.
(a) For each control period in 2012
and thereafter, the Administrator will
allocate, in accordance with the
following procedures, TR NOX Annual
allowances to TR NOX Annual units in
a State that are not listed in appendix
A to this subpart, to TR NOX Annual
units that are so listed and whose
allocation of NOX Annual allowances
for such control period is covered by
§ 97.411(c)(1) or (2), and to TR NOX
Annual units that are so listed and,
pursuant to § 97.411(a)(2), are not
allocated TR NOX Annual allowances
for such control period but operate
during the immediately preceding
control period:
(1) The Administrator will establish a
separate new unit set-aside for each
State for each control period in a given
year. Each 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 § 97.410(a). Each new unit setaside will be allocated additional TR
NOX Annual allowances in accordance
with § 97.411(a)(2) and (c)(4).
(2) The designated representative of
such TR NOX Annual unit may submit
to the Administrator a request, in a
format prescribed by the Administrator,
to be allocated TR NOX Annual
allowances for a control period, starting
with the later of the control period in
2012, the first control period after the
control period in which the TR NOX
Annual unit commences commercial
operation (for a unit not listed in
appendix A to this subpart), or the first
control period after the control period in
which the unit resumes operation (for a
unit listed in appendix A of this
subpart) and for each subsequent
control period.
(i) The request must be submitted on
or before May 1 of the first control
period for which TR NOX Annual
allowances are sought and after the date
on which the TR NOX Annual unit
commences commercial operation (for a
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45377
unit not listed in appendix A of this
subpart) or on which the unit resumes
operation (for a unit listed in appendix
A of this subpart).
(ii) For each control period for which
an allocation is sought, the request must
be for TR NOX Annual allowances in an
amount equal to the unit’s total tons of
NOX emissions during the immediately
preceding control period.
(3) The Administrator will review
each TR NOX Annual allowance
allocation request under paragraph
(a)(2) of this section and will accept the
request only if it meets the requirements
of paragraph (a)(2) of this section. The
Administrator will allocate TR NOX
Annual allowances for each control
period pursuant to an accepted request
as follows:
(i) After May 1 of such control period,
the Administrator will determine the
sum of the TR NOX Annual allowances
requested in all accepted allowance
allocation requests for such control
period.
(ii) If the amount of TR NOX Annual
allowances in the new unit set-aside for
such control period is greater than or
equal to the sum under paragraph
(a)(3)(i) of this section, then the
Administrator will allocate the amount
of TR NOX Annual allowances
requested to each TR NOX Annual unit
covered by an accepted allowance
allocation request.
(iii) If the amount of TR NOX Annual
allowances in the new unit set-aside for
such control period is less than the sum
under paragraph (a)(3)(i) of this section,
then the Administrator will allocate to
each TR NOX Annual unit covered by an
accepted allowance allocation request
the amount of the TR NOX Annual
allowances requested, multiplied by the
amount of TR NOX Annual allowances
in the new unit set-aside for such
control period, divided by the sum
determined under paragraph (a)(3)(i) of
this section, and rounded to the nearest
allowance.
(iv) The Administrator will notify,
through the promulgation of the notices
of data availability described in
§ 97.411(b), each designated
representative that submitted an
allowance allocation request of the
amount of TR NOX Annual allowances
(if any) allocated for such control period
to the TR NOX Annual unit covered by
the request.
(b) If, after completion of the
procedures under paragraph (a)(4) of
this section for a control period, any
unallocated TR NOX Annual allowances
remain in the new unit set-aside under
paragraph (a) of this section for a State
for such control period, the
Administrator will allocate to each TR
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NOX Annual unit that is in the State, is
listed in appendix A to this subpart, and
continues to be allocated TR NOX
Annual allowances for such control
period in accordance with
§ 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 § 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
amount of tons in such new unit setaside, and rounded to the nearest
allowance.
erowe on DSK5CLS3C1PROD with PROPOSALS2
§ 97.413 Authorization of designated
representative and alternate designated
representative.
(a) Except as provided under § 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
§ 97.416(a)(4)(iii).
(2) Upon and after receipt by the
Administrator of a complete certificate
of representation under § 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 § 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.
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(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 § 97.416(a)(4)(iii).
(2) Upon and after receipt by the
Administrator of a complete certificate
of representation under § 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, § 97.402,
and §§ 97.414 through 97.418, whenever
the term ‘‘designated representative’’ is
used in this subpart, the term shall be
construed to include the designated
representative or any alternate
designated representative.
§ 97.414 Responsibilities of designated
representative and alternate designated
representative.
(a) Except as provided under § 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,
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Fmt 4701
Sfmt 4702
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
§ 97.418.
§ 97.415 Changing designated
representative and alternate designated
representative; changes in owners and
operators.
(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 § 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
time upon receipt by the Administrator
of a superseding complete certificate of
representation under § 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 is not included in the list
of owners and operators in the
certificate of representation under
§ 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, including the addition of a new
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owner or operator, the designated
representative or any alternate
designated representative shall submit a
revision to the certificate of
representation under § 97.416 amending
the list of owners and operators to
include the change.
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§ 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, and actual or
projected date of commencement of
commercial operation.
(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 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-theunit, firm power contractual
arrangement, I certify that: I have given
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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.
§ 97.417 Objections concerning
designated representative and alternate
designated representative.
(a) Once a complete certificate of
representation under § 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 § 97.416 is
received by the Administrator.
(b) Except as provided in § 97.415(a)
or (b), 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 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.
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45379
§ 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
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 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
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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.
§ 97.419
[Reserved]
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§ 97.420 Establishment of Allowance
Management System accounts.
(a) Compliance accounts. Upon
receipt of a complete certificate of
representation under § 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) 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
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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
order or decision 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
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Sfmt 4702
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
order or decision issued to the
authorized account representative or
alternate authorized account
representative by the Administrator
regarding the general account.
(ii) Except as provided in paragraph
(b)(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
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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
(b)(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 (b)(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 of a new 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
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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 (b)(1)
of this section has been submitted and
received, the Administrator will rely on
the application unless and until a
superseding complete application for a
general account under paragraph (b)(1)
of this section is received by the
Administrator.
(ii) Except as provided in paragraph
(b)(3)(i) or (ii) 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
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
make an electronic submission to the
Administrator in accordance with
paragraph (b)(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:
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45381
(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
as an ‘‘agent’’);
(C) For each such natural person, a
list of the type or types of electronic
submissions under paragraph (b)(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(b)(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(b)(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(b)(5) is terminated.’’.
(iv) A notice of delegation submitted
under paragraph (b)(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
(b)(5)(iii)(D) of this section and made in
accordance with a notice of delegation
effective under paragraph (b)(5)(iv) of
this section shall be deemed to be an
electronic submission by the designated
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compliance account the TR NOX Annual
allowances allocated for the TR NOX
Annual units at the source in
accordance with § 97.411(a) for the
control period in the third year after the
year of the applicable recordation
deadline under this paragraph.
(c) By September 1, 2012 and
September 1 of each year thereafter, the
Administrator will record in each TR
NOX Annual source’s compliance
account the TR NOX Annual allowances
allocated for the TR NOX Annual units
at the source in accordance with
§ 97.412 for the control period in the
year of the applicable recordation
deadline under this paragraph.
(d) When recording the allocation of
TR NOX Annual allowances for a TR
NOX Annual unit in a compliance
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.
§ 97.421 Recordation of TR NOX Annual
allowance allocations.
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representative or alternate designated
representative submitting such notice of
delegation.
(6)(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 § 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 20
business days after the notice is sent.
The account will be closed after the 20day period unless, before the end of the
20-day period, the Administrator
receives a correctly submitted TR NOX
Annual allowance transfer under
§ 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.
(c) Account identification. The
Administrator will assign a unique
identifying number to each account
established under paragraph (a) or (b) of
this section.
(d) Responsibilities of authorized
account representative and alternate
authorized account representative. After
the establishment of an Allowance
Management System 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 §§ 97.414(a)
and 97.418 or paragraphs (b)(2)(ii) and
(b)(5) of this section.
(a) Within 5 business days (except as
provided in paragraph (b) of this
section) of receiving a TR NOX Annual
allowance transfer, 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 by the request, provided that
the transfer is correctly submitted under
§ 97.422.
(b)(1) A TR NOX Annual allowance
transfer that is submitted for recordation
(a) By September 1, 2011, the
Administrator will record in each TR
NOX Annual source’s compliance
account the TR NOX Annual allowances
allocated for the TR NOX Annual units
at the source in accordance with
§§ 97.411(a) for the control periods in
2012, 2013, and 2014.
(b) By June 1, 2012 and June 1 of each
year thereafter, the Administrator will
record in each TR NOX Annual source’s
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§ 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.
§ 97.423 Recordation of TR NOX Annual
allowance transfers.
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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 under
§ 97.424 for the control period
immediately before such allowance
transfer deadline.
(2) A TR NOX Annual allowance
transfer that is submitted for recordation
after the deadline for holding TR NOX
Annual allowances described in
§ 97.425(b)(5) and that includes any TR
NOX Annual allowances allocated for a
control period before the year of such
deadline will not be recorded until after
the Administrator completes the
deductions under § 97.425 for the
control period immediately before the
year of such deadline.
(c) Where a TR NOX Annual
allowance transfer is not correctly
submitted under § 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
§ 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 nonrecordation.
§ 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 the control
period in the year or 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
§ 97.423, of TR NOX Annual allowance
transfers submitted by the allowance
transfer deadline for a control period,
the Administrator will deduct from the
compliance account TR NOX Annual
allowances available under paragraph
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(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 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 (FIFO)
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 the control
period in the immediately following
year, equal to two times the number of
tons of the source’s excess emissions.
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(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.
§ 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 an
owner of one or more TR NOX Annual
units in a State only if the TR NOX
Annual allowances:
(1) Were allocated for the control
period in the year or a prior year; and
(2) Are held in a compliance account,
designated by the owner in accordance
with paragraph (b)(4)(ii) of this section,
of one of the owner’s TR NOX Annual
sources in the State as of the deadline
established in paragraph (b)(5) 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, 2015 and June 1 of each
year thereafter, the Administrator will:
(i) Calculate, separately for each State,
the total amount of NOX emissions from
all TR NOX Annual units in the State
during the control period in the year
before the year of this calculation
deadline and the amount, if any, by
which such total amount of NOX
emissions exceeds the State assurance
level as described in § 97.406(c)(2)(iii);
and
(ii) Promulgate a notice of availability
of the results of the calculations
required in paragraph (b)(1)(i) of this
section, including separate calculations
of the NOX emissions for each TR NOX
Annual unit and of the amounts
described in §§ 97.406(c)(2)(iii)(A) and
(B) for each State.
(2) The Administrator will provide an
opportunity for submission of objections
to the calculations referenced by each
notice described in paragraph (b)(1) of
this section.
(i) Objections shall be submitted by
the deadline specified in such notice
and shall be limited to addressing
whether the calculations for each TR
NOX Annual unit and each State for the
control period in the year involved are
in accordance with § 97.406(c)(2)(iii)
and §§ 97.406(b) and 97.430 through
97.435.
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(ii) 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)(i) of this section. By August 1
immediately after the promulgation of
such notice, the Administrator will
promulgate a notice of 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)(i) of this section.
(3) For each notice of data availability
required in paragraph (b)(2)(ii) of this
section and for any State identified in
such notice as having TR NOX Annual
sources with total NOX emissions
exceeding the State assurance level for
a control period, as described in
§ 97.406(c)(2)(iii):
(i) By August 15 immediately after the
promulgation of such notice, the
designated representative of each TR
NOX Annual source in each such State
shall submit a statement, in a format
prescribed by the Administrator:
(A) Listing all the owners of each TR
NOX Annual unit at the source,
explaining how the selection of each
owner for inclusion on the list is
consistent with the definition of
‘‘owner’’ in § 97.402, and listing,
separately for each unit, the percentage
of the legal, equitable, leasehold, or
contractual reservation or entitlement
for each such owner as of midnight of
December 31 of the control period in the
year involved; and
(B) For each TR NOX Annual unit at
the source that operates during, but is
allocated no TR NOX Annual
allowances for, the control period in the
year involved, identifying whether the
unit is a coal-fired boiler, simple
combustion turbine, or combined cycle
turbine cycle and providing the unit’s
allowable NOX emission rate for such
control period.
(ii) By September 15 immediately
after the promulgation of such notice,
the Administrator will calculate, for
each such State and each owner of one
or more TR NOX Annual units in the
State and for the control period in the
year involved, each owner’s share of the
total NOX emissions from all TR NOX
Annual units in the State, each owner’s
assurance level, and the amount (if any)
of TR NOX Annual allowances that each
owner must hold in accordance with the
calculation formula in § 97.406(c)(2)(i)
and will promulgate a notice of
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
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required in paragraph (b)(3)(ii) of this
section.
(A) Objections shall be submitted by
the deadline specified in such notice
and shall be limited to addressing
whether the calculations for each owner
for the control period in the year
involved are consistent with the NOX
emissions for the relevant TR NOX
Annual units as set forth in the notice
required in paragraph (b)(2)(ii) of this
section, the definitions of ‘‘owner’’,
‘‘owner’s assurance level’’, and ‘‘owner’s
share’’ in § 97.402, and the calculation
formula in § 97.406(c)(2)(i) and shall not
raise any issues about any data used in
the notice of data availability required
in paragraph (b)(2)(ii) of this section.
(B) The Administrator will adjust the
calculations to the extent necessary to
ensure that they are consistent with the
data and provisions referenced in
paragraph (b)(3)(iii)(A) of this section.
By November 15 immediately after the
promulgation of such notice, the
Administrator will promulgate a notice
of 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)(3)(iii)(A)
of this section.
(4) By December 1 immediately after
the promulgation of each notice of data
availability required in paragraph
(b)(3)(iii)(B) of this section:
(i) Each owner identified, in such
notice, as owning one or more TR NOX
Annual units in a State and as being
required to hold TR NOX Annual
allowances shall designate the
compliance account of one of the
sources at which such unit or units are
located to hold such required TR NOX
Annual allowances;
(ii) The authorized account
representative for the compliance
account designated under paragraph
(b)(4)(i) of this section shall submit to
the Administrator a statement, in a
format prescribed by the Administrator,
making this designation.
(5)(i) As of midnight of December 15
immediately after the promulgation of
each notice of data availability required
in paragraph (b)(3)(iii)(B) of this section,
each owner described in paragraph
(b)(4)(i) of this section shall hold in the
compliance account designated by the
owner in accordance with paragraph
(b)(4)(ii) of this section the total amount
of TR NOX Annual allowances, available
for deduction under paragraph (a) of
this section, equal to the amount the
owner is required to hold as calculated
by the Administrator and referenced in
such notice.
(ii) Notwithstanding the allowanceholding deadline specified in paragraph
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(b)(5)(i) of this section, if December 15
is not a business day, then such
allowance-holding deadline shall be
midnight of the first business day
thereafter.
(6) After December 15 (or the date
described in paragraph (b)(5)(ii) of this
section) immediately after the
promulgation of each notice of data
availability required in paragraph
(b)(3)(iii)(B) of this section and after the
recordation, in accordance with
§ 97.423, of TR NOX Annual allowance
transfers submitted by midnight of such
date, the Administrator will deduct
from each compliance account
designated in accordance with
paragraph (b)(4)(ii) of this section, TR
NOX Annual allowances available under
paragraph (a) of this section, as follows:
(i) Until the amount of TR NOX
Annual allowances deducted equals the
amount that the owner designating the
compliance account is required to hold
as calculated by the Administrator and
referenced in the notice required in
paragraph (b)(3)(iii)(B) of this section; or
(ii) If there are insufficient TR NOX
Annual allowances to complete the
deductions in paragraph (b)(6)(i) of this
section, until no more TR NOX Annual
allowances available under paragraph
(a) of this section remain in the
compliance account.
(7) Notwithstanding any other
provision of this subpart and any
revision, made by or submitted to the
Administrator after the promulgation of
the notices of data availability required
in paragraphs (b)(2)(ii) and (b)(3)(iii)(B)
of this section respectively for a control
period, of any data used in making the
calculations referenced in such notice,
the amount of TR NOX Annual
allowances that each owner is required
to hold in accordance with
§ 97.406(c)(2)(i) for the control period in
the year involved shall continue to be
such amount as calculated by the
Administrator and referenced in such
notice required in paragraph
(b)(3)(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 are required to hold in
accordance with the calculation formula
in § 97.406(c)(2)(i) for the control period
in the year involved with regard to the
State involved, provided that—
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(A) With regard to such litigation
involving such notice required in
paragraph (b)(2)(ii) of this section, 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)(ii) of this section; and
(B) With regard to such litigation
involving such notice required in
paragraph (b)(3)(iii) of this section, 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)(3)(iii) of this section.
(ii) If any such data are revised by the
owners and operators of a source whose
designated representative submitted
such data under paragraph (b)(3)(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 are
required to hold in accordance with the
calculation formula in § 97.406(c)(2)(i)
for the control period in the year
involved with regard to the State
involved, provided that such litigation
was initiated no later than 30 days after
promulgation of such notice required in
paragraph (b)(3)(iii)(B) of this section.
(iii) If the revised data are used to
recalculate, in accordance with
paragraphs (b)(7)(i) and (b)(7)(ii) of this
section, the amount of TR NOX Annual
allowances that an owner is required to
hold for the control period in the year
involved with regard to the State
involved(A) Where the amount of TR NOX
Annual allowances that an owner is
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 owner
shall hold the additional amount of TR
NOX Annual allowances in the
compliance account designated by the
owner in accordance with paragraph
(b)(4)(ii) of this section. The owner’s
failure to hold such additional amount,
as required, before the new deadline
shall not be a violation of the Clean Air
Act. The owner’s 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 Annual
allowance that the owner fails to hold
as required as of the new deadline, and
each day in the control period in the
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year involved, shall be a separate
violation of the Clean Air Act. After
such deadline, the Administrator will
make the appropriate deductions from
the compliance account.
(B) For an owner 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 the
compliance account that the owner
designated in accordance with
paragraph (b)(4)(ii) of this section, an
amount of TR NOX Annual allowances
equal to the amount of the decrease to
the extent such amount was previously
deducted from the compliance account
under paragraph (b)(6) of this section
(and has not already been restored to the
compliance account) for the control
period in the year involved.
(C) Each TR NOX Annual allowance
held and deducted under paragraph
(b)(7)(iii)(A) of this section, or recorded
under paragraph (b)(7)(iii)(B) of this
section, as a result of recalculation of
requirements under the TR NOX Annual
assurance provisions for a control
period in a given year must be a TR NOX
Annual allowance allocated for a
control period in the same or a prior
year.
(c)(1) Identification of TR NOX
Annual allowances by serial number.
The authorized account representative
for each source’s compliance account
designated in accordance with
paragraph (b)(4)(ii) of this section may
request that specific TR NOX Annual
allowances, identified by serial number,
in the compliance account be deducted
in accordance with paragraph (b)(6) or
(7) of this section. In order to be
complete, such request shall be
submitted to the Administrator by the
allowance-holding deadline described
in paragraph (b)(5) of this section and
include, in a format prescribed by the
Administrator, the identification of the
compliance account and the appropriate
serial numbers.
(2) First-in, first-out. The
Administrator will deduct TR NOX
Annual allowances under paragraphs
(b)(6) and (7) of this section from each
source’s compliance account designated
under paragraph (b)(4)(ii) of this section
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
(FIFO) 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
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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) Recordation of deductions. The
Administrator will record in the
appropriate compliance account all
deductions from such an account under
paragraph (b) of this section.
§ 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 § 97.411(c), § 97.423,
§ 97.424, § 97.425, 97.427, 97.428,
97.442, or 97.443.
§ 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.
§ 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
source’s compliance account based on
the information in a submission, as
adjusted under paragraph (a)(1) of this
section, and record such deductions and
transfers.
§ 97.429
[Reserved]
§ 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 § 97.402
and in § 72.2 of this chapter shall apply,
the terms ‘‘affected unit,’’ ‘‘designated
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45385
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
§ 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 § 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 §§ 75.71 and 75.72 of this chapter);
(2) Successfully complete all
certification tests required under
§ 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, whichever
occurs first, after the date on which the
unit commences commercial operation;
(3) For 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
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controls is completed after the
applicable deadline under paragraph
(b)(1) or (2) of this section, by 90 unit
operating days or 180 calendar days,
whichever occurs first, after the date on
which emissions first exit to the
atmosphere through the new stack or
flue or add-on NOX emissions controls;
(4) Notwithstanding the dates in
paragraphs (b)(1) and (2) of this section,
for the owner or operator of a unit for
which a TR opt-in application is
submitted and not withdrawn and is not
yet approved or disapproved, by the
date specified in § 97.441(c); and
(5) Notwithstanding the dates in
paragraphs (b)(1) and (2) of this section,
for the owner or operator of a TR NOX
Annual opt-in unit, by the date on
which the TR NOX Annual opt-in unit
enters the TR NOX Annual Trading
Program as provided in § 97.441(h).
(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 § 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 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 § 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 emissions to the atmosphere
without accounting for all such
emissions in accordance with the
applicable provisions of this subpart
and part 75 of this chapter.
(3) No owner or operator of a 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 emissions
discharged into the atmosphere or heat
input, except for periods of
recertification or periods when
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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 § 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 § 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
§ 75.4(d) of this chapter concerning
units in long-term cold storage.
§ 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
§ 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
§ 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 § 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 § 75.17(a) or
(b) of this chapter for apportioning the
NOX emission rate measured in a
common stack or a petition under
§ 75.66 of this chapter for an alternative
to a requirement in § 75.12 or § 75.17 of
this chapter, the designated
representative shall resubmit the
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petition to the Administrator under
§ 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 § 97.430(a)(1). The
owner or operator of a unit that qualifies
to use the low mass emissions excepted
monitoring methodology under § 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 § 97.430(a)(1)
(including the automated data
acquisition and handling system)
successfully completes all of the initial
certification testing required under
§ 75.20 of this chapter by the applicable
deadline in § 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 § 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 § 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 qualityassurance and quality-control
requirements of § 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
§ 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 § 75.20(b) of this
chapter. Examples of changes to a
continuous emission monitoring system
that require recertification include
replacement of the analyzer, complete
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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
§ 97.430(a)(1) are subject to the
recertification requirements in
§ 75.20(g)(6) of this chapter.
(3) Approval process for initial
certification and recertification. For
initial certification of a continuous
monitoring system under § 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 §§ 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 § 97.433.
(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 § 75.63 of this chapter.
(iii) Provisional certification date. The
provisional certification date for a
monitoring system shall be determined
in accordance with § 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
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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. The 120-day
review period specified in paragraph
(d)(3) of this section shall not begin
before receipt of a complete certification
application.
(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 § 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
§ 97.432(b).
(v) Procedures for loss of certification.
If the Administrator issues a notice of
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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
§ 75.20(a)(4)(iii), § 75.20(g)(7), or
§ 75.21(e) of this chapter and continuing
until the applicable date and hour
specified under § 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 § 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 § 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
§ 75.19 of this chapter shall meet the
applicable certification and
recertification requirements in
§§ 75.19(a)(2) and 75.20(h) of this
chapter. If the owner or operator of such
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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 § 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 § 75.20(f) of this chapter.
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§ 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
§ 97.431 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 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 § 97.431 for each
disapproved monitoring system.
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§ 97.433 Notifications concerning
monitoring.
The designated representative of a TR
NOX Annual unit shall submit written
notice to the Administrator in
accordance with § 75.61 of this chapter.
§ 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 § 75.73 of this
chapter, and the requirements of
§ 97.414(a).
(b) Monitoring plans. The owner or
operator of a TR NOX Annual unit shall
comply with requirements of § 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 § 97.431, including
the information required under § 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;
(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 § 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;
(iii) Notwithstanding paragraphs
(d)(1)(i) and (ii) of this section, for a unit
for which a TR opt-in application is
submitted and not withdrawn and is not
yet approved or disapproved, the
calendar quarter corresponding to the
date specified in § 97.441(c); and
(iv) Notwithstanding paragraphs
(d)(1)(i) and (ii) of this section, for a TR
NOX Annual opt-in unit, the calendar
quarter corresponding to the date on
which the TR NOX Annual opt-in unit
enters the TR NOX Annual Trading
Program as provided in § 97.441(h).
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(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
§ 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
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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 § 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.
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§ 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 § 75.66 of this chapter to
the Administrator, requesting approval
to apply an alternative to any
requirement of §§ 97.430 through 97.434
or paragraph (5)(i) or (ii) of the
definition of ‘‘owner’s share’’ in
§ 97.402.
(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.
§ 97.440 General requirements for TR NOX
Annual opt-in units.
(a) A TR NOX Annual opt-in unit
must be a unit that:
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(1) Is located in a State;
(2) Is not a TR NOX Annual unit
under § 97.404;
(3) Is not covered by a retired unit
exemption under § 72.8 of this chapter
that is in effect; and
(4) Vents all of its emissions to a stack
and can meet the monitoring,
recordkeeping, and reporting
requirements of this subpart.
(b) A TR NOX Annual opt-in unit
shall be deemed to be a TR NOX Annual
unit for purposes of applying this
subpart, except for §§ 97.405, 97.411,
and 97.412.
(c) Solely for purposes of applying the
requirements of §§ 97.413 through
97.418 and §§ 97.430 through 97.435, a
unit for which a TR opt-in application
is submitted and not withdrawn and is
not yet approved or disapproved under
§ 97.442 shall be deemed to be a TR
NOX Annual unit.
(d) Any TR NOX Annual opt-in unit,
and any unit for which a TR opt-in
application is submitted and not
withdrawn and is not yet approved or
disapproved under § 97.442, located at
the same source as one or more TR NOX
Annual units shall have the same
designated representative and alternate
designated representative as such TR
NOX Annual units.
§ 97.441
Opt-In process.
A unit meeting the requirements for a
TR NOX Annual opt-in unit in
§ 97.440(a) may become a TR NOX
Annual opt-in unit only if, in
accordance with this section, the
designated representative of the unit
submits a complete TR opt-in
application for the unit and the
Administrator approves the application.
(a) Applying to opt in. The designated
representative of the unit may submit a
complete TR opt-in application for the
unit at any time, except as provided
under § 97.442(e). A complete TR opt-in
application shall include the following
elements in a format prescribed by the
Administrator:
(1) Identification of the unit and the
source where the unit is located,
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, and unit identification
number and type;
(2) A certification that the unit:
(i) Is not a TR NOX Annual unit under
§ 97.404;
(ii) Is not covered by a retired unit
exemption under § 72.8 of this chapter
that is in effect;
(iii) Vents all of its emissions to a
stack; and
(iv) Has documented heat input
(greater than 0 mmBtu) for more than
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876 hours during the 6 months
immediately preceding submission of
the TR opt-in application;
(3) A monitoring plan in accordance
with §§ 97.430 through 97.435;
(4) A statement that the unit, if
approved to become a TR NOX Annual
unit under paragraph (g) of this section,
may withdraw from the TR NOX Annual
Trading Program only in accordance
with § 97.442;
(5) A statement that the unit, if
approved to become a TR NOX Annual
unit under paragraph (g) of this section,
is subject to, and the owners and
operators of the unit must comply with,
the requirements of § 97.443;
(6) A complete certificate of
representation under § 97.416 consistent
with § 97.440, if no designated
representative has been previously
designated for the source that includes
the unit; and
(7) The signature of the designated
representative and the date signed.
(b) Interim review of monitoring plan.
The Administrator will determine, on
an interim basis, the sufficiency of the
monitoring plan submitted under
paragraph (a)(3) of this section. The
monitoring plan is sufficient, for
purposes of interim review, if the plan
appears to contain information
demonstrating that the NOX emission
rate and heat input of the unit and all
other applicable parameters are
monitored and reported in accordance
with §§ 97.430 through 97.435. A
determination of sufficiency shall not be
construed as acceptance or approval of
the monitoring plan.
(c) Monitoring and reporting. (1)(i) If
the Administrator determines that the
monitoring plan is sufficient under
paragraph (b) of this section, the owner
or operator of the unit shall monitor and
report the NOX emission rate and the
heat input of the unit and all other
applicable parameters, in accordance
with §§ 97.430 through 97.435, starting
on the date of certification of the
necessary monitoring systems under
§§ 97.430 through 97.435 and
continuing until the TR opt-in
application submitted under paragraph
(a) of this section is disapproved under
this section or, if such TR opt-in
application is approved, the date and
time when the unit is withdrawn from
the TR NOX Annual Trading Program in
accordance with § 97.442.
(ii) The monitoring and reporting
under paragraph (c)(1)(i) of this section
shall cover the entire control period
immediately before the date on which
the unit enters the TR NOX Annual
Trading Program under paragraph (h) of
this section, during which period
monitoring system availability must not
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be less than 98 percent under §§ 97.430
through 97.435 and the unit must be in
full compliance with any applicable
State or Federal emissions or emissionsrelated requirements.
(2) To the extent the NOX emission
rate and the heat input of the unit are
monitored and reported in accordance
with §§ 97.430 through 97.435 for one or
more entire control periods, in addition
to the control period under paragraph
(c)(1)(ii) of this section, during which
control periods monitoring system
availability is not less than 98 percent
under §§ 97.430 through 97.435 and the
unit is in full compliance with any
applicable State or Federal emissions or
emissions-related requirements and
which control periods begin not more
than 3 years before the unit enters the
TR NOX Annual Trading Program under
paragraph (h) of this section, such
information shall be used as provided in
paragraphs (e) and (f) of this section.
(d) Statement on compliance. After
submitting to the Administrator all
quarterly reports required for the unit
under paragraph (c) of this section, the
designated representative shall submit,
in a format prescribed by the
Administrator, to the Administrator a
statement that, for the years covered by
such quarterly reports, the unit was in
full compliance with any applicable
State or Federal emissions or emissionsrelated requirements.
(e) Baseline heat input. The unit’s
baseline heat input shall equal:
(1) If the unit’s NOX emission rate and
heat input are monitored and reported
for only one entire control period, in
accordance with paragraph (c) of this
section, the unit’s total heat input (in
mmBtu) for such control period; or
(2) If the unit’s NOX emission rate and
heat input are monitored and reported
for more than one entire control period,
in accordance with paragraph (c) of this
section, the average of the amounts of
the unit’s total heat input (in mmBtu)
for such control periods.
(f) Baseline NOX emission rate. The
unit’s baseline NOX emission rate shall
equal:
(1) If the unit’s NOX emission rate and
heat input are monitored and reported
for only one entire control period, in
accordance with paragraph (c) of this
section, the unit’s NOX emission rate (in
lb/mmBtu) for such control period;
(2) If the unit’s NOX emission rate and
heat input are monitored and reported
for more than one entire control period,
in accordance with paragraph (c) of this
section, and the unit does not have addon NOX emission controls during any
such control periods, the average of the
amounts of the unit’s NOX emission rate
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(in lb/mmBtu) for such control periods;
or
(3) If the unit’s NOX emission rate and
heat input are monitored and reported
for more than one entire control period,
in accordance with paragraph (c) of this
section, and the unit has add-on NOX
emission controls during any such
control periods, the average of the
amounts of the unit’s NOX emission rate
(in lb/mmBtu) for such control periods
during which the unit has add-on NOX
emission controls.
(g) Review of TR opt-in application.
(1) After the designated representative
submits the complete TR opt-in
application, quarterly reports, and
statement required in paragraphs (a), (c),
and (d) of this section and if the
Administrator determines that the
designated representative shows that the
unit meets the requirements for a TR
NOX Annual opt-in unit in § 97.440, the
element certified in paragraph (a)(2)(iv)
of this section, and the monitoring and
reporting requirements of paragraph (c)
of this section, the Administrator will
issue a written approval of the TR optin application for the unit. The written
approval will state the unit’s baseline
heat input and baseline NOX emission
rate. The Administrator will thereafter
establish a compliance account for the
source that includes the unit unless the
source already has a compliance
account.
(2) Notwithstanding paragraphs (a)
through (f) of this section, if, at any time
before the TR opt-in application is
approved under paragraph (g)(1) of this
section, the Administrator determines
that the unit cannot meet the
requirements for a TR NOX Annual optin unit in § 97.440, the element certified
in paragraph (a)(2)(iv) of this section, or
the monitoring and reporting
requirements in paragraph (c) of this
section, the Administrator will issue a
written disapproval of the TR opt-in
application for the unit.
(h) Date of entry into TR NOX Annual
Trading Program. A unit for which a TR
opt-in application is approved under
paragraph (g)(1) of this section shall
become a TR NOX Annual opt-in unit,
and a TR NOX Annual unit, effective as
of the later of January 1, 2012 or January
1 of the first control period during
which such approval is issued.
§ 97.442 Withdrawal of TR NOX Annual
opt-in unit from TR NOX Annual Trading
Program.
A TR NOX Annual opt-in unit may
withdraw from the TR NOX Annual
Trading Program only if, in accordance
with this section, the designated
representative of the unit submits a
request to withdraw the unit and the
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Administrator issues a written approval
of the request.
(a) Requesting withdrawal. In order to
withdraw the TR NOX Annual opt-in
unit from the TR NOX Annual Trading
Program, the designated representative
of the unit shall submit to the
Administrator a request to withdraw the
unit effective as of midnight of
December 31 of a specified calendar
year, which date must be at least 4 years
after December 31 of the year of the
unit’s entry into the TR NOX Annual
Trading Program under § 97.441(h). The
request shall be in a format prescribed
by the Administrator and shall be
submitted no later than 90 days before
the requested effective date of
withdrawal.
(b) Conditions for withdrawal. Before
a TR NOX Annual opt-in unit covered
by the request to withdraw may
withdraw from the TR NOX Annual
Trading Program, the following
conditions must be met:
(1) For the control period ending on
the date on which the withdrawal is to
be effective, the source that includes the
TR NOX Annual opt-in unit must meet
the requirement to hold TR NOX Annual
allowances under §§ 97.424 and 97.425
and cannot have any excess emissions.
(2) After the requirement under
paragraph (b)(1) of this section is met,
the Administrator will deduct from the
compliance account of the source that
includes the TR NOX Annual opt-in unit
TR NOX Annual allowances equal in
amount to and allocated for the same or
a prior control period as any TR NOX
Annual allowances allocated to the TR
NOX Annual opt-in unit under § 97.444
for any control period after the date on
which the withdrawal is to be effective.
If there are no other TR NOX Annual
units at the source, the Administrator
will close the compliance account, and
the owners and operators of the TR NOX
Annual opt-in unit may submit a TR
NOX Annual allowance transfer for any
remaining TR NOX Annual allowances
to another Allowance Management
System account in accordance with
§§ 97.422 and 97.423.
(c) Approving withdrawal. (1) After
the requirements for withdrawal under
paragraphs (a) and (b) of this section are
met (including deduction of the full
amount of TR NOX Annual allowances
required), the Administrator will issue a
written approval of the request to
withdraw, which will become effective
as of midnight on December 31 of the
calendar year for which the withdrawal
was requested. The unit covered by the
request shall continue to be a TR NOX
Annual opt-in unit until the effective
date of the withdrawal and shall comply
with all requirements under the TR NOX
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Annual Trading Program concerning
any control periods for which the unit
is a TR NOX Annual opt-in unit, even
if such requirements arise or must be
complied with after the withdrawal
takes effect.
(2) If the requirements for withdrawal
under paragraphs (a) and (b) of this
section are not met, the Administrator
will issue a written disapproval of the
request to withdraw. The unit covered
by the request shall continue to be a TR
NOX Annual opt-in unit.
(d) Reapplication upon failure to meet
conditions of withdrawal. If the
Administrator disapproves the request
to withdraw, the designated
representative of the unit may submit
another request to withdraw in
accordance with paragraphs (a) and (b)
of this section.
(e) Ability to reapply to the TR NOX
Annual Trading Program. Once a TR
NOX Annual opt-in unit withdraws from
the TR NOX Annual Trading Program,
the designated representative may not
submit another opt-in application under
§ 97.441 for such unit before the date
that is 4 years after the date on which
the withdrawal became effective.
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§ 97.443
Change in regulatory status.
(a) Notification. If a TR NOX Annual
opt-in unit becomes a TR NOX Annual
unit under § 97.404, then the designated
representative of the unit shall notify
the Administrator in writing of such
change in the TR NOX Annual opt-in
unit’s regulatory status, within 30 days
of such change.
(b) Administrator’s actions. (1) If a TR
NOX Annual opt-in unit becomes a TR
NOX Annual unit under § 97.404, the
Administrator will deduct, from the
compliance account of the source that
includes the TR NOX Annual opt-in unit
that becomes a TR NOX Annual unit
under § 97.404, TR NOX Annual
allowances equal in amount to and
allocated for the same or a prior control
period as:
(i) Any TR NOX Annual allowances
allocated to the TR NOX Annual opt-in
unit under § 97.444 for any control
period starting after the date on which
the TR NOX Annual opt-in unit becomes
a TR NOX Annual unit under § 97.404;
and
(ii) If the date on which the TR NOX
Annual opt-in unit becomes a TR NOX
Annual unit under § 97.404 is not
December 31, the TR NOX Annual
allowances allocated to the TR NOX
Annual opt-in unit under § 97.444 for
the control period that includes the date
on which the TR NOX Annual opt-in
unit becomes a TR NOX Annual unit
under § 97.404—
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(A) Multiplied by the ratio of the
number of days, in the control period,
starting with the date on which the TR
NOX Annual opt-in unit becomes a TR
NOX Annual unit under § 97.404,
divided by the total number of days in
the control period, and
(B) Rounded to the nearest allowance.
(2) The designated representative
shall ensure that the compliance
account of the source that includes the
TR NOX Annual opt-in unit that
becomes a TR NOX Annual unit under
§ 97.404 contains the TR NOX Annual
allowances necessary for completion of
the deduction under paragraph (b)(1) of
this section.
(3)(i) For control periods starting after
the date on which the TR NOX Annual
opt-in unit becomes a TR NOX Annual
unit under § 97.404, the TR NOX Annual
opt-in unit will be allocated TR NOX
Annual allowances in accordance with
§ 97.412.
(ii) If the date on which the TR NOX
Annual opt-in unit becomes a TR NOX
Annual unit under § 97.404 is not
December 31, the following amount of
TR NOX Annual allowances will be
allocated to the TR NOX Annual opt-in
unit (as a TR NOX Annual unit) in
accordance with § 97.412 for the control
period that includes the date on which
the TR NOX Annual opt-in unit becomes
a TR NOX Annual unit under § 97.404:
(A) The amount of TR NOX Annual
allowances otherwise allocated to the
TR NOX Annual opt-in unit (as a TR
NOX Annual unit) in accordance with
§ 97.412 for the control period;
(B) Multiplied by the ratio of the
number of days, in the control period,
starting with the date on which the TR
NOX Annual opt-in unit becomes a TR
NOX Annual unit under § 97.404,
divided by the total number of days in
the control period; and (C) Rounded to
the nearest allowance.
§ 97.444 TR NOX Annual allowance
allocations to TR NOX Annual opt-in units.
(a) Timing requirements. (1) When the
TR opt-in application is approved for a
unit under § 97.441(g), the
Administrator will issue TR NOX
Annual allowances and allocate them to
the unit for the control period in which
the unit enters the TR NOX Annual
Trading Program under § 97.441(h), in
accordance with paragraph (b) of this
section.
(2) By no later than October 31 of the
control period after the control period in
which a TR NOX Annual opt-in unit
enters the TR NOX Annual Trading
Program under § 97.441(h) and October
31 of each year thereafter, the
Administrator will issue TR NOX
Annual allowances and allocate them to
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the TR NOX Annual opt-in unit for the
control period that includes such
allocation deadline and in which the
unit is a TR NOX Annual opt-in unit, in
accordance with paragraph (b) of this
section.
(b) Calculation of allocation. For each
control period for which a TR NOX
Annual opt-in unit is to be allocated TR
NOX Annual allowances, the
Administrator will issue and allocate TR
NOX Annual allowances in accordance
with the following procedures:
(1) The heat input (in mmBtu) used
for calculating the TR NOX Annual
allowance allocation will be the lesser
of:
(i) The TR NOX Annual opt-in unit’s
baseline heat input determined under
§ 97.441(g); or
(ii) The TR NOX Annual opt-in unit’s
heat input, as determined in accordance
with §§ 97.430 through 97.435, for the
immediately prior control period,
except when the allocation is being
calculated for the control period in
which the TR NOX Annual opt-in unit
enters the TR NOX Annual Trading
Program under § 97.441(h).
(2) The NOX emission rate (in lb/
mmBtu) used for calculating TR NOX
Annual allowance allocations will be
the lesser of:
(i) The TR NOX Annual opt-in unit’s
baseline NOX emission rate (in lb/
mmBtu) determined under § 97.441(g)
and multiplied by 70 percent; or
(ii) The most stringent State or
Federal NOX emissions limitation
applicable to the TR NOX Annual optin unit at any time during the control
period for which TR NOX Annual
allowances are to be allocated.
(3) The Administrator will issue TR
NOX Annual allowances and allocate
them to the TR NOX Annual opt-in unit
in an amount equaling the heat input
under paragraph (b)(1) of this section,
multiplied by the NOX emission rate
under paragraph (b)(2) of this section,
divided by 2,000 lb/ton, and rounded to
the nearest allowance.
(c) Recordation. (1) The Administrator
will record, in the compliance account
of the source that includes the TR NOX
Annual opt-in unit, the TR NOX Annual
allowances allocated to the TR NOX
Annual opt-in unit under paragraph
(a)(1) of this section.
(2) By December 1 of the control
period after the control period in which
a TR NOX Annual opt-in unit enters the
TR NOX Annual Trading Program under
§ 97.441(h) and December 1 of each year
thereafter, the Administrator will
record, in the compliance account of the
source that includes the TR NOX
Annual opt-in unit, the TR NOX Annual
allowances allocated to the TR NOX
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Annual opt-in unit under paragraph
(a)(2) of this section.
36. Part 97 is amended by adding
subpart BBBBB to read as follows:
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Subpart BBBBB—TR NOX Ozone Season
Trading Program
Sec.
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, and
variability limits.
97.511 Timing requirements for TR NOX
Ozone Season allowance allocations.
97.512 TR NOX Ozone Season allowance
allocations for 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 Allowance
Management System 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.
97.540 General requirements for TR NOX
Ozone Season opt-in units.
97.541 Opt-in process.
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97.542 Withdrawal of TR NOX Ozone
Season opt-in unit from TR NOX Ozone
Season Trading Program.
97.543 Change in regulatory status.
97.544 TR NOX Ozone Season allowance
allocations to TR NOX Ozone Season optin units.
Subpart BBBBB—TR NOX Ozone
Season Trading Program
§ 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 § 52.37(b) of this
chapter, as a means of mitigating
interstate transport of fine particulates
and nitrogen oxides.
§ 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 multistate 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) 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 of the amount of such TR
NOX Ozone Season allowances to be
initially credited to a TR NOX Ozone
Season source or a new unit set-aside.
Allowable NOX emission rate means,
with regard to a unit, the NOX emission
rate limit 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, held,
deducted, or transferred only as whole
allowances. The Allowance
Management System is a component of
the CAMD Business System, which is
the system used by the Administrator to
handle TR NOX Ozone Season
allowances and data related to NOX
emissions.
Allowance Management System
account means an account in the
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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, 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
§ 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 § 72.2 of this chapter,
§ 97.402, § 97.602, or § 97.702
respectively.
Authorized account representative
means, with regard to 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, with regard to 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;
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(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.
Certifying official means a natural
person who is:
(1) For a corporation, a president,
secretary, treasurer, or vice-president or
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 any solid fuel classified as
anthracite, bituminous, subbituminous,
or lignite.
Coal-derived fuel means any fuel
(whether in a solid, liquid, or gaseous
state) produced by the mechanical,
thermal, or chemical processing of coal.
Coal-fired means combusting any
amount of coal or coal-derived fuel,
alone or in combination with any
amount of any other fuel, during 1990
or any year thereafter.
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
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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—
(1) Operating as part of a cogeneration
system; and
(2) Producing during the later of 1990
or the 12-month period starting on the
date that the unit first produces
electricity and during each calendar
year after the later of 1990 or the
calendar year in which the unit first
produces electricity—
(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 then 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 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
(4) Provided that, if a topping-cycle
unit is operated as part of a cogeneration
system during a calendar year and the
cogeneration system meets on a systemwide basis the requirement in paragraph
(2)(i)(B) of this definition, the toppingcycle unit shall be deemed to meet such
requirement during that 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 § 97.505.
(i) For a unit that is a TR NOX Ozone
Season unit under § 97.504 on the later
of November 15, 1990 or the date the
unit commences commercial operation
as defined in the introductory text of
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paragraph (1) of this definition and that
subsequently undergoes a physical
change (other than replacement of the
unit by a unit at the same 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 § 97.504 on the later
of November 15, 1990 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 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 § 97.505, for a unit that is not a TR
NOX Ozone Season unit under § 97.504
on the later of November 15, 1990 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 § 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
and that subsequently undergoes a
physical change (other than replacement
of the unit by a unit at the same 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 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.
Commence operation means, with
regard to a unit:
(1) To have begun any mechanical,
chemical, or electronic process,
including start-up of the unit’s
combustion chamber.
(2) For a unit that undergoes a
physical change (other than replacement
of the unit by a unit at the same source)
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after the date the unit commences
operation as defined in paragraph (1) of
this definition, such date shall remain
the date of commencement of operation
of the unit, which shall continue to be
treated as the same unit.
(3) For a unit that is replaced by a unit
at the same source after the date the unit
commences operation as defined in
paragraph (1) of this definition, such
date shall remain the replaced unit’s
date of commencement of operation,
and the replacement unit shall be
treated as a separate unit with a separate
date for commencement of operation as
defined in paragraph (1), (2), or (3) of
this definition as appropriate.
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 for 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 complying
with the source’s TR NOX Ozone Season
emissions limitation in accordance with
§ 97.524 and the TR NOX Ozone Season
assurance provisions in accordance with
§ 97.525.
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 §§ 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 NOXdiluent) monitoring system, consisting
of a NOX pollutant concentration
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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 § 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 § 97.506(c)(3), and
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
§ 72.2 of this chapter, § 97.402, § 97.602,
or § 97.702 respectively.
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 in
accordance with this subpart.
Excess emissions means any ton of
NOX emitted from the TR NOX Ozone
Season units at a TR NOX Ozone Season
source during a control period that
exceeds the TR NOX Ozone Season
emissions limitation for the source.
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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
§§ 97.504(b)(2)(i)(B), 97.504(b)(2)(ii)(B),
and 97.504(b)(2)(iii), 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 1990 or any calendar year
thereafter.
Fuel oil means any petroleum-based
fuel (including diesel fuel or petroleum
derivatives such as oil tar) and any
recycled or blended petroleum products
or petroleum by-products used as a fuel
whether in a liquid, solid, or gaseous
state.
General account means an Allowance
Management System account,
established under this subpart, that is
not a compliance account.
Generator means a device that
produces electricity.
Gross electrical output means, with
regard to 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, with regard to a
unit for a specified period of time, the
product (in mmBtu/time) of the gross
calorific value of the fuel (in mmBtu/lb)
multiplied by the fuel feed rate into a
combustion device (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 the amount of
heat input (in mmBtu) divided by unit
operating time (in hr) or, with regard to
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.
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;
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(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
the maximum amount of fuel per hour
(in Btu/hr) that a 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) 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
(in MWe) 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 as of such completion as
specified by the person conducting the
physical change.
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 any person who
operates, controls, or supervises a TR
NOX Ozone Season unit or a TR NOX
Ozone Season source and shall include,
but not be limited to, any holding
company, utility system, or plant
manager of such a unit or source.
Owner means, with regard to 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
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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;
(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;
(4) Provided that, for purposes of
applying the TR NOX Ozone Season
assurance provisions in §§ 97.506(c)(2)
and 97.525, if one or more owners (as
defined in paragraphs (1) through (3) of
this definition) of one or more TR NOX
Ozone Season units in a State are
wholly owned by another, common
owner, all such owners shall be treated
collectively as a single owner in the
State.
Owner’s assurance level means:
(1) With regard to a State and control
period for which the State assurance
level is exceeded as described in
§ 97.506(c)(2)(iii)(A) and not as
described in § 97.506(c)(2)(iii)(B), the
owner’s share of the State NOX Ozone
Season trading budget with the one-year
variability limit for the State for such
control period; or
(2) With regard to a State and control
period for which the State assurance
level is exceeded as described in
§ 97.506(c)(2)(iii)(B), the owner’s share
of the State NOX Ozone Season trading
budget with the three-year variability
limit for the State for such control
period.
Owner’s share means:
(1) With regard to a total amount of
NOX emissions from all TR NOX Ozone
Season units in a State during a control
period, the total tonnage of NOX
emissions during such control period
from all of the owner’s TR NOX Ozone
Season units in the State;
(2) With regard to a State NOX Ozone
Season trading budget with a one-year
variability limit for a control period, the
amount (rounded to the nearest
allowance) equal to the total amount of
TR NOX Ozone Season allowances
allocated for such control period to all
of the owner’s TR NOX Ozone Season
units in the State, multiplied by the sum
of the State NOX Ozone Season trading
budget under § 97.510(a) and the State’s
one-year variability limit under
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45395
§ 97.510(b) and divided by such State
NOX Ozone Season trading budget;
(3) With regard to a State NOX Ozone
Season trading budget with a three-year
variability limit for a control period, the
amount (rounded to the nearest
allowance) equal to the total amount of
TR NOX Ozone Season allowances
allocated for such control period to all
of the owner’s TR NOX Ozone Season
units in the State, multiplied by the sum
of the State NOX Ozone Season trading
budget under § 97.510(a) and the State’s
three-year variability limit under
§ 97.510(b) and divided by such State
NOX Ozone Season trading budget;
(4) Provided that, in the case of a unit
with more than one owner, the amount
of tonnage of NOX emissions and of TR
NOX Ozone Season allowances allocated
for a control period, with regard to such
unit, used in determining each owner’s
share shall be the amount (rounded to
the nearest ton and the nearest
allowance) equal to the unit’s NOX
emissions and allocation of such
allowances, respectively, for such
control period multiplied by the
percentage of ownership in the unit that
the owner’s legal, equitable, leasehold,
or contractual reservation or entitlement
in the unit comprises as of September
30 of such control period;
(5) Provided that, where two or more
units emit through a common stack that
is the monitoring location from which
NOX mass emissions are reported for a
control period for a year, the amount of
tonnage of each unit’s NOX emissions
used in determining each owner’s share
for such control period shall be:
(i) The amount (rounded to the
nearest ton) of NOX emissions reported
at the common stack multiplied by the
quotient of such unit’s heat input for
such control period divided by the total
heat input reported from the common
stack for such control period;
(ii) An amount determined in
accordance with a methodology that the
Administrator determines is consistent
with the purposes of this definition and
whose adverse effect (if any) the
Administrator determines will be de
minimis; or
(iii) An amount approved by the
Administrator in response to a petition
for an alternative requirement submitted
in accordance with § 97.535; and
(6) Provided that, in the case of a unit
that operates during, but is allocated no
TR NOX Ozone Season allowances for,
a 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 lesser
of—
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(i) The unit’s allowable NOX emission
rate (in lb per MWe) applicable to such
control period, multiplied by a capacity
factor of 0.89 (if the unit is a coal-fired
boiler), 0.22 (if the unit is a simple
combustion turbine), or 0.72 (if the unit
is a combined cycle turbine), 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; or
(ii) For a unit listed in appendix A to
this subpart, the sum of the unit’s NOX
emissions in the control period in the
last three years during which the unit
operated during the control period,
divided by three.
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
§§ 70.2 and 71.2 of this chapter.
Potential electrical output capacity
means 33 percent of a 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,
transfer, or deduction.
Reference method means any direct
test method of sampling and analyzing
for an air pollutant as specified in
§ 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) For a topping-cycle unit, the use
of reject heat from electricity production
in a useful thermal energy application
or process; or
(2) For a bottoming-cycle unit, the use
of reject heat from useful thermal energy
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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 or the
District of Columbia that is subject to
the TR NOX Ozone Season Trading
Program pursuant to § 52.37(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 total energy
of all forms supplied to a 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.
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Total energy output means 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 by the Administrator in
accordance with subpart AAAAA of this
part and 52.37(a) 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 by the Administrator
under this subpart to emit one ton of
NOX during a control period of the
specified calendar year for which the
authorization is allocated or of any
calendar year thereafter under the TR
NOX Ozone Season 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
assurance provisions.
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
by the TR NOX Ozone Season
allowances available for deduction for
the source under § 97.524(a) for such
control period.
TR NOX Ozone Season Trading
Program means a multi-state NOX air
pollution control and emission
reduction program established by the
Administrator in accordance with this
subpart and 52.37(b) of this chapter, as
a means of mitigating interstate
transport of ozone and NOX.
TR NOX Ozone Season source means
a source that includes one or more TR
NOX Ozone Season units.
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TR NOX Ozone Season unit means a
unit that is subject to the TR NOX Ozone
Season Trading Program under § 97.504.
TR SO2 Group 1 Trading Program
means a multi-state SO2 air pollution
control and emission reduction program
established by the Administrator in
accordance with subpart CCCCC of this
part and 52.38(b) 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 by the Administrator in
accordance with subpart DDDDD of this
part and 52.38(c) of this chapter, as a
means of mitigating interstate transport
of fine particulates and SO2.
Unit means a stationary, fossil-fuelfired boiler, stationary, fossil-fuel-fired
combustion turbine, or other stationary,
fossil-fuel-fired combustion device.
Unit operating day means a calendar
day in which a unit combusts any fuel.
Unit operating hour or hour of unit
operation means an hour in which a
unit combusts any fuel.
Useful power means electricity or
mechanical energy that a 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.
§ 97.503 Measurements, abbreviations,
and acronyms.
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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
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MWh—megawatt hour
NOX—nitrogen oxides
O2—oxygen
ppm—parts per million
scfh—standard cubic feet per hour
SO2—sulfur dioxide
yr—year
§ 97.504
Applicability.
(a) Except as provided in paragraph
(b) of this section:
(1) The following units in a 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-fuelfired boiler or stationary, fossil-fuelfired combustion turbine serving at any
time, since the later of November 15,
1990 or the start-up of the unit’s
combustion chamber, 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 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), (b)(2)(i), or (b)(2)(ii)
of this section shall not be a TR NOX
Ozone Season unit:
(1)(i) Any unit:
(A) Qualifying as a cogeneration unit
during the later of 1990 or the 12-month
period starting on the date the unit first
produces electricity and continuing to
qualify as a cogeneration unit; and
(B) Not serving at any time, since the
later of November 15, 1990 or the startup of the unit’s combustion chamber, a
generator with nameplate capacity of
more than 25 MWe supplying in any
calendar year 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 a unit qualifies as a cogeneration
unit during the later of 1990 or the 12month period starting on the date the
unit first produces electricity and meets
the requirements of paragraphs (b)(1)(i)
of this section for at least one calendar
year, but subsequently no longer meets
such qualification and requirements, the
unit shall become a TR NOX Ozone
Season unit starting on the earlier of
January 1 after the first calendar year
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45397
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.
(2)(i) Any unit commencing operation
before January 1, 1985:
(A) Qualifying as a solid waste
incineration unit during the later of
1990 or the 12-month period starting on
the date the unit first produces
electricity and continuing to qualify as
a solid waste incineration unit; and
(B) With an average Ozone Season
fuel consumption of fossil fuel for 1985–
1987 less than 20 percent (on a Btu
basis) and an average Ozone Season fuel
consumption of fossil fuel for any 3
consecutive calendar years after 1990
less than 20 percent (on a Btu basis).
(ii) Any unit commencing operation
on or after January 1, 1985:
(A) Qualifying as a solid waste
incineration unit during the later of
1990 or the 12-month period starting on
the date the unit first produces
electricity and continuing to qualify as
a solid waste incineration unit; and
(B) With an average Ozone Season
fuel consumption of fossil fuel for the
first 3 calendar years of operation less
than 20 percent (on a Btu basis) and an
average Ozone Season fuel consumption
of fossil fuel for any 3 consecutive
calendar years after 1990 less than 20
percent (on a Btu basis).
(iii) If a unit qualifies as a solid waste
incineration unit during the later of
1990 or the 12-month period starting on
the date the unit first produces
electricity and meets the requirements
of paragraph (b)(2)(i) or (ii) of this
section for at least 3 consecutive
calendar years, but subsequently no
longer meets such qualification and
requirements, 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
1990 for which the unit has an average
Ozone Season fuel consumption of
fossil fuel of 20 percent or more.
(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, 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
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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
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.
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§ 97.505
Retired unit exemption.
(a)(1) Any TR NOX Ozone Season unit
that is permanently retired and is not a
TR NOX Ozone Season opt-in unit shall
be exempt from § 97.506(b) and (c)(1),
§ 97.524, and §§ 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.
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(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.
§ 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
§§ 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 §§ 97.530 through
97.535.
(2) The emissions data determined in
accordance with §§ 97.530 through
97.535 shall be used to calculate
allocations of TR NOX Ozone Season
allowances under §§ 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
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Sfmt 4702
§§ 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,
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 § 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 a TR NOX Ozone Season source
emits NOX during any control period 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 § 97.524(d) and pay
any fine, penalty, or assessment or
comply with any other remedy imposed,
for the same violations, under the Clean
Air Act; and
(B) 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 the total amount of
NOX emissions from all TR NOX Ozone
Season units in a State during a control
period in 2014 or any year thereafter
exceeds the State assurance level as
described in paragraph (c)(2)(iii) of this
section, then each owner whose share of
such NOX emissions during such
control period exceeds the owner’s
assurance level for the State and such
control period shall hold, in a
compliance account designated by the
owner in accordance with
§ 97.525(b)(4)(ii), TR NOX Ozone Season
allowances available for deduction for
such control period under § 97.525(a) in
an amount equal to the product, as
determined by the Administrator in
accordance with § 97.525(b), of
multiplying—
(A) The quotient (rounded to the
nearest whole number) of the amount by
which the owner’s share of such NOX
emissions exceeds the owner’s
assurance level divided by the sum of
the amounts, determined for all such
owners, by which each owner’s share of
such NOX emissions exceeds that
owner’s assurance level; and
(B) The amount by which total NOX
emissions for all TR NOX Ozone Season
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units in the State for such control period
exceed the State assurance level as
determined in accordance with
paragraph (c)(2)(iii) of this section.
(ii) The owner shall hold the TR NOX
Ozone Season allowances required
under paragraph (c)(2)(i) of this section,
as of midnight of August 1 (if it is a
business day), or midnight of the first
business day thereafter (if August 1 is
not a business day), immediately after
such control period.
(iii) The total amount of NOX
emissions from all TR NOX Ozone
Season units in a State during a control
period in 2014 or any year thereafter
exceeds the State assurance level:
(A) If such total amount of NOX
emissions exceeds the sum, for such
control period, of the State NOX Ozone
Season trading budget and the State’s
one-year variability limit under
§ 97.510(b); or
(B) If, with regard to a control period
in 2016 or any year thereafter, the sum,
divided by three, of such total amount
of NOX emissions and the total amounts
of NOX emissions from all TR NOX
Ozone Season units in the State during
the control periods in the immediately
preceding two years exceeds the sum,
for such control period, of the State NOX
Ozone Season trading budget and the
State’s three-year variability limit under
§ 97.510(b);
(C) Provided that the amount by
which such total amount of NOX
emissions exceeds the State assurance
level shall be the greater of the amounts
of the exceedance calculated under
paragraph (c)(2)(iii)(A) of this section
and under paragraph (c)(2)(iii)(B) of this
section.
(iv) It shall not be a violation of this
subpart or of the Clean Air Act if the
total amount of NOX emissions from all
TR NOX Ozone Season units in a State
during a control period exceeds the
State assurance level or if an owner’s
share of total NOX emissions from the
TR NOX Ozone Season units in a State
during a control period exceeds the
owner’s assurance level.
(v) To the extent an owner fails to
hold TR NOX Ozone Season allowances
for a control period in accordance with
paragraphs (c)(2)(i) and (ii) of this
section,
(A) The owner 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 owner fails to hold
for a control period in accordance with
paragraphs (c)(2)(i) and (ii) of this
section and each day of such control
period shall constitute a separate
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15:19 Jul 30, 2010
Jkt 220001
violation of this subpart and the Clean
Air Act.
(3) Compliance periods. A TR NOX
Ozone Season unit shall be subject to
the requirements:
(i) Under paragraph (c)(1) of this
section for the control period starting on
the later of September 1, 2012 or the
deadline for meeting the unit’s monitor
certification requirements under
§ 97.530(b) and for each control period
thereafter; and
(ii) Under paragraph (c)(2) of this
section for the control period starting on
the later of September 1, 2014 or the
deadline for meeting the unit’s monitor
certification requirements under
§ 97.530(b) and for each control period
thereafter.
(4) Vintage of deducted allowances. A
TR NOX Ozone Season allowance shall
not be deducted, for compliance with
the requirements under paragraphs
(c)(1) and (2) of this section, for a
control period in a calendar year before
the year for which the TR NOX Ozone
Season allowance was allocated.
(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. (i) A TR
NOX Ozone Season allowance is a
limited authorization to emit one ton of
NOX in accordance with the TR NOX
Ozone Season Trading Program.
(ii) Notwithstanding any other
provision of this subpart, the
Administrator has the authority to
terminate or limit 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 § 75.19 of this
chapter), or an alternative monitoring
system (under subpart E of part 75 of
this chapter) in accordance with
§§ 97.530 through 97.535 may be added
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Sfmt 4702
45399
to, or changed in, a title V permit using
minor permit modification procedures
in accordance with §§ 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 §§ 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 § 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 documents are superseded
because of the submission of a new
certificate of representation under
§ 97.516 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 Ozone
Season Trading Program, including any
monitoring plans and monitoring
system certification and recertification
applications.
(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, including any
submissions required for compliance
with the TR NOX Ozone Season
assurance provisions. This requirement
does not change, create an exemption
from, or or otherwise affect the
responsible official submission
requirements under a title V operating
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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
§ 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.
NOX Ozone Season Trading Program,
falls on a weekend or a State or Federal
holiday, the time period shall be
extended to the next business day.
§ 97.507
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.
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
§ 97.508 Administrative appeal
procedures.
§ 97.509
[Reserved]
§ 97.510 State NOX Ozone Season trading
budgets, new-unit set-asides, and variability
limits.
(a) The State NOX Ozone Season
trading budgets and 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 trading budget
(tons)*
For 2012 and
thereafter
State
New-unit set-aside
(tons)
For 2012 and
thereafter
Alabama .......................................................................................................................................................
Arkansas ......................................................................................................................................................
Connecticut ..................................................................................................................................................
Delaware ......................................................................................................................................................
District of Columbia .....................................................................................................................................
Florida ..........................................................................................................................................................
Georgia ........................................................................................................................................................
Illinois ...........................................................................................................................................................
Indiana .........................................................................................................................................................
Kansas .........................................................................................................................................................
Kentucky ......................................................................................................................................................
Louisiana ......................................................................................................................................................
Maryland ......................................................................................................................................................
Michigan .......................................................................................................................................................
Mississippi ....................................................................................................................................................
New Jersey ..................................................................................................................................................
New York .....................................................................................................................................................
North Carolina ..............................................................................................................................................
Ohio .............................................................................................................................................................
Oklahoma .....................................................................................................................................................
Pennsylvania ................................................................................................................................................
South Carolina .............................................................................................................................................
Tennessee ...................................................................................................................................................
Texas ...........................................................................................................................................................
Virginia .........................................................................................................................................................
West Virginia ................................................................................................................................................
29,738
16,660
1,315
2,450
105
56,939
32,144
23,570
49,987
21,433
30,908
21,220
7,232
28,253
16,530
5,269
11,090
23,539
40,661
37,087
48,271
15,222
11,575
75,574
12,608
22,234
892
500
39
74
3
1,708
964
707
1,500
643
927
637
217
848
496
158
333
706
1,220
1,113
1,448
457
347
2,267
378
667
Total ......................................................................................................................................................
641,614
19,249
erowe on DSK5CLS3C1PROD with PROPOSALS2
* Without variability limits.
(b) The States’ one-year and three-year
variability limits for the State NOX
Ozone Season trading budgets for the
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Jkt 220001
control periods in 2014 and thereafter
are as follows:
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45401
One-year variability limits
Three-year variability limits
2014 and thereafter
(tons)
2016 and thereafter
(tons)
State
Alabama .......................................................................................................................................................
Arkansas ......................................................................................................................................................
Connecticut ..................................................................................................................................................
Delaware ......................................................................................................................................................
District of Columbia .....................................................................................................................................
Florida ..........................................................................................................................................................
Georgia ........................................................................................................................................................
Illinois ...........................................................................................................................................................
Indiana .........................................................................................................................................................
Kansas .........................................................................................................................................................
Kentucky ......................................................................................................................................................
Louisiana ......................................................................................................................................................
Maryland ......................................................................................................................................................
Michigan .......................................................................................................................................................
Mississippi ....................................................................................................................................................
New Jersey ..................................................................................................................................................
New York .....................................................................................................................................................
North Carolina ..............................................................................................................................................
Ohio .............................................................................................................................................................
Oklahoma .....................................................................................................................................................
Pennsylvania ................................................................................................................................................
South Carolina .............................................................................................................................................
Tennessee ...................................................................................................................................................
Texas ...........................................................................................................................................................
Virginia .........................................................................................................................................................
West Virginia ................................................................................................................................................
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§ 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 set forth in appendix A to
this subpart. Listing a unit in such
appendix does not constitute a
determination that the unit is a TR NOX
Ozone Season unit, and not listing a
unit in such appendix 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 listed in
appendix A to this subpart as being
allocated TR NOX Ozone Season
allowances does not operate, starting
after 2011, during the control period in
three consecutive years, such unit will
not be allocated the TR NOX Ozone
Season allowances set forth in appendix
A to this subpart for the unit for the
control periods in the seventh year after
the first such year and in each year after
that seventh 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 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) By April 1, 2012
and April 1 of each year thereafter, the
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Administrator will calculate the TR
NOX Ozone Season allowance allocation
for each TR NOX Ozone Season unit, in
accordance with § 97.512, for the
control period in the year of the
applicable calculation deadline under
this paragraph and will promulgate a
notice of availability of the results of the
calculations.
(2) For each notice of data availability
required in paragraph (b)(1) of this
section, the Administrator will provide
an opportunity for submission of
objections to the calculations referenced
in such notice.
(i) Objections shall be submitted by
the deadline specified in such notice
and shall be limited to addressing
whether the calculations are in
accordance with § 97.512 and
§§ 97.506(b)(2) and 97.530 through
97.535.
(ii) 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)(i) of this section. By June 1
immediately after the promulgation of
such notice, the Administrator will
promulgate a notice of 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)(i) of this section.
(c) Units that are not TR NOX Ozone
Season units. For each control period in
PO 00000
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Fmt 4701
Sfmt 4702
2,974
2,100
2,100
2,100
2,100
5,694
3,214
2,357
4,999
2,143
3,091
2,122
2,100
2,825
2,100
2,100
2,100
2,354
4,066
3,709
4,827
2,100
2,100
7,557
2,100
2,223
1,717
1,212
1,212
1,212
1,212
3,287
1,856
1,361
2,886
1,237
1,784
1,225
1,212
1,631
1,212
1,212
1,212
1,359
2,348
2,141
2,787
1,212
1,212
4,363
1,212
1,284
2012 and thereafter, if the Administrator
determines that TR NOX Ozone Season
allowances were allocated under
paragraph (a) of this section for the
control period to a recipient that is not
actually a TR NOX Ozone Season unit
under § 97.504 as of May 1, 2012 or
whose deadline for meeting monitor
certification requirements under
§ 97.530(b)(1) and (2) is after May 1,
2012 or if the Administrator determines
that TR NOX Ozone Season allowances
were allocated under paragraph (b) of
this section and § 97.512 for the control
period to a recipient that is not actually
a TR NOX Ozone Season unit under
§ 97.504 as of May 1 of the control
period, then the Administrator will
notify the designated representative and
will act in accordance with the
following procedures:
(1) Except as provided in paragraph
(c)(2) or (3) of this section, the
Administrator will not record such TR
NOX Ozone Season allowances under
§ 97.521.
(2) If the Administrator already
recorded such TR NOX Ozone Season
allowances under § 97.521 and if the
Administrator makes such
determination before making deductions
for the source that includes such
recipient under § 97.524(b) for such
control period, then the Administrator
will deduct from the account in which
such TR NOX Ozone Season allowances
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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.
(3) If the Administrator already
recorded such TR NOX Ozone Season
allowances under § 97.521 and if the
Administrator makes such
determination after making deductions
for the source that includes such
recipient under § 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.
(4) The Administrator will transfer the
TR NOX Ozone Season allowances that
are not recorded, or that are deducted,
in accordance with paragraphs (c)(1)
and (2) of this section to the new unit
set-aside, for the State in which such
recipient is located, for the control
period in the year of such transfer if the
notice required in paragraph (b)(1) of
this section for the control period in that
year has not been promulgated or, if
such notice has been promulgated, in
the next year.
erowe on DSK5CLS3C1PROD with PROPOSALS2
§ 97.512 TR NOX Ozone Season allowance
allocations for new units.
(a) For each control period in 2012
and thereafter, the Administrator will
allocate, in accordance with the
following procedures, TR NOX Ozone
Season allowances to TR NOX Ozone
Season units in a State that are not
listed in appendix A to this subpart, to
TR NOX Ozone Season units that are so
listed and whose allocation of NOX
Ozone Season allowances for such
control period is covered by
§ 97.511(c)(1) or (2), and to TR NOX
Ozone Season units that are so listed
and, pursuant to § 97.511(a)(2), are not
allocated TR NOX Ozone Season
allowances for such control period but
that operate during the immediately
preceding control period:
(1) The Administrator will establish a
separate new unit set-aside for each
State for each control period in a given
year. Each 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 § 97.510(a).
Each new unit set-aside will be
allocated additional TR NOX Ozone
Season allowances in accordance with
§ 97.511(a)(2) and (c)(4).
(2) The designated representative of
such TR NOX Ozone Season unit may
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15:19 Jul 30, 2010
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submit to the Administrator a request,
in a format prescribed by the
Administrator, to be allocated TR NOX
Ozone Season allowances for a control
period, starting with the later of the
control period in 2012, the first control
period after the control period in which
the TR NOX Ozone Season unit
commences commercial operation (for a
unit not listed in appendix A to this
subpart), or the first control period after
the control period in which the unit
resumes operation (for a unit listed in
appendix A of this subpart) and for each
subsequent control period.
(i) The request must be submitted on
or before February 1 immediately
preceding the first control period for
which TR NOX Ozone Season
allowances are sought and after the date
on which the TR NOX Ozone Season
unit commences commercial operation
(for a unit not listed in appendix A of
this subpart) or on which the unit
resumes operation (for a unit listed in
appendix A of this subpart).
(ii) For each control period for which
an allocation is sought, the request must
be for TR NOX Ozone Season
allowances in an amount equal to the
unit’s total tons of NOX emissions
during the immediately preceding
control period.
(3) The Administrator will review
each TR NOX Ozone Season allowance
allocation request under paragraph
(a)(2) of this section and will accept the
request only if it meets the requirements
of paragraph (a)(2) of this section. The
Administrator will allocate TR NOX
Ozone Season allowances for each
control period pursuant to an accepted
request as follows:
(i) After February 1 immediately
preceding such control period, the
Administrator will determine the sum of
the TR NOX Ozone Season allowances
requested in all accepted allowance
allocation requests for such control
period.
(ii) If the amount of TR NOX Ozone
Season allowances in the new unit setaside for such control period is greater
than or equal to the sum under
paragraph (a)(3)(i) of this section, then
the Administrator will allocate the
amount of TR NOX Ozone Season
allowances requested to each TR NOX
Ozone Season unit covered by an
accepted allowance allocation request.
(iii) If the amount of TR NOX Ozone
Season allowances in the new unit setaside for such control period is less than
the sum under paragraph (a)(3)(i) of this
section, then the Administrator will
allocate to each TR NOX Ozone Season
unit covered by an accepted allowance
allocation request the amount of the TR
NOX Ozone Season allowances
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Fmt 4701
Sfmt 4702
requested, multiplied by the amount of
TR NOX Ozone Season allowances in
the new unit set-aside for such control
period, divided by the sum determined
under paragraph (a)(3)(i) of this section,
and rounded to the nearest allowance.
(iv) The Administrator will notify,
through the promulgation of the notices
of data availability described in
§ 97.511(b), each designated
representative that submitted an
allowance allocation request of the
amount of TR NOX Ozone Season
allowances (if any) allocated for such
control period to the TR NOX Ozone
Season unit covered by the request.
(b) If, after completion of the
procedures under paragraph (a)(4) of
this section for a control period, any
unallocated TR NOX Ozone Season
allowances remain in the new unit setaside under paragraph (a) of this section
for a State for such control period, the
Administrator will allocate to each TR
NOX Ozone Season unit that is in the
State, is listed in appendix A to this
subpart, and continues to be allocated
TR NOX Ozone Season allowances for
such control period in accordance with
§ 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 setaside, multiplied by the unit’s allocation
under § 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 amount of tons in such new
unit set-aside, and rounded to the
nearest allowance.
§ 97.513 Authorization of designated
representative and alternate designated
representative.
(a) Except as provided under § 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 § 97.516(a)(4)(iii).
(2) Upon and after receipt by the
Administrator of a complete certificate
of representation under § 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
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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 § 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
§ 97.516(a)(4)(iii).
(2) Upon and after receipt by the
Administrator of a complete certificate
of representation under § 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, § 97.502,
and §§ 97.514 through 97.518, whenever
the term ‘‘designated representative’’ is
used in this subpart, the term shall be
construed to include the designated
representative or any alternate
designated representative.
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§ 97.514 Responsibilities of designated
representative and alternate designated
representative.
(a) Except as provided under § 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
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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
submission has been made, signed, and
certified in accordance with paragraph
(a) of this section and § 97.518.
§ 97.515 Changing designated
representative and alternate designated
representative; changes in owners and
operators.
(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 § 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 § 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,
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45403
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 is not included
in the list of owners and operators in the
certificate of representation under
§ 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, including the
addition of a new owner or operator, the
designated representative or any
alternate designated representative shall
submit a revision to the certificate of
representation under § 97.516 amending
the list of owners and operators to
include the change.
§ 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, and actual or
projected date of commencement of
commercial operation.
(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—
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(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
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.
(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.
§ 97.517 Objections concerning
designated representative and alternate
designated representative.
(a) Once a complete certificate of
representation under § 97.516 has been
submitted and received, the
Administrator will rely on the certificate
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of representation unless and until a
superseding complete certificate of
representation under § 97.516 is
received by the Administrator.
(b) Except as provided in § 97.515(a)
or (b), 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.
§ 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
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 as an
‘‘agent’’);
(3) For each such natural person, a list
of the type or types of electronic
submissions under paragraph (a) or (b)
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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.
§ 97.519
[Reserved]
§ 97.520 Establishment of Allowance
Management System accounts.
(a) Compliance accounts. Upon
receipt of a complete certificate of
representation under § 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
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shall be the authorized account
representative and the alternate
authorized account representative
respectively of the compliance account.
(b) 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
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
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representations, actions, inactions, or
submissions and by any order or
decision 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 order or decision issued to the
authorized account representative or
alternate authorized account
representative by the Administrator
regarding the general account.
(ii) Except as provided in paragraph
(b)(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
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45405
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
(b)(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 (b)(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
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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 of a new
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 (b)(1)
of this section has been submitted and
received, the Administrator will rely on
the application unless and until a
superseding complete application for a
general account under paragraph (b)(1)
of this section is received by the
Administrator.
(ii) Except as provided in paragraph
(b)(3)(i) or (ii) 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
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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
make an electronic submission to the
Administrator in accordance with
paragraph (b)(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
as an ‘‘agent’’);
(C) For each such natural person, a
list of the type or types of electronic
submissions under paragraph (b)(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(b)(5)(iv) shall be deemed to be an
electronic submission by me.’’; and
(E) The following certification
statement by such authorized account
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representative or alternate authorized
account representative: ‘‘Until this
notice of delegation is superseded by
another notice of delegation under 40
CFR 97.520(b)(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(b)(5) is terminated.’’.
(iv) A notice of delegation submitted
under paragraph (b)(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
(b)(5)(iii)(D) of this section and made in
accordance with a notice of delegation
effective under paragraph (b)(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)(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
§ 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 20 business days after the
notice is sent. The account will be
closed after the 20-day period unless,
before the end of the 20-day period, the
Administrator receives a correctly
submitted TR NOX Ozone Season
allowance transfer under § 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
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cause as to why the account should not
be closed.
(c) Account identification. The
Administrator will assign a unique
identifying number to each account
established under paragraph (a) or (b) of
this section.
(d) Responsibilities of authorized
account representative and alternate
authorized account representative. After
the establishment of an Allowance
Management System 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 §§ 97.514(a)
and 97.518 or paragraphs (b)(2)(ii) and
(b)(5) of this section.
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§ 97.521 Recordation of TR NOX Ozone
Season allowance allocations.
(a) By September 1, 2011, the
Administrator will record in each TR
NOX Ozone Season source’s compliance
account the TR NOX Ozone Season
allowances allocated for the TR NOX
Ozone Season units at the source in
accordance with §§ 97.511(a) for the
control periods in 2012, 2013, and 2014.
(b) By June 1, 2012 and June 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
for the TR NOX Ozone Season units at
the source in accordance with
§ 97.511(a) for the control period in the
third year after the year of the
applicable recordation deadline under
this paragraph.
(c) By June 1, 2012 and June 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
for the TR NOX Ozone Season units at
the source in accordance with § 97.512
for the control period in the year of the
applicable recordation deadline under
this paragraph.
(d) When recording the allocation of
TR NOX Ozone Season allowances for a
TR NOX Ozone Season unit in a
compliance 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.
§ 97.522 Submission of TR NOX Ozone
Season allowance transfers.
(a) An authorized account
representative seeking recordation of a
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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.
§ 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, 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 by
the request, provided that the transfer is
correctly submitted under § 97.522.
(b)(1) A TR NOX Ozone Season
allowance transfer 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 under § 97.524 for the
control period immediately before such
allowance transfer deadline.
(2) A TR NOX Ozone Season
allowance transfer that is submitted for
recordation after the deadline for
holding TR NOX Ozone Season
allowances described in § 97.525(b)(5)
and that includes any TR NOX Ozone
Season allowances allocated for a
control period before the year of such
deadline will not be recorded until after
the Administrator completes the
deductions under § 97.525 for the
control period immediately before the
year of such deadline.
(c) Where a TR NOX Ozone Season
allowance transfer is not correctly
submitted under § 97.522, the
Administrator will not record such
transfer.
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(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 § 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 nonrecordation.
§ 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 the control
period in the year or 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
§ 97.523, of TR NOX Ozone Season
allowance transfers submitted by the
allowance transfer deadline for a control
period, the Administrator will deduct
from the 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
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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 (FIFO) 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 the control period 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.
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§ 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 an owner of one or more
TR NOX Ozone Season units in a State
only if the TR NOX Ozone Season
allowances:
(1) Were allocated for the control
period in the year or a prior year; and
(2) Are held in a compliance account,
designated by the owner in accordance
with paragraph (b)(4)(ii) of this section,
of one of the owner’s TR NOX Ozone
Season sources in the State as of the
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deadline established in paragraph (b)(5)
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 March 1, 2015 and March 1 of
each year thereafter, the Administrator
will:
(i) Calculate, separately for each State,
the total amount of NOX emissions from
all TR NOX Ozone Season units in the
State during the control period in the
year before the year of this calculation
deadline and the amount, if any, by
which such total amount of NOX
emissions exceeds the State assurance
level as described in § 97.506(c)(2)(iii);
and
(ii) Promulgate a notice of availability
of the results of the calculations
required in paragraph (b)(1)(i) of this
section, including separate calculations
of the NOX emissions for each TR NOX
Ozone Season unit and of the amounts
described in §§ 97.506(c)(2)(iii)(A) and
(B) for each State.
(2) The Administrator will provide an
opportunity for submission of objections
to the calculations referenced by each
notice described in paragraph (b)(1) of
this section.
(i) Objections shall be submitted by
the deadline specified in such notice
and shall be limited to addressing
whether the calculations for each TR
NOX Ozone Season unit and each State
for the control period in the year
involved are in accordance with
§ 97.506(c)(2)(iii) and §§ 97.506(b) and
97.530 through 97.535.
(ii) 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)(i) of this section. By May 1
immediately after the promulgation of
such notice, the Administrator will
promulgate a notice of 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)(i) of this section.
(3) For each notice of data availability
required in paragraph (b)(2)(ii) of this
section and for any State identified in
such notice as having TR NOX Ozone
Season sources with total NOX
emissions exceeding the State assurance
level for a control period, as described
in § 97.506(c)(2)(iii):
(i) By May 15 immediately after the
promulgation of such notice, the
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designated representative of each TR
NOX Ozone Season source in each such
State shall submit a statement, in a
format prescribed by the Administrator:
(A) Listing all the owners of each TR
NOX Ozone Season unit at the source,
explaining how the selection of each
owner for inclusion on the list is
consistent with the definition of
‘‘owner’’ in § 97.502, and listing,
separately for each unit, the percentage
of the legal, equitable, leasehold, or
contractual reservation or entitlement
for each such owner as of midnight of
December 31 of the control period in the
year involved; and
(B) For each TR NOX Ozone Season
unit at the source that operates during,
but is allocated no TR NOX Ozone
Season allowances for, the control
period in the year involved, identifying
whether the unit is a coal-fired boiler,
simple combustion turbine, or
combined cycle turbine cycle and
providing the unit’s allowable NOX
emission rate for such control period.
(ii) By June 15 immediately after the
promulgation of such notice, the
Administrator will calculate, for each
such State and each owner of one or
more TR NOX Ozone Season units in the
State and for the control period in the
year involved, each owner’s share of the
total NOX emissions from all TR NOX
Ozone Season units in the State, each
owner’s assurance level, and the amount
(if any) of TR NOX Ozone Season
allowances that each owner must hold
in accordance with the calculation
formula in § 97.506(c)(2)(i) and will
promulgate a notice of 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)(3)(ii) of this
section.
(A) Objections shall be submitted by
the deadline specified in such notice
and shall be limited to addressing
whether the calculations for each owner
for the control period in the year
involved are consistent with the NOX
emissions for the relevant TR NOX
Ozone Season units as set forth in the
notice required in paragraph (b)(2)(ii) of
this section, the definitions of ‘‘owner’’,
‘‘owner’s assurance level’’, and ‘‘owner’s
share’’ in § 97.502, and the calculation
formula in § 97.506(c)(2)(i) and shall not
raise any issues about any data used in
the notice of data availability required
in paragraph (b)(2)(ii) of this section.
(B) The Administrator will adjust the
calculations to the extent necessary to
ensure that they are consistent with the
data and provisions referenced in
paragraph (b)(3)(iii)(A) of this section.
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By August 15 immediately after the
promulgation of such notice, the
Administrator will promulgate a notice
of 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)(3)(iii)(A)
of this section.
(4) By September 1 immediately after
the promulgation of each notice of data
availability required in paragraph
(b)(3)(iii)(B) of this section:
(i) Each owner identified, in such
notice, as owning one or more TR NOX
Ozone Season units in a State and as
being required to hold TR NOX Ozone
Season allowances shall designate the
compliance account of one of the
sources at which such unit or units are
located to hold such required TR NOX
Ozone Season allowances;
(ii) The authorized account
representative for the compliance
account designated under paragraph
(b)(4)(i) of this section shall submit to
the Administrator a statement, in a
format prescribed by the Administrator,
making this designation.
(5)(i) As of midnight of September 15
immediately after the promulgation of
each notice of data availability required
in paragraph (b)(3)(iii)(B) of this section,
each owner described in paragraph
(b)(4)(i) of this section shall hold in the
compliance account designated by the
owner in accordance with paragraph
(b)(4)(ii) of this section the total amount
of TR NOX Ozone Season allowances,
available for deduction under paragraph
(a) of this section, equal to the amount
the owner is required to hold as
calculated by the Administrator and
referenced in such notice.
(ii) Notwithstanding the allowanceholding deadline specified in paragraph
(b)(5)(i) of this section, if September 15
is not a business day, then such
allowance-holding deadline shall be
midnight of the first business day
thereafter.
(6) After September 15 (or the date
described in paragraph (b)(5)(ii) of this
section) immediately after the
promulgation of each notice of data
availability required in paragraph
(b)(3)(iii)(B) of this section and after the
recordation, in accordance with
§ 97.523, of TR NOX Ozone Season
allowance transfers submitted by
midnight of such date, the
Administrator will deduct from each
compliance account designated in
accordance with paragraph (b)(4)(ii) of
this section, TR NOX Ozone Season
allowances available under paragraph
(a) of this section, as follows:
(i) Until the amount of TR NOX Ozone
Season allowances deducted equals the
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amount that the owner designating the
compliance account is required to hold
as calculated by the Administrator and
referenced in the notice required in
paragraph (b)(3)(iii)(B) of this section; or
(ii) If there are insufficient TR NOX
Ozone Season allowances to complete
the deductions in paragraph (b)(6)(i) of
this section, until no more TR NOX
Ozone Season allowances available
under paragraph (a) of this section
remain in the compliance account.
(7) Notwithstanding any other
provision of this subpart and any
revision, made by or submitted to the
Administrator after the promulgation of
the notices of data availability required
in paragraphs (b)(2)(ii) and (b)(3)(iii)(B)
of this section respectively for a control
period, of any data used in making the
calculations referenced in such notice,
the amount of TR NOX Ozone Season
allowances that each owner is required
to hold in accordance with
§ 97.506(c)(2)(i) for the control period in
the year involved shall continue to be
such amount as calculated by the
Administrator and referenced in such
notice required in paragraph
(b)(3)(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 are required to hold in
accordance with the calculation formula
in § 97.506(c)(2)(i) for the control period
in the year involved with regard to the
State involved, provided that—
(A) With regard to such litigation
involving such notice required in
paragraph (b)(2)(ii) of this section, 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)(ii) of this section; and
(B) With regard to such litigation
involving such notice required in
paragraph (b)(3)(iii) of this section, 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)(3)(iii) of this section.
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45409
(ii) If any such data are revised by the
owners and operators of a source whose
designated representative submitted
such data under paragraph (b)(3)(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 are required to hold in
accordance with the calculation formula
in § 97.506(c)(2)(i) for the control period
in the year involved with regard to the
State involved, provided that such
litigation was initiated no later than 30
days after promulgation of such notice
required in paragraph (b)(3)(iii)(B) of
this section.
(iii) If the revised data are used to
recalculate, in accordance with
paragraphs (b)(7)(i) and (b)(7)(ii) of this
section, the amount of TR NOX Ozone
Season allowances that an owner is
required to hold for the control period
in the year involved with regard to the
State involved(A) Where the amount of TR NOX
Ozone Season allowances that an owner
is 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 owner
shall hold the additional amount of TR
NOX Ozone Season allowances in the
compliance account designated by the
owner in accordance with paragraph
(b)(4)(ii) of this section. The owner’s
failure to hold such additional amount,
as required, before the new deadline
shall not be a violation of the Clean Air
Act. The owner’s 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 owner fails to
hold as required as of the new deadline,
and each day in the control period in
the year involved, shall be a separate
violation of the Clean Air Act. After
such deadline, the Administrator will
make the appropriate deductions from
the compliance account.
(B) For an owner 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 the compliance account
that the owner designated in accordance
with paragraph (b)(4)(ii) of this section,
an amount of TR NOX Ozone Season
allowances equal to the amount of the
decrease to the extent such amount was
previously deducted from the
compliance account under paragraph
(b)(6) of this section (and has not
already been restored to the compliance
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account) for the control period in the
year involved.
(C) Each TR NOX Ozone Season
allowance held and deducted under
paragraph (b)(7)(iii)(A) of this section, or
recorded under paragraph (b)(7)(iii)(B)
of this section, as a result of
recalculation of requirements for
compliance with the TR NOX Ozone
Season assurance provisions for a
control period in a given year must be
a TR NOX Ozone Season allowance
allocated for a control period in the
same or a prior year.
(c)(1) Identification of TR NOX Ozone
Season allowances by serial number.
The authorized account representative
for each source’s compliance account
designated in accordance with
paragraph (b)(4)(ii) of this section may
request that specific TR NOX Ozone
Season allowances, identified by serial
number, in the compliance account be
deducted in accordance with paragraph
(b)(6) or (7) of this section. In order to
be complete, such request shall be
submitted to the Administrator by the
allowance-holding deadline described
in paragraph (b)(5) of this section and
include, in a format prescribed by the
Administrator, the identification of the
compliance account and the appropriate
serial numbers.
(2) First-in, first-out. The
Administrator will deduct TR NOX
Ozone Season allowances under
paragraphs (b)(6) and (7) of this section
from each source’s compliance account
designated under paragraph (b)(4)(ii) of
this section 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 (FIFO)
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) Recordation of deductions. The
Administrator will record in the
appropriate compliance account all
deductions from such an account under
paragraph (b) of this section.
§ 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.
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(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
§ 97.511(c), § 97.523, § 97.524, § 97.525,
97.527, 97.528, 97.542, or 97.543.
§ 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.
§ 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 source’s compliance
account based on the information in a
submission, as adjusted under
paragraph (a)(1) of this section, and
record such deductions and transfers.
§ 97.529
[Reserved]
§ 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
§ 97.502 and in § 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 § 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
§ 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.
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(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 §§ 75.71 and 75.72 of this chapter);
(2) Successfully complete all
certification tests required under
§ 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.
(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. The owner or
operator 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, by 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 § 97.534(d), by the
later of the following dates:
(i) 180 calendar days, whichever
occurs first, 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
§ 97.534(d)(2)(ii), by the later of the
following dates:
(i) 180 calendar days, whichever
occurs first, 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) For the owner or operator of a TR
NOX Ozone Season unit for which
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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 and that
reports on an annual basis under
§ 97.534(d), by 90 unit operating days or
180 calendar days, whichever occurs
first, after the date on which emissions
first exit to the atmosphere through the
new stack or flue or add-on NOX
emissions controls.
(5) For 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) or (3) of this section and that
reports on a control period basis under
§ 97.534(d)(2)(ii), by the later of the
following dates:
(i) 90 unit operating days or 180
calendar days, whichever occurs first,
after the date on which emissions first
exit to the atmosphere through the new
stack or flue or add-on NOX emissions
controls; or
(ii) If the compliance date under
paragraph (b)(5)(i) of this section is not
during a control period, May 1
immediately after the compliance date
under paragraph (b)(5)(i) of this section.
(6) Notwithstanding the dates in
paragraphs (b)(1), (2), and (3) of this
section, for the owner or operator of a
unit for which a TR opt-in application
is submitted and not withdrawn and is
not yet approved or disapproved, by the
date specified in § 97.541(c).
(7) Notwithstanding the dates in
paragraphs (b)(1), (2), and (3) of this
section, for the owner or operator of a
TR NOX Ozone Season opt-in unit, by
the date on which the TR NOX Annual
opt-in unit enters the TR NOX Ozone
Season Trading Program as provided in
§ 97.541(h).
(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 § 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.
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(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 § 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 emissions to the
atmosphere without accounting for all
such emissions in accordance with the
applicable provisions of this subpart
and part 75 of this chapter.
(3) No owner or operator of a 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 emissions
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 § 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 § 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 § 75.4(d) of this chapter
concerning units in long-term cold
storage.
§ 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
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45411
this section for a monitoring system
under § 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
§ 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 § 97.530(a)(1) exempt
from initial certification requirements
under paragraph (a) of this section.
(c) If the Administrator has previously
approved a petition under § 75.17(a) or
(b) of this chapter for apportioning the
NOX emission rate measured in a
common stack or a petition under
§ 75.66 of this chapter for an alternative
to a requirement in § 75.12 or § 75.17 of
this chapter, the designated
representative shall resubmit the
petition to the Administrator under
§ 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
§ 97.530(a)(1). The owner or operator of
a unit that qualifies to use the low mass
emissions excepted monitoring
methodology under § 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 § 97.530(a)(1)
(including the automated data
acquisition and handling system)
successfully completes all of the initial
certification testing required under
§ 75.20 of this chapter by the applicable
deadline in § 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 § 75.20
of this chapter is required.
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(2) Requirements for recertification.
Whenever the owner or operator makes
a replacement, modification, or change
in any certified continuous emission
monitoring system under § 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 qualityassurance and quality-control
requirements of § 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
§ 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 § 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 systems, and any excepted
NOX monitoring system under appendix
E to part 75 of this chapter, under
§ 97.530(a)(1) are subject to the
recertification requirements in
§ 75.20(g)(6) of this chapter.
(3) Approval process for initial
certification and recertification. For
initial certification of a continuous
monitoring system under § 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 §§ 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 § 97.533.
(ii) Certification application. The
designated representative shall submit
to the Administrator a certification
application for each monitoring system.
A complete certification application
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shall include the information specified
in § 75.63 of this chapter.
(iii) Provisional certification date. The
provisional certification date for a
monitoring system shall be determined
in accordance with § 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. The 120-day
review period specified in paragraph
(d)(3) of this section shall not begin
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before receipt of a complete certification
application.
(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 § 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
§ 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
§ 75.20(a)(4)(iii), § 75.20(g)(7), or
§ 75.21(e) of this chapter and continuing
until the applicable date and hour
specified under § 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 § 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
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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 § 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
§ 75.19 of this chapter shall meet the
applicable certification and
recertification requirements in
§§ 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 § 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 § 75.20(f) of this chapter.
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§ 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
§ 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
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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 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 § 97.531 for each
disapproved monitoring system.
45413
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;
(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 § 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
§ 97.533 Notifications concerning
monitoring.
NOX mass emissions) for such unit for
The designated representative of a TR the entire year and report the NOX mass
emissions data and heat input data for
NOX Ozone Season unit shall submit
such unit in accordance with paragraph
written notice to the Administrator in
accordance with § 75.61 of this chapter. (d)(1) of this section; or
(ii) Meet the requirements of subpart
§ 97.534 Recordkeeping and reporting.
H of part 75 for the control period
(a) General provisions. The designated (including the requirements in
representative shall comply with all
§ 75.74(c) of this chapter) and report
recordkeeping and reporting
NOX mass emissions data and heat
requirements in this section, the
input data (including the data described
applicable recordkeeping and reporting
in § 75.74(c)(6) of this chapter) for such
requirements under § 75.73 of this
unit only for the control period of each
chapter, and the requirements of
year and report, in an electronic
§ 97.514(a).
quarterly report in a format prescribed
(b) Monitoring plans. The owner or
by the Administrator, for each calendar
operator of a TR NOX Ozone Season unit quarter beginning with:
shall comply with requirements of
(A) For a unit that commences
§ 75.73(c) and (e) of this chapter.
commercial operation before July 1,
(c) Certification applications. The
2011, the calendar quarter covering May
designated representative shall submit
1, 2012 through June 30, 2012;
an application to the Administrator
(B) For a unit that commences
within 45 days after completing all
commercial operation on or after July 1,
initial certification or recertification
2011, the calendar quarter
tests required under § 97.531, including corresponding to the earlier of the date
the information required under § 75.63
of provisional certification or the
of this chapter.
applicable deadline for initial
(d) Quarterly reports. The designated
certification under § 97.530(b), unless
representative shall submit quarterly
that date is not during a control period,
reports, as follows:
in which case reporting shall commence
(1) If the TR NOX Ozone Season unit
in the quarter that includes May 1
is subject to the Acid Rain Program or
through June 30 of the first control
a TR NOX Annual emissions limitation
period after such date;
or if the owner or operator of such unit
(3) Notwithstanding paragraphs (d)(1)
chooses to report on an annual basis
and (2) of this section, for a unit for
under this subpart, the designated
which a TR opt-in application is
representative shall meet the
submitted and not withdrawn and is not
requirements of subpart H of part 75 of
yet approved or disapproved, the
this chapter (concerning monitoring of
calendar quarter corresponding to the
NOX mass emissions) for such unit for
date specified in § 97.541(c); and
(4) Notwithstanding paragraphs (d)(1)
the entire year and shall report the NOX
mass emissions data and heat input data and (2) of this section, for a TR NOX
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Ozone Season opt-in unit, the calendar
quarter corresponding to the date on
which the TR NOX Annual opt-in unit
enters the TR NOX Ozone Season
Trading Program as provided in
§ 97.541(h).
(5) 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
§ 75.73(f) of this chapter.
(6) 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 1 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.
(7) 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.
(8) 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)(5) of
this section.
(e) Compliance certification. The
designated representative shall submit
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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 § 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.
§ 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 § 75.66 of this chapter
to the Administrator, requesting
approval to apply an alternative to any
requirement of §§ 97.530 through 97.534
or paragraph (5)(i) or (ii) of the
definition of ‘‘owner’s share’’ in
§ 97.502.
(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
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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.
§ 97.540 General requirements for TR NOX
Ozone Season opt-in units.
(a) A TR NOX Ozone Season opt-in
unit must be a unit that:
(1) Is located in a State;
(2) Is not a TR NOX Ozone Season
unit under § 97.504;
(3) Is not covered by a retired unit
exemption under § 72.8 of this chapter
that is in effect; and
(4) Vents all of its emissions to a stack
and can meet the monitoring,
recordkeeping, and reporting
requirements of this subpart.
(b) A TR NOX Ozone Season opt-in
unit shall be deemed to be a TR NOX
Ozone Season unit for purposes of
applying this subpart, except for
§§ 97.505, 97.511, and 97.512.
(c) Solely for purposes of applying the
requirements of §§ 97.513 through
97.518 and §§ 97.530 through 97.535, a
unit for which a TR opt-in application
is submitted and not withdrawn and is
not yet approved or disapproved under
§ 97.542 shall be deemed to be a TR
NOX Ozone Season unit.
(d) Any TR NOX Ozone Season opt-in
unit, and any unit for which a TR optin application is submitted and not
withdrawn and is not yet approved or
disapproved under § 97.542, located at
the same source as one or more TR NOX
Ozone Season units shall have the same
designated representative and alternate
designated representative as such TR
NOX Ozone Season units.
§ 97.541
Opt-in process.
A unit meeting the requirements for a
TR NOX Ozone Season opt-in unit in
§ 97.540(a) may become a TR NOX
Ozone Season opt-in unit only if, in
accordance with this section, the
designated representative of the unit
submits a complete TR opt-in
application for the unit and the
Administrator approves the application.
(a) Applying to opt-in. The designated
representative of the unit may submit a
complete TR opt-in application for the
unit at any time, except as provided
under § 97.542(e). A complete TR opt-in
application shall include the following
elements in a format prescribed by the
Administrator:
(1) Identification of the unit and the
source where the unit is located,
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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, and unit identification
number and type;
(2) A certification that the unit:
(i) Is not a TR NOX Ozone Season unit
under § 97.504;
(ii) Is not covered by a retired unit
exemption under § 72.8 of this chapter
that is in effect;
(iii) Vents all of its emissions to a
stack; and
(iv) Has documented heat input
(greater than 0 mmBtu) for more than
876 hours during the 6 months
immediately preceding submission of
the TR opt-in application;
(3) A monitoring plan in accordance
with §§ 97.530 through 97.535;
(4) A statement that the unit, if
approved to become a TR NOX Ozone
Season unit under paragraph (g) of this
section, may withdraw from the TR NOX
Ozone Season Trading Program only in
accordance with § 97.542;
(5) A statement that the unit, if
approved to become a TR NOX Ozone
Season unit under paragraph (g) of this
section, is subject to, and the owners
and operators of the unit must comply
with, the requirements of § 97.543;
(6) A complete certificate of
representation under § 97.516 consistent
with § 97.540, if no designated
representative has been previously
designated for the source that includes
the unit; and
(7) The signature of the designated
representative and the date signed.
(b) Interim review of monitoring plan.
The Administrator will determine, on
an interim basis, the sufficiency of the
monitoring plan submitted under
paragraph (a)(3) of this section. The
monitoring plan is sufficient, for
purposes of interim review, if the plan
appears to contain information
demonstrating that the NOX emission
rate and heat input of the unit and all
other applicable parameters are
monitored and reported in accordance
with §§ 97.530 through 97.535. A
determination of sufficiency shall not be
construed as acceptance or approval of
the monitoring plan.
(c) Monitoring and reporting. (1)(i) If
the Administrator determines that the
monitoring plan is sufficient under
paragraph (b) of this section, the owner
or operator of the unit shall monitor and
report the NOX emission rate and the
heat input of the unit and all other
applicable parameters, in accordance
with §§ 97.530 through 97.535, starting
on the date of certification of the
necessary monitoring systems under
§§ 97.530 through 97.535 and
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continuing until the TR opt-in
application submitted under paragraph
(a) of this section is disapproved under
this section or, if such TR opt-in
application is approved, the date and
time when the unit is withdrawn from
the TR NOX Ozone Season Trading
Program in accordance with § 97.542.
(ii) The monitoring and reporting
under paragraph (c)(1)(i) of this section
shall cover the entire control period
immediately before the date on which
the unit enters the TR NOX Ozone
Season Trading Program under
paragraph (h) of this section, during
which period monitoring system
availability must not be less than 98
percent under §§ 97.530 through 97.535
and the unit must be in full compliance
with any applicable State or Federal
emissions or emissions-related
requirements.
(2) To the extent the NOX emissions
rate and the heat input of the unit are
monitored and reported in accordance
with §§ 97.530 through 97.535 for one or
more entire control periods, in addition
to the control period under paragraph
(c)(1)(ii) of this section, during which
control periods monitoring system
availability is not less than 98 percent
under §§ 97.530 through 97.535 and the
unit is in full compliance with any
applicable State or Federal emissions or
emissions-related requirements and
which control periods begin not more
than 3 years before the unit enters the
TR NOX Ozone Season Trading Program
under paragraph (h) of this section, such
information shall be used as provided in
paragraphs (e) and (f) of this section.
(d) Statement on compliance. After
submitting to the Administrator all
quarterly reports required for the unit
under paragraph (c) of this section, the
designated representative shall submit,
in a format prescribed by the
Administrator, to the Administrator a
statement that, for the years covered by
such quarterly reports, the unit was in
full compliance with any applicable
State or Federal emissions or emissionsrelated requirements.
(e) Baseline heat input. The unit’s
baseline heat input shall equal:
(1) If the unit’s NOX emissions rate
and heat input are monitored and
reported for only one entire control
period, in accordance with paragraph (c)
of this section, the unit’s total heat input
(in mmBtu) for such control period; or
(2) If the unit’s NOX emission rate and
heat input are monitored and reported
for more than one entire control period,
in accordance with paragraph (c) of this
section, the average of the amounts of
the unit’s total heat input (in mmBtu)
for such control periods.
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(f) Baseline NOX emission rate. The
unit’s baseline NOX emission rate shall
equal:
(1) If the unit’s NOX emission rate and
heat input are monitored and reported
for only one entire control period, in
accordance with paragraph (c) of this
section, the unit’s NOX emission rate (in
lb/mmBtu) for such control period;
(2) If the unit’s NOX emission rate and
heat input are monitored and reported
for more than one entire control period,
in accordance with paragraph (c) of this
section, and the unit does not have addon NOX emission controls during any
such control periods, the average of the
amounts of the unit’s NOX emission rate
(in lb/mmBtu) for such control periods;
or
(3) If the unit’s NOX emission rate and
heat input are monitored and reported
for more than one entire control period,
in accordance with paragraph (c) of this
section, and the unit has add-on NOX
emission controls during any such
control periods, the average of the
amounts of the unit’s NOX emission rate
(in lb/mmBtu) for such control periods
during which the unit has add-on NOX
emission controls.
(g) Review of TR opt-in application.
(1) After the designated representative
submits the complete TR opt-in
application, quarterly reports, and
statement required in paragraphs (a), (c),
and (d) of this section and if the
Administrator determines that the
designated representative shows that the
unit meets the requirements for a TR
NOX Ozone Season opt-in unit in
§ 97.540, the element certified in
paragraph (a)(2)(iv) of this section, and
the monitoring and reporting
requirements of paragraph (c) of this
section, the Administrator will issue a
written approval of the TR opt-in
application for the unit. The written
approve will state the unit’s baseline
heat input and baseline NOX emission
rate. The Administrator will thereafter
establish a compliance account for the
source that includes the unit unless the
source already has a compliance
account.
(2) Notwithstanding paragraphs (a)
through (f) of this section, if, at any time
before the TR opt-in application is
approved under paragraph (g)(1) of this
section, the Administrator determines
that the unit cannot meet the
requirements for a TR NOX Ozone
Season opt-in unit in § 97.540, the
element certified in paragraph (a)(2)(iv)
of this section, or the monitoring and
reporting requirements in paragraph (c)
of this section, the Administrator will
issue a written disapproval of the TR
opt-in application for the unit.
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(h) Date of entry into TR NOX Ozone
Season Trading Program. A unit for
which a TR opt-in application is
approved under paragraph (g)(1) of this
section shall become a TR NOX Ozone
Season opt-in unit, and a TR NOX
Ozone Season unit, effective as of the
later of May 1, 2012 or May 1 of the first
control period during which such
approval is issued.
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§ 97.542 Withdrawal of TR NOX Ozone
Season opt-in unit from TR NOX Ozone
Season Trading Program.
A TR NOX Ozone Season opt-in unit
may withdraw from the TR NOX Ozone
Season Trading Program only if, in
accordance with this section, the
designated representative of the unit
submits a request to withdraw the unit
and the Administrator issues a written
approval of the request.
(a) Requesting withdrawal. In order to
withdraw the TR NOX Ozone Season
opt-in unit from the TR NOX Ozone
Season Trading Program, the designated
representative of the unit shall submit to
the Administrator a request to withdraw
the unit effective as of midnight of
September 30 of a specified calendar
year, which date must be at least 4 years
after September 30 of the year of the
unit’s entry into the TR NOX Ozone
Season Trading Program under
§ 97.541(h). The request shall be in a
format prescribed by the Administrator
and shall be submitted no later than 90
days before the requested effective date
of withdrawal.
(b) Conditions for withdrawal. Before
a TR NOX Ozone Season opt-in unit
covered by the request to withdraw may
withdraw from the TR NOX Ozone
Season Trading Program, the following
conditions must be met:
(1) For the control period ending on
the date on which the withdrawal is to
be effective, the source that includes the
TR NOX Ozone Season opt-in unit must
meet the requirement to hold TR NOX
Ozone Season allowances under
§§ 97.524 and 97.525 and cannot have
any excess emissions.
(2) After the requirement under
paragraph (b)(1) of this section is met,
the Administrator will deduct from the
compliance account of the source that
includes the TR NOX Ozone Season optin unit TR NOX Ozone Season
allowances equal in amount to and
allocated for the same or a prior control
period as any TR NOX Ozone Season
allowances allocated to the TR NOX
Ozone Season opt-in unit under
§ 97.544 for any control period after the
date on which the withdrawal is to be
effective. If there are no other TR NOX
Ozone Season units at the source, the
Administrator will close the compliance
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account, and the owners and operators
of the TR NOX Ozone Season opt-in unit
may submit a TR NOX Ozone Season
allowance transfer for any remaining TR
NOX Ozone Season allowances to
another Allowance Management System
account in accordance §§ 97.522 and
97.523.
(c) Approving withdrawal. (1) After
the requirements for withdrawal under
paragraphs (a) and (b) of this section are
met (including deduction of the full
amount of TR NOX Ozone Season
allowances required), the Administrator
will issue a written approval of the
request to withdraw, which will become
effective as of midnight on September
30 of the calendar year for which the
withdrawal was requested. The unit
covered by the request shall continue to
be a TR NOX Ozone Season opt-in unit
until the effective date of the
withdrawal and shall comply with all
requirements under the TR NOX Ozone
Season Trading Program concerning any
control periods for which the unit is a
TR NOX Ozone Season opt-in unit, even
if such requirements arise or must be
complied with after the withdrawal
takes effect.
(2) If the requirements for withdrawal
under paragraphs (a) and (b) of this
section are not met, the Administrator
will issue a written disapproval of the
request to withdraw. The unit covered
by the request shall continue to be a TR
NOX Ozone Season opt-in unit.
(d) Reapplication upon failure to meet
conditions of withdrawal. If the
Administrator disapproves the request
to withdraw, the designated
representative of the unit may submit
another request to withdraw in
accordance with paragraphs (a) and (b)
of this section.
(e) Ability to reapply to the TR NOX
Ozone Season Trading Program. Once a
TR NOX Ozone Season opt-in unit
withdraws from the TR NOX Ozone
Season Trading Program, the designated
representative may not submit another
opt-in application under § 97.541 for
such unit before the date that is 4 years
after the date on which the withdrawal
became effective.
§ 97.543
Change in regulatory status.
(a) Notification. If a TR NOX Ozone
Season opt-in unit becomes a TR NOX
Ozone Season unit under § 97.504, then
the designated representative of the unit
shall notify the Administrator in writing
of such change in the TR NOX Ozone
Season opt-in unit’s regulatory status,
within 30 days of such change.
(b) Administrator’s actions. (1) If a TR
NOX Ozone Season opt-in unit becomes
a TR NOX Ozone Season unit under
§ 97.504, the Administrator will deduct,
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from the compliance account of the
source that includes the TR NOX Ozone
Season opt-in unit that becomes a TR
NOX Ozone Season unit under § 97.504,
TR NOX Ozone Season allowances equal
in amount to and allocated for the same
or a prior control period as:
(i) Any TR NOX Ozone Season
allowances allocated to the TR NOX
Ozone Season opt-in unit under
§ 97.544 for any control period starting
after the date on which the TR NOX
Ozone Season opt-in unit becomes a TR
NOX Ozone Season unit under § 97.504;
and
(ii) If the date on which the TR NOX
Ozone Season opt-in unit becomes a TR
NOX Ozone Season unit under § 97.504
is not September 30, the TR NOX Ozone
Season allowances allocated to the TR
NOX Ozone Season opt-in unit under
§ 97.544 for the control period that
includes the date on which the TR NOX
Ozone Season opt-in unit becomes a TR
NOX Ozone Season unit under
§ 97.504—
(A) Multiplied by the ratio of the
number of days, in the control period,
starting with the date on which the TR
NOX Ozone Season opt-in unit becomes
a TR NOX Ozone Season unit under
§ 97.504, divided by the total number of
days in the control period, and
(B) Rounded to the nearest allowance.
(2) The designated representative
shall ensure that the compliance
account of the source that includes the
TR NOX Ozone Season opt-in unit that
becomes a TR NOX Ozone Season unit
under § 97.504 contains the TR NOX
Ozone Season allowances necessary for
completion of the deduction under
paragraph (b)(1) of this section.
(3)(i) For control periods starting after
the date on which the TR NOX Ozone
Season opt-in unit becomes a TR NOX
Ozone Season unit under § 97.504, the
TR NOX Ozone Season opt-in unit will
be allocated TR NOX Ozone Season
allowances in accordance with § 97.512.
(ii) If the date on which the TR NOX
Ozone Season opt-in unit becomes a TR
NOX Ozone Season unit under § 97.504
is not September 30, the following
amount of TR NOX Ozone Season
allowances will be allocated to the TR
NOX Ozone Season opt-in unit (as a TR
NOX Ozone Season unit) in accordance
with § 97.512 for the control period that
includes the date on which the TR NOX
Ozone Season opt-in unit becomes a TR
NOX Ozone Season unit under § 97.504:
(A) The amount of TR NOX Ozone
Season allowances otherwise allocated
to the TR NOX Ozone Season opt-in unit
(as a TR NOX Ozone Season unit) in
accordance with § 97.512 for the control
period;
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(B) Multiplied by the ratio of the
number of days, in the control period,
starting with the date on which the TR
NOX Ozone Season opt-in unit becomes
a TR NOX Ozone Season unit under
§ 97.504, divided by the total number of
days in the control period; and
(C) Rounded to the nearest allowance.
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§ 97.544 TR NOX Ozone Season allowance
allocations to TR NOX Ozone Season opt-in
units.
(a) Timing requirements. (1) When the
TR opt-in application is approved for a
unit under § 97.541(g), the
Administrator will issue TR NOX Ozone
Season allowances and allocate them to
the unit for the control period in which
the unit enters the TR NOX Ozone
Season Trading Program under
§ 97.541(h), in accordance with
paragraph (b) of this section.
(2) By no later than July 30 of the
control period after the control period in
which a TR NOX Ozone Season opt-in
unit enters the TR NOX Ozone Season
Trading Program under § 97.541(h) and
July 30 of each year thereafter, the
Administrator will issue TR NOX Ozone
Season allowances and allocate them to
the TR NOX Ozone Season opt-in unit
for the control period that includes such
allocation deadline and in which the
unit is a TR NOX Ozone Season opt-in
unit, in accordance with paragraph (b)
of this section.
(b) Calculation of allocation. For each
control period for which a TR NOX
Ozone Season opt-in unit is to be
allocated TR NOX Ozone Season
allowances, the Administrator will issue
and allocate TR NOX Ozone Season
allowances in accordance with the
following procedures:
(1) The heat input (in mmBtu) used
for calculating the TR NOX Ozone
Season allowance allocation will be the
lesser of:
(i) The TR NOX Ozone Season opt-in
unit’s baseline heat input determined
under § 97.541(g); or
(ii) The TR NOX Ozone Season opt-in
unit’s heat input, as determined in
accordance with §§ 97.530 through
97.535, for the immediately prior
control period, except when the
allocation is being calculated for the
control period in which the TR NOX
Ozone Season opt-in unit enters the TR
NOX Ozone Season Trading Program
under § 97.541(h).
(2) The NOX emission rate (in lb/
mmBtu) used for calculating TR NOX
Ozone Season allowance allocations
will be the lesser of:
(i) The TR NOX Ozone Season opt-in
unit’s baseline NOX emission rate (in lb/
mmBtu) determined under § 97.541(g)
and multiplied by 70 percent; or
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(ii) The most stringent State or
Federal NOX emissions limitation
applicable to the TR NOX Ozone Season
opt-in unit at any time during the
control period for which TR NOX Ozone
Season allowances are to be allocated.
(3) The Administrator will issue TR
NOX Ozone Season allowances and
allocate them to the TR NOX Ozone
Season opt-in unit in an amount
equaling the heat input under paragraph
(b)(1) of this section, multiplied by the
NOX emission rate under paragraph
(b)(2) of this section, divided by 2,000
lb/ton, and rounded to the nearest
allowance.
(c) Recordation. (1) The Administrator
will record, in the compliance account
of the source that includes the TR NOX
Ozone Season opt-in unit, the TR NOX
Ozone Season allowances allocated to
the TR NOX Ozone Season opt-in unit
under paragraph (a)(1) of this section.
(2) By September 1 of the control
period after the control period in which
a TR NOX Ozone Season opt-in unit
enters the TR NOX Ozone Season
Trading Program under § 97.541(h) and
September 1 of each year thereafter, the
Administrator will record, in the
compliance account of the source that
includes the TR NOX Ozone Season optin unit, the TR NOX Ozone Season
allowances allocated to the TR NOX
Ozone Season opt-in unit under
paragraph (a)(2) of this section.
37. 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, and variability
limits.
97.611 Timing requirements for TR SO2
Group 1 allowance allocations.
97.612 TR SO2 Group 1 allowance
allocations for 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.
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97.618 Delegation by designated
representative and alternate designated
representative.
97.619 [Reserved]
97.620 Establishment of Allowance
Management System 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.
97.633 Notifications concerning
monitoring.
97.634 Recordkeeping and reporting.
97.635 Petitions for alternatives to
monitoring, recordkeeping, or reporting
requirements.
97.640 General requirements for TR SO2
Group 1 opt-in units.
97.641 Opt-in process.
97.642 Withdrawal of TR SO2 Group 1 optin unit from TR SO2 Group 1 Trading
Program.
97.643 Change in regulatory status.
97.644 TR SO2 Group 1 allowance
allocations to TR SO2 Group 1 opt-in
units.
Subpart CCCCC—TR SO2 Group 1
Trading Program
§ 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 § 52.38(b) of this
chapter, as a means of mitigating
interstate transport of fine particulates
and nitrogen oxides.
§ 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 multistate 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) of the United
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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
of the amount of such TR SO2 Group 1
allowances to be initially credited to a
TR SO2 Group 1 source or a new unit
set-aside.
Allowable SO2 emission rate means,
with regard to a unit, the SO2 emission
rate limit 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, held,
deducted, or transferred only as whole
allowances. The Allowance
Management System is a component of
the CAMD Business System, which is
the system used by the Administrator to
handle TR SO2 Group 1 allowances and
data related to SO2 emissions.
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, 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 Annual emissions limitation for
such control period in accordance with
§ 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
Season 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
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§ 72.2 of this chapter, § 97.402, or
§ 97.502 respectively.
Authorized account representative
means, with regard to 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, with regard to 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.
Certifying official means a natural
person who is:
(1) For a corporation, a president,
secretary, treasurer, or vice-president or
the corporation in charge of a principal
business function or any other person
who performs similar policy or
decision-making functions for the
corporation;
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(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 any solid fuel classified as
anthracite, bituminous, subbituminous,
or lignite.
Coal-derived fuel means any fuel
(whether in a solid, liquid, or gaseous
state) produced by the mechanical,
thermal, or chemical processing of coal.
Coal-fired means combusting any
amount of coal or coal-derived fuel,
alone or in combination with any
amount of any other fuel, during 1990
or any year thereafter.
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—
(1) Operating as part of a cogeneration
system; and
(2) Producing during the later of 1990
or the 12-month period starting on the
date that the unit first produces
electricity and during each calendar
year after the later of 1990 or the
calendar year in which the unit first
produces electricity—
(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 then 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 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
(4) Provided that, if a topping-cycle
unit is operated as part of a cogeneration
system during a calendar year and the
cogeneration system meets on a systemwide basis the requirement in paragraph
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(2)(i)(B) of this definition, the toppingcycle unit shall be deemed to meet such
requirement during that 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 § 97.605.
(i) For a unit that is a TR SO2 Group
1 unit under § 97.604 on the later of
November 15, 1990 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 (other than replacement of the
unit by a unit at the same 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 § 97.604 on the later of
November 15, 1990 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 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 § 97.605, for a unit that is not a TR
SO2 Group 1 unit under § 97.604 on the
later of November 15, 1990 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 § 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 (other than replacement
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of the unit by a unit at the same 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 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.
Commence operation means, with
regard to a unit:
(1) To have begun any mechanical,
chemical, or electronic process,
including start-up of the unit’s
combustion chamber.
(2) For a unit that undergoes a
physical change (other than replacement
of the unit by a unit at the same source)
after the date the unit commences
operation as defined in paragraph (1) of
this definition, such date shall remain
the date of commencement of operation
of the unit, which shall continue to be
treated as the same unit.
(3) For a unit that is replaced by a unit
at the same source after the date the unit
commences operation as defined in
paragraph (1) of this definition, such
date shall remain the replaced unit’s
date of commencement of operation,
and the replacement unit shall be
treated as a separate unit with a separate
date for commencement of operation as
defined in paragraph (1), (2), or (3) of
this definition as appropriate.
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
for 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
complying with the source’s TR SO2
Group 1 emissions limitation in
accordance with § 97.624 and the TR
SO2 Group 1 assurance provisions in
accordance with § 97.625.
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
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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 §§ 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 § 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 § 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 § 72.2 of
this chapter, § 97.402, or § 97.502
respectively.
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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 in
accordance with this subpart.
Excess emissions means any ton of
SO2 emitted from the TR SO2 Group 1
units at a TR SO2 Group 1 source during
a control period that exceeds the TR SO2
Group 1 emissions limitation for the
source.
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
§§ 97.604(b)(2)(i)(B), 97.604(b)(2)(ii)(B),
and 97.604(b)(2)(iii), 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 1990 or any calendar year
thereafter.
Fuel oil means any petroleum-based
fuel (including diesel fuel or petroleum
derivatives such as oil tar) and any
recycled or blended petroleum products
or petroleum by-products used as a fuel
whether in a liquid, solid, or gaseous
state.
General account means an Allowance
Management System account,
established under this subpart, that is
not a compliance account.
Generator means a device that
produces electricity.
Gross electrical output means, with
regard to 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, with regard to a
unit for a specified period of time, the
product (in mmBtu/time) of the gross
calorific value of the fuel (in mmBtu/lb)
multiplied by the fuel feed rate into a
combustion device (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 the amount of
heat input (in mmBtu) divided by unit
operating time (in hr) or, with regard to
a specific fuel, the amount of heat input
attributed to the fuel (in mmBtu)
divided by the unit operating time (in
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hr) during which the unit combusts the
fuel.
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
the maximum amount of fuel per hour
(in Btu/hr) that a 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) 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
(in MWe) 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 as of such completion as
specified by the person conducting the
physical change.
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.
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Operator means any person who
operates, controls, or supervises a TR
SO2 Group 1 unit or a TR SO2 Group 1
source and shall include, but not be
limited to, any holding company, utility
system, or plant manager of such a unit
or source.
Owner means, with regard to 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;
(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-theunit, firm power contractual
arrangement;
(4) Provided that, for purposes of
applying the TR SO2 Group 1 assurance
provisions in §§ 97.606(c)(2) and 97.625,
if one or more owners (as defined in
paragraphs (1) through (3) of this
definition) of one or more TR SO2 Group
1 units in a State are wholly owned by
another, common owner, all such
owners shall be treated collectively as a
single owner in the State.
Owner’s assurance level means:
(1) With regard to a State and control
period for which the State assurance
level is exceeded as described in
§ 97.606(c)(2)(iii)(A) and not as
described in § 97.606(c)(2)(iii)(B), the
owner’s share of the State SO2 Group 1
trading budget with the one-year
variability limit for the State for such
control period; or
(2) With regard to a State and control
period for which the State assurance
level is exceeded as described in
§ 97.606(c)(2)(iii)(B), the owner’s share
of the State SO2 Group 1 trading budget
with the three-year variability limit for
the State for such control period.
Owner’s share means:
(1) With regard to a total amount of
SO2 emissions from all TR SO2 Group 1
units in a State during a control period,
the total tonnage of SO2 emissions
during such control period from all of
the owner’s TR SO2 Group 1 units in the
State;
(2) With regard to a State SO2 Group
1 trading budget with a one-year
variability limit for a control period, the
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amount (rounded to the nearest
allowance) equal to the total amount of
TR SO2 Group 1 allowances allocated
for such control period to all of the
owner’s TR SO2 Group 1 units in the
State, multiplied by the sum of the State
SO2 Group 1 trading budget under
§ 97.610(a) and the State’s one-year
variability limit under § 97.610(b) and
divided by such State SO2 Group 1
trading budget;
(3) With regard to a State SO2 Group
1 trading budget with a three-year
variability limit for a control period, the
amount (rounded to the nearest
allowance) equal to the total amount of
TR SO2 Group 1 allowances allocated
for such control period to all of the
owner’s TR SO2 Group 1 units in the
State, multiplied by the sum of the State
SO2 Group 1 trading budget under
§ 97.610(a) and the State’s three-year
variability limit under § 97.610(b) and
divided by such State SO2 Group 1
trading budget;
(4) Provided that, in the case of a unit
with more than one owner, the amount
of tonnage of SO2 emissions and of TR
SO2 Group 1 allowances allocated for a
control period, with regard to such unit,
used in determining each owner’s share
shall be the amount (rounded to the
nearest ton and the nearest allowance)
equal to the unit’s SO2 emissions and
allocation of such allowances,
respectively, for such control period
multiplied by the percentage of
ownership in the unit that the owner’s
legal, equitable, leasehold, or
contractual reservation or entitlement in
the unit comprises as of December 31 of
such control period;
(5) Provided that, where two or more
units emit through a common stack that
is the monitoring location from which
SO2 mass emissions are reported for a
control period for a year, the amount of
tonnage of each unit’s SO2 emissions
used in determining each owner’s share
for such control period shall be:
(i) The amount (rounded to the
nearest ton) of SO2 emissions reported
at the common stack multiplied by the
quotient of such unit’s heat input for
such control period divided by the total
heat input reported from the common
stack for such control period;
(ii) An amount determined in
accordance with a methodology that the
Administrator determines is consistent
with the purposes of this definition and
whose adverse effect (if any) the
Administrator determines will be de
minimis; or
(iii) An amount approved by the
Administrator in response to a petition
for an alternative requirement submitted
in accordance with § 97.635; and
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(6) Provided that, in the case of a unit
that operates during, but is allocated no
TR SO2 Group 1 allowances for, a
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 lesser of—
(i) The unit’s allowable SO2 emission
rate (in lb per MWe) applicable to such
control period, multiplied by a capacity
factor of 0.84 (if the unit is a coal-fired
boiler), 0.15 (if the unit is a simple
combustion turbine), or 0.66 (if the unit
is a combined cycle turbine), 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; or
(ii) For a unit listed in appendix A to
this subpart, the sum of the unit’s SO2
emissions in the control period in the
last three years during which the unit
operated during the control period,
divided by three.
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
§§ 70.2 and 71.2 of this chapter.
Potential electrical output capacity
means 33 percent of a 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,
transfer, or deduction.
Reference method means any direct
test method of sampling and analyzing
for an air pollutant as specified in
§ 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
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instead of the demolished or retired unit
(the replaced unit).
Sequential use of energy means:
(1) For a topping-cycle unit, the use
of reject heat from electricity production
in a useful thermal energy application
or process; or
(2) For a bottoming-cycle unit, 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 or the
District of Columbia that is subject to
the TR SO2 Group 1 Trading Program
pursuant to § 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 total energy
of all forms supplied to a 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,
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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 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 by the Administrator in
accordance with subpart AAAAA and
52.37(a) 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 by the
Administrator in accordance with
subpart BBBBB of this part and 52.37(b)
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 by the Administrator under
this subpart to emit one ton of SO2
during a control period of the specified
calendar year for which the
authorization is allocated 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 assurance
provisions.
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 § 97.624(a) for such
control period.
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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 by the Administrator in
accordance with this subpart and
52.38(b) 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 § 97.604.
Unit means a stationary, fossil-fuelfired boiler, stationary, fossil-fuel-fired
combustion turbine, or other stationary,
fossil-fuel-fired combustion device.
Unit operating day means a calendar
day in which a unit combusts any fuel.
Unit operating hour or hour of unit
operation means an hour in which a
unit combusts any fuel.
Useful power means electricity or
mechanical energy that a 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.
§ 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
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yr—year
§ 97.604
Applicability.
(a) Except as provided in paragraph
(b) of this section:
(1) The following units in a 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 stationary, fossil-fuel-fired
combustion turbine serving at any time,
since the later of November 15, 1990 or
the start-up of the unit’s combustion
chamber, 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 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), (b)(2)(i), or (b)(2)(ii)
of this section shall not be a TR SO2
Group 1 unit:
(1)(i) Any unit:
(A) Qualifying as a cogeneration unit
during the later of 1990 or the 12-month
period starting on the date the unit first
produces electricity and continuing to
qualify as a cogeneration unit; and
(B) Not serving at any time, since the
later of November 15, 1990 or the startup of the unit’s combustion chamber, a
generator with nameplate capacity of
more than 25 MWe supplying in any
calendar year 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 a unit qualifies as a cogeneration
unit during the later of 1990 or the 12month period starting on the date the
unit first produces electricity and meets
the requirements of paragraphs (b)(1)(i)
of this section for at least one calendar
year, but subsequently no longer meets
such qualification and requirements, 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.
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(2)(i) Any unit commencing operation
before January 1, 1985:
(A) Qualifying as a solid waste
incineration unit during the later of
1990 or the 12-month period starting on
the date the unit first produces
electricity and continuing to qualify as
a solid waste incineration unit; and
(B) With an average annual fuel
consumption of fossil fuel for 1985–
1987 less than 20 percent (on a Btu
basis) and an average annual fuel
consumption of fossil fuel for any 3
consecutive calendar years after 1990
less than 20 percent (on a Btu basis).
(ii) Any unit commencing operation
on or after January 1, 1985:
(A) Qualifying as a solid waste
incineration unit during the later of
1990 or the 12-month period starting on
the date the unit first produces
electricity and continuing to qualify as
a solid waste incineration unit; and
(B) With an average annual fuel
consumption of fossil fuel for the first
3 calendar years of operation less than
20 percent (on a Btu basis) and an
average annual fuel consumption of
fossil fuel for any 3 consecutive
calendar years after 1990 less than 20
percent (on a Btu basis).
(iii) If a unit qualifies as a solid waste
incineration unit during the later of
1990 or the 12-month period starting on
the date the unit first produces
electricity and meets the requirements
of paragraph (b)(2)(i) or (ii) of this
section for at least 3 consecutive
calendar years, but subsequently no
longer meets such qualification and
requirements, 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
1990 for which the unit has an average
annual fuel consumption of fossil fuel of
20 percent or more.
(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, 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
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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
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.
§ 97.605
Retired unit exemption.
(a)(1) Any TR SO2 Group 1 unit that
is permanently retired and is not a TR
SO2 Group 1 opt-in unit shall be exempt
from § 97.606(b) and (c)(1), § 97.624,
and §§ 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
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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.
§ 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
§§ 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 §§ 97.630
through 97.635.
(2) The emissions data determined in
accordance with §§ 97.630 through
97.635 shall be used to calculate
allocations of TR SO2 Group 1
allowances under §§ 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
§§ 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
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a control period, 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 § 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 a TR SO2 Group 1 source emits
SO2 during any control period 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 § 97.624(d) and pay
any fine, penalty, or assessment or
comply with any other remedy imposed,
for the same violations, under the Clean
Air Act; and
(B) 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 the total amount of SO2
emissions from all TR SO2 Group 1
units in a State during a control period
in 2014 or any year thereafter exceeds
the State assurance level as described in
paragraph (c)(2)(iii) of this section, then
each owner whose share of such SO2
emissions during such control period
exceeds the owner’s assurance level for
the State and such control period shall
hold, in a compliance account
designated by the owner in accordance
with § 97.625(b)(4)(ii), TR SO2 Group 1
allowances available for deduction for
such control period under § 97.625(a) in
an amount equal to the product, as
determined by the Administrator in
accordance with § 97.625(b), of
multiplying—
(A) The quotient (rounded to the
nearest whole number) of the amount by
which the owner’s share of such SO2
emissions exceeds the owner’s
assurance level divided by the sum of
the amounts, determined for all such
owners, by which each owner’s share of
such SO2 emissions exceeds that
owner’s assurance level; and
(B) The amount by which total SO2
emissions for all TR SO2 Group 1 units
in the State for such control period
exceed the State assurance level as
determined in accordance with
paragraph (c)(2)(iii) of this section.
(ii) The owner 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
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business day thereafter (if November 1
is not a business day), immediately after
such control period.
(iii) The total amount of SO2
emissions from all TR SO2 Group 1
units in a State during a control period
in 2014 or any year thereafter exceeds
the State assurance level:
(A) If such total amount of SO2
emissions exceeds the sum, for such
control period, of the State SO2 Group
1 trading budget and the State’s oneyear variability limit under § 97.610(b);
or
(B) If, with regard to a control period
in 2016 or any year thereafter, the sum,
divided by three, of such total amount
of SO2 emissions and the total amounts
of SO2 emissions from all TR SO2 Group
1 units in the State during the control
periods in the immediately preceding
two years exceeds the sum, for such
control period, of the State SO2 Group
1 trading budget and the State’s threeyear variability limit under § 97.610(b);
(C) Provided that the amount by
which such total amount of SO2
emissions exceeds the State assurance
level shall be the greater of the amounts
of the exceedance calculated under
paragraph (c)(2)(iii)(A) of this section
and under paragraph (c)(2)(iii)(B) of this
section.
(iv) It shall not be a violation of this
subpart or of the Clean Air Act if the
total amount of SO2 emissions from all
TR SO2 Group 1 units in a State during
a control period exceeds the State
assurance level or if an owner’s share of
total SO2 emissions from the TR SO2
Group 1 units in a State during a control
period exceeds the owner’s assurance
level.
(v) To the extent an owner fails to
hold TR SO2 Group 1 allowances for a
control period in accordance with
paragraphs (c)(2)(i) and (ii) of this
section,
(A) The owner 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 owner fails to hold for a control
period in accordance with paragraphs
(c)(2)(i) and (ii) 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:
(i) Under paragraph (c)(1) 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
§ 97.630(b) and for each control period
thereafter; and
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(ii) Under paragraph (c)(2) of this
section for the control period starting on
the later of January 1, 2014 or the
deadline for meeting the unit’s monitor
certification requirements under
§ 97.630(b) and for each control period
thereafter.
(4) Vintage of deducted allowances. A
TR SO2 Group 1 allowance shall not be
deducted, for compliance with the
requirements under paragraphs (c)(1)
and (2) of this section, for a control
period in a calendar year before the year
for which the TR SO2 Group 1
allowance was allocated.
(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
System accounts in accordance with
this subpart.
(6) Limited authorization. (i) A TR
SO2 Group 1 allowance is a limited
authorization to emit one ton of SO2 in
accordance with the TR SO2 Group 1
Trading Program.
(ii) Notwithstanding any other
provision of this subpart, the
Administrator has the authority to
terminate or limit 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 §§ 75.10,
75.11, and 75.16 of this chapter), an
excepted monitoring system (under
appendix D to part 75 of this chapter),
a low mass emissions excepted
monitoring methodology (under § 75.19
of this chapter), or an alternative
monitoring system (under subpart E of
part 75 of this chapter) in accordance
with §§ 97.630 through 97.635 may be
added to, or changed in, a title V permit
using minor permit modification
procedures in accordance with
§§ 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
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permit modification procedures in
accordance with §§ 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 § 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
documents are superseded because of
the submission of a new certificate of
representation under § 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, including any
monitoring plans and monitoring
system certification and recertification
applications.
(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,
including any submissions required for
compliance with the TR SO2 Group 1
assurance provisions. 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 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
§ 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.
§ 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, falls on
a weekend or a State or Federal holiday,
the time period shall be extended to the
next business day.
§ 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.
§ 97.609
[Reserved]
§ 97.610 State SO2 Group 1 trading
budgets, new-unit set-asides, and variability
limits.
(a) The State SO2 Group 1 trading
budgets and 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 trading budget
(tons) *
New-unit set-aside (tons)
State
For 2012–2013
For 2014 and
thereafter
For 2012–2013
For 2014 and
thereafter
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Georgia ....................................................................................................
Illinois .......................................................................................................
Indiana .....................................................................................................
Iowa .........................................................................................................
Kentucky ..................................................................................................
Michigan ...................................................................................................
Missouri ....................................................................................................
New York .................................................................................................
North Carolina ..........................................................................................
Ohio .........................................................................................................
Pennsylvania ............................................................................................
Tennessee ...............................................................................................
Virginia .....................................................................................................
West Virginia ............................................................................................
Wisconsin .................................................................................................
233,260
208,957
400,378
94,052
219,549
251,337
203,689
66,542
111,485
464,964
388,612
100,007
72,595
205,422
96,439
85,717
151,530
201,412
86,088
113,844
155,675
158,764
42,041
81,859
178,307
141,693
100,007
40,785
119,016
66,683
6,998
6,269
12,011
2,822
6,586
7,540
6,111
1,996
3,345
13,949
11,658
3,000
2,178
6,163
2,893
2,572
4,546
6,042
2,583
3,415
4,670
4,763
1,261
2,456
5,349
4,251
3,000
1,224
3,570
2,000
Total ..................................................................................................
3,117,288
1,723,421
93,519
51,703
* Without variability limits.
(b) The States’ one-year and three-year
variability limits for the State SO2
Group 1 trading budgets for the control
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periods in 2014 and thereafter are as
follows:
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One-year
variability limits
2014 and
thereafter
(tons)
State
Three-year
variability limits
2016 and
thereafter
(tons)
Georgia ................................................................................................................................................
Illinois ...................................................................................................................................................
Indiana .................................................................................................................................................
Iowa .....................................................................................................................................................
Kentucky ..............................................................................................................................................
Michigan ...............................................................................................................................................
Missouri ................................................................................................................................................
New York .............................................................................................................................................
North Carolina ......................................................................................................................................
Ohio .....................................................................................................................................................
Pennsylvania ........................................................................................................................................
Tennessee ...........................................................................................................................................
Virginia .................................................................................................................................................
West Virginia ........................................................................................................................................
Wisconsin .............................................................................................................................................
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§ 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 set forth in appendix A to
this subpart. Listing a unit in such
appendix does not constitute a
determination that the unit is a TR SO2
Group 1 unit, and not listing a unit in
such appendix 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 listed in
appendix A to this subpart as being
allocated TR SO2 Group 1 allowances
does not operate, starting after 2011,
during the control period in three
consecutive years, such unit will not be
allocated the TR SO2 Group 1
allowances set forth in appendix A to
this subpart for the unit for the control
periods in the seventh year after the first
such year and in each year after that
seventh year. All TR SO2 Group 1
allowances that would otherwise have
been allocated to such unit will be
allocated to the new unit set-aside 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) By July 1, 2012 and
July 1 of each year thereafter, the
Administrator will calculate the TR SO2
Group 1 allowance allocation for each
TR SO2 Group 1 unit, in accordance
with § 97.612, for the control period in
the year of the applicable calculation
deadline under this paragraph and will
promulgate a notice of availability of the
results of the calculations.
(2) For each notice of data availability
required in paragraph (b)(1) of this
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section, the Administrator will provide
an opportunity for submission of
objections to the calculations referenced
in such notice.
(i) Objections shall be submitted by
the deadline specified in such notice
and shall be limited to addressing
whether the calculations are in
accordance with § 97.612 and
§§ 97.606(b)(2) and 97.630 through
97.635.
(ii) 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)(i) of this section. By September 1
immediately after the promulgation of
such notice, the Administrator will
promulgate a notice of 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)(i) of this section.
(c) Units that are not TR SO2 Group
1 units. 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 for the
control period to a recipient that is not
actually a TR SO2 Group 1 unit under
§ 97.604 as of January 1, 2012 or whose
deadline for meeting monitor
certification requirements under
§ 97.630(b)(1) and (2) is after January 1,
2012 or if the Administrator determines
that TR SO2 Group 1 allowances were
allocated under paragraph (b) of this
section and § 97.612 for the control
period to a recipient that is not actually
a TR SO2 Group 1 unit under § 97.604
as of January 1 of the control period,
then the Administrator will notify the
designated representative and will act in
accordance with the following
procedures:
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8,572
15,153
20,141
8,609
11,384
15,568
15,876
4,204
8,186
17,831
14,169
10,001
4,079
11,902
6,668
4,949
8,749
11,629
4,970
6,573
8,988
9,166
2,427
4,726
10,295
8,181
5,774
2,355
6,871
3,850
(1) Except as provided in paragraph
(c)(2) or (3) of this section, the
Administrator will not record such TR
SO2 Group 1 allowances under § 97.621.
(2) If the Administrator already
recorded such TR SO2 Group 1
allowances under § 97.621 and if the
Administrator makes such
determination before making deductions
for the source that includes such
recipient under § 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.
(3) If the Administrator already
recorded such TR SO2 Group 1
allowances under § 97.621 and if the
Administrator makes such
determination after making deductions
for the source that includes such
recipient under § 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.
(4) The Administrator will transfer the
TR SO2 Group 1 allowances that are not
recorded, or that are deducted, in
accordance with paragraphs (c)(1) and
(2) of this section to the new unit setaside, for the State in which such
recipient is located, for the control
period in the year of such transfer if the
notice required in paragraph (b)(1) of
this section for the control period in that
year has not been promulgated or, if
such notice has been promulgated, in
the next year.
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§ 97.612 TR SO2 Group 1 allowance
allocations for new units.
(a) For each control period in 2012
and thereafter, the Administrator will
allocate, in accordance with the
following procedures, TR SO2 Group 1
allowances to TR SO2 Group 1 units in
a State that are not listed in appendix
A to this subpart, to TR SO2 Group 1
units that are so listed and whose
allocation of SO2 Group 1 allowances
for such control period is covered by
§ 97.611(c)(1) or (2), and to TR SO2
Group 1 units that are so listed and,
pursuant to § 97.611(a)(2), are not
allocated TR SO2 Group 1 allowances
for such control period but that operate
during the immediately preceding
control period:
(1) The Administrator will establish a
separate new unit set-aside for each
State for each control period in a given
year. Each 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 § 97.610(a). Each new unit setaside will be allocated additional TR
SO2 Group 1 allowances in accordance
with § 97.611(a)(2) and (c)(4).
(2) The designated representative of
such TR SO2 Group 1 unit may submit
to the Administrator a request, in a
format prescribed by the Administrator,
to be allocated TR SO2 Group 1
allowances for a control period, starting
with the later of the control period in
2012, the first control period after the
control period in which the TR SO2
Group 1 unit commences commercial
operation (for a unit not listed in
appendix A to this subpart), or the first
control period after the control period in
which the unit resumes operation (for a
unit listed in appendix A of this
subpart) and for each subsequent
control period.
(i) The request must be submitted on
or before May 1 of the first control
period for which TR SO2 Group 1
allowances are sought and after the date
on which the TR SO2 Group 1 unit
commences commercial operation (for a
unit not listed in appendix A of this
subpart) or on which the unit resumes
operation (for a unit listed in appendix
A of this subpart).
(ii) For each control period for which
an allocation is sought, the request must
be for TR SO2 Group 1 allowances in an
amount equal to the unit’s total tons of
SO2 emissions during the immediately
preceding control period.
(3) The Administrator will review
each TR SO2 Group 1 allowance
allocation request under paragraph
(a)(2) of this section and will accept the
request only if it meets the requirements
of paragraph (a)(2) of this section. The
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Administrator will allocate TR SO2
Group 1 allowances for each control
period pursuant to an accepted request
as follows:
(i) After May 1 of such control period,
the Administrator will determine the
sum of the TR SO2 Group 1 allowances
requested in all accepted allowance
allocation requests for such control
period.
(ii) If the amount of TR SO2 Group 1
allowances in the new unit set-aside for
such control period is greater than or
equal to the sum under paragraph
(a)(3)(i) of this section, then the
Administrator will allocate the amount
of TR SO2 Group 1 allowances requested
to each TR SO2 Group 1 unit covered by
an accepted allowance allocation
request.
(iii) If the amount of TR SO2 Group 1
allowances in the new unit set-aside for
such control period is less than the sum
under paragraph (a)(3)(i) of this section,
then the Administrator will allocate to
each TR SO2 Group 1 unit covered by
an accepted allowance allocation
request the amount of the TR SO2 Group
1 allowances requested, multiplied by
the amount of TR SO2 Group 1
allowances in the new unit set-aside for
such control period, divided by the sum
determined under paragraph (a)(3)(i) of
this section, and rounded to the nearest
allowance.
(iv) The Administrator will notify,
through the promulgation of the notices
of data availability described in
§ 97.611(b), each designated
representative that submitted an
allowance allocation request of the
amount of TR SO2 Group 1 allowances
(if any) allocated for such control period
to the TR SO2 Group 1 unit covered by
the request.
(b) If, after completion of the
procedures under paragraph (a)(4) of
this section for a control period, any
unallocated TR SO2 Group 1 allowances
remain in the new unit set-aside under
paragraph (a) of this section for a State
for such control period, the
Administrator will allocate to each TR
SO2 Group 1 unit that is in the State, is
listed in appendix A to this subpart, and
continues to be allocated TR SO2 Group
1 allowances for such control period in
accordance with § 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 § 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 amount of tons in
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45427
such new unit set-aside, and rounded to
the nearest allowance.
§ 97.613 Authorization of designated
representative and alternate designated
representative.
(a) Except as provided under § 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
§ 97.616(a)(4)(iii).
(2) Upon and after receipt by the
Administrator of a complete certificate
of representation under § 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 § 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 § 97.616(a)(4)(iii).
(2) Upon and after receipt by the
Administrator of a complete certificate
of representation under § 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,
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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,
§ 97.602, and §§ 97.614 through 97.618,
whenever the term ‘‘designated
representative’’ is used in this subpart,
the term shall be construed to include
the designated representative or any
alternate designated representative.
§ 97.614 Responsibilities of designated
representative and alternate designated
representative.
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(a) Except as provided under § 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
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 § 97.618.
§ 97.615 Changing designated
representative and alternate designated
representative; changes in owners and
operators.
(a) Changing designated
representative. The designated
representative may be changed at any
time upon receipt by the Administrator
of a superseding complete certificate of
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representation under § 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 § 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 is not included in the list
of owners and operators in the
certificate of representation under
§ 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, including the addition of a new
owner or operator, the designated
representative or any alternate
designated representative shall submit a
revision to the certificate of
representation under § 97.616 amending
the list of owners and operators to
include the change.
§ 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,
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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, and actual or
projected date of commencement of
commercial operation.
(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 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-theunit, 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
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
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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.
§ 97.617 Objections concerning
designated representative and alternate
designated representative.
(a) Once a complete certificate of
representation under § 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 § 97.616 is
received by the Administrator.
(b) Except as provided in § 97.615(a)
or (b), 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.
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§ 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
make an electronic submission to the
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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 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
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45429
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.
§ 97.619
[Reserved]
§ 97.620 Establishment of Allowance
Management System accounts.
(a) Compliance accounts. Upon
receipt of a complete certificate of
representation under § 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) 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
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
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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
order or decision 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.
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(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
order or decision issued to the
authorized account representative or
alternate authorized account
representative by the Administrator
regarding the general account. (ii)
Except as provided in paragraph (b)(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
(b)(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
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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 (b)(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 of a new 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
authorized account representative. (i)
Once a complete application for a
general account under paragraph (b)(1)
of this section has been submitted and
received, the Administrator will rely on
the application unless and until a
superseding complete application for a
general account under paragraph (b)(1)
of this section is received by the
Administrator.
(ii) Except as provided in paragraph
(b)(3)(i) or (ii) of this section, no
objection or other communication
submitted to the Administrator
concerning the authorization, or any
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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
make an electronic submission to the
Administrator in accordance with
paragraph (b)(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
as an ‘‘agent’’);
(C) For each such natural person, a
list of the type or types of electronic
submissions under paragraph (b)(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
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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(b)(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(b)(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(b)(5) is terminated.’’.
(iv) A notice of delegation submitted
under paragraph (b)(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
(b)(5)(iii)(D) of this section and made in
accordance with a notice of delegation
effective under paragraph (b)(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)(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 § 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
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45431
may notify the authorized account
representative for the account that the
account will be closed after 20 business
days after the notice is sent. The
account will be closed after the 20-day
period unless, before the end of the 20day period, the Administrator receives a
correctly submitted TR SO2 Group 1
allowance transfer under § 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.
(c) Account identification. The
Administrator will assign a unique
identifying number to each account
established under paragraph (a) or (b) of
this section.
(d) Responsibilities of authorized
account representative and alternate
authorized account representative. After
the establishment of an Allowance
Management System 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 §§ 97.614(a)
and 97.618 or paragraphs (b)(2)(ii) and
(b)(5) of this section.
§ 97.621 Recordation of TR SO2 Group 1
allowance allocations.
(a) By September 1, 2011, the
Administrator will record in each TR
SO2 Group 1 source’s compliance
account the TR SO2 Group 1 allowances
allocated for the TR SO2 Group 1 units
at the source in accordance with
§§ 97.611(a) for the control periods in
2012, 2013, and 2014.
(b) By June 1, 2012 and June 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 for the TR SO2
Group 1 units at the source in
accordance with § 97.611(a) for the
control period in the third year after the
year of the applicable recordation
deadline under this paragraph.
(c) By September 1, 2012 and
September 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 for the TR SO2 Group 1 units
at the source in accordance with
§ 97.612 for the control period in the
year of the applicable recordation
deadline under this paragraph.
(d) When recording the allocation of
TR SO2 Group 1 allowances for a TR
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SO2 Group 1 unit in a compliance
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.
§ 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.
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§ 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, 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 by
the request, provided that the transfer is
correctly submitted under § 97.622.
(b)(1) A TR SO2 Group 1 allowance
transfer 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 any control period before such
allowance transfer deadline will not be
recorded until after the Administrator
completes the deductions under
§ 97.624 for the control period
immediately before such allowance
transfer deadline.
(2) A TR SO2 Group 1 allowance
transfer that is submitted for recordation
after the deadline for holding TR SO2
Group 1 allowances described in
§ 97.625(b)(5) and that includes any TR
SO2 Group 1 allowances allocated for a
control period before the year of such
deadline will not be recorded until after
the Administrator completes the
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deductions under § 97.625 for the
control period immediately before the
year of such deadline.
(c) Where a TR SO2 Group 1
allowance transfer is not correctly
submitted under § 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
§ 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 nonrecordation.
§ 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 the control
period in the year or 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
§ 97.623, of TR SO2 Group 1 allowance
transfers submitted by the allowance
transfer deadline for a control period,
the Administrator will deduct from the
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
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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 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 (FIFO)
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 the control
period 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.
§ 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 an
owner of one or more TR SO2 Group 1
units in a State only if the TR SO2
Group 1 allowances:
(1) Were allocated for the control
period in the year or a prior year; and
(2) Are held in a compliance account,
designated by the owner in accordance
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with paragraph (b)(4)(ii) of this section,
of one of the owner’s TR SO2 Group 1
sources in the State as of the deadline
established in paragraph (b)(5) 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, 2015 and June 1 of each
year thereafter, the Administrator will:
(i) Calculate, separately for each State,
the total amount of SO2 emissions from
all TR SO2 Group 1 units in the State
during the control period in the year
before the year of this calculation
deadline and the amount, if any, by
which such total amount of NOX
emissions exceeds the State assurance
level as described in § 97.606(c)(2)(iii);
and
(ii) Promulgate a notice of availability
of the results of the calculations
required in paragraph (b)(1)(i) of this
section, including separate calculations
of the SO2 emissions for each TR SO2
Group 1 unit and of the amounts
described in §§ 97.606(c)(2)(iii)(A) and
(B) for each State.
(2) The Administrator will provide an
opportunity for submission of objections
to the calculations referenced by each
notice described in paragraph (b)(1) of
this section.
(i) Objections shall be submitted by
the deadline specified in such notice
and shall be limited to addressing
whether the calculations for each TR
SO2 Group 1 unit and each State for the
control period in the year involved are
in accordance with § 97.606(c)(2)(iii)
and §§ 97.606(b) and 97.630 through
97.635.
(ii) 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)(i) of this section. By August 1
immediately after the promulgation of
such notice, the Administrator will
promulgate a notice of 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)(i) of this section.
(3) For each notice of data availability
required in paragraph (b)(2)(ii) of this
section and for any State identified in
such notice as having TR SO2 Group 1
sources with total SO2 emissions
exceeding the State assurance level for
a control period, as described in
§ 97.606(c)(2)(iii):
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(i) By August 15 immediately after the
promulgation of such notice, the
designated representative of each TR
SO2 Group 1 source in each such State
shall submit a statement, in a format
prescribed by the Administrator:
(A) Listing all the owners of each TR
SO2 Group 1 unit at the source,
explaining how the selection of each
owner for inclusion on the list is
consistent with the definition of
‘‘owner’’ in § 97.602, and listing,
separately for each unit, the percentage
of the legal, equitable, leasehold, or
contractual reservation or entitlement
for each such owner as of midnight of
December 31 of the control period in the
year involved; and
(B) For each TR SO2 Group 1 unit at
the source that operates during, but is
allocated no TR SO2 Group 1 allowances
for, the control period in the year
involved, identifying whether the unit is
a coal-fired boiler, simple combustion
turbine, or combined cycle turbine cycle
and providing the unit’s allowable SO2
emission rate for such control period.
(ii) By September 15 immediately
after the promulgation of such notice,
the Administrator will calculate, for
each such State and each owner of one
or more TR SO2 Group 1 units in the
State and for the control period in the
year involved, each owner’s share of the
total SO2 emissions from all TR SO2
Group 1 units in the State, each owner’s
assurance level, and the amount (if any)
of TR SO2 Group 1 allowances that each
owner must hold in accordance with the
calculation formula in § 97.606(c)(2)(i)
and will promulgate a notice of
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)(3)(ii) of this
section.
(A) Objections shall be submitted by
the deadline specified in such notice
and shall be limited to addressing
whether the calculations for each owner
for the control period in the year
involved are consistent with the SO2
emissions for the relevant TR SO2 Group
1 units as set forth in the notice required
in paragraph (b)(2)(ii) of this section, the
definitions of ‘‘owner’’, ‘‘owner’s
assurance level’’, and ‘‘owner’s share’’ in
§ 97.602, and the calculation formula in
§ 97.606(c)(2)(i) and shall not raise any
issues about any data used in the notice
of data availability required in
paragraph (b)(2)(ii) of this section.
(B) The Administrator will adjust the
calculations to the extent necessary to
ensure that they are consistent with the
data and provisions referenced in
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45433
paragraph (b)(3)(iii)(A) of this section.
By November 15 immediately after the
promulgation of such notice, the
Administrator will promulgate a notice
of 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)(3)(iii)(A)
of this section.
(4) By December 1 immediately after
the promulgation of each notice of data
availability required in paragraph
(b)(3)(iii)(B) of this section:
(i) Each owner identified, in such
notice, as owning one or more TR SO2
Group 1 units in a State and as being
required to hold TR SO2 Group 1
allowances shall designate the
compliance account of one of the
sources at which such unit or units are
located to hold such required TR SO2
Group 1 allowances;
(ii) The authorized account
representative for the compliance
account designated under paragraph
(b)(4)(i) of this section shall submit to
the Administrator a statement, in a
format prescribed by the Administrator,
making this designation.
(5)(i) As of midnight of December 15
immediately after the promulgation of
each notice of data availability required
in paragraph (b)(3)(iii)(B) of this section,
each owner described in paragraph
(b)(4)(i) of this section shall hold in the
compliance account designated by the
owner in accordance with paragraph
(b)(4)(ii) of this section the total amount
of TR SO2 Group 1 allowances, available
for deduction under paragraph (a) of
this section, equal to the amount the
owner is required to hold as calculated
by the Administrator and referenced in
such notice.
(ii) Notwithstanding the allowanceholding deadline specified in paragraph
(b)(5)(i) of this section, if December 15
is not a business day, then such
allowance-holding deadline shall be
midnight of the first business day
thereafter.
(6) After December 15 (or the date
described in paragraph (b)(5)(ii) of this
section) immediately after the
promulgation of each notice of data
availability required in paragraph
(b)(3)(iii)(B) of this section and after the
recordation, in accordance with
§ 97.623, of TR SO2 Group 1 allowance
transfers submitted by midnight of such
date, the Administrator will deduct
from each compliance account
designated in accordance with
paragraph (b)(4)(ii) of this section, TR
SO2 Group 1 allowances available under
paragraph (a) of this section, as follows:
(i) Until the amount of TR SO2 Group
1 allowances deducted equals the
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amount that the owner designating the
compliance account is required to hold
as calculated by the Administrator and
referenced in the notice required in
paragraph (b)(3)(iii)(B) of this section; or
(ii) If there are insufficient TR SO2
Group 1 allowances to complete the
deductions in paragraph (b)(6)(i) of this
section, until no more TR SO2 Group 1
allowances available under paragraph
(a) of this section remain in the
compliance account.
(7) Notwithstanding any other
provision of this subpart and any
revision, made by or submitted to the
Administrator after the promulgation of
the notices of data availability required
in paragraphs (b)(2)(ii) and (b)(3)(iii)(B)
of this section respectively for a control
period, of any data used in making the
calculations referenced in such notice,
the amount of TR SO2 Group 1
allowances that each owner is required
to hold in accordance with
§ 97.606(c)(2)(i) for the control period in
the year involved shall continue to be
such amount as calculated by the
Administrator and referenced in such
notice required in paragraph
(b)(3)(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 are required to hold in
accordance with the calculation formula
in § 97.606(c)(2)(i) for the control period
in the year involved with regard to the
State involved, provided that—
(A) With regard to such litigation
involving such notice required in
paragraph (b)(2)(ii) of this section, 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)(ii) of this section; and
(B) With regard to such litigation
involving such notice required in
paragraph (b)(3)(iii) of this section, 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)(3)(iii) of this section.
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(ii) If any such data are revised by the
owners and operators of a source whose
designated representative submitted
such data under paragraph (b)(3)(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 are
required to hold in accordance with the
calculation formula in § 97.606(c)(2)(i)
for the control period in the year
involved with regard to the State
involved, provided that such litigation
was initiated no later than 30 days after
promulgation of such notice required in
paragraph (b)(3)(iii)(B) of this section.
(iii) If the revised data are used to
recalculate, in accordance with
paragraphs (b)(7)(i) and (b)(7)(ii) of this
section, the amount of TR SO2 Group 1
allowances that an owner is required to
hold for the control period in the year
involved with regard to the State
involved—
(A) Where the amount of TR SO2
Group 1 allowances that an owner is
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 owner
shall hold the additional amount of TR
SO2 Group 1 allowances in the
compliance account designated by the
owner in accordance with paragraph
(b)(4)(ii) of this section. The owner’s
failure to hold such additional amount,
as required, before the new deadline
shall not be a violation of the Clean Air
Act. The owner’s 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 owner fails to hold
as required as of the new deadline, and
each day in the control period in the
year involved, shall be a separate
violation of the Clean Air Act. After
such deadline, the Administrator will
make the appropriate deductions from
the compliance account.
(B) For an owner 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 the
compliance account that the owner
designated in accordance with
paragraph (b)(4)(ii) of this section, an
amount of TR SO2 Group 1 allowances
equal to the amount of the decrease to
the extent such amount was previously
deducted from the compliance account
under paragraph (b)(6) of this section
(and has not already been restored to the
compliance account) for the control
period in the year involved.
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(C) Each TR SO2 Group 1 allowance
held and deducted under paragraph
(b)(7)(iii)(A) of this section, or recorded
under paragraph (b)(7)(iii)(B) of this
section, as a result of recalculation of
requirements under the TR SO2 Group
1 assurance provisions for a control
period in a given year must be a TR SO2
Group 1 allowance allocated for a
control period in the same or a prior
year.
(c)(1) Identification of TR SO2 Group
1 allowances by serial number. The
authorized account representative for
each source’s compliance account
designated in accordance with
paragraph (b)(4)(ii) of this section may
request that specific TR SO2 Group 1
allowances, identified by serial number,
in the compliance account be deducted
in accordance with paragraph (b)(6) or
(7) of this section. In order to be
complete, such request shall be
submitted to the Administrator by the
allowance-holding deadline described
in paragraph (b)(5) of this section and
include, in a format prescribed by the
Administrator, the identification of the
compliance account and the appropriate
serial numbers.
(2) First-in, first-out. The
Administrator will deduct TR SO2
Group 1 allowances under paragraphs
(b)(6) and (7) of this section from each
source’s compliance account designated
under paragraph (b)(4)(ii) of this section
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
(FIFO) 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) Recordation of deductions. The
Administrator will record in the
appropriate compliance account all
deductions from such an account under
paragraph (b) of this section.
§ 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
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account unless and until the TR SO2
Group 1 allowance is deducted or
transferred under § 97.611(c), § 97.623,
§ 97.624, § 97.625, 97.627, 97.628,
97.642, or 97.643.
§ 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.
§ 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
source’s compliance account based on
the information in a submission, as
adjusted under paragraph (a)(1) of this
section, and record such deductions and
transfers.
§ 97.629
[Reserved]
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§ 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 § 97.602
and in § 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
§ 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 § 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:
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(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 §§ 75.11
and 75.16 of this chapter);
(2) Successfully complete all
certification tests required under
§ 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. The owner or
operator 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, by 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 dates:
(i) January 1, 2012; or
(ii) 180 calendar days, whichever
occurs first, after the date on which the
unit commences commercial operation.
(3) For 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, by 90 unit
operating days or 180 calendar days,
whichever occurs first, after the date on
which emissions first exit to the
atmosphere through the new stack or
flue or add-on SO2 emissions controls.
(4) Notwithstanding the dates in
paragraphs (b)(1) and (2) of this section,
for the owner or operator of a unit for
which a TR opt-in application is
submitted and not withdrawn and is not
yet approved or disapproved, by the
date specified in § 97.641(c).
(5) Notwithstanding the dates in
paragraphs (b)(1) and (2) of this section,
for the owner or operator of a TR SO2
Group 1 opt-in unit, by the date on
which the TR SO2 Group 1 opt-in unit
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enters the TR SO2 Group 1 Trading
Program as provided in § 97.641(h).
(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 § 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 § 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 emissions to the
atmosphere without accounting for all
such emissions in accordance with the
applicable provisions of this subpart
and part 75 of this chapter.
(3) No owner or operator of a 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 emissions
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 § 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
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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 § 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
§ 75.4(d) of this chapter concerning
units in long-term cold storage.
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§ 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
§ 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
§ 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 § 97.630(a)(1) 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 § 97.630(a)(1). The
owner or operator of a unit that qualifies
to use the low mass emissions excepted
monitoring methodology under § 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 § 97.630(a)(1)
(including the automated data
acquisition and handling system)
successfully completes all of the initial
certification testing required under
§ 75.20 of this chapter by the applicable
deadline in § 97.630(b). In addition,
whenever the owner or operator installs
a monitoring system to meet the
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requirements of this subpart in a
location where no such monitoring
system was previously installed, initial
certification in accordance with § 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 § 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 § 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 § 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
§ 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 § 97.630(a)(1) is subject to the
recertification requirements in
§ 75.20(g)(6) of this chapter.
(3) Approval process for initial
certification and recertification. For
initial certification of a continuous
monitoring system under § 97.630(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 §§ 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 § 97.633.
(ii) Certification application. The
designated representative shall submit
to the Administrator a certification
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application for each monitoring system.
A complete certification application
shall include the information specified
in § 75.63 of this chapter.
(iii) Provisional certification date. The
provisional certification date for a
monitoring system shall be determined
in accordance with § 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. The 120-day
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review period specified in paragraph
(d)(3) of this section shall not begin
before receipt of a complete certification
application.
(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 § 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
§ 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
§ 75.20(a)(4)(iii), § 75.20(g)(7), or
§ 75.21(e) of this chapter and continuing
until the applicable date and hour
specified under § 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.
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(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
§ 75.19 of this chapter shall meet the
applicable certification and
recertification requirements in
§§ 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 § 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 § 75.20(f) of this chapter.
§ 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
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
§ 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 permitting
authority. By issuing the notice of
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45437
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 § 97.631 for each
disapproved monitoring system.
§ 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 § 75.61 of this chapter.
§ 97.634
Recordkeeping and reporting.
(a) General provisions. The designated
representative shall comply with all
recordkeeping and reporting
requirements in this section, the
applicable recordkeeping and reporting
requirements in subparts F and G of part
75 of this chapter, and the requirements
of § 97.614(a).
(b) Monitoring plans. The owner or
operator of a TR SO2 Group 1 unit shall
comply with requirements of § 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 § 97.631, including
the information required under § 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;
(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 § 97.630(b), unless
that quarter is the third or fourth quarter
of 2011, in which case reporting shall
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commence in the quarter covering
January 1, 2012 through March 31, 2012;
(iii) Notwithstanding paragraphs
(d)(1)(i) and (ii) of this section, for a unit
for which a TR opt-in application is
submitted and not withdrawn and is not
yet approved or disapproved, the
calendar quarter corresponding to the
date specified in § 97.641(c); and
(iv) Notwithstanding paragraphs
(d)(1)(i) and (ii) of this section, for a TR
SO2 Group 1 opt-in unit, the calendar
quarter corresponding to the date on
which the TR SO2 Group 1 opt-in unit
enters the TR SO2 Group 1 Trading
Program as provided in § 97.641(h).
(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
§ 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.
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(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 § 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.
§ 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 § 75.66 of this chapter to
the Administrator, requesting approval
to apply an alternative to any
requirement of §§ 97.630 through 97.634
or paragraph (5)(i) or (ii) of the
definition of ‘‘owner’s share’’ in
§ 97.602.
(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
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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.
§ 97.640 General requirements for TR SO2
Group 1 opt-in units.
(a) A TR SO2 Group 1 opt-in unit must
be a unit that:
(1) Is located in a State;
(2) Is not a TR SO2 Group 1 unit under
§ 97.604;
(3) Is not covered by a retired unit
exemption under § 72.8 of this chapter
that is in effect; and
(4) Vents all of its emissions to a stack
and can meet the monitoring,
recordkeeping, and reporting
requirements of this subpart.
(b) A TR SO2 Group 1 opt-in unit shall
be deemed to be a TR SO2 Group 1 unit
for purposes of applying this subpart,
except for §§ 97.605, 97.611, and 97.612.
(c) Solely for purposes of applying the
requirements of §§ 97.613 through
97.618 and §§ 97.630 through 97.635, a
unit for which a TR opt-in application
is submitted and not withdrawn and is
not yet approved or disapproved under
§ 97.642 shall be deemed to be a TR SO2
Group 1 unit.
(d) Any TR SO2 Group 1 opt-in unit,
and any unit for which a TR opt-in
application is submitted and not
withdrawn and is not yet approved or
disapproved under § 97.642, located at
the same source as one or more TR SO2
Group 1 units shall have the same
designated representative and alternate
designated representative as such TR
SO2 Group 1 units.
§ 97.641
Opt-in process.
A unit meeting the requirements for a
TR SO2 Group 1 opt-in unit in
§ 97.640(a) may become a TR SO2 Group
1 opt-in unit only if, in accordance with
this section, the designated
representative of the unit submits a
complete TR opt-in application for the
unit and the Administrator approves the
application.
(a) Applying to opt-in. The designated
representative of the unit may submit a
complete TR opt-in application for the
unit at any time, except as provided
under § 97.642(e). A complete TR opt-in
application shall include the following
elements in a format prescribed by the
Administrator:
(1) Identification of the unit and the
source where the unit is located,
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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, and unit identification
number and type;
(2) A certification that the unit:
(i) Is not a TR SO2 Group 1 unit under
§ 97.604;
(ii) Is not covered by a retired unit
exemption under § 72.8 of this chapter
that is in effect;
(iii) Vents all of its emissions to a
stack; and
(iv) Has documented heat input
(greater than 0 mmBtu) for more than
876 hours during the 6 months
immediately preceding submission of
the TR opt-in application;
(3) A monitoring plan in accordance
with §§ 97.630 through 97.635;
(4) A statement that the unit, if
approved to become a TR SO2 Group 1
unit under paragraph (g) of this section,
may withdraw from the TR SO2 Group
1 Trading Program only in accordance
with § 97.642;
(5) A statement that the unit, if
approved to become a TR SO2 Group 1
unit under paragraph (g) of this section,
is subject to, and the owners and
operators of the unit must comply with,
the requirements of § 97.643;
(6) A complete certificate of
representation under § 97.616 consistent
with § 97.640, if no designated
representative has been previously
designated for the source that includes
the unit; and
(7) The signature of the designated
representative and the date signed.
(b) Interim review of monitoring plan.
The Administrator will determine, on
an interim basis, the sufficiency of the
monitoring plan submitted under
paragraph (a)(3) of this section. The
monitoring plan is sufficient, for
purposes of interim review, if the plan
appears to contain information
demonstrating that the SO2 emission
rate and heat input of the unit and all
other applicable parameters are
monitored and reported in accordance
with §§ 97.630 through 97.635. A
determination of sufficiency shall not be
construed as acceptance or approval of
the monitoring plan.
(c) Monitoring and reporting. (1)(i) If
the Administrator determines that the
monitoring plan is sufficient under
paragraph (b) of this section, the owner
or operator of the unit shall monitor and
report the SO2 emission rate and the
heat input of the unit and all other
applicable parameters, in accordance
with §§ 97.630 through 97.635, starting
on the date of certification of the
necessary monitoring systems under
§§ 97.630 through 97.635 and
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continuing until the TR opt-in
application submitted under paragraph
(a) of this section is disapproved under
this section or, if such TR opt-in
application is approved, the date and
time when the unit is withdrawn from
the TR SO2 Group 1 Trading Program in
accordance with § 97.642.
(ii) The monitoring and reporting
under paragraph (c)(1)(i) of this section
shall cover the entire control period
immediately before the date on which
the unit enters the TR SO2 Group 1
Trading Program under paragraph (h) of
this section, during which period
monitoring system availability must not
be less than 98 percent under §§ 97.630
through 97.635 and the unit must be in
full compliance with any applicable
State or Federal emissions or emissionsrelated requirements.
(2) To the extent the SO2 emission
rate and the heat input of the unit are
monitored and reported in accordance
with §§ 97.630 through 97.635 for one or
more entire control periods, in addition
to the control period under paragraph
(c)(1)(ii) of this section, during which
control periods monitoring system
availability is not less than 98 percent
under §§ 97.630 through 97.635 and the
unit is in full compliance with any
applicable State or Federal emissions or
emissions-related requirements and
which control periods begin not more
than 3 years before the unit enters the
TR SO2 Group 1 Trading Program under
paragraph (h) of this section, such
information shall be used as provided in
paragraphs (e) and (f) of this section.
(d) Statement on compliance. After
submitting to the Administrator all
quarterly reports required for the unit
under paragraph (c) of this section, the
designated representative shall submit,
in a format prescribed by the
Administrator, to the Administrator a
statement that, for the years covered by
such quarterly reports, the unit was in
full compliance with any applicable
State or Federal emissions or emissionsrelated requirements.
(e) Baseline heat input. The unit’s
baseline heat input shall equal:
(1) If the unit’s SO2 emission rate and
heat input are monitored and reported
for only one entire control period, in
accordance with paragraph (c) of this
section, the unit’s total heat input (in
mmBtu) for such control period; or
(2) If the unit’s SO2 emission rate and
heat input are monitored and reported
for more than one entire control period,
in accordance with paragraph (c) of this
section, the average of the amounts of
the unit’s total heat input (in mmBtu)
for such control periods.
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45439
(f) Baseline SO2 emission rate. The
unit’s baseline SO2 emission rate shall
equal:
(1) If the unit’s SO2 emission rate and
heat input are monitored and reported
for only one entire control period, in
accordance with paragraph (c) of this
section, the unit’s SO2 emission rate (in
lb/mmBtu) for such control period;
(2) If the unit’s SO2 emission rate and
heat input are monitored and reported
for more than one entire control period,
in accordance with paragraph (c) of this
section, and the unit does not have addon SO2 emission controls during any
such control periods, the average of the
amounts of the unit’s SO2 emission rate
(in lb/mmBtu) for such control periods;
or
(3) If the unit’s SO2 emission rate and
heat input are monitored and reported
for more than one entire control period,
in accordance with paragraph (c) of this
section, and the unit has add-on SO2
emission controls during any such
control periods, the average of the
amounts of the unit’s SO2 emission rate
(in lb/mmBtu) for such control periods
during which the unit has add-on SO2
emission controls.
(g) Review of TR opt-in application.
(1) After the designated representative
submits the complete TR opt-in
application, quarterly reports, and
statement required in paragraphs (a), (c),
and (d) of this section and if the
Administrator determines that the
designated representative shows that the
unit meets the requirements for a TR
SO2 Group 1 opt-in unit in § 97.640, the
element certified in paragraph (a)(2)(iv)
of this section, and the monitoring and
reporting requirements of paragraph (c)
of this section, the Administrator will
issue a written approval of the TR optin application for the unit. The written
approve will state the unit’s baseline
heat input and baseline SO2 emission
rate. The Administrator will thereafter
establish a compliance account for the
source that includes the unit unless the
source already has a compliance
account.
(2) Notwithstanding paragraphs (a)
through (f) of this section, if, at any time
before the TR opt-in application is
approved under paragraph (g)(1) of this
section, the Administrator determines
that the unit cannot meet the
requirements for a TR SO2 Group 1
opt-in unit in § 97.640, the element
certified in paragraph (a)(2)(iv) of this
section, or the monitoring and reporting
requirements in paragraph (c) of this
section, the Administrator will issue a
written disapproval of the TR opt-in
application for the unit.
(h) Date of entry into TR SO2 Group
1 Trading Program. A unit for which a
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TR opt-in application is approved under
paragraph (g)(1) of this section shall
become a TR SO2 Group 1 opt-in unit,
and a TR SO2 Group 1 unit, effective as
of the later of January 1, 2012, or
January 1 of the first control period
during which such approval is issued.
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§ 97.642 Withdrawal of TR SO2 Group 1
opt-in unit from TR SO2 Group 1 Trading
Program.
A TR SO2 Group 1 opt-in unit may
withdraw from the TR SO2 Group 1
Trading Program only if, in accordance
with this section, the designated
representative of the unit submits a
request to withdraw the unit and the
Administrator issues a written approval
of the request.
(a) Requesting withdrawal. In order to
withdraw the TR SO2 Group 1 opt-in
unit from the TR SO2 Group 1 Trading
Program, the designated representative
of the unit shall submit to the
Administrator a request to withdraw the
unit effective as of midnight of
December 31 of a specified calendar
year, which date must be at least 4 years
after December 31 of the year of the
unit’s entry into the TR SO2 Group 1
Trading Program under § 97.641(h). The
request shall be in a format prescribed
by the Administrator and shall be
submitted no later than 90 days before
the requested effective date of
withdrawal.
(b) Conditions for withdrawal. Before
a TR SO2 Group 1 opt-in unit covered
by the request to withdraw may
withdraw from the TR SO2 Group 1
Trading Program, the following
conditions must be met:
(1) For the control period ending on
the date on which the withdrawal is to
be effective, the source that includes the
TR SO2 Group 1 opt-in unit must meet
the requirement to hold TR SO2 Group
1 allowances under §§ 97.624 and
97.625 and cannot have any excess
emissions.
(2) After the requirement under
paragraph (b)(1) of this section is met,
the Administrator will deduct from the
compliance account of the source that
includes the TR SO2 Group 1 opt-in unit
TR SO2 Group 1 allowances equal in
amount to and allocated for the same or
a prior control period as any TR SO2
Group 1 allowances allocated to the TR
SO2 Group 1 opt-in unit under § 97.644
for any control period after the date on
which the withdrawal is to be effective.
If there are no other TR SO2 Group 1
units at the source, the Administrator
will close the compliance account, and
the owners and operators of the TR SO2
Group 1 opt-in unit may submit a TR
SO2 Group 1 allowance transfer for any
remaining TR SO2 Group 1 allowances
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to another Allowance Management
System account in accordance with
§§ 97.622 and 97.623.
(c) Approving withdrawal. (1) After
the requirements for withdrawal under
paragraphs (a) and (b) of this section are
met (including deduction of the full
amount of TR SO2 Group 1 allowances
required), the Administrator will issue a
written approval of the request to
withdraw, which will become effective
as of midnight on December 31 of the
calendar year for which the withdrawal
was requested. The unit covered by the
request shall continue to be a TR SO2
Group 1 opt-in unit until the effective
date of the withdrawal and shall comply
with all requirements under the TR SO2
Group 1 Trading Program concerning
any control periods for which the unit
is a TR SO2 Group 1 opt-in unit, even
if such requirements arise or must be
complied with after the withdrawal
takes effect.
(2) If the requirements for withdrawal
under paragraphs (a) and (b) of this
section are not met, the Administrator
will issue a written disapproval of the
request to withdraw. The unit covered
by the request shall continue to be a TR
SO2 Group 1 opt-in unit.
(d) Reapplication upon failure to meet
conditions of withdrawal. If the
Administrator disapproves the request
to withdraw, the designated
representative of the unit may submit
another request to withdraw in
accordance with paragraphs (a) and (b)
of this section.
(e) Ability to reapply to the TR SO2
Group 1 Trading Program. Once a TR
SO2 Group 1 opt-in unit withdraws from
the TR SO2 Group 1 Trading Program,
the designated representative may not
submit another opt-in application under
§ 97.641 for such unit before the date
that is 4 years after the date on which
the withdrawal became effective.
§ 97.643
Change in regulatory status.
(a) Notification. If a TR SO2 Group 1
opt-in unit becomes a TR SO2 Group 1
unit under § 97.604, then the designated
representative of the unit shall notify
the Administrator in writing of such
change in the TR SO2 Group 1 opt-in
unit’s regulatory status, within 30 days
of such change.
(b) Administrator’s actions. (1) If a TR
SO2 Group 1 opt-in unit becomes a TR
SO2 Group 1 unit under § 97.604, the
Administrator will deduct, from the
compliance account of the source that
includes the TR SO2 Group 1 opt-in unit
that becomes a TR SO2 Group 1 unit
under § 97.604, TR SO2 Group 1
allowances equal in amount to and
allocated for the same or a prior control
period as:
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(i) Any TR SO2 Group 1 allowances
allocated to the TR SO2 Group 1 opt-in
unit under § 97.644 for any control
period starting after the date on which
the TR SO2 Group 1 opt-in unit becomes
a TR SO2 Group 1 unit under § 97.604;
and
(ii) If the date on which the TR SO2
Group 1 opt-in unit becomes a TR SO2
Group 1 unit under § 97.604 is not
December 31, the TR SO2 Group 1
allowances allocated to the TR SO2
Group 1 opt-in unit under § 97.644 for
the control period that includes the date
on which the TR SO2 Group 1 opt-in
unit becomes a TR SO2 Group 1 unit
under § 97.604—
(A) Multiplied by the ratio of the
number of days, in the control period,
starting with the date on which the TR
SO2 Group 1 opt-in unit becomes a TR
SO2 Group 1 unit under § 97.604,
divided by the total number of days in
the control period, and
(B) Rounded to the nearest allowance.
(2) The designated representative
shall ensure that the compliance
account of the source that includes the
TR SO2 Group 1 opt-in unit that
becomes a TR SO2 Group 1 unit under
§ 97.604 contains the TR SO2 Group 1
allowances necessary for completion of
the deduction under paragraph (b)(1) of
this section.
(3)(i) For control periods starting after
the date on which the TR SO2 Group 1
opt-in unit becomes a TR SO2 Group 1
unit under § 97.604, the TR SO2 Group
1 opt-in unit will be allocated TR SO2
Group 1 allowances in accordance with
§ 97.612.
(ii) If the date on which the TR SO2
Group 1 opt-in unit becomes a TR SO2
Group 1 unit under § 97.604 is not
December 31, the following amount of
TR SO2 Group 1 allowances will be
allocated to the TR SO2 Group 1 opt-in
unit (as a TR SO2 Group 1 unit) in
accordance with § 97.612 for the control
period that includes the date on which
the TR SO2 Group 1 opt-in unit becomes
a TR SO2 Group 1 unit under § 97.604:
(A) The amount of TR SO2 Group 1
allowances otherwise allocated to the
TR SO2 Group 1 opt-in unit (as a TR SO2
Group 1 unit) in accordance with
§ 97.612 for the control period;
(B) Multiplied by the ratio of the
number of days, in the control period,
starting with the date on which the TR
SO2 Group 1 opt-in unit becomes a TR
SO2 Group 1 unit under § 97.604,
divided by the total number of days in
the control period; and
(C) Rounded to the nearest allowance.
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§ 97.644 TR SO2 Group 1 allowance
allocations to TR SO2 Group 1 opt-in units.
(a) Timing requirements. (1) When the
TR opt-in application is approved for a
unit under § 97.641(g), the
Administrator will issue TR SO2 Group
1 allowances and allocate them to the
unit for the control period in which the
unit enters the TR SO2 Group 1 Trading
Program under § 97.641(h), in
accordance with paragraph (b) of this
section.
(2) By no later than October 31 of the
control period after the control period in
which a TR SO2 Group 1 opt-in unit
enters the TR SO2 Group 1 Trading
Program under § 97.641(h) and October
31 of each year thereafter, the
Administrator will issue TR SO2 Group
1 allowances and allocate them to the
TR SO2 Group 1 opt-in unit for the
control period that includes such
allocation deadline and in which the
unit is a TR SO2 Group 1 opt-in unit, in
accordance with paragraph (b) of this
section.
(b) Calculation of allocation. For each
control period for which a TR SO2
Group 1 opt-in unit is to be allocated TR
SO2 Group 1 allowances, the
Administrator will issue and allocate TR
SO2 Group 1 allowances in accordance
with the following procedures:
(1) The heat input (in mmBtu) used
for calculating the TR SO2 Group 1
allowance allocation will be the lesser
of:
(i) The TR SO2 Group 1 opt-in unit’s
baseline heat input determined under
§ 97.641(g); or
(ii) The TR SO2 Group 1 opt-in unit’s
heat input, as determined in accordance
with §§ 97.630 through 97.635, for the
immediately prior control period,
except when the allocation is being
calculated for the control period in
which the TR SO2 Group 1 opt-in unit
enters the TR SO2 Group 1 Trading
Program under § 97.641(h).
(2) The SO2 emission rate (in lb/
mmBtu) used for calculating TR SO2
Group 1 allowance allocations will be
the lesser of:
(i) The TR SO2 Group 1 opt-in unit’s
baseline SO2 emission rate (in lb/
mmBtu) determined under § 97.641(g)
and multiplied by 70 percent; or
(ii) The most stringent State or
Federal SO2 emissions limitation
applicable to the TR SO2 Group 1 optin unit at any time during the control
period for which TR SO2 Group 1
allowances are to be allocated.
(3) The Administrator will issue TR
SO2 Group 1 allowances and allocate
them to the TR SO2 Group 1 opt-in unit
in an amount equaling the heat input
under paragraph (b)(1) of this section,
multiplied by the SO2 emission rate
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under paragraph (b)(2) of this section,
divided by 2,000 lb/ton, and rounded to
the nearest allowance.
(c) Recordation. (1) The Administrator
will record, in the compliance account
of the source that includes the TR SO2
Group 1 opt-in unit, the TR SO2 Group
1 allowances allocated to the TR SO2
Group 1 opt-in unit under paragraph
(a)(1) of this section.
(2) By December 1 of the control
period after the control period in which
a TR SO2 Group 1 opt-in unit enters the
TR SO2 Group 1 Trading Program under
§ 97.641(h) and December 1 of each year
thereafter, the Administrator will
record, in the compliance account of the
source that includes the TR SO2 Group
1 opt-in unit, the TR SO2 Group 1
allowances allocated to the TR SO2
Group 1 opt-in unit under paragraph
(a)(2) of this section.
38. 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, and variability
limits.
97.711 Timing requirements for TR SO2
Group 2 allowance allocations.
97.712 TR SO2 Group 2 allowance
allocations for 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 Allowance
Management System 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.
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45441
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.
97.740 General requirements for TR SO2
Group 2 opt-in units.
97.741 Opt-in process.
97.742 Withdrawal of TR SO2 Group 2 optin unit from TR SO2 Group 2 Trading
Program.
97.743 Change in regulatory status.
97.744 TR SO2 Group 2 allowance
allocations to TR SO2 Group 2 opt-in
units.
Subpart DDDDD—TR SO2 Group 2
Trading Program
§ 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 § 52.38(b) of this
chapter, as a means of mitigating
interstate transport of fine particulates
and nitrogen oxides.
§ 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 multistate 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) 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
of the amount of such TR SO2 Group 2
allowances to be initially credited to a
TR SO2 Group 2 source or a new unit
set-aside.
Allowable SO2 emission rate means,
with regard to a unit, the SO2 emission
rate limit that is applicable to the unit
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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, held,
deducted, or transferred only as whole
allowances. The Allowance
Management System is a component of
the CAMD Business System, which is
the system used by the Administrator to
handle TR SO2 Group 2 allowances and
data related to SO2 emissions.
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, 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 Annual emissions limitation for
such control period in accordance with
§ 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
Season 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
§ 72.2 of this chapter, § 97.402, or
§ 97.502 respectively.
Authorized account representative
means, with regard to 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, with regard to 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
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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.
Certifying official means a natural
person who is:
(1) For a corporation, a president,
secretary, treasurer, or vice-president or
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 any solid fuel classified as
anthracite, bituminous, subbituminous,
or lignite.
Coal-derived fuel means any fuel
(whether in a solid, liquid, or gaseous
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state) produced by the mechanical,
thermal, or chemical processing of coal.
Coal-fired means combusting any
amount of coal or coal-derived fuel,
alone or in combination with any
amount of any other fuel, during 1990
or any year thereafter.
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—
(1) Operating as part of a cogeneration
system; and
(2) Producing during the later of 1990
or the 12-month period starting on the
date that the unit first produces
electricity and during each calendar
year after the later of 1990 or the
calendar year in which the unit first
produces electricity—
(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 then 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 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
(4) Provided that, if a topping-cycle
unit is operated as part of a cogeneration
system during a calendar year and the
cogeneration system meets on a systemwide basis the requirement in paragraph
(2)(i)(B) of this definition, the toppingcycle unit shall be deemed to meet such
requirement during that 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
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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 § 97.705.
(i) For a unit that is a TR SO2 Group
2 unit under § 97.704 on the later of
November 15, 1990 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 (other than replacement of the
unit by a unit at the same 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 § 97.704 on the later of
November 15, 1990 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 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 § 97.705, for a unit that is not a TR
SO2 Group 2 unit under § 97.704 on the
later of November 15, 1990 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 § 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
and that subsequently undergoes a
physical change (other than replacement
of the unit by a unit at the same 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 source, such date shall
remain the replaced unit’s date of
commencement of commercial
operation, and the replacement unit
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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.
Commence operation means, with
regard to a unit:
(1) To have begun any mechanical,
chemical, or electronic process,
including start-up of the unit’s
combustion chamber.
(2) For a unit that undergoes a
physical change (other than replacement
of the unit by a unit at the same source)
after the date the unit commences
operation as defined in paragraph (1) of
this definition, such date shall remain
the date of commencement of operation
of the unit, which shall continue to be
treated as the same unit.
(3) For a unit that is replaced by a unit
at the same source after the date the unit
commences operation as defined in
paragraph (1) of this definition, such
date shall remain the replaced unit’s
date of commencement of operation,
and the replacement unit shall be
treated as a separate unit with a separate
date for commencement of operation as
defined in paragraph (1), (2), or (3) of
this definition as appropriate.
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
for 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
complying with the source’s TR SO2
Group 2 emissions limitation in
accordance with § 97.724 and the TR
SO2 Group 2 assurance provisions in
accordance with § 97.725.
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 §§ 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
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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 § 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 § 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
natural person as the designated
representative, as defined in § 72.2 of
this chapter, § 97.402, or § 97.502
respectively.
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 in
accordance with this subpart.
Excess emissions means any ton of
SO2 emitted from the TR SO2 Group 2
units at a TR SO2 Group 2 source during
a control period that exceeds the TR SO2
Group 2 emissions limitation for the
source.
Fossil fuel means—
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(1) Natural gas, petroleum, coal, or
any form of solid, liquid, or gaseous fuel
derived from such material; or
(2) For purposes of applying
§§ 97.704(b)(2)(i)(B), 97.704(b)(2)(ii)(B),
and 97.704(b)(2)(iii), 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 1990 or any calendar year
thereafter.
Fuel oil means any petroleum-based
fuel (including diesel fuel or petroleum
derivatives such as oil tar) and any
recycled or blended petroleum products
or petroleum by-products used as a fuel
whether in a liquid, solid, or gaseous
state.
General account means an Allowance
Management System account,
established under this subpart, that is
not a compliance account.
Generator means a device that
produces electricity.
Gross electrical output means, with
regard to 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, with regard to a
unit for a specified period of time, the
product (in mmBtu/time) of the gross
calorific value of the fuel (in mmBtu/lb)
multiplied by the fuel feed rate into a
combustion device (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 the amount of
heat input (in mmBtu) divided by unit
operating time (in hr) or, with regard to
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.
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;
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(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
the maximum amount of fuel per hour
(in Btu/hr) that a 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) 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
(in MWe) 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 as of such completion as
specified by the person conducting the
physical change.
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 any person who
operates, controls, or supervises a TR
SO2 Group 2 unit or a TR SO2 Group 2
source and shall include, but not be
limited to, any holding company, utility
system, or plant manager of such a unit
or source.
Owner means, with regard to 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
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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;
(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-theunit, firm power contractual
arrangement;
(4) Provided that, for purposes of
applying the TR SO2 Group 2 assurance
provisions in §§ 97.706(c)(2) and 97.725,
if one or more owners (as defined in
paragraphs (1) through (3) of this
definition) of one or more TR SO2 Group
2 units in a State are wholly owned by
another, common owner, all such
owners shall be treated collectively as a
single owner in the State.
Owner’s assurance level means:
(1) With regard to a State and control
period for which the State assurance
level is exceeded as described in
§ 97.706(c)(2)(iii)(A) and not as
described in § 97.706(c)(2)(iii)(B), the
owner’s share of the State SO2 Group 2
trading budget with the one-year
variability limit for the State for such
control period; or
(2) With regard to a State and control
period for which the State assurance
level is exceeded as described in
§ 97.706(c)(2)(iii)(B), the owner’s share
of the State SO2 Group 2 trading budget
with the three-year variability limit for
the State for such control period.
Owner’s share means:
(1) With regard to a total amount of
SO2 emissions from all TR SO2 Group 2
units in a State during a control period,
the total tonnage of SO2 emissions
during such control period from all of
the owner’s TR SO2 Group 2 units in the
State;
(2) With regard to a State SO2 Group
2 trading budget with a one-year
variability limit for a control period, the
amount (rounded to the nearest
allowance) equal to the total amount of
TR SO2 Group 2 allowances allocated
for such control period to all of the
owner’s TR SO2 Group 2 units in the
State, multiplied by the sum of the State
SO2 Group 2 trading budget under
§ 97.710(a) and the State’s one-year
variability limit under § 97.710(b) and
divided by such State SO2 Group 2
trading budget;
(3) With regard to a State SO2 Group
2 trading budget with a three-year
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variability limit for a control period, the
amount (rounded to the nearest
allowance) equal to the total amount of
TR SO2 Group 2 allowances allocated
for such control period to all of the
owner’s TR SO2 Group 2 units in the
State, multiplied by the sum of the State
SO2 Group 2 trading budget under
§ 97.710(a) and the State’s three-year
variability limit under § 97.710(b) and
divided by such State SO2 Group 2
trading budget;
(4) Provided that, in the case of a unit
with more than one owner, the amount
of tonnage of SO2 emissions and of TR
SO2 Group 2 allowances allocated for a
control period, with regard to such unit,
used in determining each owner’s share
shall be the amount (rounded to the
nearest ton and the nearest allowance)
equal to the unit’s SO2 emissions and
allocation of such allowances,
respectively, for such control period
multiplied by the percentage of
ownership in the unit that the owner’s
legal, equitable, leasehold, or
contractual reservation or entitlement in
the unit comprises as of December 31 of
such control period;
(5) Provided that, where two or more
units emit through a common stack that
is the monitoring location from which
SO2 mass emissions are reported for a
control period for a year, the amount of
tonnage of each unit’s SO2 emissions
used in determining each owner’s share
for such control period shall be:
(i) The amount (rounded to the
nearest ton) of SO2 emissions reported
at the common stack multiplied by the
quotient of such unit’s heat input for
such control period divided by the total
heat input reported from the common
stack for such control period;
(ii) An amount determined in
accordance with a methodology that the
Administrator determines is consistent
with the purposes of this definition and
whose adverse effect (if any) the
Administrator determines will be de
minimis; or
(iii) An amount approved by the
Administrator in response to a petition
for an alternative requirement submitted
in accordance with § 97.735; and
(6) Provided that, in the case of a unit
that operates during, but is allocated no
TR SO2 Group 2 allowances for, a
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 lesser of—
(i) The unit’s allowable SO2 emission
rate (in lb per MWe) applicable to such
control period, multiplied by a capacity
factor of 0.84 (if the unit is a coal-fired
boiler), 0.15 (if the unit is a simple
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combustion turbine), or 0.66 (if the unit
is a combined cycle turbine), 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; or
(ii) For a unit listed in appendix A to
this subpart, the sum of the unit’s SO2
emissions in the control period in the
last three years during which the unit
operated during the control period,
divided by three.
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
§§ 70.2 and 71.2 of this chapter.
Potential electrical output capacity
means 33 percent of a 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 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,
transfer, or deduction.
Reference method means any direct
test method of sampling and analyzing
for an air pollutant as specified in
§ 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) For a topping-cycle unit, the use
of reject heat from electricity production
in a useful thermal energy application
or process; or
(2) For a bottoming-cycle unit, 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
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45445
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 or the
District of Columbia that is subject to
the TR SO2 Group 2 Trading Program
pursuant to § 52.38(c) 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 total energy
of all forms supplied to a 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 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 by the Administrator in
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accordance with subpart AAAAA and
52.37(a) 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 by the
Administrator in accordance with
subpart BBBBB of this part and 52.37(b)
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 by the Administrator under
this subpart to emit one ton of SO2
during a control period of the specified
calendar year for which the
authorization is allocated 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 assurance
provisions.
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 § 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 by the Administrator in
accordance with this subpart and
52.38(c) of this chapter, as a means of
mitigating interstate transport of fine
particulates and SO2.
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TR SO2 Group 2 unit means a unit
that is subject to the TR SO2 Group 2
Trading Program under § 97.704.
Unit means a stationary, fossil-fuelfired boiler, stationary, fossil-fuel-fired
combustion turbine, or other stationary,
fossil-fuel-fired combustion device.
Unit operating day means a calendar
day in which a unit combusts any fuel.
Unit operating hour or hour of unit
operation means an hour in which a
unit combusts any fuel.
Useful power means electricity or
mechanical energy that a 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.
§ 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
§ 97.704
Applicability.
(a) Except as provided in paragraph
(b) of this section:
(1) The following units in a 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
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boiler or stationary, fossil-fuel-fired
combustion turbine serving at any time,
since the later of November 15, 1990 or
the start-up of the unit’s combustion
chamber, 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 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), (b)(2)(i), or (b)(2)(ii)
of this section shall not be a TR SO2
Group 2 unit:
(1)(i) Any unit:
(A) Qualifying as a cogeneration unit
during the later of 1990 or the 12-month
period starting on the date the unit first
produces electricity and continuing to
qualify as a cogeneration unit; and
(B) Not serving at any time, since the
later of November 15, 1990 or the startup of the unit’s combustion chamber, a
generator with nameplate capacity of
more than 25 MWe supplying in any
calendar year 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 a unit qualifies as a cogeneration
unit during the later of 1990 or the
12-month period starting on the date the
unit first produces electricity and meets
the requirements of paragraphs (b)(1)(i)
of this section for at least one calendar
year, but subsequently no longer meets
such qualification and requirements, 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.
(2)(i) Any unit commencing operation
before January 1, 1985:
(A) Qualifying as a solid waste
incineration unit during the later of
1990 or the 12-month period starting on
the date the unit first produces
electricity and continuing to qualify as
a solid waste incineration unit; and
(B) With an average annual fuel
consumption of fossil fuel for 1985–
1987 less than 20 percent (on a Btu
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basis) and an average annual fuel
consumption of fossil fuel for any 3
consecutive calendar years after 1990
less than 20 percent (on a Btu basis).
(ii) Any unit commencing operation
on or after January 1, 1985:
(A) Qualifying as a solid waste
incineration unit during the later of
1990 or the 12-month period starting on
the date the unit first produces
electricity and continuing to qualify as
a solid waste incineration unit; and
(B) With an average annual fuel
consumption of fossil fuel for the first
3 calendar years of operation less than
20 percent (on a Btu basis) and an
average annual fuel consumption of
fossil fuel for any 3 consecutive
calendar years after 1990 less than 20
percent (on a Btu basis).
(iii) If a unit qualifies as a solid waste
incineration unit during the later of
1990 or the 12-month period starting on
the date the unit first produces
electricity and meets the requirements
of paragraph (b)(2)(i) or (ii) of this
section for at least 3 consecutive
calendar years, but subsequently no
longer meets such qualification and
requirements, 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
1990 for which the unit has an average
annual fuel consumption of fossil fuel of
20 percent or more.
(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, 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
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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
2 Trading Program to the unit or other
equipment shall be binding on any
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.
§ 97.705
Retired unit exemption.
(a)(1) Any TR SO2 Group 2 unit that
is permanently retired and is not a TR
SO2 Group 2 opt-in unit shall be exempt
from § 97.706(b) and (c)(1), § 97.724,
and §§ 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
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45447
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.
§ 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
§§ 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 §§ 97.730
through 97.735.
(2) The emissions data determined in
accordance with §§ 97.730 through
97.735 shall be used to calculate
allocations of TR SO2 Group 2
allowances under §§ 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
§§ 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, 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 § 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.
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(ii) If a TR SO2 Group 2 source emits
SO2 during any control period 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 § 97.724(d) and pay
any fine, penalty, or assessment or
comply with any other remedy imposed,
for the same violations, under the Clean
Air Act; and
(B) 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 the total amount of SO2
emissions from all TR SO2 Group 2
units in a State during a control period
in 2014 or any year thereafter exceeds
the State assurance level as described in
paragraph (c)(2)(iii) of this section, then
each owner whose share of such SO2
emissions during such control period
exceeds the owner’s assurance level for
the State and such control period shall
hold, in a compliance account
designated by the owner in accordance
with § 97.725(b)(4)(ii), TR SO2 Group 2
allowances available for deduction for
such control period under § 97.725(a) in
an amount equal to the product, as
determined by the Administrator in
accordance with § 97.725(b), of
multiplying—
(A) The quotient (rounded to the
nearest whole number) of the amount by
which the owner’s share of such SO2
emissions exceeds the owner’s
assurance level divided by the sum of
the amounts, determined for all such
owners, by which each owner’s share of
such SO2 emissions exceeds that
owner’s assurance level; and
(B) The amount by which total SO2
emissions for all TR SO2 Group 2 units
in the State for such control period
exceed the State assurance level as
determined in accordance with
paragraph (c)(2)(iii) of this section.
(ii) The owner 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) The total amount of SO2
emissions from all TR SO2 Group 2
units in a State during a control period
in 2014 or any year thereafter exceeds
the State assurance level:
(A) If such total amount of SO2
emissions exceeds the sum, for such
control period, of the State SO2 Group
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2 trading budget and the State’s oneyear variability limit under § 97.710(b);
or
(B) If, with regard to a control period
in 2016 or any year thereafter, the sum,
divided by three, of such total amount
of SO2 emissions and the total amounts
of SO2 emissions from all TR SO2 Group
2 units in the State during the control
periods in the immediately preceding
two years exceeds the sum, for such
control period, of the State SO2 Group
2 trading budget and the State’s threeyear variability limit under § 97.710(b);
(C) Provided that the amount by
which such total amount of SO2
emissions exceeds the State assurance
level shall be the greater of the amounts
of the exceedance calculated under
paragraph (c)(2)(iii)(A) of this section
and under paragraph (c)(2)(iii)(B) of this
section.
(iv) It shall not be a violation of this
subpart or of the Clean Air Act if the
total amount of SO2 emissions from all
TR SO2 Group 2 units in a State during
a control period exceeds the State
assurance level or if an owner’s share of
total SO2 emissions from the TR SO2
Group 2 units in a State during a control
period exceeds the owner’s assurance
level.
(v) To the extent an owner fails to
hold TR SO2 Group 2 allowances for a
control period in accordance with
paragraphs (c)(2)(i) and (ii) of this
section,
(A) The owner 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 owner fails to hold for a control
period in accordance with paragraphs
(c)(2)(i) and (ii) 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:
(i) Under paragraph (c)(1) 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
§ 97.730(b) and for each control period
thereafter; and
(ii) Under paragraph (c)(2) of this
section for the control period starting on
the later of January 1, 2014 or the
deadline for meeting the unit’s monitor
certification requirements under
§ 97.730(b) and for each control period
thereafter.
(4) Vintage of deducted allowances. A
TR SO2 Group 2 allowance shall not be
deducted, for compliance with the
requirements under paragraphs (c)(1)
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and (2) of this section, for a control
period in a calendar year before the year
for which the TR SO2 Group 2
allowance was allocated.
(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. (i) A TR
SO2 Group 2 allowance is a limited
authorization to emit one ton of SO2 in
accordance with the TR SO2 Group 2
Trading Program.
(ii) Notwithstanding any other
provision of this subpart, the
Administrator has the authority to
terminate or limit 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 §§ 75.10,
75.11, and 75.16 of this chapter), an
excepted monitoring system (under
appendix D to part 75 of this chapter),
a low mass emissions excepted
monitoring methodology (under § 75.19
of this chapter), or an alternative
monitoring system (under subpart E of
part 75 of this chapter) in accordance
with §§ 97.730 through 97.735 may be
added to, or changed in, a title V permit
using minor permit modification
procedures in accordance with
§§ 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 §§ 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
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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 § 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
documents are superseded because of
the submission of a new certificate of
representation under § 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, including any
monitoring plans and monitoring
system certification and recertification
applications.
(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,
including any submissions required for
compliance with the TR SO2 Group 2
assurance provisions. 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 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
§ 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.
§ 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, falls on
a weekend or a State or Federal holiday,
the time period shall be extended to the
next business day.
§ 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.
§ 97.709
[Reserved]
§ 97.710 State SO2 Group 2 trading
budgets, new-unit set-asides, and variability
limits.
(a) The State SO2 Group 2 trading
budgets and 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
trading budget
(tons) *
For 2012 and
thereafter
State
New-unit
set-aside
(tons)
For 2012 and
thereafter
Alabama ...........................................................................................................................................................
Connecticut ......................................................................................................................................................
Delaware ..........................................................................................................................................................
District of Columbia .........................................................................................................................................
Florida ..............................................................................................................................................................
Kansas .............................................................................................................................................................
Louisiana ..........................................................................................................................................................
Maryland ..........................................................................................................................................................
Massachusetts .................................................................................................................................................
Minnesota ........................................................................................................................................................
Nebraska ..........................................................................................................................................................
New Jersey ......................................................................................................................................................
South Carolina .................................................................................................................................................
161,871
3,059
7,784
337
161,739
57,275
90,477
39,665
7,902
47,101
71,598
11,291
116,483
4,856
92
234
10
4,852
1,718
2,714
1,190
237
1,413
2,148
339
3,494
Total ..........................................................................................................................................................
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* Without variability limits.
(b) The States’ one-year and three-year
variability limits for the State SO2
Group 2 trading budgets for the control
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periods in 2014 and thereafter are as
follows:
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One-year
variability
limits
Three-year
variability
limits
2014 and thereafter
(tons)
2016 and
thereafter
(tons)
State
Alabama ...........................................................................................................................................................
Connecticut ......................................................................................................................................................
Delaware ..........................................................................................................................................................
District of Columbia .........................................................................................................................................
Florida ..............................................................................................................................................................
Kansas .............................................................................................................................................................
Louisiana ..........................................................................................................................................................
Maryland ..........................................................................................................................................................
Massachusetts .................................................................................................................................................
Minnesota ........................................................................................................................................................
Nebraska ..........................................................................................................................................................
New Jersey ......................................................................................................................................................
South Carolina .................................................................................................................................................
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§ 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 set forth in appendix A to
this subpart. Listing a unit in such
appendix does not constitute a
determination that the unit is a TR SO2
Group 2 unit, and not listing a unit in
such appendix 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 listed in
appendix A to this subpart as being
allocated TR SO2 Group 2 allowances
does not operate, starting after 2011,
during the control period in three
consecutive years, such unit will not be
allocated the TR SO2 Group 2
allowances set forth in appendix A to
this subpart for the unit for the control
periods in the seventh year after the first
such year and in each year after that
seventh 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 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.
(b) New units. (1) By July 1, 2012, and
July 1 of each year thereafter, the
Administrator will calculate the TR SO2
Group 2 allowance allocation for each
TR SO2 Group 2 unit, in accordance
with § 97.712, for the control period in
the year of the applicable calculation
deadline under this paragraph and will
promulgate a notice of availability of the
results of the calculations.
(2) For each notice of data availability
required in paragraph (b)(1) of this
section, the Administrator will provide
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an opportunity for submission of
objections to the calculations referenced
in such notice.
(i) Objections shall be submitted by
the deadline specified in such notice
and shall be limited to addressing
whether the calculations are in
accordance with § 97.712 and
§§ 97.706(b)(2) and 97.730 through
97.735.
(ii) 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)(i) of this section. By September 1
immediately after the promulgation of
such notice, the Administrator will
promulgate a notice of 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)(i) of this section.
(c) Units that are not TR SO2 Group
2 units. 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 for the
control period to a recipient that is not
actually a TR SO2 Group 2 unit under
§ 97.704 as of January 1, 2012, or whose
deadline for meeting monitor
certification requirements under
§ 97.730(b)(1) and (2) is after January 1,
2012, or if the Administrator determines
that TR SO2 Group 2 allowances were
allocated under paragraph (b) of this
section and § 97.712 for the control
period to a recipient that is not actually
a TR SO2 Group 2 unit under § 97.704
as of January 1 of the control period,
then the Administrator will notify the
designated representative and will act in
accordance with the following
procedures:
(1) Except as provided in paragraph
(c)(2) or (3) of this section, the
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16,187
1,700
1,700
1,700
16,174
5,728
9,048
3,967
1,700
4,710
7,160
1,700
11,648
9,346
981
981
981
9,338
3,307
5,224
2,290
981
2,719
4,134
981
6,725
Administrator will not record such TR
SO2 Group 2 allowances under § 97.721.
(2) If the Administrator already
recorded such TR SO2 Group 2
allowances under § 97.721 and if the
Administrator makes such
determination before making deductions
for the source that includes such
recipient under § 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.
(3) If the Administrator already
recorded such TR SO2 Group 2
allowances under § 97.721 and if the
Administrator makes such
determination after making deductions
for the source that includes such
recipient under § 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.
(4) The Administrator will transfer the
TR SO2 Group 2 allowances that are not
recorded, or that are deducted, in
accordance with paragraphs (c)(1) and
(2) of this section to the new unit setaside, for the State in which such
recipient is located, for the control
period in the year of such transfer if the
notice required in paragraph (b)(1) of
this section for the control period in that
year has not been promulgated or, such
notice has been promulgated, in the
next year.
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§ 97.712 TR SO2 Group 2 allowance
allocations for new units.
(a) For each control period in 2012
and thereafter, the Administrator will
allocate, in accordance with the
following procedures, TR SO2 Group 2
allowances to TR SO2 Group 2 units in
a State that are not listed in appendix
A to this subpart, to TR SO2 Group 2
units that are so listed and whose
allocation of SO2 Group 2 allowances
for such control period is covered by
§ 97.711(c)(1) or (2), and to TR SO2
Group 2 units that are so listed and,
pursuant to § 97.711(a)(2), are not
allocated TR SO2 Group 2 allowances
for such control period but that operate
during the immediately preceding
control period:
(1) The Administrator will establish a
separate new unit set-aside for each
State for each control period in a given
year. Each 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 § 97.710(a). Each new unit setaside will be allocated additional TR
SO2 Group 2 allowances in accordance
with § 97.711(a)(2) and (c)(4).
(2) The designated representative of
such TR SO2 Group 2 unit may submit
to the Administrator a request, in a
format prescribed by the Administrator,
to be allocated TR SO2 Group 2
allowances for a control period, starting
with the later of the control period in
2012, the first control period after the
control period in which the TR SO2
Group 2 unit commences commercial
operation (for a unit not listed in
appendix A to this subpart), or the first
control period after the control period in
which the unit resumes operation (for a
unit listed in appendix A of this
subpart) and for each subsequent
control period.
(i) The request must be submitted on
or before May 1 of the first control
period for which TR SO2 Group 2
allowances are sought and after the date
on which the TR SO2 Group 2 unit
commences commercial operation (for a
unit not listed in appendix A of this
subpart) or on which the unit resumes
operation (for a unit listed in appendix
A of this subpart).
(ii) For each control period for which
an allocation is sought, the request must
be for TR SO2 Group 2 allowances in an
amount equal to the unit’s total tons of
SO2 emissions during the immediately
preceding control period.
(3) The Administrator will review
each TR SO2 Group 2 allowance
allocation request under paragraph
(a)(2) of this section and will accept the
request only if it meets the requirements
of paragraph (a)(2) of this section. The
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Administrator will allocate TR SO2
Group 2 allowances for each control
period pursuant to an accepted request
as follows:
(i) After May 1 of such control period,
the Administrator will determine the
sum of the TR SO2 Group 2 allowances
requested in all accepted allowance
allocation requests for such control
period.
(ii) If the amount of TR SO2 Group 2
allowances in the new unit set-aside for
such control period is greater than or
equal to the sum under paragraph
(a)(3)(i) of this section, then the
Administrator will allocate the amount
of TR SO2 Group 2 allowances requested
to each TR SO2 Group 2 unit covered by
an accepted allowance allocation
request.
(iii) If the amount of TR SO2 Group 2
allowances in the new unit set-aside for
such control period is less than the sum
under paragraph (a)(3)(i) of this section,
then the Administrator will allocate to
each TR SO2 Group 2 unit covered by
an accepted allowance allocation
request the amount of the TR SO2 Group
2 allowances requested, multiplied by
the amount of TR SO2 Group 2
allowances in the new unit set-aside for
such control period, divided by the sum
determined under paragraph (a)(3)(i) of
this section, and rounded to the nearest
allowance.
(iv) The Administrator will notify,
through the promulgation of the notices
of data availability described in
§ 97.711(b), each designated
representative that submitted an
allowance allocation request of the
amount of TR SO2 Group 2 allowances
(if any) allocated for such control period
to the TR SO2 Group 2 unit covered by
the request.
(b) If, after completion of the
procedures under paragraph (a)(4) of
this section for a control period, any
unallocated TR SO2 Group 2 allowances
remain in the new unit set-aside under
paragraph (a) of this section for a State
for such control period, the
Administrator will allocate to each TR
SO2 Group 2 unit that is in the State, is
listed in appendix A to this subpart, and
continues to be allocated TR SO2 Group
2 allowances for such control period in
accordance with § 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 § 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 amount of tons in
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45451
such new unit set-aside, and rounded to
the nearest allowance.
§ 97.713 Authorization of designated
representative and alternate designated
representative.
(a) Except as provided under § 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
§ 97.716(a)(4)(iii).
(2) Upon and after receipt by the
Administrator of a complete certificate
of representation under § 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 § 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 § 97.716(a)(4)(iii).
(2) Upon and after receipt by the
Administrator of a complete certificate
of representation under § 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,
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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, § 97.702,
and §§ 97.714 through 97.718, whenever
the term ‘‘designated representative’’ is
used in this subpart, the term shall be
construed to include the designated
representative or any alternate
designated representative.
§ 97.714 Responsibilities of designated
representative and alternate designated
representative.
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(a) Except as provided under § 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
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 § 97.718.
§ 97.715 Changing designated
representative and alternate designated
representative; changes in owners and
operators.
(a) Changing designated
representative. The designated
representative may be changed at any
time upon receipt by the Administrator
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of a superseding complete certificate of
representation under § 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 § 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 is not included in the list
of owners and operators in the
certificate of representation under
§ 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, including the addition of a new
owner or operator, the designated
representative or any alternate
designated representative shall submit a
revision to the certificate of
representation under § 97.716 amending
the list of owners and operators to
include the change.
§ 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
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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, and actual or
projected date of commencement of
commercial operation.
(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 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-theunit, 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
allowances by contract, TR SO2 Group
2 allowances and proceeds of
transactions involving TR SO2 Group 2
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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.
§ 97.717 Objections concerning
designated representative and alternate
designated representative.
(a) Once a complete certificate of
representation under § 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 § 97.716 is
received by the Administrator.
(b) Except as provided in § 97.715(a)
or (b), 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.
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§ 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
make an electronic submission to the
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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 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
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45453
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.
§ 97.719
[Reserved]
§ 97.720 Establishment of Allowance
Management System accounts.
(a) Compliance accounts. Upon
receipt of a complete certificate of
representation under § 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) 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
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
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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
order or decision 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.
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(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
order or decision issued to the
authorized account representative or
alternate authorized account
representative by the Administrator
regarding the general account.
(ii) Except as provided in paragraph
(b)(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
(b)(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
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Sfmt 4702
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 (b)(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 of a new 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 (b)(1)
of this section has been submitted and
received, the Administrator will rely on
the application unless and until a
superseding complete application for a
general account under paragraph (b)(1)
of this section is received by the
Administrator.
(ii) Except as provided in paragraph
(b)(3)(i) or (ii) of this section, no
objection or other communication
submitted to the Administrator
concerning the authorization, or any
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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
make an electronic submission to the
Administrator in accordance with
paragraph (b)(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
as an ‘‘agent’’);
(C) For each such natural person, a
list of the type or types of electronic
submissions under paragraph (b)(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
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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(b)(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(b)(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(b)(5) is terminated.’’.
(iv) A notice of delegation submitted
under paragraph (b)(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
(b)(5)(iii)(D) of this section and made in
accordance with a notice of delegation
effective under paragraph (b)(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)(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 § 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
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45455
may notify the authorized account
representative for the account that the
account will be closed 20 business days
after the notice is sent. The account will
be closed after the 20-day period unless,
before the end of the 20-day period, the
Administrator receives a correctly
submitted TR SO2 Group 2 allowance
transfer under § 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.
(c) Account identification. The
Administrator will assign a unique
identifying number to each account
established under paragraph (a) or (b) of
this section.
(d) Responsibilities of authorized
account representative and alternate
authorized account representative. After
the establishment of an Allowance
Management System 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 §§ 97.714(a)
and 97.718 or paragraphs (b)(2)(ii) and
(b)(5) of this section.
§ 97.721 Recordation of TR SO2 Group 2
allowance allocations.
(a) By September 1, 2011, the
Administrator will record in each TR
SO2 Group 2 source’s compliance
account the TR SO2 Group 2 allowances
allocated for the TR SO2 Group 2 units
at the source in accordance with
§§ 97.711(a) for the control periods in
2012, 2013, and 2014.
(b) By June 1, 2012 and June 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 for the TR SO2
Group 2 units at the source in
accordance with § 97.711(a) for the
control period in the third year after the
year of the applicable recordation
deadline under this paragraph.
(c) By September 1, 2012 and
September 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 for the TR SO2 Group 2 units
at the source in accordance with
§ 97.712 for the control period in the
year of the applicable recordation
deadline under this paragraph.
(d) When recording the allocation of
TR SO2 Group 2 allowances for a TR
SO2 Group 2 unit in a compliance
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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.
§ 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.
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§ 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, 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 by
the request, provided that the transfer is
correctly submitted under § 97.722.
(b)(1) A TR SO2 Group 2 allowance
transfer 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 under
§ 97.724 for the control period
immediately before such allowance
transfer deadline.
(2) A TR SO2 Group 2 allowance
transfer that is submitted for recordation
after the deadline for holding TR SO2
Group 2 allowances described in
§ 97.725(b)(5) and that includes any TR
SO2 Group 2 allowances allocated for a
control period before the year of such
deadline will not be recorded until after
the Administrator completes the
deductions under § 97.725 for the
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control period immediately before the
year of such deadline.
(c) Where a TR SO2 Group 2
allowance transfer is not correctly
submitted under § 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
§ 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 nonrecordation.
§ 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 the control
period in the year or 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
§ 97.723, of TR SO2 Group 2 allowance
transfers submitted by the allowance
transfer deadline for a control period,
the Administrator will deduct from the
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
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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 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 (FIFO)
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 the control
period 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.
§ 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 an
owner of one or more TR SO2 Group 2
units in a State only if the TR SO2
Group 2 allowances:
(1) Were allocated for the control
period in the year or a prior year; and
(2) Are held in a compliance account,
designated by the owner in accordance
with paragraph (b)(4)(ii) of this section,
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of one of the owner’s TR SO2 Group 2
sources in the State as of the deadline
established in paragraph (b)(5) 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, 2015 and June 1 of each
year thereafter, the Administrator will:
(i) Calculate, separately for each State,
the total amount of SO2 emissions from
all TR SO2 Group 2 units in the State
during the control period in the year
before the year of this calculation
deadline and the amount, if any, by
which such total amount of NOX
emissions exceeds the State assurance
level as described in § 97.706(c)(2)(iii);
and
(ii) Promulgate a notice of availability
of the results of the calculations
required in paragraph (b)(1)(i) of this
section, including separate calculations
of the SO2 emissions for each TR SO2
Group 2 unit and of the amounts
described in §§ 97.706(c)(2)(iii)(A) and
(B) for each State.
(2) The Administrator will provide an
opportunity for submission of objections
to the calculations referenced by each
notice described in paragraph (b)(1) of
this section.
(i) Objections shall be submitted by
the deadline specified in such notice
and shall be limited to addressing
whether the calculations for each TR
SO2 Group 2 unit and each State for the
control period in the year involved are
in accordance with § 97.706(c)(2)(iii)
and §§ 97.706(b) and 97.730 through
97.735.
(ii) 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)(i) of this section. By August 1
immediately after the promulgation of
such notice, the Administrator will
promulgate a notice of 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)(i) of this section.
(3) For each notice of data availability
required in paragraph (b)(2)(ii) of this
section and for any State identified in
such notice as having TR SO2 Group 2
sources with total SO2 emissions
exceeding the State assurance level for
a control period, as described in
§ 97.706(c)(2)(iii):
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(i) By August 15 immediately after the
promulgation of such notice, the
designated representative of each TR
SO2 Group 2 source in each such State
shall submit a statement, in a format
prescribed by the Administrator:
(A) Listing all the owners of each TR
SO2 Group 2 unit at the source,
explaining how the selection of each
owner for inclusion on the list is
consistent with the definition of
‘‘owner’’ in § 97.702, and listing,
separately for each unit, the percentage
of the legal, equitable, leasehold, or
contractual reservation or entitlement
for each such owner as of midnight of
December 31 of the control period in the
year involved; and
(B) For each TR SO2 Group 2 unit at
the source that operates during, but is
allocated no TR SO2 Group 2 allowances
for, the control period in the year
involved, identifying whether the unit is
a coal-fired boiler, simple combustion
turbine, or combined cycle turbine cycle
and providing the unit’s allowable SO2
emission rate for such control period.
(ii) By September 15 immediately
after the promulgation of such notice,
the Administrator will calculate, for
each such State and each owner of one
or more TR SO2 Group 2 units in the
State and for the control period in the
year involved, each owner’s share of the
total SO2 emissions from all TR SO2
Group 2 units in the State, each owner’s
assurance level, and the amount (if any)
of TR SO2 Group 2 allowances that each
owner must hold in accordance with the
calculation formula in § 97.706(c)(2)(i)
and will promulgate a notice of
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)(3)(ii) of this
section.
(A) Objections shall be submitted by
the deadline specified in such notice
and shall be limited to addressing
whether the calculations for each owner
for the control period in the year
involved are consistent with the SO2
emissions for the relevant TR SO2 Group
2 units as set forth in the notice required
in paragraph (b)(2)(ii) of this section, the
definitions of ‘‘owner’’, ‘‘owner’s
assurance level’’, and ‘‘owner’s share’’ in
§ 97.702, and the calculation formula in
§ 97.706(c)(2)(i) and shall not raise any
issues about any data used in the notice
of data availability required in
paragraph (b)(2)(ii) of this section.
(B) The Administrator will adjust the
calculations to the extent necessary to
ensure that they are consistent with the
data and provisions referenced in
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45457
paragraph (b)(3)(iii)(A) of this section.
By November 15 immediately after the
promulgation of such notice, the
Administrator will promulgate a notice
of 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)(3)(iii)(A)
of this section.
(4) By December 1 immediately after
the promulgation of each notice of data
availability required in paragraph
(b)(3)(iii)(B) of this section:
(i) Each owner identified, in such
notice, as owning one or more TR SO2
Group 2 units in a State and as being
required to hold TR SO2 Group 2
allowances shall designate the
compliance account of one of the
sources at which such unit or units are
located to hold such required TR SO2
Group 2 allowances;
(ii) The authorized account
representative for the compliance
account designated under paragraph
(b)(4)(i) of this section shall submit to
the Administrator a statement, in a
format prescribed by the Administrator,
making this designation.
(5)(i) As of midnight of December 15
immediately after the promulgation of
each notice of data availability required
in paragraph (b)(3)(iii)(B) of this section,
each owner described in paragraph
(b)(4)(i) of this section shall hold in the
compliance account designated by the
owner in accordance with paragraph
(b)(4)(ii) of this section the total amount
of TR SO2 Group 2 allowances, available
for deduction under paragraph (a) of
this section, equal to the amount the
owner is required to hold as calculated
by the Administrator and referenced in
such notice.
(ii) Notwithstanding the allowanceholding deadline specified in paragraph
(b)(5)(i) of this section, if December 15
is not a business day, then such
allowance-holding deadline shall be
midnight of the first business day
thereafter.
(6) After December 15 (or the date
described in paragraph (b)(5)(ii) of this
section) immediately after the
promulgation of each notice of data
availability required in paragraph
(b)(3)(iii)(B) of this section and after the
recordation, in accordance with
§ 97.723, of TR SO2 Group 2 allowance
transfers submitted by midnight of such
date, the Administrator will deduct
from each compliance account
designated in accordance with
paragraph (b)(4)(ii) of this section, TR
SO2 Group 2 allowances available under
paragraph (a) of this section, as follows:
(i) Until the amount of TR SO2 Group
2 allowances deducted equals the
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amount that the owner designating the
compliance account is required to hold
as calculated by the Administrator and
referenced in the notice required in
paragraph (b)(3)(iii)(B) of this section; or
(ii) If there are insufficient TR SO2
Group 2 allowances to complete the
deductions in paragraph (b)(6)(i) of this
section, until no more TR SO2 Group 2
allowances available under paragraph
(a) of this section remain in the
compliance account.
(7) Notwithstanding any other
provision of this subpart and any
revision, made by or submitted to the
Administrator after the promulgation of
the notices of data availability required
in paragraphs (b)(2)(ii) and (b)(3)(iii)(B)
of this section respectively for a control
period, of any data used in making the
calculations referenced in such notice,
the amount of TR SO2 Group 2
allowances that each owner is required
to hold in accordance with
§ 97.706(c)(2)(i) for the control period in
the year involved shall continue to be
such amount as calculated by the
Administrator and referenced in such
notice required in paragraph
(b)(3)(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 are required to hold in
accordance with the calculation formula
in § 97.706(c)(2)(i) for the control period
in the year involved with regard to the
State involved, provided that—
(A) With regard to such litigation
involving such notice required in
paragraph (b)(2)(ii) of this section, 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)(ii) of this section; and
(B) With regard to such litigation
involving such notice required in
paragraph (b)(3)(iii) of this section, 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)(3)(iii) of this section.
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(ii) If any such data are revised by the
owners and operators of a source whose
designated representative submitted
such data under paragraph (b)(3)(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 are
required to hold in accordance with the
calculation formula in § 97.706(c)(2)(i)
for the control period in the year
involved with regard to the State
involved, provided that such litigation
was initiated no later than 30 days after
promulgation of such notice required in
paragraph (b)(3)(iii)(B) of this section.
(iii) If the revised data are used to
recalculate, in accordance with
paragraphs (b)(7)(i) and (b)(7)(ii) of this
section, the amount of TR SO2 Group 2
allowances that an owner is required to
hold for the control period in the year
involved with regard to the State
involved—
(A) Where the amount of TR SO2
Group 2 allowances that an owner is
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 owner
shall hold the additional amount of TR
SO2 Group 2 allowances in the
compliance account designated by the
owner in accordance with paragraph
(b)(4)(ii) of this section. The owner’s
failure to hold such additional amount,
as required, before the new deadline
shall not be a violation of the Clean Air
Act. The owner’s 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 owner fails to hold
as required as of the new deadline, and
each day in the control period in the
year involved, shall be a separate
violation of the Clean Air Act. After
such deadline, the Administrator will
make the appropriate deductions from
the compliance account.
(B) For an owner 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 the
compliance account that the owner
designated in accordance with
paragraph (b)(4)(ii) of this section, an
amount of TR SO2 Group 2 allowances
equal to the amount of the decrease to
the extent such amount was previously
deducted from the compliance account
under paragraph (b)(6) of this section
(and has not already been restored to the
compliance account) for the control
period in the year involved.
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(C) Each TR SO2 Group 2 allowance
held and deducted under paragraph
(b)(7)(iii)(A) of this section, or recorded
under paragraph (b)(7)(iii)(B) of this
section, as a result of recalculation of
requirements under the TR SO2 Group
2 assurance provisions for a control
period in a given year must be a TR SO2
Group 2 allowance allocated for a
control period in the same or a prior
year.
(c)(1) Identification of TR SO2 Group
2 allowances by serial number. The
authorized account representative for
each source’s compliance account
designated in accordance with
paragraph (b)(4)(ii) of this section may
request that specific TR SO2 Group 2
allowances, identified by serial number,
in the compliance account be deducted
in accordance with paragraph (b)(6) or
(7) of this section. In order to be
complete, such request shall be
submitted to the Administrator by the
allowance-holding deadline described
in paragraph (b)(5) of this section and
include, in a format prescribed by the
Administrator, the identification of the
compliance account and the appropriate
serial numbers.
(2) First-in, first-out. The
Administrator will deduct TR SO2
Group 2 allowances under paragraphs
(b)(6) and (7) of this section from each
source’s compliance account designated
under paragraph (b)(4)(ii) of this section
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
(FIFO) 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) Recordation of deductions. The
Administrator will record in the
appropriate compliance account all
deductions from such an account under
paragraph (b) of this section.
§ 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
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account unless and until the TR SO2
Group 2 allowance is deducted or
transferred under § 97.711(c), § 97.723,
§ 97.724, § 97.725, 97.727, 97.728,
97.742, or 97.743.
§ 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.
§ 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
source’s compliance account based on
the information in a submission, as
adjusted under paragraph (a)(1) of this
section, and record such deductions and
transfers.
§ 97.729
[Reserved]
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§ 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 § 97.702
and in § 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
§ 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 § 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:
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(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 §§ 75.11
and 75.16 of this chapter);
(2) Successfully complete all
certification tests required under
§ 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. The owner or
operator 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, by 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 dates:
(i) January 1, 2012; or
(ii) 180 calendar days, whichever
occurs first, after the date on which the
unit commences commercial operation.
(3) For 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 under paragraph
(b)(1) or (2) of this section, by 90 unit
operating days or 180 calendar days,
whichever occurs first, after the date on
which emissions first exit to the
atmosphere through the new stack or
flue or add-on SO2 emissions controls.
(4) Notwithstanding the dates in
paragraphs (b)(1) and (2) of this section,
for the owner or operator of a unit for
which a TR opt-in application is
submitted and not withdrawn and is not
yet approved or disapproved, by the
date specified in § 97.741(c).
(5) Notwithstanding the dates in
paragraphs (b)(1) and (2) of this section,
for the owner or operator of a TR SO2
Group 2 opt-in unit, by the date on
which the TR SO2 Group 2 opt-in unit
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enters the TR SO2 Group 2 Trading
Program as provided in § 97.741(h).
(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 § 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 § 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 emissions to the
atmosphere without accounting for all
such emissions in accordance with the
applicable provisions of this subpart
and part 75 of this chapter.
(3) No owner or operator of a 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 emissions
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 § 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
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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 § 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
§ 75.4(d) of this chapter concerning
units in long-term cold storage.
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§ 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
§ 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
§ 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 § 97.730(a)(1) 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 § 97.730(a)(1). The
owner or operator of a unit that qualifies
to use the low mass emissions excepted
monitoring methodology under § 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 § 97.730(a)(1)
(including the automated data
acquisition and handling system)
successfully completes all of the initial
certification testing required under
§ 75.20 of this chapter by the applicable
deadline in § 97.730(b). In addition,
whenever the owner or operator installs
a monitoring system to meet the
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requirements of this subpart in a
location where no such monitoring
system was previously installed, initial
certification in accordance with § 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 § 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 § 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 § 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
§ 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 § 97.730(a)(1) is subject to the
recertification requirements in
§ 75.20(g)(6) of this chapter.
(3) Approval process for initial
certification and recertification. For
initial certification of a continuous
monitoring system under § 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 §§ 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 § 97.733.
(ii) Certification application. The
designated representative shall submit
to the Administrator a certification
application for each monitoring system.
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A complete certification application
shall include the information specified
in § 75.63 of this chapter.
(iii) Provisional certification date. The
provisional certification date for a
monitoring system shall be determined
in accordance with § 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. The 120-day
review period specified in paragraph
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(d)(3) of this section shall not begin
before receipt of a complete certification
application.
(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 § 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
§ 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
§ 75.20(a)(4)(iii), § 75.20(g)(7), or
§ 75.21(e) of this chapter and continuing
until the applicable date and hour
specified under § 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.
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(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
§ 75.19 of this chapter shall meet the
applicable certification and
recertification requirements in
§§ 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 § 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 § 75.20(f) of this chapter.
§ 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
specification or other requirement under
§ 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 permitting
authority. By issuing the notice of
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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 § 97.731 for each
disapproved monitoring system.
§ 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 § 75.61 of this chapter.
§ 97.734
Recordkeeping and reporting.
(a) General provisions. The designated
representative shall comply with all
recordkeeping and reporting
requirements in this section, the
applicable recordkeeping and reporting
requirements in subparts F and G of part
75 of this chapter, and the requirements
of § 97.714(a).
(b) Monitoring plans. The owner or
operator of a TR SO2 Group 2 unit shall
comply with requirements of § 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 § 97.731, including
the information required under § 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;
(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 § 97.730(b), unless
that quarter is the third or fourth quarter
of 2011, in which case reporting shall
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commence in the quarter covering
January 1, 2012 through March 31, 2012;
(iii) Notwithstanding paragraphs
(d)(1)(i) and (ii) of this section, for a unit
for which a TR opt-in application is
submitted and not withdrawn and is not
yet approved or disapproved, the
calendar quarter corresponding to the
date specified in § 97.741(c); and
(iv) Notwithstanding paragraphs
(d)(1)(i) and (ii) of this section, for a TR
SO2 Group 2 opt-in unit, the calendar
quarter corresponding to the date on
which the TR SO2 Group 1 opt-in unit
enters the TR SO2 Group 2 Trading
Program as provided in § 97.71(h).
(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
§ 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.
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(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 § 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.
§ 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 § 75.66 of this chapter to
the Administrator, requesting approval
to apply an alternative to any
requirement of §§ 97.730 through 97.734
or paragraph (5)(i) or (ii) of the
definition of ‘‘owner’s share’’ in
§ 97.702.
(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
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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.
§ 97.740 General requirements for TR SO2
Group 2 opt-in units.
(a) A TR SO2 Group 2 opt-in unit must
be a unit that:
(1) Is located in a State;
(2) Is not a TR SO2 Group 2 unit under
§ 97.704;
(3) Is not covered by a retired unit
exemption under § 72.8 of this chapter
that is in effect; and
(4) Vents all of its emissions to a stack
and can meet the monitoring,
recordkeeping, and reporting
requirements of this subpart.
(b) A TR SO2 Group 2 opt-in unit shall
be deemed to be a TR SO2 Group 2 unit
for purposes of applying this subpart,
except for §§ 97.705, 97.711, and 97.712.
(c) Solely for purposes of applying the
requirements of §§ 97.713 through
97.718 and §§ 97.730 through 97.735, a
unit for which a TR opt-in application
is submitted and not withdrawn and is
not yet approved or disapproved under
§ 97.742 shall be deemed to be a TR SO2
Group 2 unit.
(d) Any TR SO2 Group 2 opt-in unit,
and any unit for which a TR opt-in
application is submitted and not
withdrawn and is not yet approved or
disapproved under § 97.742, located at
the same source as one or more TR SO2
Group 2 units shall have the same
designated representative and alternate
designated representative as such TR
SO2 Group 2 units.
§ 97.741
Opt-in process.
A unit meeting the requirements for a
TR SO2 Group 2 opt-in unit in
§ 97.740(a) may become a TR SO2 Group
2 opt-in unit only if, in accordance with
this section, the designated
representative of the unit submits a
complete TR opt-in application for the
unit and the Administrator approves the
application.
(a) Applying to opt-in. The designated
representative of the unit may submit a
complete TR opt-in application for the
unit at any time, except as provided
under § 97.742(e). A complete TR opt-in
application shall include the following
elements in a format prescribed by the
Administrator:
(1) Identification of the unit and the
source where the unit is located,
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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, and unit identification
number and type;
(2) A certification that the unit:
(i) Is not a TR SO2 Group 2 unit under
§ 97.704;
(ii) Is not covered by a retired unit
exemption under § 72.8 of this chapter
that is in effect;
(iii) Vents all of its emissions to a
stack; and
(iv) Has documented heat input
(greater than 0 mmBtu) for more than
876 hours during the 6 months
immediately preceding submission of
the TR opt-in application;
(3) A monitoring plan in accordance
with §§ 97.730 through 97.735;
(4) A statement that the unit, if
approved to become a TR SO2 Group 2
unit under paragraph (g) of this section,
may withdraw from the TR SO2 Group
2 Trading Program only in accordance
with § 97.742;
(5) A statement that the unit, if
approved to become a TR SO2 Group 2
unit under paragraph (g) of this section,
is subject to, and the owners and
operators of the unit must comply with,
the requirements of § 97.743;
(6) A complete certificate of
representation under § 97.716 consistent
with § 97.740, if no designated
representative has been previously
designated for the source that includes
the unit; and
(7) The signature of the designated
representative and the date signed.
(b) Interim review of monitoring plan.
The Administrator will determine, on
an interim basis, the sufficiency of the
monitoring plan submitted under
paragraph (a)(3) of this section. The
monitoring plan is sufficient, for
purposes of interim review, if the plan
appears to contain information
demonstrating that the SO2 emission
rate and heat input of the unit and all
other applicable parameters are
monitored and reported in accordance
with §§ 97.730 through 97.735. A
determination of sufficiency shall not be
construed as acceptance or approval of
the monitoring plan.
(c) Monitoring and reporting. (1)(i) If
the Administrator determines that the
monitoring plan is sufficient under
paragraph (b) of this section, the owner
or operator of the unit shall monitor and
report the SO2 emission rate and the
heat input of the unit and all other
applicable parameters, in accordance
with §§ 97.730 through 97.735, starting
on the date of certification of the
necessary monitoring systems under
§§ 97.730 through 97.735 and
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continuing until the TR opt-in
application submitted under paragraph
(a) of this section is disapproved under
this section or, if such TR opt-in
application is approved, the date and
time when the unit is withdrawn from
the TR SO2 Group 2 Trading Program in
accordance with § 97.742.
(ii) The monitoring and reporting
under paragraph (c)(1)(i) of this section
shall cover the entire control period
immediately before the date on which
the unit enters the TR SO2 Group 2
Trading Program under paragraph (h) of
this section, during which period
monitoring system availability must not
be less than 98 percent under §§ 97.730
through 97.735 and the unit must be in
full compliance with any applicable
State or Federal emissions or emissionsrelated requirements.
(2) To the extent the SO2 emission
rate and the heat input of the unit are
monitored and reported in accordance
with §§ 97.730 through 97.735 for one or
more entire control periods, in addition
to the control period under paragraph
(c)(1)(ii) of this section, during which
control periods monitoring system
availability is not less than 98 percent
under §§ 97.730 through 97.735 and the
unit is in full compliance with any
applicable State or Federal emissions or
emissions-related requirements and
which control periods begin not more
than 3 years before the unit enters the
TR SO2 Group 2 Trading Program under
paragraph (h) of this section, such
information shall be used as provided in
paragraphs (e) and (f) of this section.
(d) Statement on compliance. After
submitting to the Administrator all
quarterly reports required for the unit
under paragraph (c) of this section, the
designated representative shall submit,
in a format prescribed by the
Administrator, to the Administrator a
statement that, for the years covered by
such quarterly reports, the unit was in
full compliance with any applicable
State or Federal emissions or emissionsrelated requirements.
(e) Baseline heat input. The unit’s
baseline heat input shall equal:
(1) If the unit’s SO2 emission rate and
heat input are monitored and reported
for only one entire control period, in
accordance with paragraph (c) of this
section, the unit’s total heat input (in
mmBtu) for such control period; or
(2) If the unit’s SO2 emission rate and
heat input are monitored and reported
for more than one entire control period,
in accordance with paragraph (c) of this
section, the average of the amounts of
the unit’s total heat input (in mmBtu)
for such control periods.
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(f) Baseline SO2 emission rate. The
unit’s baseline SO2 emission rate shall
equal:
(1) If the unit’s SO2 emission rate and
heat input are monitored and reported
for only one entire control period, in
accordance with paragraph (c) of this
section, the unit’s SO2 emission rate (in
lb/mmBtu) for such control period;
(2) If the unit’s SO2 emission rate and
heat input are monitored and reported
for more than one entire control period,
in accordance with paragraph (c) of this
section, and the unit does not have addon SO2 emission controls during any
such control periods, the average of the
amounts of the unit’s SO2 emission rate
(in lb/mmBtu) for such control periods;
or
(3) If the unit’s SO2 emission rate and
heat input are monitored and reported
for more than one entire control period,
in accordance with paragraph (c) of this
section, and the unit has add-on SO2
emission controls during any such
control periods, the average of the
amounts of the unit’s SO2 emission rate
(in lb/mmBtu) for such control periods
during which the unit has add-on SO2
emission controls.
(g) Review of TR opt-in application.
(1) After the designated representative
submits the complete TR opt-in
application, quarterly reports, and
statement required in paragraphs (a), (c),
and (d) of this section and if the
Administrator determines that the
designated representative shows that the
unit meets the requirements for a TR
SO2 Group 2 opt-in unit in § 97.640, the
element certified in paragraph (a)(2)(iv)
of this section, and the monitoring and
reporting requirements of paragraph (c)
of this section, the Administrator will
issue a written approval of the TR optin application for the unit. The written
approval will state the unit’s baseline
heat input and baseline SO2 emission
rate. The Administrator will thereafter
establish a compliance account for the
source that includes the unit unless the
source already has a compliance
account.
(2) Notwithstanding paragraphs (a)
through (f) of this section, if, at any time
before the TR opt-in application is
approved under paragraph (g)(1) of this
section, the Administrator determines
that the unit cannot meet the
requirements for a TR SO2 Group 2 optin unit in § 97.740, the element certified
in paragraph (a)(2)(iv) of this section, or
the monitoring and reporting
requirements in paragraph (c) of this
section, the Administrator will issue a
written disapproval of the TR opt-in
application for the unit.
(h) Date of entry into TR SO2 Group
2 Trading Program. A unit for which a
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TR opt-in application is approved under
paragraph (g)(1) of this section shall
become a TR SO2 Group 2 opt-in unit,
and a TR SO2 Group 2 unit, effective as
of the later of January 1, 2012 or January
1 of the first control period during
which such approval is issued.
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§ 97.742 Withdrawal of TR SO2 Group 2
opt-in unit from TR SO2 Group 2 Trading
Program.
A TR SO2 Group 2 opt-in unit may
withdraw from the TR SO2 Group 2
Trading Program only if, in accordance
with this section, the designated
representative of the unit submits a
request to withdraw the unit and the
Administrator issues a written approval
of the request.
(a) Requesting withdrawal. In order to
withdraw the TR SO2 Group 2 opt-in
unit from the TR SO2 Group 2 Trading
Program, the designated representative
of the unit shall submit to the
Administrator a request to withdraw the
unit effective as of midnight of
December 31 of a specified calendar
year, which date must be at least 4 years
after December 31 of the year of the
unit’s entry into the TR SO2 Group 2
Trading Program under § 97.741(h). The
request shall be in a format prescribed
by the Administrator and shall be
submitted no later than 90 days before
the requested effective date of
withdrawal.
(b) Conditions for withdrawal. Before
a TR SO2 Group 2 opt-in unit covered
by the request to withdraw may
withdraw from the TR SO2 Group 2
Trading Program, the following
conditions must be met:
(1) For the control period ending on
the date on which the withdrawal is to
be effective, the source that includes the
TR SO2 Group 2 opt-in unit must meet
the requirement to hold TR SO2 Group
2 allowances under §§ 97.724 and
97.725 and cannot have any excess
emissions.
(2) After the requirement under
paragraph (b)(1) of this section is met,
the Administrator will deduct from the
compliance account of the source that
includes the TR SO2 Group 2 opt-in unit
TR SO2 Group 2 allowances equal in
amount to and allocated for the same or
a prior control period as any TR SO2
Group 2 allowances allocated to the TR
SO2 Group 2 opt-in unit under § 97.744
for any control period after the date on
which the withdrawal is to be effective.
If there are no other TR SO2 Group 2
units at the source, the Administrator
will close the compliance account, and
the owners and operators of the TR SO2
Group 2 opt-in unit may submit a TR
SO2 Group 2 allowance transfer for any
remaining TR SO2 Group 2 allowances
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to another Allowance Management
System account in accordance with
§§ 97.722 and 97.723.
(c) Approving withdrawal. (1) After
the requirements for withdrawal under
paragraphs (a) and (b) of this section are
met (including deduction of the full
amount of TR SO2 Group 2 allowances
required), the Administrator will issue a
written approval of the request to
withdraw, which will become effective
as of midnight on December 31 of the
calendar year for which the withdrawal
was requested. The unit covered by the
request shall continue to be a TR SO2
Group 2 opt-in unit until the effective
date of the withdrawal and shall comply
with all requirements under the TR SO2
Group 2 Trading Program concerning
any control periods for which the unit
is a TR SO2 Group 2 opt-in unit, even
if such requirements arise or must be
complied with after the withdrawal
takes effect.
(2) If the requirements for withdrawal
under paragraphs (a) and (b) of this
section are not met, the Administrator
will issue a written disapproval of the
request to withdraw. The unit covered
by the request shall continue to be a TR
SO2 Group 2 opt-in unit.
(d) Reapplication upon failure to meet
conditions of withdrawal. If the
Administrator disapproves the request
to withdraw, the designated
representative of the unit may submit
another request to withdraw in
accordance with paragraphs (a) and (b)
of this section.
(e) Ability to reapply to the TR SO2
Group 2 Trading Program. Once a TR
SO2 Group 2 opt-in unit withdraws from
the TR SO2 Group 2 Trading Program,
the designated representative may not
submit another opt-in application under
§ 97.741 for such unit before the date
that is 4 years after the date on which
the withdrawal became effective.
§ 97.743
Change in regulatory status.
(a) Notification. If a TR SO2 Group 2
opt-in unit becomes a TR SO2 Group 2
unit under § 97.704, then the designated
representative of the unit shall notify
the Administrator in writing of such
change in the TR SO2 Group 2 opt-in
unit’s regulatory status, within 30 days
of such change.
(b) Administrator’s actions. (1) If a TR
SO2 Group 2 opt-in unit becomes a TR
SO2 Group 2 unit under § 97.604, the
Administrator will deduct, from the
compliance account of the source that
includes the TR SO2 Group 2 opt-in unit
that becomes a TR SO2 Group 2 unit
under § 97.704, TR SO2 Group 2
allowances equal in amount to and
allocated for the same or a prior control
period as:
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(i) Any TR SO2 Group 2 allowances
allocated to the TR SO2 Group 2 opt-in
unit under § 97.744 for any control
period starting after the date on which
the TR SO2 Group 2 opt-in unit becomes
a TR SO2 Group 2 unit under § 97.704;
and
(ii) If the date on which the TR SO2
Group 2 opt-in unit becomes a TR SO2
Group 2 unit under § 97.704 is not
December 31, the TR SO2 Group 2
allowances allocated to the TR SO2
Group 2 opt-in unit under § 97.744 for
the control period that includes the date
on which the TR SO2 Group 2 opt-in
unit becomes a TR SO2 Group 2 unit
under § 97.704—
(A) Multiplied by the ratio of the
number of days, in the control period,
starting with the date on which the TR
SO2 Group 2 opt-in unit becomes a TR
SO2 Group 2 unit under § 97.704,
divided by the total number of days in
the control period, and
(B) Rounded to the nearest allowance.
(2) The designated representative
shall ensure that the compliance
account of the source that includes the
TR SO2 Group 2 opt-in unit that
becomes a TR SO2 Group 2 unit under
§ 97.704 contains the TR SO2 Group 2
allowances necessary for completion of
the deduction under paragraph (b)(1) of
this section.
(3)(i) For control periods starting after
the date on which the TR SO2 Group 2
opt-in unit becomes a TR SO2 Group 2
unit under § 97.704, the TR SO2 Group
2 opt-in unit will be allocated TR SO2
Group 2 allowances in accordance with
§ 97.712.
(ii) If the date on which the TR SO2
Group 2 opt-in unit becomes a TR SO2
Group 2 unit under § 97.704 is not
December 31, the following amount of
TR SO2 Group 2 allowances will be
allocated to the TR SO2 Group 2 opt-in
unit (as a TR SO2 Group 2 unit) in
accordance with § 97.712 for the control
period that includes the date on which
the TR SO2 Group 2 opt-in unit becomes
a TR SO2 Group 2 unit under § 97.704:
(A) The amount of TR SO2 Group 2
allowances otherwise allocated to the
TR SO2 Group 2 opt-in unit (as a TR SO2
Group 2 unit) in accordance with
§ 97.712 for the control period;
(B) Multiplied by the ratio of the
number of days, in the control period,
starting with the date on which the TR
SO2 Group 2 opt-in unit becomes a TR
SO2 Group 2 unit under § 97.704,
divided by the total number of days in
the control period; and
(C) Rounded to the nearest allowance.
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§ 97.744 TR SO2 Group 2 allowance
allocations to TR SO2 Group 2 opt-in units.
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(a) Timing requirements. (1) When the
TR opt-in application is approved for a
unit under § 97.741(g), the
Administrator will issue TR SO2 Group
2 allowances and allocate them to the
unit for the control period in which the
unit enters the TR SO2 Group 2 Trading
Program under § 97.741(h), in
accordance with paragraph (b) of this
section.
(2) By no later than October 31 of the
control period after the control period in
which a TR SO2 Group 2 opt-in unit
enters the TR SO2 Group 2 Trading
Program under § 97.741(h) and October
31 of each year thereafter, the
Administrator will issue TR SO2 Group
2 allowances and allocate them to the
TR SO2 Group 2 opt-in unit for the
control period that includes such
allocation deadline and in which the
unit is a TR SO2 Group 2 opt-in unit, in
accordance with paragraph (b) of this
section.
(b) Calculation of allocation. For each
control period for which a TR SO2
Group 2 opt-in unit is to be allocated TR
SO2 Group 2 allowances, the
Administrator will issue and allocate TR
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SO2 Group 2 allowances in accordance
with the following procedures:
(1) The heat input (in mmBtu) used
for calculating the TR SO2 Group 2
allowance allocation will be the lesser
of:
(i) The TR SO2 Group 2 opt-in unit’s
baseline heat input determined under
§ 97.741(g); or
(ii) The TR SO2 Group 2 opt-in unit’s
heat input, as determined in accordance
with §§ 97.730 through 97.735, for the
immediately prior control period,
except when the allocation is being
calculated for the control period in
which the TR SO2 Group 2 opt-in unit
enters the TR SO2 Group 2 Trading
Program under § 97.741(h).
(2) The SO2 emission rate (in lb/
mmBtu) used for calculating TR SO2
Group 2 allowance allocations will be
the lesser of:
(i) The TR SO2 Group 2 opt-in unit’s
baseline SO2 emission rate (in lb/
mmBtu) determined under § 97.741(g)
and multiplied by 70 percent; or
(ii) The most stringent State or
Federal SO2 emissions limitation
applicable to the TR SO2 Group 2 optin unit at any time during the control
period for which TR SO2 Group 2
allowances are to be allocated.
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45465
(3) The Administrator will issue TR
SO2 Group 2 allowances and allocate
them to the TR SO2 Group 2 opt-in unit
in an amount equaling the heat input
under paragraph (b)(1) of this section,
multiplied by the SO2 emission rate
under paragraph (b)(2) of this section,
divided by 2,000 lb/ton, and rounded to
the nearest allowance.
(c) Recordation. (1) The Administrator
will record, in the compliance account
of the source that includes the TR SO2
Group 2 opt-in unit, the TR SO2 Group
2 allowances allocated to the TR SO2
Group 2 opt-in unit under paragraph
(a)(1) of this section.
(2) By December 1 of the control
period after the control period in which
a TR SO2 Group 2 opt-in unit enters the
TR SO2 Group 2 Trading Program under
§ 97.741(h) and December 1 of each year
thereafter, the Administrator will
record, in the compliance account of the
source that includes the TR SO2 Group
2 opt-in unit, the TR SO2 Group 2
allowances allocated to the TR SO2
Group 2 opt-in unit under paragraph
(a)(2) of this section.
[FR Doc. 2010–17007 Filed 7–30–10; 8:45 am]
BILLING CODE 6560–50–P
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]]>Agencies
[Federal Register Volume 75, Number 147 (Monday, August 2, 2010)]
[Proposed Rules]
[Pages 45210-45465]
From the Federal Register Online via the Government Printing Office [www.gpo.gov]
[FR Doc No: 2010-17007]
[[Page 45209]]
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Part II
Environmental Protection Agency
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40 CFR Parts 51, 52, 72, et al.
Federal Implementation Plans To Reduce Interstate Transport of Fine
Particulate Matter and Ozone; Proposed Rule
Federal Register / Vol. 75, No. 147 / Monday, August 2, 2010 /
Proposed Rules
[[Page 45210]]
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ENVIRONMENTAL PROTECTION AGENCY
40 CFR Parts 51, 52, 72, 78, and 97
[EPA-HQ-OAR-2009-0491; FRL-9174-9]
RIN 2060-AP50
Federal Implementation Plans To Reduce Interstate Transport of
Fine Particulate Matter and Ozone
AGENCY: Environmental Protection Agency (EPA).
ACTION: Proposed rule.
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SUMMARY: EPA is proposing to limit the interstate transport of
emissions of nitrogen oxides (NOX) and sulfur dioxide
(SO2). In this action, EPA is proposing to both identify and
limit emissions within 32 states in the eastern United States that
affect the ability of downwind states to attain and maintain compliance
with the 1997 and 2006 fine particulate matter (PM2.5)
national ambient air quality standards (NAAQS) and the 1997 ozone
NAAQS. EPA is proposing to limit these emissions through Federal
Implementation Plans (FIPs) that regulate electric generating units
(EGUs) in the 32 states. This action will substantially reduce the
impact of transported emissions on downwind states. In conjunction with
other federal and state actions, it helps assure that all but a handful
of areas in the eastern part of the country will be in compliance with
the current ozone and PM2.5 NAAQS by 2014 or earlier. To the
extent the proposed FIPs do not fully address all significant
transport, EPA is committed to assuring that any additional reductions
needed are addressed quickly. EPA takes comments on ways this proposal
could achieve additional NOX reductions and additional
actions including other rulemakings that EPA could undertake to achieve
any additional reductions needed.
DATES: Comments. Comments must be received on or before October 1,
2010.
Public Hearing: Three public hearings will be held before the end
of the comment period. The dates, times and locations will be announced
separately. Please refer to SUPPLEMENTARY INFORMATION for additional
information on the comment period and the public hearings.
ADDRESSES: Submit your comments, identified by Docket ID No. EPA-HQ-
OAR-2009-0491 by one of the following methods:
https://www.regulations.gov. Follow the online instructions
for submitting comments. Attention Docket ID No. EPA-HQ-OAR-2009-0491.
E-mail: a-and-r-docket@epa.gov. Attention Docket ID No.
EPA-HQ-OAR-2009-0491.
Fax: (202) 566-9744. Attention Docket ID No. EPA-HQ-OAR-
2009-0491.
Mail: EPA Docket Center, EPA West (Air Docket), Attention
Docket ID No. EPA-HQ-OAR-2009-0491, U.S. Environmental Protection
Agency, Mailcode: 2822T, 1200 Pennsylvania Avenue, NW., Washington, DC
20460. Please include 2 copies. In addition, please mail a copy of your
comments on the information collection provisions to the Office of
Information and Regulatory Affairs, Office of Management and Budget
(OMB), Attn: Desk Officer for EPA, 725 17th Street, NW., Washington, DC
20503.
Hand Delivery: U.S. Environmental Protection Agency, EPA
West (Air Docket), 1301 Constitution Avenue, Northwest, Room 3334,
Washington, DC 20004, Attention Docket ID No. EPA-HQ-OAR-2009-0491.
Such deliveries are only accepted during the Docket's normal hours of
operation, and special arrangements should be made for deliveries of
boxed information.
Instructions. Direct your comments to Docket ID No. EPA-HQ-OAR-
2009-0491. EPA's policy is that all comments received will be included
in the public docket without change and may be made available online at
https://www.regulations.gov, including any personal information
provided, unless the comment includes information claimed to be
Confidential Business Information (CBI) or other information whose
disclosure is restricted by statute. Do not submit information that you
consider to be CBI or otherwise protected through https://www.regulations.gov or e-mail. The https://www.regulations.gov Web site
is an ``anonymous access'' system, which means EPA will not know your
identity or contact information unless you provide it in the body of
your comment. If you send an e-mail comment directly to EPA without
going through https://www.regulations.gov, your e-mail address will be
automatically captured and included as part of the comment that is
placed in the public docket and made available on the Internet. If you
submit an electronic comment, EPA recommends that you include your name
and other contact information in the body of your comment and with any
disk or CD-ROM you submit. If EPA cannot read your comment due to
technical difficulties and cannot contact you for clarification, EPA
may not be able to consider your comment. Electronic files should avoid
the use of special characters, avoid any form of encryption, and be
free of any defects or viruses. For additional information about EPA's
public docket, visit the EPA Docket Center homepage at https://www.epa.gov/epahome/dockets.htm.
Docket. All documents in the docket are listed in the https://www.regulations.gov index. 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, will be publicly available only in hard copy.
Publicly available docket materials are available either electronically
in https://www.regulations.gov or in hard copy at the Air and Radiation
Docket and Information Center, EPA/DC, EPA West Building, Room 3334,
1301 Constitution Ave., 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: Mr. Tim Smith, Air Quality Policy
Division, Office of Air Quality Planning and Standards (C539-04),
Environmental Protection Agency, Research Triangle Park, NC 27711;
telephone number: (919) 541-4718; fax number: (919) 541-0824; e-mail
address: smith.tim@epa.gov. 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 rodman.sonja@epa.gov.
SUPPLEMENTARY INFORMATION:
I. Preamble Glossary of Terms and Abbreviations
The following are abbreviations of terms used in the preamble.
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
CBI Confidential Business Information
CFR Code of Federal Regulations
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
Hg Mercury
IPM Integrated Planning Model
lb/mmbtu Pounds Per Million British Thermal Unit
[mu]g/m3 Micrograms Per Cubic Meter
[[Page 45211]]
NAAQS National Ambient Air Quality Standards
NOX Nitrogen Oxides
NSPS New Source Performance Standard
OTAG Ozone Transport Assessment Group
PUC Public Utility Commission
SNCR Selective Non-catalytic Reduction
SCR Selective Catalytic Reduction
SIP State Implementation Plan
PM2.5 Fine Particulate Matter, Less Than 2.5 Micrometers
PM10 Fine and Coarse Particulate Matter, Less Than 10
Micrometers
PM Particulate Matter
RIA Regulatory Impact Analysis
SO2 Sulfur Dioxide
SOX Sulfur Oxides, Including Sulfur Dioxide
(SO2) and Sulfur Trioxide (SO3)
TIP Tribal Implementation Plan tpy Tons Per Year
TSD Technical Support Document
II. General Information
A. Does this action apply to me?
This rule affects EGUs, and regulates the following groups:
------------------------------------------------------------------------
Industry group NAICS \a\
------------------------------------------------------------------------
Utilities (electric, natural gas, other 2211, 2212, 2213
systems).
------------------------------------------------------------------------
\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 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, 97,604, and 97.704.
B. Where can I get a copy of this document and other related
information?
In addition to being available in the docket, an electronic copy of
this proposal will also be available on the World Wide Web. Following
signature by the EPA Administrator, a copy of this action will be
posted on the transport rule Web site https://www.epa.gov/airtransport.
C. What should I consider as I prepare my comments for EPA?
1. Submitting CBI. Do not submit this information to EPA through
https://www.regulations.gov or e-mail. Clearly mark the part or all of
the information that you claim to be CBI. For CBI information in a disk
or CD-ROM that you mail to EPA, mark the outside of the disk or CD-ROM
as CBI and then identify electronically within the disk or CD-ROM the
specific information that is claimed as CBI. In addition to one
complete version of the comment that includes information claimed as
CBI, a copy of the comment that does not contain the information
claimed as CBI must be submitted for inclusion in the public docket.
Information so marked will not be disclosed except in accordance with
procedures set forth in 40 CFR part 2. Send or deliver information
identified as CBI only to the following address: Roberto Morales, OAQPS
Document Control Officer (C404-02), U.S. EPA, Research Triangle Park,
NC 27711, Attention Docket ID No. EPA-HQ-OAR-2009-0491.
2. Tips for preparing your comments. When submitting comments,
remember to:
Identify the rulemaking by docket number and other
identifying information (subject heading, Federal Register date and
page number).
Follow directions--The agency may ask you to respond to
specific questions or organize comments by referencing a Code of
Federal Regulations (CFR) part or section number.
Explain why you agree or disagree; suggest alternatives
and substitute language for your requested changes.
Describe any assumptions and provide any technical
information and/or data that you used.
If you estimate potential costs or burdens, explain how
you arrived at your estimate in sufficient detail to allow for it to be
reproduced.
Provide specific examples to illustrate your concerns, and
suggest alternatives.
Explain your views as clearly as possible, avoiding the
use of profanity or personal threats.
Make sure to submit your comments by the comment period
deadline identified.
D. How can I find information about the public hearings?
The EPA will hold three public hearings on this proposal. The
dates, times and locations of the pubic hearings will be announced
separately. Oral testimony will be limited to 5 minutes per commenter.
The EPA encourages commenters to provide written versions of their oral
testimonies either electronically or in paper copy. Verbatim
transcripts and written statements will be included in the rulemaking
docket. If you would like to present oral testimony at one of the
hearings, please notify Ms. Pamela S. Long, Air Quality Policy Division
(C504-03), U.S. EPA, Research Triangle Park, NC 27711, telephone number
(919) 541-0641; e-mail: long.pam@epa.gov. Persons interested in
presenting oral testimony should notify Ms. Long at least 2 days in
advance of the public hearings. For updates and additional information
on the public hearings, please check EPA's website for this rulemaking,
https://www.epa.gov/airtransport. The public hearings will provide
interested parties the opportunity to present data, views, or arguments
concerning the proposed rule. The EPA officials may ask clarifying
questions during the oral presentations, but will not respond to the
presentations or comments at that time. Written statements and
supporting information submitted during the comment period will be
considered with the same weight as any oral comments and supporting
information presented at the public hearings.
E. How is this Preamble Organized?
I. Preamble Glossary of Terms and Abbreviations
II. General Information
A. Does this action apply to me?
B. Where can I get a copy of this document and other related
information?
C. What should I consider as I prepare my comments for EPA?
D. How can I find information about the hearings?
E. How is the preamble organized?
III. Summary of Proposed Rule and Background
A. Summary of Proposed Rule
B. Background
1. What is the source of EPA's authority for this action?
2. What air quality problems does this proposal address?
3. Which NAAQS does this proposal address?
4. EPA Transport Rulemaking History
C. What are the goals of this proposed rule?
1. Primary Goals
2. Key Guiding Principles
D. Why does this proposed rule focus on the eastern half of the
United States?
E. Anticipated Rules Affecting Power Sector
IV. Defining ``Significant Contribution'' and ``Interference With
Maintenance''
A. Background
1. Approach Used in NOX SIP Call and CAIR
2. Judicial Opinions
3. Overview of Proposed Approach
B. Overview of Approach To Identify Contributing Upwind States
1. Background
2. Approach for Proposed Rule
C. Air Quality Modeling Approach and Results
1. What air quality modeling platform did EPA use?
2. How did EPA project future nonattainment and maintenance for
annual PM2.5, 24-Hour PM2.5, and 8-hour ozone?
3. How did EPA assess interstate contributions to nonattainment
and maintenance?
[[Page 45212]]
4. What are the estimated interstate contributions to annual
PM2.5, 24-hour PM2.5, and 8-hour ozone
nonattainment and maintenance?
D. Proposed Methodology To Quantify Emissions That Significantly
Contribute or Interfere With Maintenance
1. Explanation of Proposed Approach To Quantify Significant
Contribution
2. Application
3. Discussion of Control Costs for Sources Other Than EGUs
E. State Emissions Budgets
1. Defining SO2 and Annual NOX State
Emissions Budgets for EGUs
2. Defining Ozone Season NOX State Emissions Budgets
for EGUs
F. Emissions Reductions Requirements Including Variability
1. Variability
2. State Budgets With Variability Limits
3. Summary of Emissions Reductions Across All Covered States
G. How the Proposed Approach Is Consistent With Judicial
Opinions Interpreting Section 110(a)(2)(D)(i)(I) of the Clean Air
Act
H. Alternative Approaches Evaluated But Not Proposed
V. Proposed Emissions Control Requirements
A. Pollutants Included in This Proposal
B. Source Categories
1. Propose To Control Power Sector Emissions
2. Other Source Categories Are Not Included
C. Timing of Proposed Emissions Reductions Requirements
1. Date for Prohibiting Emissions That Significantly Contribute
or Interfere With Maintenance of the PM2.5 NAAQS
2. Date for Prohibiting Emissions That Significantly Contribute
or Interfere With Maintenance of the 1997 Ozone NAAQS
3. Reductions Required by 2012 To Ensure That Significant
Contribution and Interference With Maintenance Are Eliminated as
Expeditiously as Practicable
4. How Compliance Deadlines Address the Court's Concern About
Timing
5. EPA Will Consider Additional Reductions in Pollution
Transport To Assist in Meeting Any Revised or New NAAQS
D. Implementing Emission Reduction Requirements
1. Approach Taken in NOX SIP Call and CAIR
2. Judicial Opinions
3. Remedy Options Overview
4. State Budgets/Limited Trading Proposed Remedy
5. State Budgets/Intrastate Trading Remedy Option
6. Direct Control Remedy Option
E. Projected Costs and Emissions for Each Remedy Option
1. State Budgets/Limited Trading
2. State Budgets/Intrastate Trading
3. Direct Control
4. State-Level Emissions Projections
F. Transition From the CAIR Cap-and-Trade Programs to Proposed
Programs
1. Sunsetting of CAIR, CAIR SIPs, and CAIR FIPs
2. Change in States Covered
3. Applicability, CAIR Opt-Ins and NOX SIP Call Units
4. Early Reduction Provisions
5. Source Monitoring and Reporting
G. Interactions With Existing Title IV Program and
NOX SIP Call
1. Title IV Interactions
2. NOX SIP Call Interactions
VI. Stakeholder Outreach
VII. State Implementation Plan Submissions
A. Section 110(a)(2)(D)(i) SIPs for the 1997 Ozone and
PM2.5 NAAQS
B. Section 110(a)(2)(D)(i) SIPs for the 2006 PM2.5
NAAQS
C. Transport Rule SIPs
VIII. Permitting
A. Title V Permitting
B. New Source Review
IX. What benefits are projected for the proposed rule?
A. The Impacts on PM2.5 and Ozone of the Proposed
SO2 and NOX Strategy
B. Human Health Benefit Analysis
C. Quantified and Monetized Visibility Benefits
D. Benefits of Reducing GHG Emission
E. Total Monetized Benefits
F. How do the benefits compare to the costs of this proposed
rule?
G. What are the unquantified and unmonetized benefits of the
transport rule emissions reductions?
1. What are the benefits of reduced deposition of sulfur and
nitrogen to aquatic, forest, and coastal ecosystems?
2. Ozone Vegetation Effects
3. Other Health or Welfare Disbenefits of the Transport Rule
That Have Not Been Quantified
X. Economic Impacts
XI. Incorporating End-Use Energy Efficiency Into the Proposed
Transport Rule
A. Background
1. What is end-use energy efficiency?
2. How does energy efficiency contribute to cost-effective
reductions of air emissions from EGUs?
3. How does the proposed rule support greater investment in
energy efficiency?
4. How EPA and states have previously integrated energy
efficiency into air regulatory programs?
B. Incorporating End-Use Energy Efficiency Into the Transport
Rule
1. Options That Could Be Used To Incorporate Energy Efficiency
Into Allowance Based Programs
2. Why EPA did not propose these options?
XII. Statutory and Executive Order Reviews
A. Executive Order 12866: Regulatory Planning and Review
B. Paperwork Reduction Act
C. Regulatory Flexibility Act (RFA)
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 Advancement Act
J. Executive Order 12898: Federal Actions To Address
Environmental Justice in Minority Populations and Low-Income
Populations
1. Consideration of Environmental Justice Issues in the Rule
Development Process
2. Potential Environmental and Public Health Impacts to
Vulnerable Populations
3. Meaningful Public Participation
4. Determination
III. Summary of Proposed Rule and Background
A. Summary of Proposed Rule
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 notice, EPA proposes to find that
emissions of SO2 and NOX in 32 eastern 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 average PM2.5 NAAQS
promulgated in 1997, the 24-hour average PM2.5 NAAQS
promulgated in 2006, and the ozone NAAQS promulgated in 1997.\1\ These
emissions are transported downwind either as SO2 and
NOX or, after transformation in the atmosphere, as fine
particles or ozone. This notice identifies emission reduction
responsibilities of upwind states, and also proposes enforceable FIPs
to achieve the required emissions reductions in each state through
cost-effective and flexible requirements for power plants. Each state
will have the option of replacing these Federal rules with state rules
to achieve the required amount of emissions reductions from sources
selected by the state.
---------------------------------------------------------------------------
\1\ In the context of the jurisdictions covered by this proposed
rule, EPA uses the term ``states'' to include the District of
Columbia.
---------------------------------------------------------------------------
With respect to the annual average PM2.5 NAAQS, this
proposal finds that 24 eastern states have SO2 and
NOX emission reduction responsibilities, and quantifies each
state's full emission reduction responsibility under section
110(a)(2)(D)(i)(I). With respect to the 24-hour average
PM2.5 NAAQS, this proposal finds that 25 eastern states have
emission reduction responsibilities. The proposed reductions will at
least partly eliminate, and subject to further analysis may fully
eliminate, these states' significant contribution and interference with
maintenance for purposes of the 24-hour average PM2.5
standard. In all, emissions reductions related to interstate transport
[[Page 45213]]
of fine particles would be required in 28 states.
With respect to the 1997 ozone NAAQS, this proposal requires
emissions reductions in 26 states. For 16 of these states, we propose
that the required reductions represent their full significant
contribution and interference with maintenance for the ozone NAAQS. For
an additional 10 states, the required NOX reductions are
needed for these states to make measurable progress towards eliminating
their significant contribution and interference with maintenance. EPA
has begun to conduct additional information gathering and analysis to
determine the extent to which further reductions from these states may
be needed to fully eliminate significant contribution and interference
with maintenance with the 1997 ozone NAAQS.
This proposed rule would achieve substantial near-term emissions
reductions from the power sector. EPA projects that with the proposed
rule, EGU SO2 emissions would be 5.0 million tons lower,
annual NOX emissions would be 700,000 tons lower, and ozone
season NOX emissions would be 100,000 tons lower in 2012,
compared to baseline 2012 projections in the proposed covered states.
Further, EGU SO2 emissions would be 4.6 million tons lower,
annual NOX emissions would be 700,000 tons lower, and ozone
season NOX emissions would be 100,000 tons lower in 2014,
compared to baseline 2014 projections (which will have dropped from
2012 due to other federal and state requirements, thereby lowering the
2014 baseline). See Table III.A-2 for projected EGU emissions with the
proposed rule compared to baseline, and Table III.A-3 for projected EGU
emissions with the proposed rule compared to 2005 actual emissions. The
reductions obtained through the Transport Rule FIPs will help all but a
very few areas in the eastern part of the country come into attainment
with the 1997 PM2.5 and ozone standards and take major
strides toward helping states address nonattainment with the 2006 24-
hour average PM2.5 standard. See Table III.A-1 for proposed
list of covered states.
EPA is committed to fulfilling its responsibility to ensure that
downwind states receive the relief from upwind emissions guaranteed
under CAA section 110(a)(2)(D) For the 24-hour PM2.5
standard, EPA's air quality modeling shows that in the areas with
continuing non-attainment or maintenance problems, the remaining
exceedances occur almost entirely in the winter months. The relative
importance of particle species such as sulfate and nitrate, is quite
different between summer and winter. EPA is moving ahead before the
final rule is published to determine the extent to which this
wintertime problem is caused by emissions transported from upwind
states. Further study of the 24-hour PM2.5 results could
lead to a number of possible outcomes; EPA cannot judge the relative
likelihood of these outcomes at this time. To the extent possible, EPA
plans to finalize this rule with a full determination of, and remedy
for, significant contribution and interference with maintenance for the
24-hour PM2.5 standard. To that end, EPA is expeditiously
proceeding with examination of the residual wintertime problem. (See
full discussion in section IV.D.)
In the case of ozone, EPA must determine whether further
NOX reductions are warranted in certain upwind states that
affect two or three areas with relatively persistent ozone air quality
problems. To support a full significant contribution determination for
these states, EPA is expeditiously conducting further analysis of
NOX control costs, emissions reductions, air quality
impacts, and the nature of the residual air quality issues. EPA's
current information indicates that considering NOX
reductions beyond the cost per ton levels proposed in this rule will
require analysis of reductions from source categories other than EGUs,
as well as from EGUs. EPA believes that developing supplemental
information to consider NOX sources beyond EGUs would
substantially delay publication of a final rule beyond the anticipated
publication of spring 2011. EPA does not believe that this effort
should delay the reductions and large health benefits associated with
this proposed rule. Thus, EPA intends to proceed with additional
rulemaking to address fully the residual significant contribution to
nonattainment and interference with maintenance with the ozone standard
as quickly as possible. (See full discussion in section IV.D.)
This proposed rule is the first of several EPA rules to be issued
over the next 2 years that will yield substantial health and
environmental benefits for the public through regulation of power
plants. Fossil-fuel-fired power plants contribute a large and
substantial fraction of the emissions of several key air pollutants,
and the agency has statutory or judicial obligations to make several
regulatory determinations on power plant emissions. The Administrator
in January established improved air quality as an Agency priority and
announced plans to promote a cleaner and more efficient power sector
and have strong but achievable reduction goals for SO2,
NOX, mercury, and other air toxics.''
In addition to this rule, other anticipated actions include a
section 112(d) rule for electric utilities to be proposed by March
2011, potential rules to address pollution transport under revised
NAAQS, revisions to new source performance standards for coal and oil-
fired utility electric generating units, and best available retrofit
technology (BART) and regional haze program requirements to protect
visibility. These actions, and their relationship to this rule, are
discussed further in section III.E.
Ongoing reviews of the ozone and PM2.5 NAAQS could
result in revised NAAQS. To address any new NAAQS, EPA would propose
interstate transport determinations in future notices. Such proposals
could require greater emissions reductions from states covered by this
proposal and/or require reductions from states not covered by this
proposal. In addition, while this action proposes to require reductions
from the power sector only, it is possible that reductions from other
source categories could be needed to address interstate transport
requirements related to any new NAAQS.
With this proposal, EPA is also responding to the remand of the
CAIR by the Court in 2008. CAIR, promulgated May 12, 2005 (70 FR 25162)
requires 28 states and the District of Columbia 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. The CAIR FIPs, promulgated April
26, 2006 (71 FR 25328), regulate EGUs in the covered states and achieve
the emissions reductions requirements established by CAIR until states
have approved SIPs to achieve the reductions. In July 2008, the DC
Circuit Court found CAIR and the CAIR FIPs unlawful. North Carolina v.
EPA, 531 F.3d 896 (DC Cir. 2008). The Court's original decision vacated
CAIR. Id. 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 v. EPA, 550 F.3d 1176, 1178 (DC Cir. 2008). The
CAIR requirements are correctly in place and the CAIR's regional
control programs are operating
[[Page 45214]]
while EPA develops replacement rules in response to the remand.
As described more fully in the remainder of this preamble, the
approaches used in this proposed 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 v. EPA and address the flaws in CAIR
identified by the Court therein. Among other things, the proposal
relies on detailed, bottom-up scientific and technical analyses,
introduces a state-specific methodology for identifying significant
contribution to nonattainment and interference with maintenance, and
proposes remedy options to ensure that all necessary reductions are
achieved in the covered states.
In this action, EPA proposes to both identify and address emissions
within states in the eastern United States that significantly
contribute to nonattainment or interfere with maintenance by other
downwind states. As discussed in sections III and VII in this preamble
and described in greater detail in two separate Federal Register
notices published on April 25, 2005 (70 FR 21147) and June 9, 2010 (75
FR 32673), EPA has determined, or proposed to determine, that the 32
states covered by this proposal either have not submitted SIPs adequate
to meet the requirements of 110(a)(2)(D)(i)(I) with respect to the 1997
and 2006 PM2.5 NAAQS and the 1997 ozone NAAQS, or that the
SIP provisions currently in place are not adequate to meet those
requirements.
As described in section IV in this preamble, EPA is proposing a
state-specific methodology to identify specific reductions that states
in the eastern United States must make to satisfy 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. The proposed methodology uses state-specific inputs and focuses
on the emissions reductions available in each individual state to
address the Court's concern that the approach used in CAIR (which
identified a single level of emissions achievable by the application of
highly cost effective controls in the region) was insufficiently state
specific. The proposed methodology uses air quality analysis to
determine whether a state's contribution to downwind air quality
problems is above specific thresholds. If a state's contribution does
not exceed those thresholds, its contribution is found to be
insignificant and it is no longer considered in the analysis. If a
state's contribution exceeds those thresholds, EPA takes a second step
that uses a multi-factor analysis that takes into account both air
quality and cost considerations to identify the portion of a state's
contribution that is significant or that interferes with maintenance.
Section 110(a)(2)(D) requires states to eliminate the emissions that
constitute this ``significant contribution'' and ``interference with
maintenance.''
This proposed methodology for determining upwind state emission
reduction responsibility is designed to be applicable to current and
potential future ozone and PM2.5 NAAQS. It is based on cost
and air quality considerations that are common to any NAAQS, but also
calls for evaluation of facts specific to a particular NAAQS. As a
result, application of the methodology to a revised, more stringent
NAAQS might lead to a determination that greater reductions in
transported pollution from upwind states are reasonable than for a
current, less stringent NAAQS.
To facilitate implementation of the requirement that significant
contribution and interference with maintenance be eliminated, EPA
developed state emissions budgets. By tying these budgets directly to
EPA's quantification of each individual state's significant
contribution and interference with maintenance, EPA directly linked the
budgets to the mandate in section 110(a)(2)(D)(i)(I), and thus
addressed the Court's concerns about the development of budgets for the
CAIR. EPA also addressed these concerns by completely eschewing any
consideration or reliance on Fuel Adjustment Factors and the existing
allocation of Title IV allowances.
These new emissions budgets are based on the Agency's state-by-
state analysis of each upwind state's significant contribution to
nonattainment and interference with maintenance downwind. A state's
emissions budget is the quantity of emissions that would remain after
elimination of the part of significant contribution and interference
with maintenance that EPA has identified in an average year (i.e.,
before accounting for the inherent variability in power system
operations).\2\ EPA proposes SO2 and NOX budgets
for each state covered for the 24-hour and/or annual average
PM2.5 NAAQS. EPA proposes an ozone season \3\ NOX
budget for each state covered for the ozone NAAQS.
---------------------------------------------------------------------------
\2\ For the 10 states discussed above for which EPA has only
quantified a minimum amount of emissions reductions needed to make
measurable progress towards eliminating their significant
contribution and interference with maintenance with respect to the
1997 8-hour ozone NAAQS, the emissions budget is the emissions that
will remain after removal of those emissions.
\3\ Consistent with the approach taken by the Ozone Transport
Assessment Group (OTAG), the NOX SIP call, and the CAIR,
we propose to define the ozone season, for purposes of emissions
reductions requirements in this rule, as May through September. We
recognize that this ozone season for regulatory requirements differs
from the official state-specific monitoring season.
---------------------------------------------------------------------------
EPA recognizes that baseline emissions from a state can be affected
by changing weather patterns, demand growth, or disruptions in
electricity supply from other units. As a result, emissions could vary
from year to year in a state where covered sources have installed all
controls and taken all measures necessary to eliminate the state's
significant contribution and interference with maintenance. As
described in detail in section IV of this preamble, EPA proposes to
account for the inherent variability in power system operations through
``assurance provisions'' based on state variability limits which extend
above the state emissions budgets. See section V for a detailed
discussion of the assurance provisions. The small amount of variability
allowed takes into account the inherent variability in baseline
emissions. Section IV in this preamble describes the proposed approach
to significant contribution and interference with maintenance and the
state emissions budgets and variability limits in detail.
EPA is also proposing FIPs to immediately implement the emission
reduction requirements identified and quantified by EPA in this action.
For some covered states, these FIPs will completely satisfy the
emissions reductions requirements of 110(a)(2)(D)(i)(I) with respect to
the 1997 and 2006 PM2.5 NAAQS and the 1997 ozone NAAQS. The
exception is for the 10 eastern states for which EPA has not completely
quantified the total significant contribution or interference with
maintenance with respect to the 1997 ozone NAAQS and the 15 states for
which EPA has not completely quantified total significant contribution
or interference with maintenance with respect to the 2006
PM2.5 NAAQS in which case the FIPs would achieve measurable
progress towards implementing that requirement.
The emissions reductions requirements (i.e., the ``remedy'') that
EPA is proposing to include in the FIPs responds to the Court's
concerns that EPA had not shown that the CAIR reduction requirements
would get all
[[Page 45215]]
necessary reductions ``in the state'' as required by section
110(a)(2)(D)(i)(I). The proposed 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.
The proposed FIPs would regulate EGUs in the 32 covered states. EPA
is proposing to regulate these sources through a program that uses
state-specific budgets and allows intrastate and limited interstate
trading. EPA is also taking comment on two alternative regulatory
options. All options would achieve the emissions reductions necessary
to address the emissions transport requirements in section
110(a)(2)(D)(i)(I) of the CAA.
The option EPA is proposing for the FIPs (``State Budgets/Limited
Trading'') would use state-specific emissions budgets and allow for
intrastate and limited interstate trading. This approach would assure
environmental results while providing some limited flexibility to
covered sources. The approach would also facilitate the transition from
CAIR to the Transport Rule for implementing agencies and covered
sources.
The first alternative remedy option for which EPA requests comment
would use state-specific emissions budgets and allow intrastate
trading, but prohibit interstate trading. The second alternative remedy
option, for which EPA also requests comment, would use state-specific
budgets and emissions rate limits. See section V for further discussion
of the remedy options.
The proposed remedy option and the first alternative, both of which
are cap-and-trade approaches, would use new allowance allocations
developed on a different basis from CAIR. Allowance allocations, like
the state budgets described previously, would be developed based on the
methodology used by EPA to quantify each state's significant
contribution and interference with maintenance. See section IV for the
proposed state budget approach and section V for proposed allowance
allocation approaches.
In this action, EPA proposes to require reductions in
SO2 and NOX emissions in the following 25
jurisdictions that contribute significantly to nonattainment in, or
interfere with maintenance by, a downwind area with respect to the 24-
hour PM2.5 NAAQS promulgated in September 2006: Alabama,
Connecticut, Delaware, District of Columbia, Georgia, Illinois,
Indiana, Iowa, Kansas, Kentucky, Maryland, Massachusetts, Michigan,
Minnesota, Missouri, Nebraska, New Jersey, New York, North Carolina,
Ohio, Pennsylvania, Tennessee, Virginia, West Virginia, and Wisconsin.
EPA proposes to require reductions in SO2 and
NOX emissions in the following 24 jurisdictions that
contribute significantly to nonattainment in, or interfere with
maintenance by, a downwind area with respect to the annual
PM2.5 NAAQS promulgated in July 1997: Alabama, Delaware,
District of Columbia, Florida, Georgia, Illinois, Indiana, Iowa,
Kentucky, Louisiana, Maryland, Michigan, Minnesota, Missouri, New
Jersey, New York, North Carolina, Ohio, Pennsylvania, South Carolina,
Tennessee, Virginia, West Virginia, and Wisconsin.
EPA also proposes to require reductions in ozone season
NOX emissions in the following 26 jurisdictions that
contribute significantly to nonattainment in, or interfere with
maintenance by, a downwind area with respect to the 1997 ozone NAAQS
promulgated in July 1997: Alabama, Arkansas, Connecticut, Delaware,
District of Columbia, Florida, Georgia, Illinois, Indiana, Kansas,
Kentucky, Louisiana, Maryland, Michigan, Mississippi, New Jersey, New
York, North Carolina, Ohio, Oklahoma, Pennsylvania, South Carolina,
Tennessee, Texas, Virginia, and West Virginia.
As discussed previously, EPA also is proposing FIPs to directly
regulate EGU SO2 and/or NOX emissions in the 32
covered states. The proposed FIPs would require the 28 jurisdictions
covered for purposes of the 24-hour and/or annual PM2.5
NAAQS to reduce SO2 and NOX emissions by
specified amounts. The proposed FIPs would require the 26 states
covered for purposes of the ozone NAAQS to reduce ozone season
NOX emissions by specified amounts.
In response to the Court's opinion in North Carolina v. EPA, EPA
has coordinated the compliance deadlines for upwind states to eliminate
emissions that significantly contribute to or interfere with
maintenance in downwind areas with the NAAQS attainment deadlines that
apply to the downwind nonattainment and maintenance areas. EPA proposes
to require that all significant contribution to nonattainment and
interference with maintenance identified in this action with respect to
the PM2.5 NAAQS be eliminated by 2014 and proposes an
initial phase of reductions starting in 2012 (covering 2012 and 2013)
to ensure that the reductions are made as expeditiously as practicable
and that no backsliding from current emissions levels occurs when the
requirements of the CAIR are eliminated. Sources will be required to
comply by January 1, 2012 and January 1, 2014 for the first and second
phases, respectively. With respect to the 1997 ozone NAAQS, EPA
proposes to require an initial phase of NOX reductions
starting in 2012 to ensure that reductions are made as expeditiously as
practicable. Sources will be required to comply by May 1, 2012 and May
1, 2014 for the first and second phases, respectively. EPA has
determined, that for many states, these reductions will be sufficient
to eliminate their significant contribution with respect to the 1997
ozone NAAQS. EPA intends to issue a subsequent proposal that would
require all significant contribution and interference with maintenance
be eliminated by a future date for the 1997 ozone NAAQS. See Table
III.A-1 for proposed lists of covered state.
Table III.A-1--Lists of Covered States for PM2.5 and 8-Hour Ozone NAAQS
------------------------------------------------------------------------
Covered for 24- Covered for 8-
hour and/or hour ozone
annual PM2.5 ------------------
State -------------------
Required to Required to
reduce SO2 and reduce ozone
NOX Season NOX
------------------------------------------------------------------------
Alabama........................... X X
Arkansas.......................... ................. X
Connecticut....................... X X
Delaware.......................... X X
District of Columbia.............. X X
Florida........................... X X
[[Page 45216]]
Georgia........................... X X
Illinois.......................... X X
Indiana........................... X X
Iowa.............................. X .................
Kansas............................ X X
Kentucky.......................... X X
Louisiana......................... X X
Maryland.......................... X X
Massachusetts..................... X .................
Michigan.......................... X X
Minnesota......................... X .................
Mississippi....................... ................. X
Missouri.......................... X .................
Nebraska.......................... X .................
New Jersey........................ X X
New York.......................... X X
North Carolina.................... X X
Ohio.............................. X X
Oklahoma.......................... ................. X
Pennsylvania...................... X X
South Carolina.................... X X
Tennessee......................... X X
Texas............................. ................. X
Virginia.......................... X X
West Virginia..................... X X
Wisconsin......................... X .................
-------------------------------------
Totals........................ 28 26
------------------------------------------------------------------------
As discussed previously, EPA is proposing new SO2 and/or
NOX emissions budgets for each covered state. The budgets
are based on the EPA's state-by-state analysis of each upwind state's
significant contribution to nonattainment and interference with
maintenance downwind, before accounting for the inherent variability in
power system operations.
As discussed in detail in section IV, the proposed approach to
significant contribution to nonattainment and interference with
maintenance would group the 28 states covered for the 24-hour and/or
annual PM2.5 NAAQS in two tiers reflecting the stringency of
SO2 reductions required to eliminate that state's
significant contribution to nonattainment and interference with
maintenance. There would be a stringent SO2 tier comprising
15 states (``group 1'') and a moderate SO2 tier comprising
13 states (``group 2''), with uniform stringency within each tier.\4\
For these same 28 states, there would be one annual NOX tier
with uniform stringency of NOX reductions across all 28
states. Similarly, for the 26 states covered for the ozone NAAQS there
would be one ozone season NOX tier with uniform stringency
across all 26 states.
---------------------------------------------------------------------------
\4\ 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.
---------------------------------------------------------------------------
The proposed stringent SO2 tier (``group 1'') would
include Georgia, Illinois, Indiana, Iowa, Kentucky, Michigan, Missouri,
New York, North Carolina, Ohio, Pennsylvania, Tennessee, Virginia, West
Virginia, and Wisconsin. The proposed moderate SO2 tier
(``group 2'') would include Alabama, Connecticut, Delaware, District of
Columbia, Florida, Kansas, Louisiana, Maryland, Massachusetts,
Minnesota, Nebraska, New Jersey, and South Carolina.
As discussed previously, EPA proposes to require an initial phase
of reductions starting in 2012 (covering 2012 and 2013) requiring
SO2 and NOX reductions in the 28 states covered
for 24-hour and/or annual PM2.5 NAAQS. A second phase of
reductions would be due in 2014, covering 2014 and thereafter. As
described later, for certain states the 2014 reduction requirements
would be more stringent, and for certain states would remain at the
same level as the 2012 requirements.
For the 15 states in the stringent SO2 tier (``group
1''), the 2014 phase would substantially increase the SO2
reduction requirements (i.e., these states would have smaller
SO2 emissions budgets starting in 2014), reflecting the
greater reductions needed to eliminate the portion of significant
contribution and interference with maintenance that EPA has identified
in this proposal from these states with respect to the 24-hour
PM2.5 NAAQS. For the 13 states in the moderate
SO2 tier (``group 2''), the 2014 SO2 emissions
budgets would remain the same as the 2012 SO2 budgets for
these states.
The 2014 annual NOX emissions budgets for all 28 states
covered for the 24-hour and/or annual PM2.5 NAAQS would
remain the same as the 2012 annual NOX budgets.
With respect to the ozone NAAQS, EPA is proposing a single phase of
reductions which begins in 2012. Thus, the rule does not call for any
adjustment to be made to the 2012 ozone season NOX budgets
for the 26 states covered for the ozone NAAQS. EPA intends to issue a
subsequent proposal that would, among other things, address whether an
additional phase of NOX reductions is necessary to address
all significant
[[Page 45217]]
contribution and interference with maintenance with respect to the 1997
ozone NAAQS. While this proposal assures downwind states that they will
receive relief from upwind reductions that will help them achieve the
NAAQS, EPA is committed to fulfilling its obligation to assure the
downwind states that they receive the full relief they are entitled to
under section 110(a)(2)(D). The Agency intends to quickly address any
remaining significant contribution to nonattainment and interference
with maintenance in a subsequent action that will also address a new
more stringent ozone standard that is expected to be established by EPA
later in 2010.
Tables III.A-2 and III.A-3 show projected Transport Rule emissions
reductions for EGUs in all states that EPA proposes to cover.
Table III.A-2--Projected SO2 and NOX EGU Emissions in Covered States With the Transport Rule \5\ Compared to Base Case \6\ Without Transport Rule or
CAIR
[Million tons]
--------------------------------------------------------------------------------------------------------------------------------------------------------
2012 2014
2012 Base Transport 2012 2014 Base Transport 2014
case rule Emissions case rule Emissions
emissions emissions reductions emissions emissions reductions
--------------------------------------------------------------------------------------------------------------------------------------------------------
SO2..................................................... 8.4 3.4 5.0 7.2 2.6 4.6
Annual NOX.............................................. 2.0 1.3 0.7 2.0 1.3 0.7
Ozone Season NOX........................................ 0.7 0.6 0.1 0.7 0.6 0.1
--------------------------------------------------------------------------------------------------------------------------------------------------------
Table III.A-3--Projected SO2 and NOX EGU Emissions in Covered States With the Transport Rule Compared to 2005
Actual Emissions
[Million tons]
----------------------------------------------------------------------------------------------------------------
2012 2012 2014 2014
2005 Actual Transport Emissions Transport Emissions
emissions rule reductions rule reductions
emissions from 2005 emissions from 2005
----------------------------------------------------------------------------------------------------------------
SO2............................. 8.9 3.4 5.5 2.6 6.3
Annual NOX...................... 2.7 1.3 1.4 1.3 1.4
Ozone Season NOX................ 0.9 0.6 0.3 0.6 0.3
----------------------------------------------------------------------------------------------------------------
In addition to the emissions reductions shown previously, EPA
projects other substantial benefits, as described in section IX in this
preamble. Air quality modeling was used to quantify the improvements in
PM2.5 and ozone concentrations that are expected to result
from the emissions reductions in 2014. The results of this modeling
were used to calculate the average reduction in annual average
PM2.5, 24-hour average PM2.5, and 8-hour ozone
concentrations for monitoring sites in the eastern U.S. that are
projected to be nonattainment in the 2014 base case. For annual
PM2.5 and 24-hour PM2.5, the average reductions
are 2.4 micrograms per cubic meter ([mu]g/m\3\) and 4.3 [mu]g/m\3\,
respectively. The average reduction in 8-hour ozone at monitoring sites
projected to be nonattainment in the 2014 base case is 0.3 parts per
billion (ppb). The reductions in annual PM2.5, 24-hour
PM2.5, and ozone concentrations for individual nonattainment
and/or maintenance sites are provided in section IX.
---------------------------------------------------------------------------
\5\ Projected Transport Rule emissions result from individual
stae budgets in the proposed approach and include some banking of
allowances in 2012 adn use of that bank in 2014.
\6\ EPA's base case EGU emissions modeling does not assume
enforceable SO2 or NOX reductions attributed
to the Transport Rule or CAIR. In this base case, a unit with
existing SO2 or NOX control equipment, but
without an enforceable federal or state control requirement, is
allowed to choose its most economic approach to operation within
existing Acid Rain Program requirements and may opt not to operate a
control. See section IV.C.1 and the IPM Documentation for further
information on the base case modeling.
---------------------------------------------------------------------------
Table III.A-4 compares projected EGU emissions with the Transport
Rule to projected EGU emissions with CAIR.
Table III.A-4--Simple Comparison of SO2 and NOX Emissions From Electric Generating Units in States in the CAIR or Transport Rule Regions * for Each Rule
--------------------------------------------------------------------------------------------------------------------------------------------------------
2005 2012 2014
-------------------------------------------------------------------------------
Actual Transport rule CAIR ** Transport rule CAIR **
--------------------------------------------------------------------------------------------------------------------------------------------------------
SO2 (Million Tons)...................................................... 9.5 4.1 5.1 3.3 4.6
NOX (Million Tons)........................ Annual...................... 2.9 1.6 1.7 1.6 1.7
Ozone Season................ 1.0 0.7 0.8 0.7 0.8
--------------------------------------------------------------------------------------------------------------------------------------------------------
* Emissions totals include states covered by either the Transport Rule or CAIR. For PM2.5 (SO2 and annual NOX), the following 30 states are included:
AL, CT, DE, DC, FL, GA, IL, IN, IA, KS, KY, LA, MD, MA, MI, MN, MS, MO, NE, NJ, NY, NC, OH, PA, SC, TN, TX, VA, WV, WI. For ozone (ozone-season NOX),
the following 30 states are included: AL, AR, CT, DE, DC, FL, GA, IL, IN, IA, KS, KY, LA, MD, MA, MI, MS, MO, NJ, NY, NC, OH, OK, PA, SC, TN, TX, VA,
WV, WI.
** CAIR SO2 totals are interpolations from emissions analysis originally done for 2010 and 2015. CAIR NOX totals are as originally projected for 2010.
This CAIR modeling represents a scenario that differed somewhat from the final CAIR (the modeling did not include a regionwide ozone season NOX cap
and included PM2.5 requirements for the state of Arkansas).
[[Page 45218]]
In addition to discussion of EPA's proposed regulatory approach
(discussed in sections IV and V), this preamble also covers the
stakeholder outreach EPA conducted (section VI), SIP submissions
(section VII), permitting (section VIII), projected benefits of the
proposed rule (section IX), economic impacts (section X), end-use
energy efficiency (section XI), and statutory and executive order
reviews (section XII).
Table III.A-5 shows the results of the cost and benefits analysis
for the proposed and alternate remedies. Further discussion of these
results is contained in preamble section XII-A and in the Regulatory
Impacts Analysis. A listing of health and welfare effects is provided
in RIA Table 1-6. Estimates here are subject to uncertainties discussed
further in the body of the document. The social costs are the loss of
household utility as measured in Hicksian equivalent variation. The
capital costs spent for pollution controls installed for CAIR were not
included in the annual social costs since the Transport Rule did not
lead to their installation. Those CAIR-related capital investments are
roughly estimated to have an annual social cost less than $1.15 to $
1.29 billion (under the two discount rates.)
Most of the estimated PM-related benefits in this rule accrue to
populations exposed to higher levels of PM2.5. Of these
estimated PM-related mortalities avoided, about 80 percent occur among
populations initially exposed to annual mean PM2.5 level of
10 [mu]g/m\3\ and about 97 percent occur among those initially exposed
to annual mean PM2.5 level of 7.5 [mu]g/m\3\. These are the
lowest air quality levels considered in the Laden et al. (2006) and
Pope et al. (2002) studies, respectively. This fact is important,
because as we estimate PM-related mortality among populations exposed
to levels of PM2.5 that are successively lower, our
confidence in the results diminishes. However, our analysis shows that
the great majority of the impacts occur at higher exposures.
Table III.A-5--Summary of Annual Benefits, Costs, and Net Benefits of Versions of the Proposed Remedy Option in
2014 \a\
[Billions of 2006$]
----------------------------------------------------------------------------------------------------------------
Preferred remedy--State
Description budgets/ limited trading Direct control Intrastate trading
----------------------------------------------------------------------------------------------------------------
Social costs:
3% discount rate............. $2.03................... $2.68................... $2.49.
7% discount rate............. $2.23................... $2.91................... $2.70.
Health-related benefits: b, c
3% discount rate............. $118 to $288 + B........ $117 to $286 + B........ $113 to $276 + B.
7% discount rate............. $108 to $260 + B........ $108 to $262 + B........ $104 to $252 + B.
Net benefits (benefits-costs):
3% discount rate............. $116 to $286............ $115 to $283............ $110 to $273.
7% discount rate............. $105 to $258............ $105 to $259............ $101 to $249.
----------------------------------------------------------------------------------------------------------------
Notes: (a) All estimates are rounded to three significant digits and represent annualized benefits and costs
anticipated for the year 2014. For notational purposes, unquantified benefits are indicated with a ``B'' to
represent the sum of additional monetary benefits and disbenefits. Data limitations prevented us from
quantifying these endpoints, and as such, these benefits are inherently more uncertain than those benefits
that we were able to quantify. (b) The reduction in premature mortalities account for over 90 percent of total
monetized benefits. Benefit estimates are national. Valuation assumes discounting over the SAB-recommended 20
