[Federal Register Volume 75, Number 147 (Monday, August 2, 2010)]
[Proposed Rules]
[Pages 45210-45465]
From the Federal Register Online via the Government Publishing 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:
http://www.regulations.gov. Follow the online instructions
for submitting comments. Attention Docket ID No. EPA-HQ-OAR-2009-0491.
E-mail: [email protected]. 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
http://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 http://www.regulations.gov or e-mail. The http://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 http://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 http://www.epa.gov/epahome/dockets.htm.
Docket. All documents in the docket are listed in the http://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 http://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: [email protected]. For legal questions, please contact Ms.
Sonja Rodman, U.S. EPA, Office of General Counsel, Mail Code 2344A,
1200 Pennsylvania Avenue, NW., Washington, DC 20460, telephone (202)
564-4079; e-mail address [email protected].
SUPPLEMENTARY INFORMATION:
I. Preamble Glossary of Terms and Abbreviations
The following are abbreviations of terms used in the preamble.
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:
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Industry group NAICS \a\
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Utilities (electric, natural gas, other 2211, 2212, 2213
systems).
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\a\ North American Industry Classification System.
This table is not intended to be exhaustive, but rather provides a
guide for readers regarding entities likely to be regulated by this
action. This table lists 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 http://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
http://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: [email protected]. 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,
http://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.
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\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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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-
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.
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--
(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 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,
[[Page 45219]]
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 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.
2. What air quality problems does this proposal address?
a. Fine Particles
Fine particles are associated with a number of serious health
effects including premature mortality, aggravation of respiratory and
cardiovascular disease (as indicated by increased hospital admissions,
emergency room visits, health-related absences from school or work, and
restricted activity days), lung disease, decreased lung function,
asthma attacks, and certain cardiovascular problems. See EPA, Air
Quality Criteria for Particulate Matter (EPA/600/P-99/002bF, October
2004) at 9.2.2.3. See also integrated science assessment for the PM
NAAQS review, December 2009, http://cfpub.epa.gov/ncea/cfm/recordisplay.cfm?deid=216546. Individuals particularly sensitive to
fine particle exposure include older adults, people with heart and lung
disease, and children. This rule, and the NAAQS to which it is related,
consider the effects of fine particles on vulnerable populations (see
further discussion in section XII.G and section XII.J of this notice).
More detailed information on health effects of fine particles can be
found on EPA's Web site at: http://epa.gov/pm/standards.html.
In addition to effects on public health, fine particles are linked
to a number of public welfare effects. First, PM2.5 are the
major cause of reduced visibility (haze) in parts of the United States,
including many of our national parks and wilderness areas. For more
information about visibility, visit EPA's Web site at http://www.epagov/visibility. Second, particles can be carried over long
distances by wind and then settle on ground or water. The effects of
this settling include: Making lakes and streams acidic; changing the
nutrient balance in coastal waters and large river basins; depleting
the nutrients in soil; damaging sensitive forests and farm crops; and
affecting the diversity of ecosystems. More information about these
effects is available at EPA's Web site at http://www.epa.gov/acidrain/effects/index.html. 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
24-hour standards for fine particles, using PM2.5 as the
indicator (62 FR 38652). These revisions established an annual standard
of 15 [mu]g/m\3\ and a 24-hour standard of 65 [mu]g/m\3\. During 2006,
EPA revised the air quality standards for PM2.5. The 2006
standards decreased the level of the 24-hour fine particle standard
from 65 [mu]g/m\3\ to 35 [mu]g/m\3\, and retained the annual fine
particle standard at 15 [mu]g/m\3\.
In the preamble to the final rule for CAIR in May 2005, EPA
discussed ambient monitoring for 2001-2003, the most recent 3-year
period available at the time. These results showed widespread
exceedances of the 15 [mu]g/m\3\ annual PM2.5 standard in
the eastern United States, with additional exceedances in parts of
California and one county in Montana. At that time, 82 counties in the
U.S. had at least one monitor that violated the 1997 annual
PM2.5 standard.
The PM2.5 ambient air quality monitoring for the 2006-
2008 period (most recent available) shows significant improvements.
Nonetheless, areas which continue to violate the 15 [mu]g/m\3\ annual
PM2.5 standard are located across a significant portion of
the eastern half of the United States, in parts of California and one
county in Arizona. Based on these nationwide data, 23 counties have at
least one monitor that violates the annual PM2.5 standard.
The PM2.5 ambient air quality monitoring for this same
2006-2008 time period shows that areas violating the 2006 24-hour
PM2.5 standard of 35 [mu]g/m\3\ (i.e., the revised 2006
standard for 24-hour PM2.5) are located across much of the
eastern half of the United States, in parts of California, and in some
counties in several other western states--Alaska, Washington, Oregon,
Utah, and Arizona. Based on these nationwide data, 52 counties have at
least one monitor that violates the 24-hour PM2.5 standard.
EPA believes that a great deal of the improvement in
PM2.5 annual and 24-hour concentrations in the eastern U.S.
can be attributed to EGU SO2 reductions achieved due to the
CAIR. While the CAIR requirements related to SO2 did not
begin until 2010, many actions were taken by EGU owners and operators
in anticipation of those requirements. Emissions of SO2 from
EGUs covered by the CAIR that were also in the acid rain
[[Page 45220]]
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 http://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: http://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 short-term 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 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: http://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 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: http://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: http://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: http://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 8-hour ozone standard is 0.08 ppm. The 1997
PM2.5 standards promulgated in 1997 established a 15 [mu]g/
\3\ standard for 24-hour PM2.5 and a 65 [mu]g/m\3\ standard
for annual PM2.5. In 2006, the 24-hour PM2.5
standard was lowered to 35 [mu]g/m\3\ and the 15 [mu]g/m\3\ annual
PM2.5 standard was left unchanged.
[[Page 45221]]
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 [mu]g/m\3\. For the 24-hour standard of 35 [mu]g/m\3\ 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
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 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 finding designed to protect that entity from upwind
sources of air pollutants.\7\
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\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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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
[[Page 45222]]
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.
---------------------------------------------------------------------------
\8\ Guidance for Implementing the 1-hour Ozone and Pre-Existing
PM10 NAAQS, Memorandum from Richard D. Wilson, dated December 29,
1997.
---------------------------------------------------------------------------
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 1-hour 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 8-hour 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 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 pre-
existing 1-hour ozone standards. The 1-hour 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
8-hour standard identical to the new primary standard. The new
secondary standard provided increased protection to the public welfare
against ozone-induced 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 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.
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\9\ The 8 states were Connecticut, Massachusetts, Maine, New
Hampshire, New York, Pennsylvania, Rhode Island, and Vermont.
---------------------------------------------------------------------------
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?
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\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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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-and-comment rulemaking. The EPA believed
[[Page 45223]]
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 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 cost-effectiveness 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 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.
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\11\ U.S.EPA. September, 2009. The NOX Budget Trading Program:
2008 Environmental Results, p.9.
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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
[[Page 45224]]
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\
---------------------------------------------------------------------------
\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.
---------------------------------------------------------------------------
(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.
---------------------------------------------------------------------------
\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.
---------------------------------------------------------------------------
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 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 multi-state 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 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
[[Page 45225]]
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. 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 http://camddataandmaps.epa.gov/gdm/) and an assessment of emissions reduction
data will be available at the end of each compliance period.
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
[[Page 45226]]
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 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 8-hour 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 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
[[Page 45227]]
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.
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.
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
[mu]g/m\3\ 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 24-hour PM2.5 problem at each of these
locations is available at: http://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
[[Page 45228]]
CAA Section 112(d) standards; (4) revisions to the NSPS for coal and
oil-fired 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 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 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,
[[Page 45229]]
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 co-control
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 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 end-use 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 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 forward-looking 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
[[Page 45230]]
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
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 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\
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\14\ In the NOX SIP Call, because the same criteria
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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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 then-current air quality of
the area, the predicted future air quality (assuming 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\
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\15\ EPA explained in the NOX SIP Call, ``It should
be reiterated that EPA relied on the designated area solely as a
proxy to determine which areas have air quality in nonattainment.
This proxy is readily available under the 1-hour NAAQS because areas
have long been designated nonattainment. The EPA's reliance on
designated nonattainment areas for purposes of the 1-hour NAAQS does
not indicate that the reference in section 110(a)(2)(D)(i)(I) to
``nonattainment'' should be interpreted to refer to areas designated
nonattainment.'' (63 FR 57375, footnote 25)
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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.
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\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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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
[[Page 45231]]
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 cost-effective--remained
available to the states.
Determination of Highly Cost-Effective Amount. EPA determined the
dollar amount considered to be highly cost-effective by reference to
the cost-effectiveness of recently promulgated or proposed
NOX controls. EPA determined that the average cost-
effectiveness 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 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 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.
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\17\ EPA did not address 24-hour PM2.5 NAAQS in CAIR,
only the annual PM2.5 NAAQS.
---------------------------------------------------------------------------
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 [mu]g/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
[[Page 45232]]
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 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-with-
maintenance'' issue, which is identifying the downwind areas whose
maintenance of the NAAQS may suffer interference due to upwind
emissions. The EPA has analyzed the ``interfere-with-maintenance''
issue for the 8-hour NAAQS by examining areas whose current air
quality is monitored as attaining the 8-hour NAAQS [or which have no
current air quality monitoring], but for which air quality modeling
shows nonattainment in the year 2007. This result is projected to
occur, notwithstanding the imposition of certain controls required
under the CAA, because of projected increases in emissions due to
growth in emissions generating activity. Under these circumstances,
emissions from upwind areas may interfere with the downwind area's
ability to attain. Ascertaining the impact on the downwind area's
air quality of the upwind area's emissions aids in determining
whether the upwind emissions interfere with maintenance (62 FR
60326).
In today's action, EPA is taking the same positions with respect
to the interfere-with-maintenance test as described in the 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 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\
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\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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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 [mu]g/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
[[Page 45233]]
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 ``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 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-to-year 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
[[Page 45234]]
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 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 state-specific
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.
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 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.)
1. Background
a. For the CAIR, how did EPA determine which pollutants were necessary
to control to address interstate transport for PM2.5?
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
[[Page 45235]]
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. 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 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., http://www.gov/ttn/chief.) The relative importance of
NOX and VOC in ozone formation and control varies with
local- and time-specific factors, including the relative amounts of VOC
and NOX present. In rural areas with high concentrations of
VOC from biogenic sources, ozone formation and control is governed by
NOX. In some urban core situations, NOX
concentrations can be high enough relative to VOC to suppress ozone
formation locally, but still contribute to increased ozone downwind
from the city. In such situations, VOC reductions are most effective at
reducing ozone within the urban environment and immediately downwind.
The formation of ozone increases with temperature and sunlight, which
is one reason ozone levels are higher during the summer. Increased
temperature also increases emissions of volatile man-made and biogenic
organics and can indirectly increase NOX as well (e.g.,
increased electricity generation for air conditioning). Summertime
conditions also bring increased episodes of large-scale stagnation,
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: http://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
[[Page 45236]]
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: http://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.
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
annual\19\ 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.
---------------------------------------------------------------------------
\19\ For the CAIR, 24-hour PM2.5 was not at issue
because there were little or no exceedances of the then-existing 65
[mu]g/m\3\ 24-hour standards
---------------------------------------------------------------------------
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 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 [mu]g/m\3\.
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 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 [mu]g/m\3\, 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
[[Page 45237]]
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?
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 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 [mu]g/m\3\,
rather than the two-digit value in the proposed CAIR, 0.15 [mu]g/m\3\.
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 [mu]g/m\3\ (decimals 0.05 and greater are rounded
up to the next 0.1, and any decimal lower than 0.05 is rounded down
to the nearest 0.1).
Because the design value is to be reported only to the nearest 0.1
[mu]g/m\3\, EPA deemed it preferable for the final CAIR to select the
threshold value at the nearest 0.1 [mu]g/m\3\ as well, and hence one
percent of the 15 [mu]g/m\3\, rounded to the nearest 0.1 [mu]g/m\3\
became 0.2 [mu]g/m\3\.
For the 24-hour standard of 35 [mu]g/m\3\, 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 [mu]g/m\3\ (decimals 0.5 and greater are rounded up
to the nearest whole number, and any decimal lower than 0.5 is
rounded down to the nearest whole number).
One percent of the 24-hour standard is 0.35 [mu]g/m\3\, and
rounding to the nearest whole [mu]g/m\3\ 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 [mu]g/m\3\ for the annual standard, and 0.35 [mu]g/m\3\ for
the 24-hour standard. EPA believes there are a number of considerations
favoring this approach. First, it provides for a consistent approach
for the annual and 24-hour standards. Second, the 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 [mu]g/m\3\ would reduce the
air quality threshold to 0.1 [mu]g/m\3\. This would occur because any
value less than 0.15 [mu]g/m\3\ (e.g., 0.14 [mu]g/m\3\) would be
rounded down to 0.1 [mu]g/m\3\. 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
[[Page 45238]]
convention that was used in the final CAIR for the 15 [mu]g/m\3\ 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
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 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.
---------------------------------------------------------------------------
\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.
---------------------------------------------------------------------------
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 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\
---------------------------------------------------------------------------
\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.
---------------------------------------------------------------------------
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
[[Page 45239]]
biogenic emissions data were used in all scenarios modeled.
---------------------------------------------------------------------------
\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 Aerosols from Nature (MEGAN),'' 7th
Annual Community Multiscale Analysis System Conference, Chapel Hill,
NC, October 6-8, 2008.
\24\ Donna Schwede, D., Pouliot, G., and Pierce, T. ``Changes to
the Biogenic Emissions Inventory System Version 3 (BEIS3),'' 4th
Annual Community Multiscale Analysis System Conference, Chapel Hill,
NC, September 26-28, 2005.
---------------------------------------------------------------------------
(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 county-based inventories. Additionally, the inventories
were processed to provide the hourly, gridded, model-species needed by
CAMx.
---------------------------------------------------------------------------
\25\ The oil and gas exploration inventory was provided by the
Western Regional Air Partnership.
---------------------------------------------------------------------------
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
--------------------------------------------------------------------------------------------------------------------------------------------------------
State EGU NonEGU Nonpoint Nonroad Onroad Fires Total
--------------------------------------------------------------------------------------------------------------------------------------------------------
Alabama...................................................... 460,123 70,346 52,325 6,397 3,199 983 593,372
Arkansas..................................................... 66,384 13,066 27,260 5,678 1,632 728 114,749
Connecticut.................................................. 10,356 1,831 18,455 2,548 1,128 4 34,320
Delaware..................................................... 32,378 34,859 5,859 11,648 422 6 85,173
District of Columbia......................................... 1,082 686 1,559 414 172 0 3,914
Florida...................................................... 417,321 57,475 70,490 93,543 10,285 7,018 656,131
Georgia...................................................... 616,054 56,116 56,829 13,331 5,690 2,010 750,031
Illinois..................................................... 330,382 156,154 5,395 19,302 5,716 20 516,969
Indiana...................................................... 878,978 95,200 59,775 9,436 3,981 24 1,047,396
Iowa......................................................... 130,264 61,241 19,832 8,838 1,702 25 221,902
Kansas....................................................... 136,520 13,142 36,381 8,035 1,824 103 196,005
[[Page 45240]]
Kentucky..................................................... 502,731 25,811 34,229 6,942 2,711 364 572,787
Louisiana.................................................... 109,851 165,737 2,378 73,233 2,399 892 354,489
Maine........................................................ 3,887 18,519 9,969 3,725 834 150 37,084
Maryland..................................................... 283,205 34,988 40,864 17,819 2,966 32 379,874
Massachusetts................................................ 85,768 19,620 25,261 25,335 2,168 93 158,245
Michigan..................................................... 349,877 76,510 42,066 14,533 7,204 91 490,280
Minnesota.................................................... 101,666 25,169 14,747 10,410 2,558 631 155,181
Mississippi.................................................. 74,117 29,892 6,796 6,003 2,158 1,051 120,016
Missouri..................................................... 284,384 78,307 44,573 10,464 4,251 186 422,165
Nebraska..................................................... 74,955 6,429 29,575 9,199 1,326 105 121,589
New Hampshire................................................ 51,445 3,245 7,408 805 630 38 63,571
New Jersey................................................... 57,044 7,640 10,726 23,484 2,486 61 101,441
New York..................................................... 180,847 58,562 125,158 20,908 5,628 113 391,216
North Carolina............................................... 512,231 66,150 22,020 42,743 5,341 696 649,181
North Dakota................................................. 137,371 9,458 6,455 5,986 443 66 159,779
Ohio......................................................... 1,116,084 118,468 19,810 15,615 6,293 22 1,276,292
Oklahoma..................................................... 110,081 40,482 7,542 5,015 2,699 469 166,288
Pennsylvania................................................. 1,002,202 85,411 68,349 11,972 5,363 32 1,173,328
Rhode Island................................................. 176 2,743 3,365 2,494 208 1 8,987
South Carolina............................................... 218,782 31,495 30,016 20,477 2,976 646 304,393
South Dakota................................................. 12,215 1,698 10,347 3,412 511 498 28,682
Tennessee.................................................... 266,148 78,206 32,714 6,288 4,834 277 388,468
Texas........................................................ 534,949 223,625 109,215 52,749 13,470 1,178 935,187
Vermont...................................................... 9 902 5,385 385 305 49 7,036
Virginia..................................................... 220,248 69,440 32,923 18,420 3,829 399 345,259
West Virginia................................................ 469,456 48,314 14,589 2,133 1,095 215 535,802
Wisconsin.................................................... 180,200 66,807 6,369 7,129 3,110 70 263,685
------------------------------------------------------------------------------------------
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
--------------------------------------------------------------------------------------------------------------------------------------------------------
State EGU NonEGU Nonpoint Nonroad Onroad Fires Total
--------------------------------------------------------------------------------------------------------------------------------------------------------
Alabama...................................................... 133,051 74,830 32,024 61,623 142,221 3,814 447,562
Arkansas..................................................... 35,407 37,478 21,453 63,493 81,014 2,654 241,499
Connecticut.................................................. 6,865 5,824 12,554 21,785 69,645 14 116,688
Delaware..................................................... 11,917 5,567 3,259 15,567 22,569 23 58,902
District of Columbia......................................... 492 501 1,740 3,494 9,677 0 15,904
Florida...................................................... 217,263 53,778 29,533 277,888 460,474 25,600 1,064,537
Georgia...................................................... 111,017 53,297 38,919 95,175 279,449 7,955 585,812
Illinois..................................................... 127,923 97,504 47,645 223,697 276,507 71 773,347
Indiana...................................................... 213,503 73,647 30,185 110,100 187,426 88 614,949
Iowa......................................................... 72,806 39,299 15,150 92,965 91,795 90 312,105
Kansas....................................................... 90,220 70,785 42,286 86,553 76,062 378 366,285
Kentucky..................................................... 164,743 35,432 17,557 90,669 127,435 1,326 437,163
Louisiana.................................................... 63,791 165,162 27,559 301,170 112,889 3,254 673,824
Maine........................................................ 1,100 18,309 7,423 13,379 38,469 566 79,246
Maryland..................................................... 62,574 24,621 21,715 55,812 129,796 137 294,656
Massachusetts................................................ 25,618 18,429 34,373 74,419 118,148 341 271,327
Michigan..................................................... 120,005 94,139 43,499 101,087 279,816 330 638,876
Minnesota.................................................... 83,836 64,438 56,700 115,873 146,138 2,300 469,286
Mississippi.................................................. 45,166 53,985 12,212 79,394 98,060 3,833 292,649
Missouri..................................................... 127,431 38,604 32,910 123,228 183,022 678 505,873
Nebraska..................................................... 52,426 12,156 13,820 107,180 58,643 381 244,607
New Hampshire................................................ 8,827 3,241 11,235 9,246 32,537 137 65,223
New Jersey................................................... 30,114 20,598 26,393 88,486 157,736 223 323,550
New York..................................................... 63,465 55,122 87,608 121,363 282,072 412 610,042
North Carolina............................................... 111,576 44,502 18,869 135,936 225,756 11,424 548,064
North Dakota................................................. 76,381 7,545 10,046 59,635 21,575 240 175,422
Ohio......................................................... 258,687 71,715 41,466 173,988 270,383 81 816,321
Oklahoma..................................................... 86,204 73,465 94,574 55,424 117,240 1,709 ...........
Pennsylvania................................................. 176,870 89,208 53,435 118,774 266,649 117 705,053
Rhode Island................................................. 545 2,164 2,964 7,798 13,456 4 26,930
South Carolina............................................... 53,823 29,069 20,281 68,146 128,765 2,357 302,441
South Dakota................................................. 15,650 5,035 5,766 30,324 24,850 1,817 83,442
Tennessee.................................................... 102,934 60,353 18,676 82,331 207,410 1,012 472,717
Texas........................................................ 176,170 292,806 274,338 377,246 615,715 4,890 1,741,166
Vermont...................................................... 297 799 3,438 3,951 13,316 179 21,980
Virginia..................................................... 62,512 60,101 53,605 91,298 194,173 1,456 463,145
West Virginia................................................ 159,804 36,913 14,519 32,739 50,040 785 294,801
[[Page 45241]]
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
--------------------------------------------------------------------------------------------------------------------------------------------------------
Alabama...................................................... 335,734 70,346 52,315 2,333 585 983 462,297
Arkansas..................................................... 85,068 13,054 27,257 818 336 728 127,259
Connecticut.................................................. 5,493 1,831 18,443 1,292 330 4 27,392
Delaware..................................................... 7,841 10,974 5,858 14,193 98 6 38,970
District of Columbia......................................... 0 686 1,559 10 41 0 2,296
Florida...................................................... 228,360 57,491 70,482 102,076 2,072 7,018 467,498
Georgia...................................................... 552,007 56,122 56,817 7,984 1,253 2,010 676,193
Illinois..................................................... 724,657 133,201 5,384 1,960 1,174 20 866,396
Indiana...................................................... 829,988 95,201 59,767 871 775 24 986,626
Iowa......................................................... 169,039 61,242 19,821 482 346 25 250,954
Kansas....................................................... 59,567 13,048 36,376 518 302 103 109,915
Kentucky..................................................... 718,980 25,813 34,214 1,368 510 364 781,249
Louisiana.................................................... 100,239 159,722 2,373 78,051 455 892 341,731
Maine........................................................ 15,759 18,519 9,950 3,926 156 150 48,460
Maryland..................................................... 49,078 34,988 40,854 17,112 608 32 142,672
Massachusetts................................................ 16,299 19,622 25,242 29,825 575 93 91,657
Michigan..................................................... 287,807 76,458 42,066 7,636 1,074 91 415,132
Minnesota.................................................... 53,596 25,100 14,733 1,342 596 631 95,997
Mississippi.................................................. 46,432 24,426 6,788 2,094 375 1,051 81,166
Missouri..................................................... 445,643 78,310 44,550 1,307 765 186 570,761
Nebraska..................................................... 120,790 6,430 29,571 817 209 105 157,921
New Hampshire................................................ 7,290 3,245 7,396 72 142 38 18,183
New Jersey................................................... 37,746 6,747 10,715 25,286 772 61 81,327
New York..................................................... 144,074 58,566 125,187 12,336 1,541 113 341,818
North Carolina............................................... 126,620 66,128 22,000 48,861 935 696 265,240
North Dakota................................................. 77,383 9,458 6,451 288 76 66 93,722
Ohio......................................................... 946,667 105,406 19,810 3,456 1,131 22 1,076,493
Oklahoma..................................................... 156,032 36,912 7,536 341 502 469 201,791
Pennsylvania................................................. 966,136 79,142 68,330 4,938 1,135 32 1,119,712
Rhode Island................................................. 0 2,743 3,364 2,879 82 1 9,069
South Carolina............................................... 149,515 31,452 30,005 22,697 532 646 234,846
South Dakota................................................. 13,453 1,698 10,342 65 91 498 26,147
Tennessee.................................................... 596,987 77,595 32,701 828 795 277 709,182
Texas........................................................ 327,873 162,915 109,199 37,109 2,409 1,178 640,682
Vermont...................................................... 0 902 5,381 6 94 49 6,432
Virginia..................................................... 145,452 69,166 32,904 15,158 883 399 263,963
West Virginia................................................ 588,392 41,817 14,583 443 197 215 645,646
Wisconsin.................................................... 107,365 66,452 6,370 928 646 70 181,830
------------------------------------------------------------------------------------------
Grand total.............................................. 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 NonEGU Nonpoint Nonroad Onroad Fires Total
--------------------------------------------------------------------------------------------------------------------------------------------------------
Alabama...................................................... 121,809 74,832 31,958 49,622 82,135 3,814 364,171
Arkansas..................................................... 43,222 37,479 21,429 48,349 46,959 2,654 200,092
Connecticut.................................................. 2,770 5,830 12,475 15,865 37,847 14 74,801
[[Page 45242]]
Delaware..................................................... 4,639 5,567 3,248 15,511 10,700 23 39,687
District of Columbia......................................... 2 501 1,739 2,704 4,857 0 9,802
Florida...................................................... 195,673 55,017 29,475 282,147 275,603 25,600 863,515
Georgia...................................................... 78,011 53,317 38,825 76,901 158,771 7,955 413,780
Illinois..................................................... 77,920 92,440 47,564 167,046 157,915 71 542,957
Indiana...................................................... 203,107 73,651 30,125 83,760 114,396 88 505,127
Iowa......................................................... 66,316 39,301 15,064 72,031 58,920 90 251,721
Kansas....................................................... 70,823 70,751 42,249 66,897 43,914 378 295,012
Kentucky..................................................... 149,179 34,875 17,446 72,289 71,284 1,326 346,399
Louisiana.................................................... 44,773 161,724 27,525 285,562 64,074 3,254 586,912
Maine........................................................ 3,139 18,309 7,295 13,354 21,896 566 64,559
Maryland..................................................... 17,376 24,624 21,647 53,580 64,368 137 181,731
Massachusetts................................................ 6,312 18,447 34,245 75,149 57,417 341 191,911
Michigan..................................................... 96,874 93,953 43,392 80,900 163,505 330 478,955
Minnesota.................................................... 51,285 64,250 56,581 92,080 86,198 2,300 352,694
Mississippi.................................................. 37,517 52,454 12,151 64,138 52,709 3,833 222,801
Missouri..................................................... 77,571 38,610 32,731 96,197 108,298 678 354,085
Nebraska..................................................... 52,820 12,159 13,788 81,177 33,907 381 194,233
New Hampshire................................................ 2,514 3,243 11,153 7,308 19,710 137 44,067
New Jersey................................................... 15,987 18,996 26,320 81,906 76,979 223 220,410
New York..................................................... 25,755 55,167 87,776 100,212 154,260 412 423,582
North Carolina............................................... 61,643 44,514 18,715 133,476 126,081 11,424 395,854
North Dakota................................................. 59,547 7,544 10,018 46,649 12,111 240 136,110
Ohio......................................................... 159,627 69,075 41,378 133,650 149,134 81 552,945
Oklahoma..................................................... 86,858 71,808 94,528 43,057 71,207 1,709 369,167
Pennsylvania................................................. 193,032 85,168 53,289 92,594 142,217 117 566,418
Rhode Island................................................. 221 2,168 2,959 7,468 8,120 4 20,940
South Carolina............................................... 47,762 28,953 20,273 63,564 75,994 2,357 238,903
South Dakota................................................. 15,493 5,035 5,733 24,117 14,957 1,817 67,151
Tennessee.................................................... 68,425 59,594 18,573 65,209 126,353 1,012 339,166
Texas........................................................ 159,738 287,831 274,203 313,204 303,453 4,890 1,343,319
Vermont...................................................... 0 800 3,406 3,077 10,328 179 17,790
Virginia..................................................... 36,036 60,101 53,496 79,717 111,583 1,456 342,389
West Virginia................................................ 102,725 35,698 14,473 26,040 27,694 785 207,415
Wisconsin.................................................... 49,351 40,694 21,979 58,951 86,315 256 257,546
------------------------------------------------------------------------------------------
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
--------------------------------------------------------------------------------------------------------------------------------------------------------
State EGU NonEGU Nonpoint Nonroad Onroad Fires Total
--------------------------------------------------------------------------------------------------------------------------------------------------------
Alabama...................................................... 322,130 69,150 52,313 1,873 605 983 447,053
Arkansas..................................................... 88,187 13,055 27,256 142 347 728 129,714
Connecticut.................................................. 5,512 1,834 18,440 1,294 340 4 27,423
Delaware..................................................... 7,806 10,974 5,857 14,891 101 6 39,635
District of Columbia......................................... 0 686 1,559 4 42 0 2,291
Florida...................................................... 192,903 57,521 70,480 108,579 2,159 7,018 438,658
Georgia...................................................... 173,210 56,014 56,813 8,263 1,307 2,010 297,618
Illinois..................................................... 200,475 133,109 5,381 390 1,221 20 340,596
Indiana...................................................... 804,294 95,037 59,764 193 810 24 960,123
Iowa......................................................... 163,966 60,195 19,817 85 360 25 244,448
Kansas....................................................... 65,125 13,048 36,375 54 313 103 115,018
Kentucky..................................................... 739,592 23,804 34,210 258 528 364 798,755
Louisiana.................................................... 94,824 151,216 2,372 78,097 470 892 327,871
Maine........................................................ 11,650 18,520 9,945 4,215 160 150 44,640
Maryland..................................................... 42,635 34,994 40,851 16,966 631 32 136,109
Massachusetts................................................ 16,299 19,624 25,237 32,043 594 93 93,890
Michigan..................................................... 275,637 76,437 42,066 7,536 1,107 91 402,874
Minnesota.................................................... 61,447 25,112 14,728 468 618 631 103,005
Mississippi.................................................. 48,149 24,427 6,785 1,280 385 1,051 82,077
Missouri..................................................... 500,649 77,086 44,543 214 796 186 623,473
Nebraska..................................................... 115,695 6,431 29,570 55 217 105 152,072
New Hampshire................................................ 6,608 3,246 7,393 45 148 38 17,476
New Jersey................................................... 37,669 6,756 10,712 26,589 799 61 82,585
New York..................................................... 141,354 58,584 125,196 10,853 1,594 113 337,694
North Carolina............................................... 140,585 66,046 21,994 52,897 961 696 283,180
North Dakota................................................. 80,320 9,458 5,763 35 78 66 95,720
Ohio......................................................... 841,194 105,123 19,810 2,085 1,171 22 969,405
Oklahoma..................................................... 165,773 36,924 7,534 45 524 469 211,268
Pennsylvania................................................. 972,977 76,256 68,324 4,117 1,169 32 1,122,876
[[Page 45243]]
Rhode Island................................................. 0 2,745 3,364 3,128 85 1 9,323
South Carolina............................................... 156,096 31,453 30,002 24,380 551 646 243,129
South Dakota................................................. 13,459 1,699 10,298 22 94 498 26,070
Tennessee.................................................... 600,066 77,605 32,696 173 829 277 711,647
Texas........................................................ 373,950 155,720 109,194 36,109 2,511 1,178 678,662
Vermont...................................................... 0 903 5,380 7 101 49 6,439
Virginia..................................................... 135,741 69,177 32,899 15,624 918 399 254,758
West Virginia................................................ 496,307 41,817 14,581 96 201 215 553,218
Wisconsin.................................................... 117,253 66,456 6,370 638 675 70 191,461
------------------------------------------------------------------------------------------
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...................................................... 118,420 74,622 31,939 45,932 67,011 3,814 341,738
Arkansas..................................................... 44,792 37,491 21,422 44,299 38,965 2,654 189,623
Connecticut.................................................. 2,821 5,854 12,451 14,410 31,534 14 67,084
Delaware..................................................... 4,513 5,567 3,245 15,270 8,736 23 37,353
District of Columbia......................................... 1 501 1,738 2,398 3,929 0 8,568
Florida...................................................... 180,801 55,343 29,457 278,920 225,478 25,600 795,599
Georgia...................................................... 48,091 53,557 38,797 71,011 130,240 7,955 349,650
Illinois..................................................... 80,228 93,059 47,540 151,373 131,403 71 503,676
Indiana...................................................... 200,899 73,523 30,107 76,024 94,217 88 474,858
Iowa......................................................... 68,146 38,831 15,038 65,751 48,836 90 236,692
Kansas....................................................... 78,920 70,730 42,238 61,613 35,950 378 289,829
Kentucky..................................................... 148,509 34,979 17,413 65,805 57,759 1,326 325,791
Louisiana.................................................... 45,457 161,766 27,515 274,697 52,360 3,254 565,049
Maine........................................................ 2,535 18,316 7,257 13,169 18,061 566 59,903
Maryland..................................................... 19,990 24,687 21,626 52,501 53,040 137 171,980
Massachusetts................................................ 6,619 18,527 34,207 75,654 46,748 341 182,095
Michigan..................................................... 97,455 94,079 43,360 73,939 135,806 330 444,969
Minnesota.................................................... 51,859 64,372 56,545 84,040 71,161 2,300 330,278
Mississippi.................................................. 37,142 52,440 12,133 58,559 42,525 3,833 206,633
Missouri..................................................... 82,979 38,744 32,677 88,233 90,001 678 333,312
Nebraska..................................................... 52,970 12,173 13,779 75,252 27,856 381 182,410
New Hampshire................................................ 2,515 3,255 11,129 6,587 16,260 137 39,884
New Jersey................................................... 16,268 19,089 26,298 78,875 63,254 223 204,007
New York..................................................... 28,350 55,359 87,826 92,841 129,376 412 394,165
North Carolina............................................... 61,747 44,573 18,669 133,455 104,150 11,424 374,018
North Dakota................................................. 59,556 7,549 3,969 42,972 9,925 240 130,252
Ohio......................................................... 164,945 69,157 41,352 120,900 122,426 81 518,861
Oklahoma..................................................... 81,122 72,525 94,513 39,539 58,382 1,709 347,790
Pennsylvania................................................. 196,151 84,111 53,246 83,885 118,122 117 535,631
Rhode Island................................................. 281 2,186 2,957 7,384 6,772 4 19,585
South Carolina............................................... 47,512 28,969 20,271 62,400 62,996 2,357 224,505
South Dakota................................................. 15,514 5,039 5,157 22,021 12,254 1,817 62,368
Tennessee.................................................... 68,779 59,694 18,542 59,145 104,711 1,012 311,882
Texas........................................................ 166,177 282,509 274,163 289,605 241,009 4,890 1,258,354
Vermont...................................................... 0 803 3,397 2,771 8,563 179 15,713
Virginia..................................................... 32,115 60,216 53,464 75,461 92,291 1,456 315,002
West Virginia................................................ 100,103 35,700 14,459 23,798 22,863 785 197,708
Wisconsin.................................................... 53,774 40,729 21,974 53,848 71,163 256 241,743
------------------------------------------------------------------------------------------
Grand total.............................................. 2,468,057 1,900,624 1,298,473 2,884,338 2,656,134 80,932 11,288,558
--------------------------------------------------------------------------------------------------------------------------------------------------------
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 (http://www.epa.gov/airmarkt/progsregs/epa-ipm/index.html). The IPM is a multiregional,
dynamic, deterministic linear 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 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
[[Page 45244]]
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 MOVES-based 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 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 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-to-CAMx preprocessor (ref CAMx user's
guide).
---------------------------------------------------------------------------
\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.
---------------------------------------------------------------------------
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
[[Page 45245]]
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.
---------------------------------------------------------------------------
\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.
---------------------------------------------------------------------------
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 (latitude-longitude). The predictions were used to provide one-
way dynamic boundary conditions at three-hour intervals and an initial
concentration field for the coarse scale simulations.
---------------------------------------------------------------------------
\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.
---------------------------------------------------------------------------
d. Model Performance Evaluation for Ozone and PM2.5
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.
---------------------------------------------------------------------------
2. How did EPA project future nonattainment and maintenance for annual
PM2.5, 25-Hour PM2.5, and 8-hour ozone?
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.
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 8-hour O3 NAAQS is 0.08 ppm. The
8-hour ozone standard is not met if the 3-year 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 3-year 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
[[Page 45246]]
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 [mu]g/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 [mu]g/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 5-year
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 http://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.
---------------------------------------------------------------------------
\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.
---------------------------------------------------------------------------
b. Projection of Future Annual and 24-Hour PM2.5
Nonattainment and Maintenance
Annual PM2.5 modeling was performed for the 2005 base
year emissions and for the 2012 base case as part of the approach for
projecting which locations (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.
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\
---------------------------------------------------------------------------
\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.
---------------------------------------------------------------------------
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: http://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
[[Page 45247]]
(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 FRM-derived 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 [mu]g/m\3\ PM2.5 equals 3 [mu]g/
m\3\ sulfate).
---------------------------------------------------------------------------
\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.
---------------------------------------------------------------------------
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 species-specific relative response factors (RRF)
(e.g., assume that the model-predicted 2005 base year sulfate for a
particular location is 10.0 [mu]g/m\3\ and the 2012 future
concentration is 8.0 [mu]g/m\3\, 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.
---------------------------------------------------------------------------
\39\ The modeling guidance recommends calculating annual
PM2.5 RRFs using a 3 x 3 grid cell array (9 grid cells)
for a model resolution of 12km.
---------------------------------------------------------------------------
Step 3: For each quarter and each of the species, multiply the base
year quarterly mean component concentration (Step 1) by the species-
specific RRF obtained in Step 2. This results in an estimated future
year quarterly mean concentration for each species (e.g., 3 [mu]g/m\3\
sulfate multiplied by 0.8 equals a future sulfate concentration of 2.4
[mu]g/m\3\).
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).
---------------------------------------------------------------------------
\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 salt concentration was held
constant from the base to future. Blank mass was assumed to be a
constant mass of 0.5 [mu]g/m\3\ in both the base and future year.
---------------------------------------------------------------------------
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 [mu]g/m\3\ is
rounded to 15.1 [mu]g/m\3\ and is considered to be violating the NAAQS.
Thus, sites with future year annual PM2.5 design values of
15.05 [mu]g/m\3\ 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 [mu]g/m\3\ or greater
are predicted to be maintenance sites. Note that nonattainment sites
are also maintenance sites because the maximum design value is always
greater than or equal to the 5-year weighted average. For ease of
reference we use the term ``nonattainment sites'' to refer to those
sites that are projected to exceed the NAAQS based on both the average
and maximum design values. Those sites that are projected to be
attainment based on the average design value but exceed the NAAQS based
on the maximum design value are referred to as maintenance sites. The
monitoring sites that we project to be nonattainment and/or maintenance
for the annual PM2.5 NAAQS in the 2012 base case are the
nonattainment/maintenance receptors used for assessing the contribution
of emissions in upwind states to downwind nonattainment and maintenance
of the annual PM2.5 NAAQS as part of this proposal.
---------------------------------------------------------------------------
\41\ For example, a calculated annual average concentration of
14.94753 * * * becomes 14.94 when digits beyond two places to the
right are truncated.
---------------------------------------------------------------------------
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 ([mu]g/m3) at Projected Nonattainment Sites
--------------------------------------------------------------------------------------------------------------------------------------------------------
Average Maximum Average Maximum
Monitor ID State County design value design value design value design value
2003-2007 2003-2007 2012 2012
--------------------------------------------------------------------------------------------------------------------------------------------------------
10730023............................. Alabama................. Jefferson.............. 18.48 18.67 17.15 17.33
10732003............................. Alabama................. Jefferson.............. 17.07 17.45 15.99 16.35
130210007............................ Georgia................. Bibb................... 16.47 16.78 15.33 15.62
130630091............................ Georgia................. Clayton................ 16.47 16.71 15.07 15.29
131210039............................ Georgia................. Fulton................. 17.43 17.47 16.01 16.04
170310052............................ Illinois................ Cook................... 15.75 16.02 15.16 15.43
171191007............................ Illinois................ Madison................ 16.72 17.01 16.56 16.85
171630010............................ Illinois................ Saint Clair............ 15.58 15.74 15.48 15.63
180190006............................ Indiana................. Clark.................. 16.40 16.60 15.96 16.16
180372001............................ Indiana................. Dubois................. 15.18 15.68 15.07 15.57
180970078............................ Indiana................. Marion................. 15.26 15.43 15.18 15.36
[[Page 45248]]
180970081............................ Indiana................. Marion................. 16.05 16.36 15.93 16.25
180970083............................ Indiana................. Marion................. 15.90 16.27 15.77 16.15
211110043............................ Kentucky................ Jefferson.............. 15.53 15.75 15.19 15.41
261630015............................ Michigan................ Wayne.................. 15.88 16.40 15.05 15.55
261630033............................ Michigan................ Wayne.................. 17.50 18.16 16.57 17.19
390170016............................ Ohio.................... Butler................. 15.74 16.11 15.25 15.61
390350038............................ Ohio.................... Cuyahoga............... 17.37 18.1 16.26 16.95
390350045............................ Ohio.................... Cuyahoga............... 16.47 16.98 15.42 15.91
390350060............................ Ohio.................... Cuyahoga............... 17.11 17.66 16.02 16.55
390610014............................ Ohio.................... Hamilton............... 17.29 17.53 16.69 16.93
390610042............................ Ohio.................... Hamilton............... 16.85 17.25 16.33 16.71
390610043............................ Ohio.................... Hamilton............... 15.55 15.82 15.05 15.32
390617001............................ Ohio.................... Hamilton............... 16.17 16.56 15.65 16.03
390618001............................ Ohio.................... Hamilton............... 17.54 17.90 16.93 17.27
420030064............................ Pennsylvania............ Allegheny.............. 20.31 20.75 18.90 19.31
420031301............................ Pennsylvania............ Allegheny.............. 16.26 16.57 15.13 15.42
420070014............................ Pennsylvania............ Beaver................. 16.38 16.45 15.23 15.30
420710007............................ Pennsylvania............ Lancaster.............. 16.55 17.46 15.19 16.01
421330008............................ Pennsylvania............ York................... 16.52 17.25 15.25 15.94
540110006............................ West Virginia........... Cabell................. 16.30 16.57 15.25 15.50
540391005............................ West Virginia........... Kanawha................ 16.52 16.59 15.28 15.34
--------------------------------------------------------------------------------------------------------------------------------------------------------
Table IV.C-8--Average and Maximum 2003-2007 and 2012 Base Case Annual PM2.5 Design Values ([mu]/m3) at Projected Maintenance-Only Sites
--------------------------------------------------------------------------------------------------------------------------------------------------------
Average Maximum Average Maximum
Monitor ID State County design value design value design value design value
2003-2007 2003-2007 2012 2012
--------------------------------------------------------------------------------------------------------------------------------------------------------
170313301............................ Illinois................ Cook................... 15.24 15.59 14.73 15.06
170316005............................ Illinois................ Cook................... 15.48 16.07 14.92 15.48
211110044............................ Kentucky................ Jefferson.............. 15.31 15.47 14.93 15.09
360610056............................ New York................ New York............... 16.18 17.02 14.98 15.74
390350027............................ Ohio.................... Cuyahoga............... 15.46 16.13 14.50 15.13
390350065............................ Ohio.................... Cuyahoga............... 15.97 16.44 14.96 15.40
390610040............................ Ohio.................... Hamilton............... 15.50 15.88 15.03 15.40
390811001............................ Ohio.................... Jefferson.............. 16.51 17.17 14.95 15.54
391130032............................ Ohio.................... Montgomery............. 15.54 15.92 15.01 15.37
391510017............................ Ohio.................... Stark.................. 16.15 16.59 14.99 15.40
420110011............................ Pennsylvania............ Berks.................. 15.82 16.19 14.77 15.11
482011035............................ Texas................... Harris................. 15.42 15.84 14.74 15.14
540030003............................ West Virginia........... Berkeley............... 15.93 16.19 14.95 15.20
540090005............................ West Virginia........... Brooke................. 16.52 16.80 14.95 15.22
540291004............................ West Virginia........... Hancock................ 15.76 16.64 14.34 15.15
540490006............................ West Virginia........... Marion................. 15.03 15.25 14.96 15.18
--------------------------------------------------------------------------------------------------------------------------------------------------------
(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 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 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 24-hour 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
[[Page 45249]]
than or equal to the 98th percentile value over the entire year. This
results in a data set for each year (for up to 5 years) for each site
containing one quarter with the observed 98th percentile value and
three quarters with the maximum highest values from each quarter that
are less than or equal to the 98th percentile value for the year. All
20 quarters (i.e., 4 quarters in each of 5 years) of data are carried
through the calculations until the high future year quarter value is
identified in step 6.
Step 2: In this step we calculate quarterly ambient concentrations
on ``high'' \42\ days for each of the major component species of
PM2.5 (sulfate, nitrate, ammonium, elemental carbon, organic
carbon mass, particle bound water, salt, and blank mass). This
calculation is performed by multiplying the monitored concentrations of
FRM-derived total PM2.5 mass on the 10 percent highest days
from each quarter, by the monitored fractional composition of
PM2.5 species on the 10 percent highest PM2.5
days for each quarter, averaged over 3 years \43\ (e.g., 20 percent
sulfate fraction multiplied by 40 [mu]g/m\3\ PM2.5 equals 8
[mu]g/m\3\ sulfate).
---------------------------------------------------------------------------
\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.
---------------------------------------------------------------------------
Step 3: For each quarter, we calculate the ratio of future year
(i.e., 2012) to base year (i.e., 2005) predictions for each component
species for the top 10 percent of days based on predicted
concentrations of 24-hour PM2.5. The result is a set of
species-specific relative response factors (RRF) for the high
PM2.5 days in each quarter (e.g., assume that the 2005
predicted sulfate concentration on the 10 percent highest
PM2.5 days for a quarter for a particular location is 20
[mu]g/m\3\ and the 2012 base case concentration is 16 [mu]g/m\3\, then
RRF for sulfate is 0.8). The RRFs are calculated based on the modeled
concentrations at the single grid cell where the monitor is located.
Step 4: For each quarter, we multiply the quarterly species
concentration (step 2) by the quarterly \44\ species-specific RRF
obtained in step 3. This leads to an estimated future quarterly
concentration for each component. (e.g., 21.0 [mu]g/m\3\ nitrate x 0.75
= future nitrate of 15.75 [mu]g/m\3\).
---------------------------------------------------------------------------
\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.
---------------------------------------------------------------------------
Step 5: The future year concentrations for the remaining species
are then calculated.\45\ 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
calculated future year concentrations of sulfate, nitrate, and ammonium
(from step 4).
---------------------------------------------------------------------------
\45\ 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 salt concentration was held
constant from the base to future. Blank mass was assumed to be a
constant mass of 0.5 ug/m\3\ in both the base and future year.
---------------------------------------------------------------------------
Step 6: We sum the species concentrations to obtain quarterly
PM2.5 values. This step is repeated for each quarter and for
each of the 5 years of ambient data. The highest daily value (from the
4 quarterly values) for each year at each monitor is considered to be
the estimated future year 98th percentile 24-hour design value for that
year.
Step 7: The estimated 98th percentile values for each of the 5
years are averaged over 3 year intervals to create the 3 year average
design values. These design values are averaged to create a 5 year
weighted average for each monitoring site.
Step 8: The maximum future design value is calculated by following
the previous steps for 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. This maximum value is
used to identify the 24-hour PM2.5 maintenance receptors.
The preceding procedures for determining future year 24-hour
PM2.5 concentrations were applied for each FRM site. The 24-
hour PM2.5 design 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 [mu]g/m\3\ is rounded to 36
[mu]g/m\3\ and is violating the NAAQS. Sites with future year 5 year
weighted average design values of 35.5 [mu]g/m\3\ or greater, based on
the projection of 5-year weighted average concentrations, are predicted
to be nonattainment. Sites with future year maximum design values of
35.5 [mu]g/m\3\ or greater are predicted to be maintenance sites. Note
that nonattainment sites for the 24-hour NAAQS are also maintenance
sites because the maximum design value is always greater than or equal
to the 5-year weighted average. 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
24-hour PM2.5 design values and the 2012 base case average
and maximum design values for sites projected to be 2012 nonattainment
of the 24-hour PM2.5 NAAQS in 2012. Table 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 ([mu]g/m\3\) at Projected Nonattainment Sites
--------------------------------------------------------------------------------------------------------------------------------------------------------
Average design Maximum design
Monitor ID State County value 2003- value 2003- Average design Maximum design
2007 2007 value 2012 value 2012
--------------------------------------------------------------------------------------------------------------------------------------------------------
10730023............................. Alabama................. Jefferson.............. 44.0 44.2 40.0 40.7
10732003............................. Alabama................. Jefferson.............. 40.3 40.8 38.1 38.9
90091123............................. Connecticut............. New Haven.............. 38.3 40.3 35.7 36.6
170310052............................ Illinois................ Cook................... 40.2 41.4 38.5 39.7
[[Page 45250]]
170310057............................ Illinois................ Cook................... 37.3 38.6 35.7 37.0
170310076............................ Illinois................ Cook................... 38.0 39.1 36.3 37.3
170311016............................ Illinois................ Cook................... 43.0 46.3 41.0 44.1
170312001............................ Illinois................ Cook................... 37.7 40.6 35.6 38.2
170313103............................ Illinois................ Cook................... 39.6 40.3 38.1 38.7
170313301............................ Illinois................ Cook................... 40.2 43.3 38.2 41.0
170316005............................ Illinois................ Cook................... 39.1 41.8 37.4 39.8
171190023............................ Illinois................ Madison................ 37.3 38.1 39.4 40.2
171191007............................ Illinois................ Madison................ 39.1 40.1 40.0 40.6
171192009............................ Illinois................ Madison................ 34.9 35.9 37.2 38.2
171193007............................ Illinois................ Madison................ 34.0 34.6 36.5 37.3
180190006............................ Indiana................. Clark.................. 37.5 39.4 38.1 40.2
180372001............................ Indiana................. Dubois................. 35.3 36.9 36.5 38.0
180830004............................ Indiana................. Knox................... 35.9 36.3 35.9 36.5
180890022............................ Indiana................. Lake................... 38.9 44.0 37.3 42.1
180890026............................ Indiana................. Lake................... 38.4 41.3 36.3 39.3
180970042............................ Indiana................. Marion................. 34.2 35.3 36.3 37.2
180970043............................ Indiana................. Marion................. 38.4 39.9 40.5 42.0
180970066............................ Indiana................. Marion................. 38.3 39.6 40.3 41.8
180970078............................ Indiana................. Marion................. 36.6 37.6 38.7 39.7
180970079............................ Indiana................. Marion................. 35.6 36.7 37.2 38.3
180970081............................ Indiana................. Marion................. 38.2 39.2 40.1 41.1
180970083............................ Indiana................. Marion................. 36.6 37.0 39.0 39.3
181570008............................ Indiana................. Tippecanoe............. 35.6 36.7 35.9 36.9
191630019............................ Iowa.................... Scott.................. 37.1 37.1 36.8 36.8
210590005............................ Kentucky................ Daviess................ 33.8 33.8 37.0 37.0
211110043............................ Kentucky................ Jefferson.............. 35.4 36.1 35.8 36.4
211110044............................ Kentucky................ Jefferson.............. 36.1 36.6 36.0 36.5
211110048............................ Kentucky................ Jefferson.............. 36.4 37.2 35.6 36.4
245100040............................ Maryland................ Baltimore City......... 39.0 40.9 36.3 38.3
245100049............................ Maryland................ Baltimore City......... 38.1 38.1 35.5 35.5
261150005............................ Michigan................ Monroe................. 38.8 39.6 37.0 38.0
261250001............................ Michigan................ Oakland................ 39.9 40.4 37.9 38.4
261470005............................ Michigan................ St. Clair.............. 39.6 40.6 38.4 39.4
261610008............................ Michigan................ Washtenaw.............. 39.4 40.8 38.1 39.8
261630015............................ Michigan................ Wayne.................. 40.1 40.6 38.5 39.1
261630016............................ Michigan................ Wayne.................. 42.9 45.4 40.6 43.0
261630019............................ Michigan................ Wayne.................. 40.9 41.4 38.6 39.1
261630033............................ Michigan................ Wayne.................. 43.8 44.2 42.1 42.6
261630036............................ Michigan................ Wayne.................. 37.1 37.9 36.3 36.9
290990012............................ Missouri................ Jefferson.............. 33.4 34.2 35.7 36.5
291831002............................ Missouri................ Saint Charles.......... 33.1 34.7 35.5 37.1
295100007............................ Missouri................ St. Louis City......... 33.1 33.5 36.0 36.3
295100087............................ Missouri................ St. Louis City......... 34.3 34.7 36.4 36.9
340171003............................ New Jersey.............. Hudson................. 39.0 40.5 35.7 36.1
340172002............................ New Jersey.............. Hudson................. 41.4 41.4 38.2 38.2
340390004............................ New Jersey.............. Union.................. 40.4 41.4 36.7 37.2
360050080............................ New York................ Bronx.................. 38.8 40.2 35.9 36.2
360610056............................ New York................ New York............... 39.7 40.6 37.1 38.0
360610128............................ New York................ New York............... 39.4 41.8 36.2 38.0
390170003............................ Ohio.................... Butler................. 39.2 41.1 40.3 42.3
390170016............................ Ohio.................... Butler................. 37.1 37.7 37.5 37.8
390170017............................ Ohio.................... Butler................. 37.9 37.9 38.5 38.5
390171004............................ Ohio.................... Butler................. 37.1 38.1 37.8 38.6
390350038............................ Ohio.................... Cuyahoga............... 44.2 47.0 41.2 44.0
390350045............................ Ohio.................... Cuyahoga............... 38.5 41.5 36.0 39.0
390350060............................ Ohio.................... Cuyahoga............... 42.1 45.7 39.4 42.8
390350065............................ Ohio.................... Cuyahoga............... 38.6 41.0 36.5 38.9
390490024............................ Ohio.................... Franklin............... 38.5 39.7 36.6 37.6
390490025............................ Ohio.................... Franklin............... 38.4 39.1 36.1 36.4
390610006............................ Ohio.................... Hamilton............... 37.6 37.6 38.0 38.0
390610014............................ Ohio.................... Hamilton............... 38.2 39.4 37.5 38.5
390610040............................ Ohio.................... Hamilton............... 36.7 37.7 35.8 36.8
390610042............................ Ohio.................... Hamilton............... 37.3 38.2 37.2 38.0
390610043............................ Ohio.................... Hamilton............... 35.9 36.2 36.0 36.4
390617001............................ Ohio.................... Hamilton............... 38.8 39.6 37.7 38.1
390618001............................ Ohio.................... Hamilton............... 40.6 40.9 39.6 40.3
390811001............................ Ohio.................... Jefferson.............. 41.9 45.5 36.5 39.9
391130032............................ Ohio.................... Montgomery............. 37.8 40.0 36.3 38.5
[[Page 45251]]
391530017............................ Ohio.................... Summit................. 38.0 39.6 35.6 37.2
420030008............................ Pennsylvania............ Allegheny.............. 39.4 39.9 35.9 36.3
420030064............................ Pennsylvania............ Allegheny.............. 64.2 68.2 58.8 62.3
420030093............................ Pennsylvania............ Allegheny.............. 45.6 51.5 41.1 46.2
420030116............................ Pennsylvania............ Allegheny.............. 42.5 42.5 37.1 37.1
420031008............................ Pennsylvania............ Allegheny.............. 41.3 42.8 38.0 39.3
420031301............................ Pennsylvania............ Allegheny.............. 40.3 42.4 36.6 38.6
420070014............................ Pennsylvania............ Beaver................. 43.4 44.6 37.7 39.1
420110011............................ Pennsylvania............ Berks.................. 37.7 39.1 35.8 37.0
420210011............................ Pennsylvania............ Cambria................ 39.0 39.4 40.3 40.7
420430401............................ Pennsylvania............ Dauphin................ 38.0 39.0 35.7 37.1
420710007............................ Pennsylvania............ Lancaster.............. 40.8 44.0 37.7 40.1
421330008............................ Pennsylvania............ York................... 38.2 40.7 35.9 38.8
471251009............................ Tennessee............... Montgomery............. 36.3 37.5 36.6 37.9
540090011............................ West Virginia........... Brooke................. 43.9 44.9 39.9 40.8
550790010............................ Wisconsin............... Milwaukee.............. 38.6 40.0 37.7 39.0
550790026............................ Wisconsin............... Milwaukee.............. 37.3 41.3 36.3 40.1
550790043............................ Wisconsin............... Milwaukee.............. 39.9 40.8 38.8 39.7
550790099............................ Wisconsin............... Milwaukee.............. 37.7 38.7 36.8 37.7
--------------------------------------------------------------------------------------------------------------------------------------------------------
Table IV.C-10--Average and Maximum 2003-2007 and 2012 Base Case 24-Hour PM2.5 Design Values ([mu]g/m\3\) at Projected Maintenance-Only Sites
--------------------------------------------------------------------------------------------------------------------------------------------------------
Average Maximum Average Maximum
Monitor ID State County design value design value design value design value
2003-2007 2003-2007 2012 2012
--------------------------------------------------------------------------------------------------------------------------------------------------------
110010041............................ Washington DC........... Washington DC.......... 36.3 37.8 34.0 35.6
110010042............................ Washington DC........... Washington DC.......... 34.9 37.0 33.0 35.6
170310022............................ Illinois................ Cook................... 36.6 38.6 34.9 36.6
170310050............................ Illinois................ Cook................... 36.1 38.0 34.1 35.8
170314007............................ Illinois................ Cook................... 34.3 36.4 33.6 35.7
171630010............................ Illinois................ Saint Clair............ 33.7 34.1 35.3 35.9
171971002............................ Illinois................ Will................... 36.4 37.1 35.1 35.8
180390003............................ Indiana................. Elkhart................ 34.4 36.3 33.8 35.6
180431004............................ Indiana................. Floyd.................. 33.2 34.5 34.3 35.7
181670023............................ Indiana................. Vigo................... 34.8 36.1 35.1 36.5
191390015............................ Iowa.................... Muscatine.............. 36.0 37.7 34.5 36.0
210290006............................ Kentucky................ Bullitt................ 34.6 35.8 35.0 36.3
211451004............................ Kentucky................ McCracken.............. 33.6 35.9 34.4 36.8
212270007............................ Kentucky................ Warren................. 33.1 35.1 33.7 36.3
240031003............................ Maryland................ Anne Arundel........... 35.5 37.4 33.8 36.7
245100035............................ Maryland................ Baltimore (City)....... 37.7 39.2 34.7 35.5
261630001............................ Michigan................ Wayne.................. 37.8 40.1 35.4 37.8
295100085............................ Missouri................ St. Louis City......... 33.2 33.8 35.3 35.7
360610062............................ New York................ New York............... 38.8 41.6 35.3 37.0
360610079............................ New York................ New York............... 37.9 40.2 34.2 36.4
390350027............................ Ohio.................... Cuyahoga............... 36.6 38.8 34.5 36.6
390350034............................ Ohio.................... Cuyahoga............... 36.5 37.9 33.7 35.7
390810017............................ Ohio.................... Jefferson.............. 40.7 42.4 35.3 36.8
390950024............................ Ohio.................... Lucas.................. 36.3 38.6 34.2 36.5
390950026............................ Ohio.................... Lucas.................. 34.9 36.7 33.6 35.6
390990014............................ Ohio.................... Mahoning............... 36.8 38.2 34.2 35.8
391130031............................ Ohio.................... Montgomery............. 35.7 37.1 34.3 35.6
391351001............................ Ohio.................... Preble................. 32.8 33.9 34.3 35.5
391550007............................ Ohio.................... Trumbull............... 36.2 37.8 33.9 35.6
420030095............................ Pennsylvania............ Allegheny.............. 38.7 40.7 34.3 36.6
420033007............................ Pennsylvania............ Allegheny.............. 37.5 43.1 33.8 38.5
420410101............................ Pennsylvania............ Cumberland............. 38.0 40.2 35.3 37.0
421255001............................ Pennsylvania............ Washington............. 38.1 39.9 33.9 35.5
471650007............................ Tennessee............... Sumner................. 33.6 34.5 35.1 36.0
540090005............................ West Virginia........... Brooke................. 39.4 41.5 33.9 36.1
550250047............................ Wisconsin............... Dane................... 35.5 36.9 35.1 36.1
550790059............................ Wisconsin............... Milwaukee.............. 35.5 37.0 34.8 36.3
551330027............................ Wisconsin............... Waukesha............... 35.4 36.2 34.9 35.6
--------------------------------------------------------------------------------------------------------------------------------------------------------
[[Page 45252]]
(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-by-site basis.
---------------------------------------------------------------------------
\46\ As specified in the attainment demonstration modeling
guidance, if there are less than 10 modeled days > 85 ppb, then the
threshold is lowered in 1 ppb increments (to as low as 70 ppb) until
there are 10 days. If there are less than 5 days > 70 ppb, then an
RRF calculation is not completed for that site.
---------------------------------------------------------------------------
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[dash]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
--------------------------------------------------------------------------------------------------------------------------------------------------------
Average design Maximum Average
Monitor ID State County value 2003- design value design value Maximum design
2007 2003-2007 2012 value 2012
--------------------------------------------------------------------------------------------------------------------------------------------------------
220330003........................... Louisiana.............. East Baton Rouge....... 92 96 87.8 91.6
361030002........................... New York............... Suffolk................ 90 91 86.3 87.2
361030009........................... New York............... Suffolk................ 90.3 91 85.1 85.8
421010024........................... Pennsylvania........... Philadelphia........... 90.3 91 85.3 86
480391004........................... Texas.................. Brazoria............... 94.7 97 88.8 91
482010051........................... Texas.................. Harris................. 93 98 88.4 93.1
482010055........................... Texas.................. Harris................. 100.7 103 95.7 97.9
482010062........................... Texas.................. Harris................. 95.7 99 90.5 93.7
482010066........................... Texas.................. Harris................. 92.3 96 89.9 93.5
482011039........................... Texas.................. Harris................. 96.3 100 90.5 93.9
484391002........................... Texas.................. Tarrant................ 93.3 95 85.1 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
--------------------------------------------------------------------------------------------------------------------------------------------------------
Average design Maximum
Monitor ID State County value 2003- design value Average design Maximum design
2007 2003-2007 value 2012 value 2012
--------------------------------------------------------------------------------------------------------------------------------------------------------
90010017............................ Connecticut............ Fairfield............. 88 90 83.1 85
90011123............................ Connecticut............ Fairfield............. 92.3 94 84.8 86.4
90013007............................ Connecticut............ Fairfield............. 90 92 84.5 86.4
[[Page 45253]]
90093002............................ Connecticut............ New Haven............. 90.3 93 82.9 85.4
130890002........................... Georgia................ DeKalb................ 88.7 93 81.6 85.6
131210055........................... Georgia................ Fulton................ 91.7 94 84.4 86.5
361192004........................... New York............... Westchester........... 87.7 90 84.7 86.9
420170012........................... Pennsylvania........... Bucks................. 88 92 81.8 85.6
481130069........................... Texas.................. Dallas................ 87 90 82.9 85.8
481130087........................... Texas.................. Dallas................ 87 88 84.6 85.6
482010024........................... Texas.................. Harris................ 88 92 83.3 87.1
482010029........................... Texas.................. Harris................ 91.7 93 84.4 85.6
482011015........................... Texas.................. Harris................ 89 96 83.7 90.3
482011035........................... Texas.................. Harris................ 86.3 95 82 90.3
482011050........................... Texas.................. Harris................ 89.3 92 83.9 86.5
484392003........................... Texas.................. Tarrant............... 93.7 95 84 85.2
--------------------------------------------------------------------------------------------------------------------------------------------------------
3. How did EPA assess interstate contributions to nonattainment and
maintenance?
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 post-processing 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
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
sensitivity-based 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
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.
---------------------------------------------------------------------------
\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.
---------------------------------------------------------------------------
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
[[Page 45254]]
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 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 CAMx-predicted 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 24-hour 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.
---------------------------------------------------------------------------
\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.
---------------------------------------------------------------------------
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 pre-processing
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 post-
processing steps needed to transform the raw model outputs to ozone
downwind contributions. We developed and applied several post-
processing 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 CAMx-predicted 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.
---------------------------------------------------------------------------
\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.
---------------------------------------------------------------------------
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 post-processing 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
[[Page 45255]]
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 [mu]g/m\3\or 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 [mu]g/m\3\ or more to 24-hour
PM2.5 nonattainment or maintenance in another state are
identified as states with contributions to downwind 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, 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 ([mu]g/
m\3\) Nonattainment and Maintenance for Each of 37 States
------------------------------------------------------------------------
Largest downwind Largest downwind
contribution to contribution to
Upwind state nonattainment for maintenance for
annual PM2.5 ([mu]g/ annual PM2.5 ([mu]g/
m\3\) m\3\)
------------------------------------------------------------------------
Alabama....................... 0.46 0.18
Arkansas...................... 0.09 0.04
Connecticut................... 0.04 0.09
Delaware...................... 0.20 0.14
Florida....................... 0.29 0.07
Georgia....................... 0.63 0.18
Illinois...................... 1.01 0.63
Indiana....................... 2.09 1.78
Iowa.......................... 0.31 0.30
Kansas........................ 0.09 0.05
Kentucky...................... 1.68 1.01
Louisiana..................... 0.11 0.34
Maine......................... 0.01 0.02
Maryland/Washington, D.C...... 0.63 0.56
Massachusetts................. 0.07 0.13
Michigan...................... 0.72 0.71
Minnesota..................... 0.19 0.17
Mississippi................... 0.07 0.03
Missouri...................... 1.38 0.27
Nebraska...................... 0.08 0.06
New Hampshire................. 0.01 0.02
New Jersey.................... 0.34 0.68
New York...................... 0.49 0.47
North Carolina................ 0.19 0.11
North Dakota.................. 0.05 0.05
Ohio.......................... 1.49 2.03
Oklahoma...................... 0.08 0.05
Pennsylvania.................. 0.83 1.60
Rhode Island.................. 0.01 0.01
South Carolina................ 0.26 0.04
South Dakota.................. 0.02 0.02
Tennessee..................... 0.68 0.64
Texas......................... 0.13 0.06
Vermont....................... 0.00 0.00
Virginia...................... 0.36 0.37
[[Page 45256]]
West Virginia................. 0.98 1.17
Wisconsin..................... 0.46 0.42
------------------------------------------------------------------------
Based on the state-by-state contribution analysis, there are 22
states and the District of Columbia \50\ which contribute 0.15 [mu]g/
m\3\ 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 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 [mu]g/
m\3\ or more (i.e., the upwind state to downwind nonattainment
``linkages'').
---------------------------------------------------------------------------
\50\ EPA 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.
---------------------------------------------------------------------------
There are 19 states and the District of Columbia \51\ which
contribute 0.15 [mu]g/m\3\ 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 [mu]g/m\3\ or more (i.e., the
upwind state to downwind maintenance ``linkages'').
---------------------------------------------------------------------------
\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.
[[Page 45257]]
Table IV.C-14--Upwind State to Downwind Nonattainment Site ``Linkages'' for Annual PM2.5
----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Number of
Upwind State linkages
---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
.......... Counties containing downwind 24-hour PM2.5 nonattainment sites (monitoring site ID)
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Alabama.......................... 6 Bibb, GA Clayton, GA Fulton, GA Clark, IN Dubois, IN Jefferson, KY
(130210007) (130630091) (131210039) (180190006) (180372001) (211110043)
Delaware......................... 2 Lancaster, PA York, PA
(420710007) (421330008)
Florida.......................... 3 Jefferson, AL Bibb, GA Clayton, GA
(10730023) (130210007) (130630091)
Georgia.......................... 7 Jefferson, AL Jefferson, AL Clark, IN Dubois, IN Jefferson, KY Kanawha, WV Cabell, WV
(10730023) (10732003) (180190006) (180372001) (211110043) (540391005) (540110006)
Illinois......................... 29 Jefferson, AL Jefferson, AL Fulton, GA Bibb, GA Clayton, GA Clark, IN Dubois, IN
(10730023) (10732003) (131210039) (130210007) (130630091) (180190006) (180372001)
.......... Marion, IN Marion, IN Marion, IN Jefferson, KY Wayne, MI Wayne, MI Butler, OH
(180970078) (180970081) (180970083) (211110043) (261630015) (261630033) (390170016)
.......... Cuyahoga, OH Cuyahoga, OH Cuyahoga, OH Hamilton, OH Hamilton, OH Hamilton, OH Hamilton, OH
(390350038) (390350045) (390350060) (390610014) (390610042) (390610043) (390617001)
.......... Hamilton, OH Allegheny, PA Allegheny, PA Beaver, PA Lancaster, PA York, PA Cabell, WV
(390618001) (420030064) (420031301) (420070014) (420710007) (421330008) (540110006)
.......... Kanawha, WV
(540391005)
Indiana.......................... 27 Jefferson, AL Jefferson, AL Bibb, GA Clayton, GA Fulton, GA Cook, IL Madison, IL
(10730023) (10732003) (130210007) (130630091) (131210039) (170310052) (171191007)
.......... Saint Clair, IL Jefferson, KY Wayne, MI Wayne, MI Butler, OH Cuyahoga, OH Cuyahoga, OH
(171630010) (211110043) (261630015) (261630033) (390170016) (390350038) (390350045)
.......... Cuyahoga, OH Hamilton, OH Hamilton, OH Hamilton, OH Hamilton, OH Hamilton, OH Allegheny, PA
(390350060) (390618001) (390610014) (390610042) (390610043) (390617001) (420030064)
.......... Allegheny, PA Beaver, PA Lancaster, PA York, PA Cabell, WV Kanawha, WV
(420031301) (420070014) (420710007) (421330008) (540110006) (540391005)
Iowa............................. 4 Cook, IL Madison, IL Saint Clair, IL Dubois, IN
(170310052) (171191007) (171630010) (180372001)
Kentucky......................... 31 Jefferson, AL Jefferson, AL Bibb, GA Clayton, GA Fulton, GA Cook, IL Madison, IL
(10730023) (10732003) (130210007) (130630091) (131210039) (170310052) (171191007)
.......... Saint Clair, IL Clark, IN Dubois, IN Marion, IN Marion, IN Marion, IN Wayne, MI
(171630010) (180190006) (180372001) (180970078) (180970081) (180970083) (261630015)
.......... Wayne, MI Butler, OH Cuyahoga, OH Cuyahoga, OH Cuyahoga, OH Hamilton, OH Hamilton, OH
(261630033) (390170016) (390350038) (390350045) (390350060) (390610014) (390610042)
.......... Hamilton, OH Hamilton, OH Hamilton, OH Allegheny, PA Allegheny, PA Beaver, PA Lancaster, PA
(390610043) (390617001) (390618001) (420030064) (420031301) (420070014) (420710007)
.......... York, PA Cabell, WV Kanawha, WV
(421330008) (540110006) (540391005)
Maryland......................... 2 Lancaster, PA York, PA
(420710007) (421330008)
Michigan......................... 25 Cook, IL Madison, IL Saint Clair, IL Clark, IN Dubois, IN Marion, IN Marion, IN
(170310052) (171191007) (171630010) (180190006) (180372001) (180970078) (180970081)
.......... Marion, IN Jefferson, KY Butler, OH Cuyahoga, OH Cuyahoga, OH Cuyahoga, OH Hamilton, OH
(180970083) (211110043) (390170016) (390350038) (390350045) (390350060) (390610014)
.......... Hamilton, OH Hamilton, OH Hamilton, OH Hamilton, OH Allegheny, PA Allegheny, PA Beaver, PA
(390610042) (390610043) (390617001) (390618001) (420030064) (420031301) (420070014)
.......... Lancaster, PA York, PA Cabell, WV Kanawha, WV
(420710007) (421330008) (540110006) (540391005)
Minnesota........................ 1 Cook, IL
(170310052)
Missouri......................... 17 Cook, IL Madison, IL Saint Clair, IL Clark, IN Dubois, IN Marion, IN Marion, IN
(170310052) (171191007) (171630010) (180190006) (180372001) (180970078) (180970081)
.......... Marion, IN Jefferson, KY Butler, OH Hamilton, OH Hamilton, OH Hamilton, OH Hamilton, OH
(180970083) (211110043) (390170016) (390610014) (390610042) (390610043) (390617001)
.......... Hamilton, OH Cabell, WV Kanawha, WV
(390618001) (540110006) (540391005)
New Jersey....................... 2 Lancaster, PA York, PA
(420710007) (421330008)
[[Page 45258]]
New York......................... 8 Cuyahoga, OH Cuyahoga, OH Cuyahoga, OH Allegheny, PA Allegheny, PA Beaver, PA Lancaster, PA
(390350038) (390350045) (390350060) (420030064) (420031301) (420070014) (420710007)
.......... York, PA
(421330008)
North Carolina................... 3 Bibb, GA Clayton, GA Fulton, GA
(130210007) (130630091) (131210039)
Ohio............................. 23 Jefferson, AL Jefferson, AL Bibb, GA Clayton, GA Fulton, GA Cook, IL Madison, IL
(10730023) (10732003) (130210007) (130630091) (131210039) (170310052) (171191007)
.......... Saint Clair, IL Clark, IN Dubois, IN Marion, IN Marion, IN Marion, IN Jefferson, KY
(171630010) (180190006) (180372001) (180970078) (180970081) (180970083) (211110043)
.......... Wayne, MI Wayne, MI Allegheny, PA Allegheny, PA Beaver, PA Lancaster, PA York, PA
(261630015) (261630033) (420030064) (420031301) (420070014) (420710007) (421330008)
.......... Cabell, WV Kanawha, WV
(540110006) (540391005)
Pennsylvania..................... 25 Bibb, GA Clayton, GA Fulton, GA Cook, IL Madison, IL Saint Clair, IL Clark, IN
(130210007) (130630091) (131210039) (170310052) (171191007) (171630010) (180190006)
.......... Dubois, IN Marion, IN Marion, IN Marion, IN Jefferson, KY Wayne, MI Wayne, MI
(180372001) (180970078) (180970081) (180970083) (211110043) (261630015) (261630033)
.......... Butler, OH Cuyahoga, OH Cuyahoga, OH Cuyahoga, OH Hamilton, OH Hamilton, OH Hamilton, OH
(390170016) (390350038) (390350045) (390350060) (390610014) (390610042) (390610043)
.......... Hamilton, OH Hamilton, OH Cabell, WV Kanawha, WV
(390617001) (390618001) (540110006) (540391005)
South Carolina................... 3 Bibb, GA Clayton, GA Fulton, GA
(130210007) (130630091) (131210039)
Tennessee........................ 29 Jefferson, AL Jefferson, AL Bibb, GA Clayton, GA Fulton, GA Clark, IN Madison, IL
(10730023) (10732003) (130210007) (130630091) (131210039) (180190006) (171191007)
.......... Saint Clair, IL Dubois, IN Marion, IN Marion, IN Marion, IN Jefferson, KY Wayne, MI
(171630010) (180372001) (180970078) (180970081) (180970083) (211110043) (261630015)
.......... Wayne, MI Butler, OH Cuyahoga, OH Cuyahoga, OH Cuyahoga, OH Hamilton, OH Hamilton, OH
(261630033) (390170016) (390350038) (390350045) (390350060) (390610014) (390610042)
.......... Hamilton, OH Hamilton, OH Hamilton, OH Allegheny, PA Allegheny, PA Beaver, PA Cabell, WV
(390610043) (390617001) (390618001) (420030064) (420031301) (420070014) (540110006)
.......... Kanawha, WV
(540391005)
Virginia......................... 4 Lancaster, PA York, PA Cabell, WV Kanawha, WV
(420710007) (421330008) (540110006) (540391005)
West Virginia.................... 25 Fulton, GA Bibb, GA Clayton, GA Clark, IN Marion, IN Marion, IN Marion, IN
(131210039) (130210007) (130630091) (180190006) (180970078) (180970081) (180970083)
.......... Dubois, IN Jefferson, KY Wayne, MI Wayne, MI Butler, OH Cuyahoga, OH Cuyahoga, OH
(180372001) (211110043) (261630015) (261630033) (390170016) (390350038) (390350045)
.......... Cuyahoga, OH Hamilton, OH Hamilton, OH Hamilton, OH Hamilton, OH Hamilton, OH Allegheny, PA
(390350060) (390610014) (390610042) (390610043) (390617001) (390618001) (420030064)
.......... Allegheny, PA Beaver, PA Lancaster, PA York, PA
(420031301) (420070014) (420710007) (421330008)
Wisconsin........................ 8 Cook, IL Dubois, IN Marion, IN Marion, IN Marion, IN Wayne, MI Wayne, MI
(170310052) (180372001) (180970078) (180970081) (180970083) (261630015) (261630033)
.......... Cuyahoga, OH
(390350045)
----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
[[Page 45259]]
Table IV.C-15--Upwind State to Downwind Maintenance Site ``Linkages'' for Annual PM2.5
----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Number of
Upwind State linkages
---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
.......... Counties containing downwind 24-hour PM2.5 nonattainment sites (monitoring site ID)
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Alabama.......................... 1 Jefferson, KY
(211110044)
Georgia.......................... 1 Jefferson, KY
(211110044)
Illinois......................... 13 Jefferson, KY Cuyahoga, OH Cuyahoga, OH Hamilton, OH Jefferson, OH Montgomery, OH Stark, OH
(211110044) (390350027) (390350065) (390610040) (390811001) (391130032) (391510017)
.......... Berks, PA Harris, TX Berkeley, WV Brooke, WV Hancock, WV Marion, WV
(420110011) (482011035) (540030003) (540090005) (540291004) (540490006)
Indiana.......................... 16 Cook, IL Cook, IL Jefferson, KY New York, NY Cuyahoga, OH Cuyahoga, OH Hamilton, OH
(170313301) (170316005) (211110044) (360610056) (390350027) (390350065) (390610040)
.......... Jefferson, OH Montgomery, OH Stark, OH Berks, PA Harris, TX Berkeley, WV Brooke, WV
(390811001) (391130032) (391510017) (420110011) (482011035) (540030003) (540090005)
.......... Hancock, WV Marion, WV
(540291004) (540490006)
Iowa............................. 2 Cook, IL Cook, IL
(170313301) (170316005)
Kentucky......................... 12 Cook, IL Cook, IL Cuyahoga, OH Cuyahoga, OH Hamilton, OH Jefferson, OH Montgomery, OH
(170313301) (170316005) (390350027) (390350065) (390610040) (390811001) (391130032)
.......... Stark, OH Berkeley, WV Brooke, WV Hancock, WV Marion, WV
(391510017) (540030003) (540090005) (540291004) (540490006)
Louisiana........................ 1 Harris, TX
(482011035)
Maryland......................... 2 Berks, PA Berkeley, WV
(420110011) (540030003)
Michigan......................... 15 Cook, IL Cook, IL Jefferson, KY New York, NY Cuyahoga, OH Cuyahoga, OH Hamilton, OH
(170313301) (170316005) (211110044) (360610056) (390350027) (390350065) (390610040)
.......... Jefferson, OH Montgomery, OH Stark, OH Berks, PA Berkeley, WV Brooke, WV Hancock, WV
(390811001) (391130032) (391510017) (420110011) (540030003) (540090005) (540291004)
.......... Marion, WV
(540490006)
Minnesota........................ 1 Cook, IL
(170316005)
Missouri......................... 6 Cook, IL Cook, IL Jefferson, KY Hamilton, OH Montgomery, OH Stark, OH
(170313301) (170316005) (211110044) (390610040) (391130032) (391510017)
New Jersey....................... 2 New York, NY Berks, PA
(360610056) (420110011)
New York......................... 9 Cuyahoga, OH Cuyahoga, OH Jefferson, OH Stark, OH Berks, PA Berkeley, WV Brooke, WV
(390350027) (390350065) (390811001) (391510017) (420110011) (540030003) (540090005)
.......... Hancock, WV Marion, WV
(540291004) (540490006)
Ohio............................. 9 Cook, IL Cook, IL Jefferson, KY New York, NY Berks, PA Berkeley, WV Brooke, WV
(170313301) (170316005) (211110044) (360610056) (420110011) (540030003) (540090005)
.......... Hancock, WV Marion, WV
(540291004) (540490006)
Pennsylvania..................... 14 Cook, IL Cook, IL Jefferson, KY New York, NY Cuyahoga, OH Cuyahoga, OH Hamilton, OH
(170313301) (170316005) (211110044) (360610056) (390350027) (390350065) (390610040)
.......... Jefferson, OH Montgomery, OH Stark, OH Berkeley, WV Brooke, WV Hancock, WV Marion, WV
(390811001) (391130032) (391510017) (540030003) (540090005) (540291004) (540490006)
Tennessee........................ 10 Jefferson, KY Cuyahoga, OH Cuyahoga, OH Hamilton, OH Jefferson, OH Montgomery, OH Stark, OH
(211110044) (390350027) (390350065) (390610040) (390811001) (391130032) (391510017)
.......... Brooke, WV Hancock, WV Marion, WV
(540090005) (540291004) (540490006)
Virginia......................... 4 New York, NY Berks, PA Berkeley, WV Marion, WV
(360610056) (420110011) (540030003) (540490006)
West Virginia.................... 9 Jefferson, KY New York, NY Cuyahoga, OH Cuyahoga, OH Hamilton, OH Jefferson, OH Montgomery, OH
(211110044) (360610056) (390350027) (390350065) (390610040) (390811001) (391130032)
.......... Stark, OH Berks, PA
(391510017) (420110011)
[[Page 45260]]
Wisconsin........................ 2 Cook, IL Cook, IL
(170313301) (170316005)
----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
[[Page 45261]]
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 ([mu]g/
m\3\) Nonattainment and Maintenance for Each of 37 States
------------------------------------------------------------------------
Largest
downwind Largest
contribution downwind
to contribution
Upwind State nonattainment to maintenance
for 24-hour for 24-hour
PM2.5 ([mu]g/ PM2.5 ([mu]g/
m\3\) m\3\)
------------------------------------------------------------------------
Alabama................................. 0.48 0.32
Arkansas................................ 0.20 0.17
Connecticut............................. 0.41 0.70
Delaware................................ 0.50 0.36
Florida................................. 0.08 0.08
Georgia................................. 0.95 0.41
Illinois................................ 7.28 6.57
Indiana................................. 9.91 8.94
Iowa.................................... 1.87 1.67
Kansas.................................. 0.77 0.45
Kentucky................................ 6.53 6.91
Louisiana............................... 0.23 0.18
Maine................................... 0.19 0.19
Maryland/Washington, DC................. 2.63 1.82
Massachusetts........................... 0.67 0.71
Michigan................................ 2.35 3.35
Minnesota............................... 0.91 0.86
Mississippi............................. 0.09 0.04
Missouri................................ 5.03 4.82
Nebraska................................ 0.62 0.39
New Hampshire........................... 0.21 0.23
New Jersey.............................. 2.69 4.74
New York................................ 5.82 1.17
North Carolina.......................... 0.50 0.45
North Dakota............................ 0.27 0.15
Ohio.................................... 5.84 5.56
Oklahoma................................ 0.16 0.21
Pennsylvania............................ 3.67 4.86
Rhode Island............................ 0.05 0.06
South Carolina.......................... 0.19 0.19
South Dakota............................ 0.13 0.09
Tennessee............................... 3.92 4.70
Texas................................... 0.21 0.28
Vermont................................. 0.06 0.07
Virginia................................ 1.32 2.26
West Virginia........................... 3.51 4.83
Wisconsin............................... 0.80 1.01
------------------------------------------------------------------------
Based on the state-by-state contribution analysis, there are 24
states and the District of Columbia \52\ which contribute 0.35 [mu]g/
m\3\ 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 [mu]g/m\3\ or more
(i.e., the upwind state to downwind nonattainment ``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.
---------------------------------------------------------------------------
There are 23 states and the District of Columbia which contribute
0.35 [mu]g/m\3\ 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
[mu]g/m\3\ or more (i.e., the upwind state to downwind maintenance
``linkages'').
[[Page 45262]]
Table IV.C-17--Upwind State to Downwind Nonattainment Site ``Linkages'' for 24-Hour PM2.5
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Number of
Upwind State linkages
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
.......... Counties containing downwind 24-hour PM2.5 nonattainment sites (monitoring site ID)
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Alabama........................ 5 Monroe, MI Wayne, MI Hamilton, OH Hamilton, OH Hamilton, OH ......................
(261150005) (261630015) (390610006) (390610014) (390618001)
Connecticut.................... 3 Hudson, NJ New York, NY New York, NY ....................... ....................... ......................
(340172002) (360610056) (360610128)
Delaware....................... 2 Union, NJ Dauphin, PA ....................... ....................... ....................... ......................
(340390004) (420430401)
Georgia........................ 12 Jefferson, AL Jefferson, AL Baltimore City, MD Baltimore City, MD Union, NJ Butler, OH
(10730023) (10732003) (245100040) (245100049) (340390004) (390170016)
Butler, OH Hamilton, OH Hamilton, OH Hamilton, OH Montgomery, OH York, PA
(390171004) (390610006) (390610014) (390618001) (391130032) (421330008)
Illinois....................... 70 Jefferson, AL Jefferson, AL New Haven, CT Clark, IN Dubois, IN Knox, IN
(10730023) (10732003) (90091123) (180190006) (180372001) (180830004)
Lake, IN Lake, IN Marion, IN Marion, IN Marion, IN Marion, IN
(180890022) (180890026) (180970042) (180970043) (180970066) (180970078)
Marion, IN Marion, IN Marion, IN Tippecanoe, IN Scott, IA Daviess, KY
(180970079) (180970081) (180970083) (181570008) (191630019) (210590005)
Jefferson, KY Jefferson, KY Jefferson, KY Monroe, MI Oakland, MI St. Clair, MI
(211110043) (211110044) (211110048) (261150005) (261250001) (261470005)
Washtenaw, MI Wayne, MI Wayne, MI Wayne, MI Wayne, MI Wayne, MI
(261610008) (261630015) (261630016) (261630019) (261630033) (261630036)
Jefferson, MO Saint Charles, MO St. Louis City, MO St. Louis City, MO Union, NJ New York, NY
(290990012) (291831002) (295100007) (295100087) (340390004) (360610128)
Butler, OH Butler, OH Butler, OH Butler, OH Cuyahoga, OH Cuyahoga, OH
(390170003) (390170016) (390170017) (390171004) (390350038) (390350045)
Cuyahoga, OH Cuyahoga, OH Franklin, OH Franklin, OH Hamilton, OH Hamilton, OH
(390350060) (390350065) (390490024) (390490025) (390610006) (390610014)
Hamilton, OH Hamilton, OH Hamilton, OH Hamilton, OH Hamilton, OH Jefferson, OH
(390610040) (390610042) (390610043) (390617001) (390618001) (390811001)
Montgomery, OH Summit, OH Allegheny, PA Allegheny, PA Allegheny, PA Allegheny, PA
(391130032) (391530017) (420030064) (420030093) (420030116) (420031008)
Allegheny, PA Beaver, PA Berks, PA Cambria, PA Montgomery, TN Brooke, WV
(420031301) (420070014) (420110011) (420210011) (471251009) (540090011)
Milwaukee, WI Milwaukee, WI Milwaukee, WI Milwaukee, WI ....................... ......................
(550790010) (550790026) (550790043) (550790099)
Indiana........................ 75 Jefferson, AL Jefferson, AL New Haven, CT Cook, IL Cook, IL Cook, IL
(10730023) (10732003) (90091123) (170310052) (170310057) (170310076)
Cook, IL Cook, IL Cook, IL Cook, IL Cook, IL Madison, IL
(170311016) (170312001) (170313103) (170313301) (170316005) (171190023)
Madison, IL Madison, IL Madison, IL Scott, IA Daviess, KY Jefferson, KY
(171191007) (171192009) (171193007) (191630019) (210590005) (211110043)
Jefferson, KY Jefferson, KY Monroe, MI Oakland, MI St. Clair, MI Washtenaw, MI
(211110044) (211110048) (261150005) (261250001) (261470005) (261610008)
Wayne, MI Wayne, MI Wayne, MI Wayne, MI Wayne, MI Jefferson, MO
(261630015) (261630016) (261630019) (261630033) (261630036) (290990012)
Saint Charles, MO St. Louis City, MO St. Louis City, MO Hudson, NJ Union, NJ Bronx, NY
(291831002) (295100007) (295100087) (340171003) (340390004) (360050080)
New York, NY New York, NY Butler, OH Butler, OH Butler, OH Butler, OH
(360610056) (360610128) (390170003) (390170016) (390170017) (390171004)
Cuyahoga, OH Cuyahoga, OH Cuyahoga, OH Cuyahoga, OH Franklin, OH Franklin, OH
(390350038) (390350045) (390350060) (390350065) (390490024) (390490025)
Hamilton, OH Hamilton, OH Hamilton, OH Hamilton, OH Hamilton, OH Hamilton, OH
(390610006) (390610014) (390610040) (390610042) (390610043) (390617001)
Hamilton, OH Jefferson, OH Montgomery, OH Summit, OH Allegheny, PA Allegheny, PA
(390618001) (390811001) (391130032) (391530017) (420030008) (420030064)
Allegheny, PA Allegheny, PA Allegheny, PA Allegheny, PA Beaver, PA Berks, PA
(420030093) (420030116) (420031008) (420031301) (420070014) (420110011)
Cambria, PA Dauphin, PA York, PA Montgomery, TN Brooke, WV Milwaukee, WI
(420210011) (420430401) (421330008) (471251009) (540090011) (550790010)
Milwaukee, WI Milwaukee, WI Milwaukee, WI ....................... ....................... ......................
(550790026) (550790043) (550790099)
Iowa........................... 17 Cook, IL Cook, IL Cook, IL Cook, IL Cook, IL Cook, IL
(170310052) (170310057) (170310076) (170311016) (170312001) (170313103)
Cook, IL Cook, IL Madison, IL Lake, IN Lake, IN Jefferson, MO
(170313301) (170316005) (171191007) (180890022) (180890026) (290990012)
St. Louis City, MO Milwaukee, WI Milwaukee, WI Milwaukee, WI Milwaukee, WI ......................
(295100007) (550790010) (550790026) (550790043) (550790099)
Kansas......................... 3 Milwaukee, WI Milwaukee, WI Milwaukee, WI ....................... ....................... ......................
(550790010) (550790026) (550790099)
Kentucky....................... 81 Jefferson, AL Jefferson, AL New Haven, CT Cook, IL Cook, IL Cook, IL
(10730023) (10732003) (90091123) (170310052) (170310057) (170310076)
Cook, IL Cook, IL Cook, IL Cook, IL Cook, IL Madison, IL
(170311016) (170312001) (170313103) (170313301) (170316005) (171190023)
Madison, IL Madison, IL Madison, IL Clark, IN Dubois, IN Knox, IN
(171191007) (171192009) (171193007) (180190006) (180372001) (180830004)
Lake, IN Marion, IN Marion, IN Marion, IN Marion, IN Marion, IN
(180890026) (180970042) (180970043) (180970066) (180970078) (180970079)
Marion, IN Marion, IN Tippecanoe, IN Scott, IA Monroe, MI Oakland, MI
(180970081) (180970083) (181570008) (191630019) (261150005) (261250001)
[[Page 45263]]
St. Clair, MI Washtenaw, MI Wayne, MI Wayne, MI Wayne, MI Wayne, MI
(261470005) (261610008) (261630015) (261630016) (261630019) (261630033)
Wayne, MI Jefferson, MO Saint Charles, MO St. Louis City, MO St. Louis City, MO Hudson, NJ
(261630036) (290990012) (291831002) (295100007) (295100087) (340171003)
Union, NJ Bronx, NY New York, NY Butler, OH Butler, OH Butler, OH
(340390004) (360050080) (360610128) (390170003) (390170016) (390170017)
Butler, OH Cuyahoga, OH Cuyahoga, OH Cuyahoga, OH Cuyahoga, OH Franklin, OH
(390171004) (390350038) (390350045) (390350060) (390350065) (390490024)
Franklin, OH Hamilton, OH Hamilton, OH Hamilton, OH Hamilton, OH Hamilton, OH
(390490025) (390610006) (390610014) (390610040) (390610042) (390610043)
Hamilton, OH Hamilton, OH Jefferson, OH Montgomery, OH Summit, OH Allegheny, PA
(390617001) (390618001) (390811001) (391130032) (391530017) (420030008)
Allegheny, PA Allegheny, PA Allegheny, PA Allegheny, PA Allegheny, PA Beaver, PA
(420030064) (420030093) (420030116) (420031008) (420031301) (420070014)
Berks, PA Cambria, PA York, PA Montgomery, TN Brooke, WV Milwaukee, WI
(420110011) (420210011) (421330008) (471251009) (540090011) (550790010)
Milwaukee, WI Milwaukee, WI Milwaukee, WI ....................... ....................... ......................
(550790026) (550790043) (550790099)
Maryland....................... 11 New Haven, CT Hudson, NJ Hudson, NJ Union, NJ Bronx, NY New York, NY
(90091123) (340171003) (340172002) (340390004) (360050080) (360610056)
New York, NY Berks, PA Dauphin, PA Lancaster, PA York, PA ......................
(360610128) (420110011) (420430401) (420710007) (421330008)
Massachusetts.................. 3 New Haven, CT New York, NY New York, NY ....................... ....................... ......................
(90091123) (360610056) (360610128)
Michigan....................... 48 Cook, IL Cook, IL Cook, IL Cook, IL Cook, IL Cook, IL
(170310052) (170310057) (170310076) (170311016) (170312001) (170313103)
Cook, IL Cook, IL Madison, IL Madison, IL Madison, IL Madison, IL
(170313301) (170316005) (171190023) (171191007) (171192009) (171193007)
Knox, IN Lake, IN Lake, IN Scott, IA Jefferson, MO Saint Charles, MO
(180830004) (180890022) (180890026) (191630019) (290990012) (291831002)
St. Louis City, MO St. Louis City, MO New York, NY Cuyahoga, OH Cuyahoga, OH Cuyahoga, OH
(295100007) (295100087) (360610128) (390350038) (390350045) (390350060)
Cuyahoga, OH Franklin, OH Franklin, OH Hamilton, OH Hamilton, OH Hamilton, OH
(390350065) (390490024) (390490025) (390610014) (390617001) (390618001)
Jefferson, OH Montgomery, OH Summit, OH Allegheny, PA Allegheny, PA Allegheny, PA
(390811001) (391130032) (391530017) (420030008) (420030064) (420030093)
Allegheny, PA Allegheny, PA Allegheny, PA Beaver, PA Cambria, PA Dauphin, PA
(420030116) (420031008) (420031301) (420070014) (420210011) (420430401)
Montgomery, TN Brooke, WV Milwaukee, WI Milwaukee, WI Milwaukee, WI ......................
(471251009) (540090011) (550790010) (550790026) (550790043)
Milwaukee, WI
(550790099)
Minnesota...................... 4 Milwaukee, WI Milwaukee, WI Milwaukee, WI Milwaukee, WI ....................... ......................
(550790010) (550790026) (550790043) (550790099)
Missouri....................... 56 Cook, IL Cook, IL Cook, IL Cook, IL Cook, IL Cook, IL
(170310052) (170310057) (170310076) (170311016) (170312001) (170313103)
Cook, IL Cook, IL Madison, IL Madison, IL Madison, IL Madison, IL
(170313301) (170316005) (171190023) (171191007) (171192009) (171193007)
Clark, IN Dubois, IN Knox, IN Lake, IN Lake, IN Marion, IN
(180190006) (180372001) (180830004) (180890022) (180890026) (180970042)
Marion, IN Marion, IN Marion, IN Marion, IN Marion, IN Marion, IN
(180970043) (180970066) (180970078) (180970079) (180970081) (180970083)
Tippecanoe, IN Scott, IA Daviess, KY Jefferson, KY Jefferson, KY Jefferson, KY
(181570008) (191630019) (210590005) (211110043) (211110044) (211110048)
Monroe, MI Oakland, MI Washtenaw, MI Wayne, MI Wayne, MI Wayne, MI
(261150005) (261250001) (261610008) (261630015) (261630033) (261630036)
Butler, OH Butler, OH Butler, OH Butler, OH Franklin, OH Franklin, OH
(390170003) (390170016) (390170017) (390171004) (390490024) (390490025)
Hamilton, OH Hamilton, OH Hamilton, OH Hamilton, OH Hamilton, OH Hamilton, OH
(390610006) (390610014) (390610040) (390610042) (390610043) (390617001)
Hamilton, OH Montgomery, OH Allegheny, PA Montgomery, TN Milwaukee, WI Milwaukee, WI
(390618001) (391130032) (420030116) (471251009) (550790010) (550790026)
Milwaukee, WI Milwaukee, WI ....................... ....................... ....................... ......................
(550790043) (550790099)
Nebraska....................... 3 Milwaukee, WI Milwaukee, WI Milwaukee, WI ....................... ....................... ......................
(550790010) (550790026) (550790099)
New Jersey..................... 9 New Haven, CT Baltimore City, MD Bronx, NY New York, NY New York, NY Berks, PA
(90091123) (245100049) (360050080) (360610056) (360610128) (420110011)
Dauphin, PA Lancaster, PA York, PA ....................... ....................... ......................
(420430401) (420710007) (421330008)
New York....................... 23 New Haven, CT Baltimore City, MD Baltimore City, MD St. Clair, MI Washtenaw, MI Wayne, MI
(90091123) (245100040) (245100049) (261470005) (261610008) (261630016)
Wayne, MI Wayne, MI Wayne, MI Hudson, NJ Hudson, NJ Union, NJ
(261630019) (261630033) (261630036) (340171003) (340172002) (340390004)
Cuyahoga, OH Cuyahoga, OH Cuyahoga, OH Cuyahoga, OH Franklin, OH Franklin, OH
(390350038) (390350045) (390350060) (390350065) (390490024) (390490025)
Summit, OH Berks, PA (420110011) Dauphin, PA Lancaster, PA York, PA ......................
(391530017) (420430401) (420710007) (421330008)
[[Page 45264]]
North Carolina................. 11 Baltimore City, MD Baltimore City, MD Hudson, NJ Hudson, NJ Union, NJ Bronx, NY
(245100040) (245100049) (340171003) (340172002) (340390004) (360050080)
New York, NY Berks, PA Dauphin, PA Lancaster, PA York, PA ......................
(360610056) (420110011) (420430401) (420710007) (421330008)
Ohio........................... 72 Jefferson, AL Jefferson, AL New Haven, CT Cook, IL Cook, IL Cook, IL
(10730023) (10732003) (90091123) (170310052) (170310057) (170310076)
Cook, IL Cook, IL Cook, IL Cook, IL Cook, IL Madison, IL
(170311016) (170312001) (170313103) (170313301) (170316005) (171190023)
Madison, IL Madison, IL Madison, IL Clark, IN Dubois, IN Knox, IN
(171191007) (171192009) (171193007) (180190006) (180372001) (180830004)
Lake, IN Lake, IN Marion, IN Marion, IN Marion, IN Marion, IN
(180890022) (180890026) (180970042) (180970043) (180970066) (180970078)
Marion, IN Marion, IN Marion, IN Tippecanoe, IN Scott, IA Daviess, KY
(180970079) (180970081) (180970083) (181570008) (191630019) (210590005)
Jefferson, KY Jefferson, KY Jefferson, KY Baltimore City, MD Baltimore City, MD Monroe, MI
(211110043) (211110044) (211110048) (245100040) (245100049) (261150005)
Oakland, MI St. Clair, MI Washtenaw, MI Wayne, MI Wayne, MI Wayne, MI
(261250001) (261470005) (261610008) (261630015) (261630016) (261630019)
Wayne, MI Wayne, MI Jefferson, MO Saint Charles, MO St. Louis City, MO St. Louis City, MO
(261630033) (261630036) (290990012) (291831002) (295100007) (295100087)
Hudson, NJ Hudson, NJ Union, NJ Bronx, NY New York, NY New York, NY
(340171003) (340172002) (340390004) (360050080) (360610056) (360610128)
Allegheny, PA Allegheny, PA Allegheny, PA Allegheny, PA Allegheny, PA Allegheny, PA
(420030008) (420030064) (420030093) (420030116) (420031008) (420031301)
Beaver, PA Berks, PA Cambria, PA Dauphin, PA Lancaster, PA York, PA
(420070014) (420110011) (420210011) (420430401) (420710007) (421330008)
Montgomery, TN Brooke, WV Milwaukee, WI Milwaukee, WI Milwaukee, WI Milwaukee, WI
(471251009) (540090011) (550790010) (550790026) (550790043) (550790099)
Pennsylvania................... 77 Jefferson, AL Jefferson, AL New Haven, CT Cook, IL Cook, IL Cook, IL
(10730023) (10732003) (90091123) (170310052) (170310057) (170310076)
Cook, IL Cook, IL Cook, IL Cook, IL Cook, IL Madison, IL
(170311016) (170312001) (170313103) (170313301) (170316005) (171191007)
Madison, IL Madison, IL Madison, IL Clark, IN Dubois, IN Knox, IN
(171192009) (171193007) (171190023) (180190006) (180372001) (180830004)
Lake, IN Marion, IN Marion, IN Marion, IN Marion, IN Marion, IN
(180890026) (180970042) (180970043) (180970066) (180970078) (180970079)
Marion, IN Marion, IN Tippecanoe, IN Scott, IA Jefferson, KY Jefferson, KY
(180970081) (180970083) (181570008) (191630019) (211110043) (211110044)
Jefferson, KY Baltimore City, MD Baltimore City, MD Monroe, MI Oakland, MI St. Clair, MI
(211110048) (245100040) (245100049) (261150005) (261250001) (261470005)
Washtenaw, MI Wayne, MI Wayne, MI Wayne, MI Wayne, MI Wayne, MI
(261610008) (261630015) (261630016) (261630019) (261630033) (261630036)
Jefferson, MO Saint Charles, MO St. Louis City, MO St. Louis City, MO Hudson, NJ Hudson, NJ
(290990012) (291831002) (295100007) (295100087) (340171003) (340172002)
Union, NJ Bronx, NY New York, NY New York, NY Butler, OH Butler, OH
(340390004) (360050080) (360610056) (360610128) (390170003) (390170016)
Butler, OH Butler, OH Cuyahoga, OH Cuyahoga, OH Cuyahoga, OH Cuyahoga, OH
(390170017) (390171004) (390350038) (390350045) (390350060) (390350065)
Franklin, OH Franklin, OH Hamilton, OH Hamilton, OH Hamilton, OH Hamilton, OH
(390490024) (390490025) (390610006) (390610014) (390610040) (390610042)
Hamilton, OH Hamilton, OH Hamilton, OH Jefferson, OH Montgomery, OH Summit, OH
(390610043) (390617001) (390618001) (390811001) (391130032) (391530017)
Montgomery, TN Brooke, WV Milwaukee, WI Milwaukee, WI Milwaukee, WI ......................
(471251009) (540090011) (550790026) (550790043) (550790099)
Tennessee...................... 61 Jefferson, AL Jefferson, AL New Haven, CT Madison, IL Madison, IL Madison, IL
(10730023) (10732003) (90091123) (171190023) (171191007) (171192009)
Madison, IL Clark, IN Dubois, IN Knox, IN Marion, IN Marion, IN
(171193007) (180190006) (180372001) (180830004) (180970042) (180970043)
Marion, IN Marion, IN Marion, IN Marion, IN Marion, IN Tippecanoe, IN
(180970066) (180970078) (180970079) (180970081) (180970083) (181570008)
Scott, IA Daviess, KY Jefferson, KY Jefferson, KY Jefferson, KY Monroe, MI
(191630019) (210590005) (211110043) (211110044) (211110048) (261150005)
Oakland, MI St. Clair, MI Washtenaw, MI Wayne, MI Wayne, MI Wayne, MI
(261250001) (261470005) (261610008) (261630015) (261630033) (261630036)
Jefferson, MO Saint Charles, MO St. Louis City, MO St. Louis City, MO Union, NJ New York, NY
(290990012) (291831002) (295100007) (295100087) (340390004) (360610128)
Butler, OH Butler, OH Butler, OH Butler, OH Cuyahoga, OH Cuyahoga, OH
(390170003) (390170016) (390170017) (390171004) (390350038) (390350045)
Cuyahoga, OH Franklin, OH Franklin, OH Hamilton, OH Hamilton, OH Hamilton, OH
(390350065) (390490024) (390490025) (390610006) (390610014) (390610040)
Hamilton, OH Hamilton, OH Hamilton, OH Hamilton, OH Jefferson, OH Montgomery, OH
(390610042) (390610043) (390617001) (390618001) (390811001) (391130032)
Summit, OH Allegheny, PA Allegheny, PA Allegheny, PA Allegheny, PA Cambria, PA
(391530017) (420030093) (420030116) (420031008) (420031301) (420210011)
York, PA ....................... ....................... ....................... ....................... ......................
(421330008)
Virginia....................... 13 New Haven, CT Baltimore City, MD Baltimore City, MD Hudson, NJ Hudson, NJ Union, NJ
(90091123) (245100040) (245100049) (340171003) (340172002) (340390004)
[[Page 45265]]
Bronx, NY New York, NY New York, NY Berks, PA Dauphin, PA Lancaster, PA
(360050080) (360610056) (360610128) (420110011) (420430401) (420710007)
York, PA ....................... ....................... ....................... ....................... ......................
(421330008)
West Virginia.................. 84 Jefferson, AL Jefferson, AL New Haven, CT Cook, IL Cook, IL Cook, IL
(10730023) (10732003) (90091123) (170310052) (170310057) (170310076)
Cook, IL Cook, IL Cook, IL Cook, IL Madison, IL Madison, IL
(170311016) (170312001) (170313301) (170316005) (171190023) (171191007)
Madison, IL Madison, IL Clark, IN Dubois, IN Lake, IN Marion, IN
(171192009) (171193007) (180190006) (180372001) (180890026) (180970042)
Marion, IN Marion, IN Marion, IN Marion, IN Marion, IN Marion, IN
(180970043) (180970066) (180970078) (180970079) (180970081) (180970083)
Tippecanoe, IN Scott, IA Jefferson, KY Jefferson, KY Jefferson, KY Baltimore City, MD
(181570008) (191630019) (211110043) (211110044) (211110048) (245100040)
Baltimore City, MD Monroe, MI Oakland, MI St. Clair, MI Washtenaw, MI Wayne, MI
(245100049) (261150005) (261250001) (261470005) (261610008) (261630015)
Wayne, MI Wayne, MI Wayne, MI Wayne, MI Jefferson, MO Saint Charles, MO
(261630016) (261630019) (261630033) (261630036) (290990012) (291831002)
St. Louis City, MO St. Louis City, MO Hudson, NJ Hudson, NJ Union, NJ Bronx, NY
(295100007) (295100087) (340171003) (340172002) (340390004) (360050080)
New York, NY New York, NY Butler, OH Butler, OH Butler, OH Butler, OH
(360610056) (360610128) (390170003) (390170016) (390170017) (390171004)
Cuyahoga, OH Cuyahoga, OH Cuyahoga, OH Cuyahoga, OH Franklin, OH Franklin, OH
(390350038) (390350045) (390350060) (390350065) (390490024) (390490025)
Hamilton, OH Hamilton, OH Hamilton, OH Hamilton, OH Hamilton, OH Hamilton, OH
(390610006) (390610014) (390610040) (390610042) (390610043) (390617001)
Hamilton, OH Jefferson, OH Montgomery, OH Summit, OH Allegheny, PA Allegheny, PA
(390618001) (390811001) (391130032) (391530017) (420030008) (420030064)
Allegheny, PA Allegheny, PA Allegheny, PA Allegheny, PA Beaver, PA Berks, PA
(420030093) (420030116) (420031008) (420031301) (420070014) (420110011)
Cambria, PA Dauphin, PA Lancaster, PA York, PA Montgomery, TN Milwaukee, WI
(420210011) (420430401) (420710007) (421330008) (471251009) (550790043)
Wisconsin...................... 12 Cook, IL Cook, IL Cook, IL Cook, IL Cook, IL Cook, IL
(170310052) (170310057) (170310076) (170311016) (170312001) (170313103)
Cook, IL Cook, IL Lake, IN Lake, IN Scott, IA Wayne, MI
(170313301) (170316005) (180890022) (180890026) (191630019) (261630016)
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Table IV.C-18--Upwind State to Downwind Maintenance Site ``Linkages'' for 24-Hour PM2.5
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Number of
Upwind State linkages
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
.......... Counties containing downwind 24-hour PM2.5 nonattainment sites (monitoring site ID)
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Connecticut.................... 1 New York, NY
(360610062)
Delaware....................... 2 Cumberland, PA New York, NY ....................... ....................... ....................... ......................
(420410101) (360610079)
Georgia........................ 3 Baltimore City, MD Lucas, OH Preble, OH ....................... ....................... ......................
(245100035) (390950026) (391351001)
Illinois....................... 29 District of Columbia District of Columbia Elkhart, IN Floyd, IN Vigo, IN Muscatine, IA
(110010041) (110010042) (180390003) (180431004) (181670023) (191390015)
Bullitt, KY McCracken, KY Warren, KY Wayne, MI St. Louis City, MO New York, NY
(210290006) (211451004) (212270007) (261630001) (295100085) (360610079)
Cuyahoga, OH Cuyahoga, OH Jefferson, OH Lucas, OH Lucas, OH Mahoning, OH
(390350027) (390350034) (390810017) (390950024) (390950026) (390990014)
Montgomery, OH Preble, OH Trumbull, OH Allegheny, PA Allegheny, PA Washington, PA
(391130031) (391351001) (391550007) (420030095) (420033007) (421255001)
Sumner, TN Brooke, WV Dane, WI Milwaukee, WI Waukesha, WI ......................
(471650007) (540090005) (550250047) (550790059) (551330027)
Indiana........................ 34 District of Columbia District of Columbia Cook, IL Cook, IL Cook, IL Saint Clair, IL
(110010041) (110010042) (170310022) (170310050) (170314007) (171630010)
Will, IL Muscatine, IA Bullitt, KY McCracken, KY Warren, KY Anne Arundel, MD
(171971002) (191390015) (210290006) (211451004) (212270007) (240031003)
Wayne, MI St. Louis City, MO New York, NY New York, NY Cuyahoga, OH Cuyahoga, OH
(261630001) (295100085) (360610062) (360610079) (390350027) (390350034)
Jefferson, OH Lucas, OH Lucas, OH Mahoning, OH Montgomery, OH Preble, OH
(390810017) (390950024) (390950026) (390990014) (391130031) (391351001)
Trumbull, OH Allegheny, PA Allegheny, PA Cumberland, PA Washington, PA Sumner, TN
(391550007) (420030095) (420033007) (420410101) (421255001) (471650007)
Brooke, WV Dane, WI Milwaukee, WI Waukesha, WI ....................... ......................
(540090005) (550250047) (550790059) (551330027)
Iowa........................... 9 Cook, IL Cook, IL Cook, IL Will, IL Elkhart, IN St. Louis City, MO
(170310022) (170310050) (170314007) (171971002) (180390003) (295100085)
[[Page 45266]]
Dane, WI Milwaukee, WI Waukesha, WI ....................... ....................... ......................
(550250047) (550790059) (551330027)
Kansas......................... 2 Muscatine, IA Milwaukee, WI ....................... ....................... ....................... ......................
(191390015) (550790059)
Kentucky....................... 33 District of Columbia District of Columbia Cook, IL Cook, IL Cook, IL Saint Clair, IL
(110010041) (110010042) (170310022) (170310050) (170314007) (171630010)
Will, IL Elkhart, IN Floyd, IN Vigo, IN Muscatine, IA Anne Arundel, MD
(171971002) (180390003) (180431004) (181670023) (191390015) (240031003)
Wayne, MI St. Louis City, MO New York, NY New York, NY Cuyahoga, OH Cuyahoga, OH
(261630001) (295100085) (360610062) (360610079) (390350027) (390350034)
Jefferson, OH Lucas, OH Lucas, OH Mahoning, OH Montgomery, OH Preble, OH
(390810017) (390950024) (390950026) (390990014) (391130031) (391351001)
Trumbull, OH Allegheny, PA Allegheny, PA Washington, PA Sumner, TN Brooke, WV
(391550007) (420030095) (420033007) (421255001) (471650007) (540090005)
Dane, WI Milwaukee, WI Waukesha, WI ....................... ....................... ......................
(550250047) (550790059) (551330027)
Maryland....................... 5 District of Columbia District of Columbia New York, NY New York, NY Cumberland, PA ......................
(110010041) (110010042) (360610062) (360610079) (420410101)
Massachusetts.................. 1 New York, NY ....................... ....................... ....................... ....................... ......................
(360610062)
Michigan....................... 28 District of Columbia Cook, IL Cook, IL Cook, IL Saint Clair, IL Will, IL
(110010041) (170310022) (170310050) (170314007) (171630010) (171971002)
Elkhart, IN Vigo, IN Muscatine, IA Warren, KY St. Louis City, MO Cuyahoga, OH
(180390003) (181670023) (191390015) (212270007) (295100085) (390350027)
Cuyahoga, OH Jefferson, OH Lucas, OH Lucas, OH Mahoning, OH Montgomery, OH
(390350034) (390810017) (390950024) (390950026) (390990014) (391130031)
Preble, OH Trumbull, OH Allegheny, PA Allegheny, PA Washington, PA Sumner, TN
(391351001) (391550007) (420030095) (420033007) (421255001) (471650007)
Brooke, WV Dane, WI Milwaukee, WI Waukesha, WI ....................... ......................
(540090005) (550250047) (550790059) (551330027)
Minnesota...................... 4 Muscatine, IA Dane, WI Milwaukee, WI Waukesha, WI ....................... ......................
(191390015) (550250047) (550790059) (551330027)
Missouri....................... 20 Cook, IL Cook, IL Cook, IL Saint Clair, IL Will, IL Elkhart, IN
(170310022) (170310050) (170314007) (171630010) (171971002) (180390003)
Floyd, IN Vigo, IN Muscatine, IA Bullitt, KY McCracken, KY Warren, KY
(180431004) (181670023) (191390015) (210290006) (211451004) (212270007)
Jefferson, OH Lucas, OH Montgomery, OH Preble, OH Sumner, TN Dane, WI
(390810017) (390950026) (391130031) (391351001) (471650007) (550250047)
Milwaukee, WI Waukesha, WI ....................... ....................... ....................... ......................
(550790059) (551330027)
Nebraska....................... 2 Muscatine, IA Milwaukee, WI ....................... ....................... ....................... ......................
(191390015) (550790059)
New Jersey..................... 5 District of Columbia Anne Arundel, MD New York, NY New York, NY Cumberland, PA ......................
(110010041) (240031003) (360610062) (360610079) (420410101)
New York....................... 9 District of Columbia District of Columbia Anne Arundel, MD Baltimore City, MD Cuyahoga, OH Cuyahoga, OH
(110010041) (110010042) (240031003) (245100035) (390350027) (390350034)
Lucas, OH Lucas, OH Cumberland, PA ....................... ....................... ......................
(390950024) (390950026) (420410101)
North Carolina................. 3 Baltimore City, MD New York, NY New York, NY ....................... ....................... ......................
(245100035) (360610062) (360610079)
Ohio........................... 29 District of Columbia District of Columbia Cook, IL Cook, IL Cook, IL Saint Clair, IL
(110010041) (110010042) (170310022) (170310050) (170314007) (171630010)
Will, IL Elkhart, IN Floyd, IN Vigo, IN Muscatine, IA Bullitt, KY
(171971002) (180390003) (180431004) (181670023) (191390015) (210290006)
McCracken, KY Warren, KY Anne Arundel, MD Baltimore City, MD Wayne, MI St. Louis City, MO
(211451004) (212270007) (240031003) (245100035) (261630001) (295100085)
New York, NY New York, NY Allegheny, PA Allegheny, PA Cumberland, PA Washington, PA
(360610062) (360610079) (420030095) (420033007) (420410101) (421255001)
Sumner, TN Brooke, WV Dane, WI Milwaukee, WI Waukesha, WI ......................
(471650007) (540090005) (550250047) (550790059) (551330027)
Pennsylvania................... 32 District of Columbia District of Columbia Cook, IL Cook, IL Cook, IL Saint Clair, IL
(110010041) (110010042) (170310022) (170310050) (170314007) (171630010)
Will, IL Elkhart, IN Floyd, IN Vigo, IN Muscatine, IA Bullitt, KY
(171971002) (180390003) (180431004) (181670023) (191390015) (210290006)
Warren, KY Anne Arundel, MD Baltimore City, MD Wayne, MI New York, NY New York, NY
(212270007) (240031003) (245100035) (261630001) (360610062) (360610079)
Cuyahoga, OH Cuyahoga, OH Jefferson, OH Lucas, OH Lucas, OH Mahoning, OH
(390350027) (390350034) (390810017) (390950024) (390950026) (390990014)
Montgomery, OH Preble, OH Trumbull, OH Sumner, TN Brooke, WV Dane, WI
(391130031) (391351001) (391550007) (471650007) (540090005) (550250047)
[[Page 45267]]
Milwaukee, WI Waukesha, WI ....................... ....................... ....................... ......................
(550790059) (551330027)
Tennessee...................... 21 Cook, IL Saint Clair, IL Will, IL Elkhart, IN Floyd, IN Vigo, IN
(170314007) (171630010) (171971002) (180390003) (180431004) (181670023)
Muscatine, IA Bullitt, KY McCracken, KY Warren, KY Wayne, MI St. Louis City, MO
(191390015) (210290006) (211451004) (212270007) (261630001) (295100085)
Jefferson, OH Lucas, OH Lucas, OH Mahoning, OH Montgomery, OH Preble, OH
(390810017) (390950024) (390950026) (390990014) (391130031) (391351001)
Trumbull, OH Allegheny, PA Washington, PA ....................... ....................... ......................
(391550007) (420033007) (421255001)
Virginia....................... 7 District of Columbia District of Columbia Anne Arundel, MD Baltimore City, MD New York, NY New York, NY
(110010041) (110010042) (240031003) (245100035) (360610062) (360610079)
Cumberland, PA ....................... ....................... ....................... ....................... ......................
(420410101)
West Virginia.................. 35 District of Columbia District of Columbia Cook, IL Cook, IL Saint Clair, IL Will, IL
(110010041) (110010042) (170310050) (170314007) (171630010) (171971002)
Elkhart, IN Floyd, IN Vigo, IN Muscatine, IA Bullitt, KY Warren, KY
(180390003) (180431004) (181670023) (191390015) (210290006) (212270007)
Anne Arundel, MD Baltimore City, MD Wayne, MI St. Louis City, MO New York, NY New York, NY
(240031003) (245100035) (261630001) (295100085) (360610062) (360610079)
Cuyahoga, OH Cuyahoga, OH Jefferson, OH Lucas, OH Lucas, OH Mahoning, OH
(390350027) (390350034) (390810017) (390950024) (390950026) (390990014)
Montgomery, OH Preble, OH Trumbull, OH Allegheny, PA Allegheny, PA Cumberland, PA
(391130031) (391351001) (391550007) (420030095) (420033007) (420410101)
Washington, PA Sumner, TN Dane, WI Milwaukee, WI Waukesha, WI ......................
(421255001) (471650007) (550250047) (550790059) (551330027)
Wisconsin...................... 6 Cook, IL Cook, IL Cook, IL Will, IL Elkhart, IN Muscatine, IA
(170310022) (170310050) (170314007) (171971002) (180390003) (191390015)
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
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 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
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 8-hour
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.
---------------------------------------------------------------------------
\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 predictions of at least 70 ppb. Thus, we did not
calculate contributions for these two maintenance sites.
Table IV.C-19--Largest Contribution to Downwind 8-Hour Ozone
Nonattainment and Maintenance for Each of 37 States
------------------------------------------------------------------------
Largest
downwind Largest
contribution downwind
Upwind State to contribution
nonattainment to maintenance
for ozone for ozone
(ppb) (ppb)
------------------------------------------------------------------------
Alabama................................. 4.7 4.7
Arkansas................................ 1.4 1.8
Connecticut............................. 1.7 1.6
Delaware................................ 3.3 2.5
Florida................................. 0.8 2.1
Georgia................................. 2.1 1.7
[[Page 45268]]
Illinois................................ 0.8 0.6
Indiana................................. 1.1 1.0
Iowa.................................... 0.3 0.3
Kansas.................................. 0.6 0.8
Kentucky................................ 2.3 1.8
Louisiana............................... 11.4 10.6
Maine................................... 0.0 0.0
Maryland/Washington, DC................. 6.1 4.2
Massachusetts........................... 0.6 0.5
Michigan................................ 0.9 0.5
Minnesota............................... 0.1 0.2
Mississippi............................. 5.2 2.5
Missouri................................ 0.7 0.6
Nebraska................................ 0.2 0.2
New Hampshire........................... 0.1 0.1
New Jersey.............................. 16.8 15.8
New York................................ 0.4 22.7
North Carolina.......................... 1.7 2.0
North Dakota............................ 0.1 0.0
Ohio.................................... 2.8 2.6
Oklahoma................................ 2.1 2.7
Pennsylvania............................ 8.9 8.1
Rhode Island............................ 0.1 0.1
South Carolina.......................... 0.6 0.8
South Dakota............................ 0.0 0.0
Tennessee............................... 1.6 3.0
Texas................................... 1.6 0.6
Vermont................................. 0.0 0.1
Virginia................................ 4.2 4.5
West Virginia........................... 2.7 2.3
Wisconsin............................... 0.3 0.2
------------------------------------------------------------------------
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'').
---------------------------------------------------------------------------
\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 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 District of Columbia
are linked as significant contributors to the same downwind
nonattainment counties.
---------------------------------------------------------------------------
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
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Number of
Upwind State linkages
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
.......... Counties containing downwind 24-hour PM2.5 nonattainment sites (monitoring site ID)
----------------------------------------------------------------------------------------------------------------------------------------------------
Alabama........................ 8 East Baton Rouge, LA Brazoria, TX Harris, TX Harris, TX Harris, TX Harris, TX
(220330003) (480391004) (482010051) (482010055) (482010062) (482010066)
.......... Harris, TX Tarrant, TX
(482011039) (484391002)
Arkansas....................... 3 East Baton Rouge, LA Brazoria, TX Tarrant, TX
(220330003) (480391004) (484391002)
[[Page 45269]]
Connecticut.................... 1 Suffolk, NY
(361030009)
Delaware....................... 3 Suffolk, NY Suffolk, NY Philadelphia, PA
(361030002) (361030009) (421010024)
Florida........................ 2 Harris, TX Tarrant, TX
(482010062) (484391002)
Georgia........................ 7 Brazoria, TX Harris, TX Harris, TX Harris, TX Harris, TX Harris, TX
(480391004) (482010051) (482010055) (482010062) (482010066) (482011039)
.......... Tarrant, TX
(484391002)
Illinois....................... 2 Suffolk, NY Harris, TX
(361030009) (482010055)
Indiana........................ 3 Suffolk, NY Suffolk, NY Philadelphia, PA
(361030002) (361030009) (421010024)
Kentucky....................... 6 Suffolk, NY Philadelphia, PA Harris, TX Harris, TX Harris, TX Harris, TX
(361030002) (421010024) (482010051) (482010055) (482010062) (482011039)
Louisiana...................... 7 Brazoria, TX Harris, TX Harris, TX Harris, TX Harris, TX Harris, TX
(480391004) (482010051) (482010055) (482010062) (482010066) (482011039)
.......... Tarrant, TX
(484391002)
Maryland....................... 3 Suffolk, NY Suffolk, NY Philadelphia, PA
(361030002) (361030009) (421010024)
Michigan....................... 1 Suffolk, NY
(361030009)
Mississippi.................... 8 East Baton Rouge, LA Brazoria, TX Harris, TX Harris, TX Harris, TX Harris, TX
(220330003) (480391004) (482010051) (482010055) (482010062) (482010066)
.......... Harris, TX Tarrant, TX
(482011039) (484391002)
New Jersey..................... 3 Suffolk, NY Suffolk, NY Philadelphia, PA
(361030002) (361030009) (421010024)
North Carolina................. 3 Suffolk, NY Suffolk, NY Philadelphia, PA
(361030002) (361030009) (421010024)
Ohio........................... 3 Suffolk, NY Suffolk, NY Philadelphia, PA
(361030002) (361030009) (421010024)
Oklahoma....................... 1 Tarrant, TX
(484391002)
Pennsylvania................... 2 Suffolk, NY Suffolk, NY
(361030002) (361030009)
Tennessee...................... 7 Philadelphia, PA Brazoria, TX Harris, TX Harris, TX Harris, TX Harris, TX
(421010024) (480391004) (482010051) (482010055) (482010062) (482010066)
.......... Harris, TX
(482011039)
Texas.......................... 1 East Baton Rouge, LA
(220330003)
Virginia....................... 3 Suffolk, NY Suffolk, NY Philadelphia, PA
(361030002) (361030009) (421010024)
West Virginia.................. 3 Suffolk, NY Suffolk, NY Philadelphia, PA
(361030002) (361030009) (421010024)
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Table IV.C-21--Upwind State to Downwind Maintenance ``Linkages'' for 8-Hour Ozone
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Number of
Upwind State linkages
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
.......... Counties containing downwind 24-hour PM2.5 nonattainment sites (monitoring site ID)
----------------------------------------------------------------------------------------------------------------------------------------------------
Alabama........................ 6 DeKalb, GA Fulton, GA Harris, TX Harris, TX Harris, TX Tarrant, TX.
(130890002) (131210055) (482010024) (482010029) (482011050) (484392003).
Arkansas....................... 4 Dallas, TX Dallas, TX Harris, TX Tarrant, TX
(481130069) (481130087) (482011050) (484392003)
Connecticut.................... 1 Westchester, NY
(361192004)
Delaware....................... 1 Bucks, PA
(420170012)
Florida........................ 4 DeKalb, GA Fulton, GA Harris, TX Harris, TX
(130890002) (131210055) (482010024) (482010029)
Georgia........................ 4 Harris, TX Harris, TX Harris, TX Tarrant, TX
(482010024) (482010029) (482011050) (484392003)
Indiana........................ 4 Fairfield, CT New Haven, CT Westchester, NY Bucks, PA
(90010017) (90093002) (361192004) (420170012)
Kansas......................... 1 Dallas, TX
(481130069)
Kentucky....................... 6 Fairfield, CT Fairfield, CT Fairfield, CT New Haven, CT Westchester, NY Bucks, PA.
(90010017) (90011123) (90013007) (90093002) (361192004) (420170012).
[[Page 45270]]
Louisiana...................... 6 Dallas, TX Dallas, TX Harris, TX Harris, TX Harris, TX Tarrant, TX.
(481130069) (481130087) (482010024) (482010029) (482011050) (484392003).
Maryland....................... 6 Fairfield, CT Fairfield, CT Fairfield, CT New Haven, CT Westchester, NY Bucks, PA.
(90010017) (90011123) (90013007) (90093002) (361192004) (420170012).
Mississippi.................... 7 DeKalb, GA Fulton, GA Dallas, TX Harris, TX Harris, TX Harris, TX.
(130890002) (131210055) (481130087) (482010024) (482010029) (482011050).
.......... Tarrant, TX
(484392003)
New Jersey..................... 6 Fairfield, CT Fairfield, CT Fairfield, CT New Haven, CT Westchester, NY Bucks, PA.
(90010017) (90011123) (90013007) (90093002) (361192004) (420170012).
New York....................... 5 Fairfield, CT Fairfield, CT Fairfield, CT New Haven, CT Bucks, PA
(90010017) (90011123) (90013007) (90093002) (420170012)
North Carolina................. 5 Fairfield, CT Fairfield, CT New Haven, CT Westchester, NY Bucks, PA
(90011123) (90013007) (90093002) (361192004) (420170012)
Ohio........................... 6 Fairfield, CT Fairfield, CT Fairfield, CT New Haven, CT Westchester, NY Bucks, PA.
(90010017) (90011123) (90013007) (90093002) (361192004) (420170012).
Oklahoma....................... 3 Dallas, TX Dallas, TX Tarrant, TX
(481130069) (481130087) (484392003)
Pennsylvania................... 5 Fairfield, CT Fairfield, CT Fairfield, CT New Haven, CT Westchester, NY
(90010017) (90011123) (90013007) (90093002) (361192004)
South Carolina................. 2 Fulton, GA Harris, TX
(131210055) (482010029)
Tennessee...................... 5 DeKalb, GA Fulton, GA Bucks, PA Harris, TX Harris, TX
(130890002) (131210055) (420170012) (482010024) (482011050)
Virginia....................... 6 Fairfield, CT Fairfield, CT Fairfield, CT New Haven, CT Westchester, NY Bucks, PA.
(90010017) (90011123) (90013007) (90093002) (361192004) (420170012).
West Virginia.................. 6 Fairfield, CT Fairfield, CT Fairfield, CT New Haven, CT Westchester, NY Bucks, PA.
(90010017) (90011123) (90013007) (90093002) (361192004) (420170012).
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
D. Proposed Methodology To Quantify Emissions That Significantly
Contribute or Interfere With Maintenance
In this section, EPA explains its general approach to quantifying
the amount of emissions that represent significant contribution and
interference with maintenance. EPA then applies that approach for the
three different NAAQS being addressed in today's notice: The 1997 ozone
NAAQS, the 1997 annual PM2.5 NAAQS and the 2006 24-hour
PM2.5 NAAQS.
With respect to the 1997 ozone NAAQS, we apply this methodology to
fully quantify the significant contribution and interference with
maintenance for 16 states. We also use the methodology to quantify, for
10 additional states, NOX emissions reductions that are
necessary to make measurable progress towards eliminating their
significant contribution and interference with maintenance. Additional
information gathering and analysis is needed 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 ozone NAAQS. As is further explained in section IV.D.2.b EPA
will fully address this issue in a future rulemaking as quickly as
possible.
With respect to the annual PM2.5 NAAQS, this proposal
finds that 24 eastern states have SO2 and NOX
emission reduction responsibilities. We apply the proposed methodology
to fully quantify the SO2 and NOX emissions from
each of these states that significantly contribute to or interfere with
maintenance in downwind areas.
With respect to the 24-hour PM2.5 NAAQS, this proposal
finds that 25 eastern states have emission reduction responsibilities.
We use the proposed methodology to quantify emissions reductions that
these states must achieve to make, at a minimum, measurable progress
towards eliminating the state's significant contribution and
interference with maintenance. Further analysis will be needed to
determine if these reductions are sufficient to fully eliminate any or
all of these states' significant contribution and interference with
maintenance for purposes of the 24-hour PM2.5 standard. As
is explained in greater detail in section IV.D.2.a, EPA intends to
finalize, to the extent possible a determination of the complete amount
of emissions that represents significant contribution and interference
with maintenance. If further analysis shows that the amounts of
emissions proposed in today's notice include all emissions that
significantly contribute or interfere with maintenance of the 24-hour
PM2.5 standard or that more SO2 emissions should
be included, we believe that we will be able to issue a supplemental
proposal and finalize a rule fully 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
[[Page 45271]]
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-per-ton
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 change on one of the cost curves, such as a point where
a large reduction occurs because a certain type of emissions control
becomes cost-effective. 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. 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).
[[Page 45272]]
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 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.
---------------------------------------------------------------------------
\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.
---------------------------------------------------------------------------
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 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
re-examined 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 non-EGU 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
[[Page 45273]]
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 mid-2011,
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 post-combustion 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 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 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 time- and 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.
---------------------------------------------------------------------------
\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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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 multi-factor assessment to identify which cost
[[Page 45274]]
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.
---------------------------------------------------------------------------
\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.
---------------------------------------------------------------------------
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 multi-factor 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 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 short-term 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 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 state-by-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.
[[Page 45275]]
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
Marginal cost per ton level $500 $1,500 $2,500
----------------------------------------------------------------------------------------------------------------
Alabama..................................................... 119 62 62 50
Connecticut................................................. 8 8 8 8
Delaware.................................................... 6 6 6 6
Florida..................................................... 196 138 113 80
Georgia..................................................... 48 46 45 45
Illinois.................................................... 80 56 56 56
Indiana..................................................... 201 114 114 107
Iowa........................................................ 68 56 50 47
Kansas...................................................... 79 38 36 35
Kentucky.................................................... 149 72 72 71
Louisiana................................................... 46 37 37 28
Maryland.................................................... 36 36 36 36
Massachusetts............................................... 13 13 13 13
Michigan.................................................... 99 68 68 66
Minnesota................................................... 55 38 38 38
Missouri.................................................... 83 82 61 55
Nebraska.................................................... 53 34 28 28
New Jersey.................................................. 27 23 23 20
New York.................................................... 36 35 32 31
North Carolina.............................................. 63 63 62 61
Ohio........................................................ 165 104 98 88
Pennsylvania................................................ 205 123 122 86
South Carolina.............................................. 48 36 36 35
Tennessee................................................... 69 29 29 29
Virginia.................................................... 38 37 37 36
West Virginia............................................... 100 54 49 45
Wisconsin................................................... 55 44 43 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 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 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
[[Page 45276]]
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
Marginal cost per ton level $100 $200 $500 $1,000 $1,400 $1,800 $2,000 $2,400
--------------------------------------------------------------------------------------------------------------------------------------------------------
Alabama.............................................. 322 307 257 171 166 146 101 84 71
Connecticut.......................................... 6 6 6 6 6 3 3 3 3
Delaware............................................. 8 9 9 9 9 9 9 8 8
Florida.............................................. 195 178 171 117 113 111 79 74 70
Georgia.............................................. 173 166 136 133 117 101 92 86 67
Illinois............................................. 200 185 165 165 164 165 161 155 143
Indiana.............................................. 804 478 433 328 291 284 242 227 190
Iowa................................................. 164 140 130 106 105 104 102 101 70
Kansas............................................... 65 64 56 49 46 46 33 31 24
Kentucky............................................. 740 275 270 248 196 178 127 115 100
Louisiana............................................ 95 95 95 95 95 95 95 82 36
Maryland............................................. 45 45 45 45 45 45 42 42 40
Massachusetts........................................ 17 18 18 10 10 10 9 9 6
Michigan............................................. 276 254 253 214 209 207 177 163 116
Minnesota............................................ 62 57 55 49 48 48 48 48 46
Missouri............................................. 501 289 238 213 212 212 196 183 94
Nebraska............................................. 116 119 113 74 73 71 69 45 33
New Jersey........................................... 40 40 27 21 21 20 18 17 14
New York............................................. 143 142 143 135 118 114 100 70 63
North Carolina....................................... 141 141 141 130 114 104 99 91 63
Ohio................................................. 841 583 553 408 294 260 236 221 203
Pennsylvania......................................... 975 825 441 337 202 175 154 145 125
South Carolina....................................... 156 138 137 134 125 83 78 57 42
Tennessee............................................ 600 154 131 127 126 108 108 100 79
Virginia............................................. 137 134 134 109 106 93 65 54 45
West Virginia........................................ 496 179 170 161 160 143 132 119 98
Wisconsin............................................ 117 111 108 97 92 89 87 81 64
--------------------------------------------------------------------------------------------------
Total............................................ 7,436 5,133 4,435 3,692 3,263 3,025 2,660 2,410 1,912
--------------------------------------------------------------------------------------------------------------------------------------------------------
(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 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 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)
[[Page 45277]]
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 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 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).
[GRAPHIC] [TIFF OMITTED] TP02AU10.000
[[Page 45278]]
[GRAPHIC] [TIFF OMITTED] TP02AU10.001
[GRAPHIC] [TIFF OMITTED] TP02AU10.002
[[Page 45279]]
[GRAPHIC] [TIFF OMITTED] TP02AU10.003
[[Page 45280]]
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 2014
-------------------------------
Number of
Number of remaining
Marginal cost per ton remaining nonattainment
nonattainment and
monitor sites maintenance
monitor sites
------------------------------------------------------------------------
>$0..................................... 12 19
>$100................................... 3 6
>$200................................... 2 3
>$300................................... 2 3
>$400................................... 1 2
>$500................................... 1 2
>$600................................... 1 1
>$800................................... 1 1
>$1,000................................. 1 1
>$1,200................................. 1 1
>$1,400................................. 1 1
>$1,600................................. 1 1
>$1,800................................. 0 1
>$2,000................................. 0 1
>$2,400................................. 0 1
------------------------------------------------------------------------
Table IV.D-4--Daily Air Quality Impacts vs. SO2 Cost per Ton Levels in 2014
----------------------------------------------------------------------------------------------------------------
Air quality improvement (average
Number of [mu]g/m[caret]3 Reduction) relative
remaining to 2014 base case (zero dollars/ton)
Marginal SO2 cost per ton nonattainment --------------------------------------
and All sites
maintenance in 2012 6 selected 3 selected
monitor sites base sites * sites **
----------------------------------------------------------------------------------------------------------------
>$0....................................................... 64 0.0 0.0 0.0
>$100..................................................... 16 3.7 2.0 1.8
>$200..................................................... 12 4.4 2.4 2.1
>$300..................................................... 8 4.7 2.6 2.3
>$400..................................................... * 6 5.0 2.9 2.6
>$500..................................................... 6 5.1 3.0 2.6
>$600..................................................... 6 5.3 3.1 2.8
>$800..................................................... 6 5.4 3.3 2.9
>$1,000................................................... 6 5.6 3.4 3.0
>$1,200................................................... 6 5.7 3.4 3.0
>$1,400................................................... 6 5.8 3.5 3.1
>$1,600................................................... 5 6.0 3.6 3.2
>$1,800................................................... 4 6.2 3.7 3.3
>$2,000................................................... ** 3 6.4 3.9 3.4
>$2,400................................................... 1 6.8 4.1 3.7
----------------------------------------------------------------------------------------------------------------
* 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 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
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.
---------------------------------------------------------------------------
\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.
---------------------------------------------------------------------------
[[Page 45281]]
(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.
---------------------------------------------------------------------------
\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.
---------------------------------------------------------------------------
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 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 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 http://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,
[[Page 45282]]
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
----------------------------------------------------------------------------------------------------------------
States covered SO2 group 1 SO2 group 2 NOX annual
----------------------------------------------------------------------------------------------------------------
Alabama...................................................... ............... X X
Connecticut.................................................. ............... X X
Delaware..................................................... ............... X X
District of Columbia......................................... ............... X X
Florida...................................................... ............... X X
Georgia...................................................... X ............... X
Illinois..................................................... X ............... X
Indiana...................................................... X ............... X
Iowa......................................................... X ............... X
Kansas....................................................... ............... X X
Kentucky..................................................... X ............... X
Louisiana.................................................... ............... X X
Maryland..................................................... ............... X X
Massachusetts................................................ ............... X X
Michigan..................................................... X ............... X
Minnesota.................................................... ............... X X
Missouri..................................................... X ............... X
Nebraska..................................................... ............... X X
New Jersey................................................... ............... X X
New York..................................................... X ............... X
North Carolina............................................... X ............... X
Ohio......................................................... X ............... X
Pennsylvania................................................. X ............... X
South Carolina............................................... ............... X X
Tennessee.................................................... X ............... X
Virginia..................................................... X ............... X
West Virginia................................................ X ............... X
Wisconsin.................................................... X ............... X
--------------------------------------------------
Totals................................................... 15 13 28
----------------------------------------------------------------------------------------------------------------
[[Page 45283]]
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.
(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 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 24-hour 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 ``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
[[Page 45284]]
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.
---------------------------------------------------------------------------
\60\ While Colorado is also a state that may see projected
increases in emissions, it was not within the domain the EPA
analyzed.
Table IV.D-6--Unregulated States With More Than 5,000 Tons of Projected
SO2 Increases Under the Proposed Transport Rule
------------------------------------------------------------------------
2012 SO2 base
2012 SO2 case emissions
increase from from all
State base case sources
(thousand (thousand
tons) tons)
------------------------------------------------------------------------
Arkansas................................ 32 127
Mississippi............................. 18 80
North Dakota............................ 11 94
South Dakota............................ 6 26
Texas................................... 136 640
------------------------------------------------------------------------
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 [mu]g/m\3\ 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.
(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 non-attainment 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.
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
[[Page 45285]]
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.
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.
(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\
---------------------------------------------------------------------------
\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.
---------------------------------------------------------------------------
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
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.
---------------------------------------------------------------------------
\62\ In the case of PM2.5, under subpart I, areas can
qualify for an extension beyond 5 years, to as many as 10 years,
based on certain statutory criteria.
---------------------------------------------------------------------------
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,
[[Page 45286]]
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 add-on 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).
---------------------------------------------------------------------------
\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).
---------------------------------------------------------------------------
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
----------------------------------------------------------------------------------------------------------------
Alabama........................ 30 30 30 30 30 30 30 29 29
Arkansas....................... 21 11 11 11 11 11 11 11 11
Connecticut.................... 3 3 3 3 3 3 3 3 3
Delaware....................... 2 2 2 2 2 2 2 2 2
Florida........................ 101 74 60 59 59 59 59 58 57
Georgia........................ 35 33 33 33 33 33 33 33 33
Illinois....................... 24 24 25 25 25 25 25 25 25
Indiana........................ 51 50 49 48 47 47 47 46 46
Kansas......................... 31 15 15 15 14 14 14 14 14
Kentucky....................... 31 31 30 30 30 30 29 29 29
Louisiana...................... 22 17 17 17 17 17 17 17 17
Maryland....................... 14 14 14 14 14 14 14 14 14
Michigan....................... 30 30 30 30 30 30 29 28 28
Mississippi.................... 17 8 8 8 8 8 8 8 8
New Jersey..................... 7 7 7 7 7 7 7 7 7
New York....................... 16 16 16 16 16 16 16 16 16
North Carolina................. 27 27 27 27 27 27 27 27 27
Ohio........................... 42 41 41 41 41 42 42 42 42
Oklahoma....................... 43 27 27 27 27 26 26 26 26
Pennsylvania................... 51 51 51 51 50 50 50 50 48
South Carolina................. 16 16 16 15 15 15 15 15 15
Tennessee...................... 12 12 12 12 12 12 12 12 12
Texas.......................... 79 67 67 67 7 66 66 66 66
Virginia....................... 18 18 18 18 18 18 17 17 17
West Virginia.................. 24 24 23 23 22 23 22 22 18
--------------------------------------------------------------------------------
Total...................... 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 non-EGU
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
[[Page 45287]]
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........................ 27 27 27 27 27 27 27 26 26
Arkansas....................... 22 12 12 12 12 11 11 11 12
Connecticut.................... 3 3 3 3 3 3 3 3 3
Delaware....................... 2 3 3 3 3 3 3 3 3
Florida........................ 95 72 58 57 57 56 53 43 37
Georgia........................ 22 20 20 20 20 20 20 20 19
Illinois....................... 24 24 24 24 24 24 24 24 24
Indiana........................ 49 48 48 47 47 47 46 44 43
Kansas......................... 35 16 16 16 16 16 16 15 15
Kentucky....................... 30 30 30 29 29 29 29 29 28
Louisiana...................... 21 17 17 17 17 17 17 13 13
Maryland....................... 15 15 15 15 15 15 15 15 15
Michigan....................... 30 30 30 30 29 29 29 29 28
Mississippi.................... 17 8 8 8 8 8 8 8 7
New Jersey..................... 10 10 10 10 10 10 10 10 9
New York....................... 17 17 17 16 16 16 15 15 15
North Carolina................. 27 27 27 27 27 27 27 27 26
Ohio........................... 45 44 43 43 42 42 42 41 38
Oklahoma....................... 39 24 24 24 24 23 23 23 20
Pennsylvania................... 53 53 52 52 52 52 52 52 41
South Carolina................. 16 16 15 15 15 15 15 15 15
Tennessee...................... 12 12 12 12 12 12 12 12 12
Texas.......................... 80 69 68 68 67 66 66 66 66
Virginia....................... 16 16 16 16 16 16 16 16 15
West Virginia.................. 24 24 24 21 22 20 20 19 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
----------------------------------------------------------------------------------------------------------------
2012 2012 2014 2014
----------------------------------------------------------------------------------------------------------------
Number of
Number of Remaining Number of Remaining
Remaining Nonattainment Number of Remaining Nonattainment and
Marginal Cost per Ton Nonattainment and Nonattainment Monitor Maintenance Monitor
Monitor Sites Maintenance Sites sites
Monitor Sites
----------------------------------------------------------------------------------------------------------------
>$0............................... 11 25 4 (all in Houston, 7 (Houston, TX; Baton
TX). Rouge, LA).
>$500............................. 10 19 1.................... 7.
----------------------------------------------------------------------------------------------------------------
[[Page 45288]]
(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.
(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 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
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
[[Page 45289]]
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 year-to-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 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 highest-
emitting 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.
---------------------------------------------------------------------------
\64\ Identification and Discussion of Sources of Regional Point
Source NOX and SO2 emissions other than EGUs.
EPA/OAQPS and CAMD. January 2004.
---------------------------------------------------------------------------
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.
---------------------------------------------------------------------------
\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.
---------------------------------------------------------------------------
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: http://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\
---------------------------------------------------------------------------
\66\ U.S. EPA. Petroleum Refinery National Priority Case
Results. Available at http://www.epa.gov/compliance/resources/cases/civil/caa/oil/index.html.
---------------------------------------------------------------------------
For sulfuric acid manufacturing, the SO2 emissions are
related to the percent recovery of sulfuric acid product. Because the
percent recovery is plant-specific, 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.
---------------------------------------------------------------------------
\67\ U.S. EPA. Acid Plant NSR Enforcement Priority. Available at
http://www.epa.gov/compliance/civil/caa/acidplant-nsr/index.html.
---------------------------------------------------------------------------
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
[[Page 45290]]
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 on-road and nonroad engine measures to reduce mobile
source SO2 at or below $2,000/ton.
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 non-EGU 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--``Non-EGU 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.
---------------------------------------------------------------------------
\68\ Identification and Discussion of Sources of Regional Point
Source NOX and SO2 emissions other than EGUs.
EPA/OAQPS and CAMD. January 2004.
---------------------------------------------------------------------------
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 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.
---------------------------------------------------------------------------
\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 Mid-Atlantic Region. Final Report.
MARAMA, January 2007. p. 2-24.
\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.
---------------------------------------------------------------------------
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
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 fossil-fuel-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.
---------------------------------------------------------------------------
\73\ Even though allowance prices dropped significantly in 2008
after the Court decision, most sources appear to have continued with
the same reduction strategies.
---------------------------------------------------------------------------
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
[[Page 45291]]
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 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 SO2, 2014 and NOX annual,
State 2013 later all years
----------------------------------------------------------------------------------------------------------------
Alabama......................................................... 161,871 161,871 69,169
Connecticut..................................................... 3,059 3,059 2,775
Delaware........................................................ 7,784 7,784 6,206
District of Columbia............................................ 337 337 170
Florida......................................................... 161,739 161,739 120,001
Georgia......................................................... 233,260 85,717 73,801
Illinois........................................................ 208,957 151,530 56,040
Indiana......................................................... 400,378 201,412 115,687
Iowa............................................................ 94,052 86,088 46,068
Kansas.......................................................... 57,275 57,275 51,321
Kentucky........................................................ 219,549 113,844 74,117
Louisiana....................................................... 90,477 90,477 43,946
Maryland........................................................ 39,665 39,665 17,044
Massachusetts................................................... 7,902 7,902 5,960
Michigan........................................................ 251,337 155,675 64,932
Minnesota....................................................... 47,101 47,101 41,322
Missouri........................................................ 203,689 158,764 57,681
Nebraska........................................................ 71,598 71,598 43,228
New Jersey...................................................... 11,291 11,291 11,826
New York........................................................ 66,542 42,041 23,341
North Carolina.................................................. 111,485 81,859 51,800
Ohio............................................................ 464,964 178,307 97,313
Pennsylvania.................................................... 388,612 141,693 113,903
South Carolina.................................................. 116,483 116,483 33,882
Tennessee....................................................... 100,007 100,007 28,362
Virginia........................................................ 72,595 40,785 29,581
West Virginia................................................... 205,422 119,016 51,990
Wisconsin....................................................... 96,439 66,683 44,846
-----------------------------------------------
Total....................................................... 3,893,870 2,500,003 1,376,312
----------------------------------------------------------------------------------------------------------------
For more detail on how the budgets were developed, see the TSD:
``State Budgets, Unit Allocations, and Unit Emissions Rates''.
---------------------------------------------------------------------------
\74\ The impact of variability on the budgets is discussed in
section IV.F, later.
---------------------------------------------------------------------------
2. Defining Ozone Season NOX State Emissions Budgets for
EGUs
Ozone season NOX budgets were developed the same way as
the annual NOX budgets were developed (explained in IV.E.1,
previously).
Table IV.E-2--Ozone-season NOX State Emissions Budgets for Electric
Generating Units Before Accounting for Variability
[Tons]
------------------------------------------------------------------------
NOX ozone
State season, all
years
------------------------------------------------------------------------
Alabama.................................................... 29,738
Arkansas................................................... 16,660
Connecticut................................................ 1,315
Delaware................................................... 2,450
District of Columbia....................................... 105
Florida.................................................... 56,939
Georgia.................................................... 32,144
Illinois................................................... 23,570
Indiana.................................................... 49,987
Kansas..................................................... 21,433
Kentucky................................................... 30,908
Louisiana.................................................. 21,220
Maryland................................................... 7,232
Michigan................................................... 28,253
Mississippi................................................ 16,530
New Jersey................................................. 5,269
New York................................................... 11,090
North Carolina............................................. 23,539
Ohio....................................................... 40,661
Oklahoma................................................... 37,087
Pennsylvania............................................... 48,271
South Carolina............................................. 15,222
Tennessee.................................................. 11,575
Texas...................................................... 75,574
Virginia................................................... 12,608
West Virginia.............................................. 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
[[Page 45292]]
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
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 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 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 state-specific 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
[[Page 45293]]
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 two-tailed 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 7-year time period to yield a percentage variability value for each
state. See the Power Sector Variability TSD for details.
---------------------------------------------------------------------------
\75\ The two-tailed 95th percent confidence level is the
equivalent of the 97.5th upper (single-tailed) confidence level.
---------------------------------------------------------------------------
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 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 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
[[Page 45294]]
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.
---------------------------------------------------------------------------
\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.
---------------------------------------------------------------------------
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 Alternative
SO2 annual ---------------------------------------------------
State emissions 3-year 3-year
budget 1-year average 1-year average
limit limit limit limit
----------------------------------------------------------------------------------------------------------------
Alabama........................................ 161,871 16,187 9,346 16,187 9,346
Connecticut.................................... 3,059 1,700 981 857 495
Delaware....................................... 7,784 1,700 981 1,700 981
District of Columbia........................... 337 1,700 981 94 54
Florida........................................ 161,739 16,174 9,338 16,174 9,338
Georgia........................................ 85,717 8,572 4,949 8,572 4,949
Illinois....................................... 151,530 15,153 8,749 15,153 8,749
Indiana........................................ 201,412 20,141 11,629 20,141 11,629
Iowa........................................... 86,088 8,609 4,970 8,609 4,970
Kansas......................................... 57,275 5,728 3,307 5,728 3,307
Kentucky....................................... 113,844 11,384 6,573 11,384 6,573
Louisiana...................................... 90,477 9,048 5,224 9,048 5,224
Maryland....................................... 39,665 3,967 2,290 3,967 2,290
Massachusetts.................................. 7,902 1,700 981 1,700 981
Michigan....................................... 155,675 15,568 8,988 15,568 8,988
Minnesota...................................... 47,101 4,710 2,719 4,710 2,719
Missouri....................................... 158,764 15,876 9,166 15,876 9,166
Nebraska....................................... 71,598 7,160 4,134 7,160 4,134
New Jersey..................................... 11,291 1,700 981 1,700 981
New York....................................... 42,041 4,204 2,427 4,204 2,427
North Carolina................................. 81,859 8,186 4,726 8,186 4,726
Ohio........................................... 178,307 17,831 10,295 17,831 10,295
Pennsylvania................................... 141,693 14,169 8,181 14,169 8,181
South Carolina................................. 116,483 11,648 6,725 11,648 6,725
Tennessee...................................... 100,007 10,001 5,774 10,001 5,774
Virginia....................................... 40,785 4,079 2,355 4,079 2,355
West Virginia.................................. 119,016 11,902 6,871 11,902 6,871
Wisconsin...................................... 66,683 6,668 3,850 6,668 3,850
--------------
Total...................................... 2,500,003
----------------------------------------------------------------------------------------------------------------
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.
[[Page 45295]]
Table IV.F-2--Variability Limits on NOX Annual Emissions for 2014 and Later for Electric Generating Units
[Tons]
----------------------------------------------------------------------------------------------------------------
Proposed Alternative
---------------------------------------------------
State NOX annual 3-year 3-year
1-year average 1-year average
limit limit limit limit
----------------------------------------------------------------------------------------------------------------
Alabama........................................ 69,169 6,917 3,993 6,917 3,993
Connecticut.................................... 2,775 5,000 2,887 583 336
Delaware....................................... 6,206 5,000 2,887 1,303 752
District of Columbia........................... 170 5,000 2,887 36 21
Florida........................................ 120,001 12,000 6,928 12,000 6,928
Georgia........................................ 73,801 7,380 4,261 7,380 4,261
Illinois....................................... 56,040 5,604 3,235 5,604 3,235
Indiana........................................ 115,687 11,569 6,679 11,569 6,679
Iowa........................................... 46,068 5,000 2,887 5,000 2,887
Kansas......................................... 51,321 5,132 2,963 5,132 2,963
Kentucky....................................... 74,117 7,412 4,279 7,412 4,279
Louisiana...................................... 43,946 5,000 2,887 5,000 2,887
Maryland....................................... 17,044 5,000 2,887 3,579 2,066
Massachusetts.................................. 5,960 5,000 2,887 1,252 723
Michigan....................................... 64,932 6,493 3,749 6,493 3,749
Minnesota...................................... 41,322 5,000 2,887 5,000 2,887
Missouri....................................... 57,681 5,768 3,330 5,768 3,330
Nebraska....................................... 43,228 5,000 2,887 5,000 2,887
New Jersey..................................... 11,826 5,000 2,887 2,483 1,434
New York....................................... 23,341 5,000 2,887 4,902 2,830
North Carolina................................. 51,800 5,180 2,991 5,180 2,991
Ohio........................................... 97,313 9,731 5,618 9,731 5,618
Pennsylvania................................... 113,903 11,390 6,576 11,390 6,576
South Carolina................................. 33,882 5,000 2,887 5,000 2,887
Tennessee...................................... 28,362 5,000 2,887 5,000 2,887
Virginia....................................... 29,581 5,000 2,887 5,000 2,887
West Virginia.................................. 51,990 5,199 3,002 5,199 3,002
Wisconsin...................................... 44,846 5,000 2,887 5,000 2,887
-------------
Total...................................... 1,376,312
----------------------------------------------------------------------------------------------------------------
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 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 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.
[[Page 45296]]
Table IV.F-3--Variability Limits on NOX Ozone Emissions for 2014 and Later for Electric Generating Units
[Tons]
----------------------------------------------------------------------------------------------------------------
Proposed Alternative
NOX ozone ---------------------------------------------------
State season 3-year 3-year
emissions 1-year average 1-year average
budget limit limit limit limit
----------------------------------------------------------------------------------------------------------------
Alabama........................................ 29,738 2,974 1,717 2,974 1,717
Arkansas....................................... 16,660 2,100 1,212 2,100 1,212
Connecticut.................................... 1,315 2,100 1,212 355 205
Delaware....................................... 2,450 2,100 1,212 662 382
District of Columbia........................... 105 2,100 1,212 28 16
Florida........................................ 56,939 5,694 3,287 5,694 3,287
Georgia........................................ 32,144 3,214 1,856 3,214 1,856
Illinois....................................... 23,570 2,357 1,361 2,357 1,361
Indiana........................................ 49,987 4,999 2,886 4,999 2,886
Kansas......................................... 21,433 2,143 1,237 2,143 1,237
Kentucky....................................... 30,908 3,091 1,784 3,091 1,784
Louisiana...................................... 21,220 2,122 1,225 2,122 1,225
Maryland....................................... 7,232 2,100 1,212 1,953 1,127
Michigan....................................... 28,253 2,825 1,631 2,825 1,631
Mississippi.................................... 16,530 2,100 1,212 2,100 1,212
New Jersey..................................... 5,269 2,100 1,212 1,423 821
New York....................................... 11,090 2,100 1,212 2,100 1,212
North Carolina................................. 23,539 2,354 1,359 2,354 1,359
Ohio........................................... 40,661 4,066 2,348 4,066 2,348
Oklahoma....................................... 37,087 3,709 2,141 3,709 2,141
Pennsylvania................................... 48,271 4,827 2,787 4,827 2,787
South Carolina................................. 15,222 2,100 1,212 2,100 1,212
Tennessee...................................... 11,575 2,100 1,212 2,100 1,212
Texas.......................................... 75,574 7,557 4,363 7,557 4,363
Virginia....................................... 12,608 2,100 1,212 2,100 1,212
West Virginia.................................. 22,234 2,223 1,284 2,223 1,284
--------------
Total...................................... 641,614
----------------------------------------------------------------------------------------------------------------
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.
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.
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 two-year 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
[[Page 45297]]
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 Two-year
State emissions 1-year average
budget limit limit
------------------------------------------------------------------------
Georgia.......................... 233,260 23,326 16,494
Illinois......................... 208,957 20,896 14,775
Indiana.......................... 400,378 40,038 28,311
Iowa............................. 94,052 9,405 6,650
Kentucky......................... 219,549 21,955 15,524
Michigan......................... 251,337 25,134 17,772
Missouri......................... 203,689 20,369 14,403
New York......................... 66,542 6,654 4,705
North Carolina................... 111,485 11,149 7,883
Ohio............................. 464,964 46,496 32,878
Pennsylvania..................... 388,612 38,861 27,479
Tennessee........................ 100,007 10,001 7,072
Virginia......................... 72,595 7,260 5,133
West Virginia.................... 205,422 20,542 14,526
Wisconsin........................ 96,439 9,644 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 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
----------------------------------------------------------------------------------------------------------------
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]
----------------------------------------------------------------------------------------------------------------
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
[[Page 45298]]
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
----------------------------------------------------------------------------------------------------------------
Note: Emissions differ from emissions budgets due to banking.
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 state-specific data
to analyze each individual state's significant contribution, uses air
quality considerations in addition to cost considerations to identify
each state's significant contribution, and gives independent meaning to
the ``interference with maintenance'' prong. This methodology is then
applied in a reasonable manner consistent with the relevant judicial
opinions.
In North Carolina, the Court held that EPA's approach to evaluating
significant contribution was inadequate because, by evaluating only
whether 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. 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-by-state 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 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
[[Page 45299]]
``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 impact (e.g., $ per [mu]g/m\3\), 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.
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\
---------------------------------------------------------------------------
\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.
---------------------------------------------------------------------------
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 man-made
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\
---------------------------------------------------------------------------
\78\ Emissions estimates are based on the 2012 baseline
projections described in section IV in this preamble.
---------------------------------------------------------------------------
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 multi-pollutant scenarios in July
2009 at the request of Senator Tom Carper. These analyses are on EPA's
Web site at: (http://www.epagov/airmarkets/progsregs/cair/multi.html).
EPA's IPM analysis for CAIR is another example: (http://www.epagov/airmarkets/progsregs/epa-ipm/cair/index.html).
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
[[Page 45300]]
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\
---------------------------------------------------------------------------
\79\ See section IV.D.3 for discussion of non-EGUs that were
included in the CAIR NOX ozone season trading program.
---------------------------------------------------------------------------
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 non-EGU 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.
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.
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\
---------------------------------------------------------------------------
\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.
---------------------------------------------------------------------------
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).
[[Page 45301]]
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.
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.
4. How Compliance Deadlines Address the Court's Concern About Timing
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 practicable
and within the applicable maximum deadlines.
5. EPA Will Consider Additional Reductions in Pollution Transport To
Assist in Meeting Any Revised or New NAAQS
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\
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\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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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
[[Page 45302]]
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.
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
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
cost-effective 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 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
[[Page 45303]]
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 cost-effective 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 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 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
[[Page 45304]]
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
http://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 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.
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\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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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 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
[[Page 45305]]
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\
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\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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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 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 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. State-specific 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
[[Page 45306]]
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.
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\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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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 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 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 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
[[Page 45307]]
the efficiency and operating standards every year starting with the
first 12-months 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 topping-cycle 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, 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 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
[[Page 45308]]
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
opt-in 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
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 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 opt-in 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 opt-in 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
[[Page 45309]]
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 opt-in 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-than-25 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 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.
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.
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\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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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
[[Page 45310]]
Rule cap and trade programs commence (see discussion of schedule,
later). The allocations generally would be permanent (with the
exception of non-operating 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.
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\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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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 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.
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 set-aside 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 set-asides 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 set-asides.
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 non-operation 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
[[Page 45311]]
immediately discontinuing allocations to such units upon the unit
ceasing operation.
Continuing allocations to non-operating 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 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 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).
[[Page 45312]]
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).
(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
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 180-day 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 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
[[Page 45313]]
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 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 3-year 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 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 (Sec. Sec. 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).
[[Page 45314]]
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 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 allowance-holding 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) 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\
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\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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Consequently, EPA believes that there is a high level of certainty
that emissions reductions projected for
[[Page 45315]]
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).
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.
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.
[cir] An emissions cap is established and the programs are phased
in, with increasing stringency to lower emissions.
Allowance allocation.
[cir] Authorizations to emit, i.e., allowances, are allocated to
affected sources and are limited by each state's trading budget.
Allowance trading.
[cir] Markets enable sources to trade allowances.
Flexible compliance.
[cir] 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.
[cir] 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.
[cir] There are automatic penalties and potentially discretionary
civil penalties for program noncompliance.
Stringent monitoring and reporting.
[cir] Sources must use approved monitoring methods under EPA's
stringent monitoring requirements (40 CFR part 75) to monitor and
report emissions.
Data transparency.
[cir] 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 paragraphs, specific results from the programs are
described. These results are documented in program progress reports
that are available on EPA's Web site (http://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 coal-fired 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 http://www.epagov/airmarkets/progress/ARP_4.html.
[[Page 45316]]
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\
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\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.
---------------------------------------------------------------------------
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.
---------------------------------------------------------------------------
\89\ G[eacute]go, 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.
---------------------------------------------------------------------------
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.
See EPA's docket for this rule for more details on the results of
the NOX Budget Trading Program, or see http://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 http://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 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.
---------------------------------------------------------------------------
\92\ Ellerman, A. Denny. 2004. ``The U.S. SO2 Cap-
and-Trade Programme,'' Tradeable Permits: Policy Evaluation, Design
and Reform, chapter 3, pp. 71-97, OECD.
\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, ICAP-United, 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.
---------------------------------------------------------------------------
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.''
---------------------------------------------------------------------------
\95\ Tietenberg, T.H. 2006. Emissions Trading Principles and
Practice. Washington, DC. Published by Resources for the Future.
---------------------------------------------------------------------------
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\
---------------------------------------------------------------------------
\96\ Ibid., p. 41.
\97\ Ibid., p. 73.
\98\ Ibid., pp. 70-71.
---------------------------------------------------------------------------
Tietenberg contrasts EPA's earlier credit-based trading programs in
the
[[Page 45317]]
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-of-the-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 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.
---------------------------------------------------------------------------
\99\ Memo from ICF International to EPA Clean air Markets
Division, September 17, 2008. Transaction Costs in Allowance Trading
Markets.
\100\ Ibid.
---------------------------------------------------------------------------
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
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
[[Page 45318]]
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.
---------------------------------------------------------------------------
\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.
---------------------------------------------------------------------------
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 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 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),
[[Page 45319]]
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 cost-effective 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 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-
with-limitations 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.
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
[[Page 45320]]
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
(i) Sec. Sec. 97.402 and 97.403, 97.502 and 97.503, 97.602 and 97.603,
and 97.702 and 97.703--Definitions and Abbreviations
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 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) Sec. Sec. 97.404 and 97.405, 97.504 and 97.505, 97.604 and
97.605, and 97.704 and 97.705--Applicability and Retired Units
The applicability provisions 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 reporting requirements and allowance-holding
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 permit-related 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) Sec. Sec. 97.406, 97.506, 97.606, and 97.706--Standard
Requirements
The basic requirements applicable to owners and operators of units
and sources covered by the 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
[[Page 45321]]
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 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.
(iv) Sec. Sec. 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 EPA-administered trading programs.
(v) Sec. Sec. 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 Sec. 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 Sec. 72.2, added in Sec. 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 Sec. 78.2. In particular, the revised ``interested
person'' definition would include, with regard to a decision 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, Sec. 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, Sec. 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.
(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,
[[Page 45322]]
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 unit-by-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 set-aside. 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 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 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
[[Page 45323]]
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) Sec. Sec. 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 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) Sec. Sec. 97.421 Through 97.423, 97.521 Through 97.523, 97.621
Through 97.623, and 97.721 Through 97.723--Recordation of Allowance
Allocations and Transfers
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 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) Sec. Sec. 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 first-in, 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
[[Page 45324]]
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) Sec. Sec. 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 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 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.
[[Page 45325]]
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) Sec. Sec. 97.426 Through 97.428, 97.526 Through 97.528, 97.626
Through 97.628, and 97.726 Through 97.728--Miscellaneous Provisions
These sections 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 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 Sec. Sec. 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
EPA-administered trading programs, e.g., the ARP and NOX
Budget and CAIR trading programs.
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
[[Page 45326]]
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 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 state-specific 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 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
[[Page 45327]]
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 fossil-fuel 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
non-operating units above for State Budgets/Limited Trading in section
V.D.4 would remain the same for this option.
(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-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 fossil-fuel 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
[[Page 45328]]
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 fossil-fuel 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.
(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
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.
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.
[[Page 45329]]
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.
(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
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 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 over-allocated, 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\
---------------------------------------------------------------------------
\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.
---------------------------------------------------------------------------
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.
---------------------------------------------------------------------------
\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.
---------------------------------------------------------------------------
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.
[[Page 45330]]
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.
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 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 cap-and-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-the-state rate limits.
Company-level average rates would be calculated as company-level total
emissions divided by company-level total heat input in each state.
Analogously, allowable company-level 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 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.
[[Page 45331]]
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 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
broadly-defined 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 (``lowest-common-
denominator'' effect), or, design more stringent requirements but
include provisions for exceptions to the requirements. At this time,
EPA believes using IPM projections and source-specific 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 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
[[Page 45332]]
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 3-year
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 2-year
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 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 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 (inflation-adjusted 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-the-state 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).
[[Page 45333]]
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
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 rate-based 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 2014 2020 2025
------------------------------------------------------------------------
Limited Interstate Trading (proposed)... 3.7 2.8 2.0 2.0
Intrastate Trading...................... 4.2 2.7 2.2 2.2
Direct Control.......................... 4.3 3.4 2.5 2.3
------------------------------------------------------------------------
[[Page 45334]]
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 state-specific 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 2012 transport 2012 emissions 2014 base case 2014 transport 2014 emissions
emissions rule emissions reductions emissions rule 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
--------------------------------------------------------------------------------------------------------------------------------------------------------
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 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 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 2012 transport 2012 emissions 2014 base case 2014 transport 2014 emissions
emissions rule emissions reductions emissions rule emissions reductions
--------------------------------------------------------------------------------------------------------------------------------------------------------
SO2......................................... 8.4 3.2 5.2 7.2 2.7 4.5
Annual NOX.................................. 2.0 1.3 0.7 2.0 1.2 0.8
Ozone Season NOX............................ 0.7 0.6 0.1 0.7 0.6 0.1
--------------------------------------------------------------------------------------------------------------------------------------------------------
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 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 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 2012 transport 2012 emissions 2014 base case 2014 transport 2014 emissions
emissions rule emissions reductions emissions rule emissions reductions
--------------------------------------------------------------------------------------------------------------------------------------------------------
SO2......................................... 8.4 3.8 4.6 7.2 2.6 4.6
Annual NOX.................................. 2.0 1.3 0.7 2.0 1.2 0.8
Ozone Season NOX............................ 0.7 0.6 0.1 0.7 0.6 0.1
--------------------------------------------------------------------------------------------------------------------------------------------------------
[[Page 45335]]
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.
---------------------------------------------------------------------------
\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 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 emissions limits in DC would have little to no effect on
the modeling results.
Table V.E-5--Projected State-level \105\ SO2 Emissions From Electric Generating Units in 2014
[Tons]
----------------------------------------------------------------------------------------------------------------
State budgets/
Base case State budgets/ intrastate Direct control
limited trading trading
----------------------------------------------------------------------------------------------------------------
Alabama................................. 322,362 172,430 162,103 172,430
Connecticut............................. 6,160 3,234 3,208 3,208
Delaware................................ 8,079 9,185 8,974 9,110
District of Columbia.................... 176 179 180 180
Florida................................. 194,723 139,805 159,120 135,366
Georgia................................. 173,257 92,375 89,706 92,375
Illinois................................ 200,484 164,741 156,049 163,902
Indiana................................. 804,425 240,730 267,564 239,852
Iowa.................................... 163,966 102,419 102,096 106,569
Kansas.................................. 65,125 51,248 52,501 53,275
Kentucky................................ 739,595 123,837 128,318 123,833
Louisiana............................... 94,866 94,933 92,647 96,390
Maryland................................ 45,294 45,449 45,304 45,752
Massachusetts........................... 17,265 10,306 8,595 8,909
Michigan................................ 275,961 173,828 188,796 172,986
Minnesota............................... 62,033 49,413 49,836 58,925
Missouri................................ 500,649 192,645 190,815 190,532
Nebraska................................ 115,695 75,095 73,219 75,061
New Jersey.............................. 39,721 16,562 14,935 16,569
New York................................ 142,762 58,455 53,373 58,455
North Carolina.......................... 140,924 97,262 109,385 97,262
Ohio.................................... 841,199 232,964 269,547 228,514
Pennsylvania............................ 974,644 154,852 183,276 154,855
South Carolina.......................... 156,200 131,232 123,525 131,232
Tennessee............................... 600,071 106,767 100,012 94,078
Virginia................................ 136,573 58,329 51,633 58,330
West Virginia........................... 496,307 127,646 147,580 127,646
Wisconsin............................... 117,397 85,933 87,328 83,709
----------------------------------------------------------------------------------------------------------------
Table V.E-6--Projected State-Level Annual NOX Emissions From Electric Generating Units in 2014
[Tons]
----------------------------------------------------------------------------------------------------------------
State budgets/
Base case State budgets/ intrastate Direct control
limited trading trading
----------------------------------------------------------------------------------------------------------------
Alabama................................. 118,955 61,793 61,618 61,865
Connecticut............................. 7,991 8,003 7,986 8,004
Delaware................................ 5,790 6,176 6,126 6,074
District of Columbia.................... 933 946 948 948
Florida................................. 196,373 126,155 126,065 94,646
Georgia................................. 48,267 44,461 44,462 44,611
Illinois................................ 80,451 57,589 54,773 57,949
Indiana................................. 201,027 112,502 112,721 108,675
Iowa.................................... 68,259 53,072 50,146 52,069
Kansas.................................. 79,018 40,020 40,074 39,558
Kentucky................................ 148,551 71,371 71,692 69,882
Louisiana............................... 45,551 37,255 36,594 37,164
Maryland................................ 36,089 36,326 33,778 36,532
Massachusetts........................... 12,650 13,047 12,219 13,064
Michigan................................ 98,941 65,066 65,973 67,525
Minnesota............................... 55,283 38,969 39,114 38,039
Missouri................................ 83,019 67,475 61,679 67,648
Nebraska................................ 53,029 35,101 34,105 35,457
New Jersey.............................. 27,127 23,377 23,358 23,338
New York................................ 36,352 36,592 34,538 36,597
North Carolina.......................... 62,608 60,516 54,639 60,517
Ohio.................................... 164,947 99,358 95,997 100,886
Pennsylvania............................ 204,950 123,629 123,095 123,409
[[Page 45336]]
South Carolina.......................... 47,742 34,735 33,781 34,616
Tennessee............................... 68,914 28,212 26,874 28,873
Virginia................................ 37,485 35,805 35,745 37,004
West Virginia........................... 100,095 48,180 48,987 50,555
Wisconsin............................... 54,515 41,875 42,498 42,450
----------------------------------------------------------------------------------------------------------------
Table V.E-7--Projected State-Level Ozone-Season NOX Emissions From Electric Generating Units in 2014
[Tons]
----------------------------------------------------------------------------------------------------------------
State budgets/
Base case State budgets/ intrastate Direct control
limited trading trading
----------------------------------------------------------------------------------------------------------------
Alabama................................. 26,995 26,727 26,552 26,823
Arkansas................................ 21,667 12,080 12,095 12,077
Connecticut............................. 3,446 3,453 3,446 3,446
Delaware................................ 2,367 2,669 2,671 2,613
District of Columbia.................... 391 397 397 398
Florida................................. 94,686 62,221 62,037 48,170
Georgia................................. 21,947 19,686 19,688 19,749
Illinois................................ 24,167 24,930 22,833 24,701
Indiana................................. 49,023 47,477 47,813 45,589
Kansas.................................. 34,537 17,470 17,590 17,282
Kentucky................................ 29,927 29,376 29,671 29,107
Louisiana............................... 21,443 17,388 17,106 17,308
Maryland................................ 15,307 15,454 14,275 15,512
Michigan................................ 29,934 27,778 28,052 29,415
Mississippi............................. 16,955 8,524 8,526 8,522
New Jersey.............................. 10,470 10,324 10,295 10,260
New York................................ 17,257 17,493 16,518 17,491
North Carolina.......................... 27,018 26,117 23,459 26,004
Ohio.................................... 44,753 41,141 40,051 42,789
Oklahoma................................ 38,546 24,471 24,471 24,426
Pennsylvania............................ 53,263 53,102 52,692 52,586
South Carolina.......................... 15,730 14,818 14,666 14,753
Tennessee............................... 12,021 11,868 10,955 12,007
Texas................................... 79,572 68,769 68,874 67,832
Virginia................................ 16,264 15,397 15,289 16,093
West Virginia........................... 24,339 20,249 21,466 21,500
----------------------------------------------------------------------------------------------------------------
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.
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 of the CAIR, Sec. Sec. 51.123
and 51.124, and the CAIR FIPs, Sec. Sec. 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 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
[[Page 45337]]
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 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 previously-described, proposed revisions to
Sec. Sec. 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 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, one-on-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
state-specific 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 Sec. Sec. 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
[[Page 45338]]
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.
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
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 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 http://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
[[Page 45339]]
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 pre-2012 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
pre-2012 CAIR NOX allowances in the Transport Rule
NOX programs. The first 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 maintenance that EPA has
identified. However, this approach would not be feasible because EPA
cannot determine in advance in which states banked pre-2012 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
pre-2012 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 pre-2012 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 year-round 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.
[[Page 45340]]
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 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. 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
[[Page 45341]]
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.
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
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 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
[[Page 45342]]
and/or had an approved SIP stating that compliance with the CAIR
satisfied their 110(a)(2)(D)(i) obligations.
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\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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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 8-hour 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.
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 24-hour PM2.5 NAAQS, and
the 1997 ozone NAAQS. In CAIR, EPA allowed the states to replace the
CAIR FIP with SIPs and provided substantial flexibility. 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, 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 24-hour
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 24-hour 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'')).
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\107\ Part 70 governs approved state Title V programs, and part
71 governs the federal Title V program.
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EPA anticipates that, given the nature of the units covered by the
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.
[[Page 45343]]
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 (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 Sec. 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 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.
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\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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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: http://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
[[Page 45344]]
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.
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 co-benefits 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.
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\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.
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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 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.
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.
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\110\ As described in the AQMTSD, the eastern U.S. was modeled
at a horizontal resolution of 12 x 12 km. The remainder of the U.S.
was modeled at a resolution of 36 x 36 km.
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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
[[Page 45345]]
between 2012 and the 2014 remedy are provided in Table IX-2.
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\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.
Table IX-1--Projected Reduction in Nonattainment and/or Maintenance Problems for PM2.5 and Ozone in the Eastern U.S.
--------------------------------------------------------------------------------------------------------------------------------------------------------
Percent Percent
reduction: reduction:
Ambient (2003- 2014 proposed 2012 base case 2014 base case
2007) 2012 base case 2014 base case remedy vs. 2014 vs. 2014
remedy remedy
(percent) (percent)
--------------------------------------------------------------------------------------------------------------------------------------------------------
Annual PM2.5 Nonattainment Sites \112\.................. 102 32 15 1 97 93
Annual PM2.5 Maintenance-Only Sites..................... 21 16 7 1 94 86
Daily PM2.5 Nonattainment Sites......................... 151 92 54 17 82 69
Daily PM2.5 Maintenance-Only Sites...................... 48 38 28 11 71 61
Ozone Nonattainment Sites............................... 103 11 7 7 36 0
Ozone Maintenance-Only Sites............................ 67 16 6 5 69 17
--------------------------------------------------------------------------------------------------------------------------------------------------------
---------------------------------------------------------------------------
\112\ ``Nonattainment'' is used to denote sites that are
projected to have both nonattainment and maintenance problems.
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: Peak reduction:
2012 base case to 2012 base case to
2014 remedy 2014 remedy
------------------------------------------------------------------------
Annual PM2.5 Nonattainment Sites 2.8 [mu]g/m\3\.... 3.9 [mu]g/m\3\
Annual PM2.5 Maintenance-Only 2.6 [mu]g/m\3\.... 4.2 [mu]g/m\3\
Sites.
Daily PM2.5 Nonattainment Sites. 5.8 [mu]g/m\3\.... 15.3 [mu]g/m\3\
Daily PM2.5 Maintenance-Only 5.1 [mu]g/m\3\.... 13.5 [mu]g/m\3\
Sites.
Ozone Nonattainment Sites....... 1.9 ppb........... 3.9 ppb
Ozone Maintenance-Only Sites.... 2.3 ppb........... 4.2 ppb
------------------------------------------------------------------------
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
[mu]g/m\3\ and the peak reduction at an individual nonattainment site
is 3.2 [mu]g/m\3\. 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 [mu]g/m\3\ and the peak reduction at an
individual nonattainment site is 15.3 [mu]g/m\3\. Comparable reductions
are projected at 24-hour PM2.5 maintenance-only 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 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.
[[Page 45346]]
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\
---------------------------------------------------------------------------
\113\ Pope et al., 2002. ``Lung Cancer, Cardiopulmonary
Mortality, and Long-term Exposure to Fine Particulate Air
Pollution.'' Journal of the American Medical Association. 287:1132-
1141.
\114\ Laden et al., 2006. ``Reduction in Fine Particulate Air
Pollution and Mortality.'' American Journal of Respiratory and
Critical Care Medicine. 173:667-672.
---------------------------------------------------------------------------
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 PM-related
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 short-term 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).......... 14,000 (4,000-25,000)
Laden et al. (2006) (age >25)......... 36,000 (17,000-56,000)
Infant (< 1 year)..................... 59 (-66-180)
Chronic Bronchitis.................... 9,200 (320-18,000)
Non-fatal heart attacks (age > 18).... 22,000 (5,800-39,000)
Hospital admissions--respiratory (all 3,500 (1,400-5,500)
ages)................................
Hospital admissions--cardiovascular 7,500 (5,200-8,900)
(age > 18)...........................
Emergency room visits for asthma (age 14,000 (7,200-21,000)
< 18)................................
Acute bronchitis (age 8-12)........... 21,000 (-4,800-46,000)
Lower respiratory symptoms (age 7-14). 250,000 (98,000-400,000)
Upper respiratory symptoms (asthmatics 190,000 (36,000-350,000)
age 9-18)............................
Asthma exacerbation (asthmatics 6-18). 240,000 (8,300-800,000)
Lost work days (ages 18-65)........... 1,800,000 (1,500,000-
2,000,000)
Minor restricted-activity days (ages 10,000,000 (8,600,000-
18-65)............................... 12,000,000)
Ozone-related endpoints
Premature mortality
Bell et al. (2004) (all ages)......... 50 (17-84)
Levy et al. (2005) (all ages)......... 230 (160-300)
Hospital admissions--respiratory 390 (-18-740)
causes (ages > 65)...................
Hospital admissions--respiratory 300 (130-460)
causes (ages < 2)....................
Emergency room visits for asthma (all 230 (-30-730)
ages)................................
Minor restricted-activity days (ages 300,000 (130,000-480,000)
18-65)...............................
[[Page 45347]]
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............................... PM2.5 & O3....................... $110 ($8.8-$340)
7% discount rate............................... PM2.5 & O3....................... $100 ($7.9-$300)
----------------------------------------------------------------------------------------------------------------
Premature mortality (Laden et al. 2006 PM mortality and Levy et al. 2005 ozone mortality estimates)
----------------------------------------------------------------------------------------------------------------
3% discount rate............................... PM2.5 & O3....................... $280 ($25-$820)
7% discount rate............................... PM2.5 & O3....................... $260 ($22-$310)
Chronic bronchitis............................. PM2.5............................ $4.3 $0.2-$20)
Non-fatal heart attacks........................
3% discount rate............................... PM2.5............................ $2.5 ($0.4-$6)
7% discount rate............................... PM2.5............................ $2.4 ($0.4-$5.9)
Hospital admissions--respiratory............... PM2.5 & O3....................... $0.06 ($0.03-$0.1)
Hospital admissions--cardiovascular............ PM2.5............................ $0.2 ($0.1-$0.3)
Emergency room visits for asthma............... PM2.5 & O3....................... $0.005 ($0.002-$0.008)
Acute bronchitis............................... PM2.5............................ $0.009 (-$0.0004-$0.03)
Lower respiratory symptoms..................... PM2.5............................ $0.005 ($0.002-$0.009)
Upper respiratory symptoms..................... PM2.5............................ $0.006 ($0.001-$0.014)
Asthma exacerbation............................ PM2.5............................ $0.012 ($0.001-$0.046)
Lost work days................................. PM2.5............................ $0.2 ($0.19-$0.24)
School loss days............................... ................................. $0.01 ($0.004-$0.013)
Minor restricted-activity days................. PM2.5 & O3....................... $0.64 ($0.34-$0.97)
Recreational visibility, Class I areas......... PM2.5............................ $3.6
----------------------------------------------------------------------------------------------------------------
Total benefits based on Pope et al. 2002 PM mortality and Bell et al. 2004 ozone mortality estimates
----------------------------------------------------------------------------------------------------------------
3% discount rate............................... PM2.5 & O3....................... $120 ($10-$360)
7% discount rate............................... PM2.5 & O3....................... $110 ($9-$330)
----------------------------------------------------------------------------------------------------------------
Total benefits based on Laden et al. 2006 PM mortality and Levy et al. 2005 ozone mortality estimates
----------------------------------------------------------------------------------------------------------------
3% discount rate............................... PM2.5 & O3....................... $290 ($26-$840)
7% discount rate............................... PM2.5 & O3....................... $270 ($24-$760)
----------------------------------------------------------------------------------------------------------------
\A\ Estimates rounded to two significant figures.
[[Page 45348]]
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
------------------------------------------------------------------------
Social costs:
3 percent discount rate...... $2.0.
7 percent discount rate...... $2.2.
Social benefits:
3 percent discount rate...... $122 to 294 + B.
7 percent discount rate...... $111 to 266 + B.
Health-related benefits:
3 percent discount rate...... $118 to 290.
7 percent discount rate...... $107 to 262.
Visibility benefits:
3 percent discount rate...... $3.6.
7 percent discount rate...... $3.6.
Annual net benefits (benefits-
costs)
3 percent discount rate...... $120 to 292.
7 percent discount rate...... $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 NOX and SO2 in the Transport Rule region.
\c\ As this table indicates, total benefits are driven primarily by
PM2.5-related health benefits. The reduction in premature fatalities
each year accounts 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.
[[Page 45349]]
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.
---------------------------------------------------------------------------
\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.
---------------------------------------------------------------------------
As Table IX-4 indicates, total benefits are driven primarily by the
reduction in premature mortalities each year. Some key assumptions
underlying the primary estimate for the premature mortality category
include the following:
(1) EPA assumes inhalation of fine particles is causally associated
with premature death at concentrations near those experienced by most
Americans on a 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 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
[[Page 45350]]
concentrations. Biological effects of episodes include reduced fish
condition factor, changes in species composition and declines in
aquatic species richness across multiple taxa, ecosystems and regions,
as well as fish mortality. Waters that are sensitive to acidification
tend to be located in small watersheds that have few alkaline minerals
and shallow soils. Conversely, watersheds that contain alkaline
minerals, such as limestone, tend to have waters with a high ANC. Areas
especially sensitive to acidification include portions of the Northeast
(particularly, the Adirondack and Catskill Mountains, portions of New
England, and streams in the mid-Appalachian highlands) and southeastern
streams. This regulatory action will decrease acid deposition 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).
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 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 regional-scale 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
[[Page 45351]]
ozone, scientists have developed ozone-exposure/tree-response functions
by exposing tree seedlings to different ozone levels and measuring
reductions in growth as ``biomass loss.'' Typically, seedlings are used
because they are easy to manipulate and measure their growth loss from
ozone pollution. The mechanisms of susceptibility to ozone within the
leaves of seedlings and mature trees are identical, and the decreases
predicted using the seedlings should be related to the decrease in
overall plant fitness for mature trees, but the magnitude of the effect
may be higher or lower depending on the tree species (Chappelka and
Samuelson, 1998). In areas where certain ozone-sensitive species
dominate the forest community, the biomass loss from ozone can be
significant. Significant biomass loss can be defined as a more than 2
percent annual biomass loss, which would cause long-term ecological
harm as the short-term negative effects on seedlings compound to affect
long-term forest health (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 climate-related 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\....................... Low birth weight.
Pulmonary function.
Chronic respiratory diseases
other than chronic bronchitis.
Non-asthma respiratory emergency
room visits.
UVb exposure (+/-) \c\.
PM: welfare.......................... Household soiling.
Visibility in residential and non-
class I areas.
UVb exposure (+/-) \c\.
Global climate impacts \c\.
Ozone: health........................ Chronic respiratory damage.
Premature aging of the lungs.
Non-asthma respiratory emergency
room visits.
Increased exposure to UVb (+/-)
\c\.
Ozone: welfare....................... Yields for:
--Commercial forests.
--Fruits and vegetables, and
--Other commercial and
noncommercial crops.
Damage to urban ornamental
plants.
Recreational demand from damaged
forest aesthetics.
Ecosystem functions.
Increased exposure to UVb (+/-)
\c\.
NO2: health.......................... Respiratory hospital admissions.
Respiratory emergency department
visits.
Asthma exacerbation.
Acute respiratory symptoms.
Premature mortality.
Pulmonary function.
NO2: welfare......................... Commercial fishing and forestry
from acidic deposition.
Commercial fishing, agriculture
and forestry from nutrient
deposition.
Recreation in terrestrial and
estuarine ecosystems from
nutrient deposition.
[[Page 45352]]
Other ecosystem services and
existence values for currently
healthy ecosystems.
SO2: health.......................... Respiratory hospital admissions.
Asthma emergency room visits.
Asthma exacerbation.
Acute respiratory symptoms.
Premature mortality.
Pulmonary function.
SO2: welfare......................... Commercial fishing and forestry
from acidic deposition.
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.
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 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 http://www.epa.gov/airmarkets/progsregs/epa-ipm/index.html. 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 http://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 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 cost-effectiveness 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
[[Page 45353]]
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.
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 cost-effective 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 cost-effectiveness 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 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 non-capped 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.
---------------------------------------------------------------------------
\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. http://www.epa.gov/ttn/oarpg/t1/memoranda/ereseerem_gd.pdf.
---------------------------------------------------------------------------
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, allowance-based 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.
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,
[[Page 45354]]
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 concentration-response
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 PM-mortality 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 ``lowest-measured-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
Description budgets/limited trading Direct control Intrastate trading
----------------------------------------------------------------------------------------------------------------
Social costs \b\
3% discount rate................. $2.03.................. $2.68.................. $2.49.
7% discount rate................. $2.23.................. $2.91.................. $2.70.
Health-related benefits \c,d\
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. 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 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 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
[[Page 45355]]
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 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 Examples of potentially
Category Code b regulated entities
------------------------------------------------------------------------
Industry....................... 221112 Fossil fuel-fired electric
utility steam generating
units.
Federal Government............. c 221112 Fossil fuel-fired electric
utility steam generating
units owned by the federal
government.
State/Local.................... c 221112 Fossil fuel-fired electric
utility steam generating
units owned by
municipalities.
Tribal Government.............. 921150 Fossil fuel-fired electric
utility steam generating
units in Indian Country.
------------------------------------------------------------------------
a Include NAICS categories for source categories that own and operate
electric generating units only.
b North American Industry Classification System.
c Federal, state, or local government-owned and operated establishments
are classified according to the activity in which they are engaged.
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 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
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
municipality-owned 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.
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 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 lower-sulfur 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 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 cost-effective for the regulated
community; it is also intended to encourage innovation in analytical
technology and improved data quality. At this time, EPA is not
recommending any revisions to Part 75; however, EPA periodically
revises the test procedures set forth in Part 75.
When EPA revises the test procedures set forth in Part 75 in the
future, EPA will address the use of any new voluntary consensus
standards that are equivalent. Currently, even if a test procedure is
not set forth in Part 75, EPA is not precluding the use of any method,
whether it constitutes a voluntary consensus standard or not, as long
as it meets the performance criteria specified; however, any
alternative methods must be approved through the petition process under
40 CFR 75.66 before they are used.
J. Executive Order 12898: Federal Actions To Address Environmental
Justice in Minority Populations and Low-Income Populations
Executive Order (EO) 12898 (59 FR 7629 (Feb. 16, 1994)) establishes
federal executive policy on environmental justice. Its main provision
directs federal agencies, to the greatest extent practicable and
permitted by law, to make environmental justice part of their mission
by identifying and addressing, as appropriate, disproportionately high
and adverse human health or environmental effects of their programs,
policies, and activities on minority, low-income, and Tribal
populations in the United States.
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 http://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 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 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 most-contaminated 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 long-range 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 Sec. 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 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 [mu]g/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 Sec. 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 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
low-income 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
high quality health care to treat these illnesses.
We estimate that in 2014 the PM-related 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
[[Page 45361]]
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.
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.
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.
Sec. 51.121 [Amended]
2. Section 51.121 is amended by revising paragraph (r)(2) by
removing the words ``Sec. 51.123(bb)'' and adding, in their place, the
words ``Sec. 51.123(bb) with regard to an ozone season that occurs
before January 1, 2012''.
Sec. 51.123 [Amended]
3. Section 51.123 is amended by adding a new paragraph (ff) to read
as follows:
Sec. 51.123 Findings and requirements for submission of State
implementation plan revisions relating to emissions of oxides of
nitrogen pursuant to the Clean Air Interstate Rule.
* * * * *
(ff) Notwithstanding any provisions of paragraphs (a) through (ee)
of this section, subparts AA through II and 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.
[[Page 45362]]
Sec. 51.124 [Amended]
4. Section 51.124 is amended by adding a new paragraph (s) to read
as follows:
Sec. 51.124 Findings and requirements for submission of State
implementation plan revisions relating to emissions of sulfur dioxide
pursuant to the Clean Air Interstate Rule.
* * * * *
(s) Notwithstanding any provisions of paragraphs (a) through (r) of
this section, subparts AAA through III of part 96 of this chapter,
subparts AAA through III of part 97 of this chapter, and any State's
SIP to the contrary:
(1) With regard to any control period that begins after December
31, 2011, the Administrator:
(i) Rescinds the determination in paragraph (a) of this section
that the States identified in paragraph (c) of this section must submit
a SIP revision with respect to the fine particles (PM2.5)
NAAQS meeting the requirements of paragraphs (b) through (r) of this
section; and
(ii) Will not carry out any of the functions set forth for the
Administrator in subparts AAA through III of part 96 of this chapter,
subparts AAA through III of part 97 of this chapter, or in any
emissions trading program in a State's SIP approved under this section;
and
(2) The Administrator will not deduct for excess emissions any CAIR
SO2 allowances allocated for 2012 or any year thereafter.
Sec. 51.125 [Reserved]
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
Sec. 52.35 [Amended]
7. Section 52.35 is amended by adding a new paragraph (f) to read
as follows:
Sec. 52.35 What are the requirements of the Federal Implementation
Plans (FIPs) for the Clean Air Interstate Rule (CAIR) relating to
emissions of nitrogen oxides?
* * * * *
(f) Notwithstanding any provisions of paragraphs (a) through (d) of
this section, subparts AA through II and AAAA through IIII of part 97
of this chapter, and any State's SIP to the contrary:
(1) With regard to any control period that begins after December
31, 2011,
(i) The provisions in paragraphs (a) through (d) of this section
relating to NOX annual or ozone season emissions shall not
be applicable; and
(ii) The Administrator will not carry out any of the functions set
forth for the Administrator in subparts AA through II and AAAA through
IIII of part 97 of this chapter; 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.
Sec. 52.36 [Amended]
8. Section 52.36 is amended by adding a new paragraph (e) to read
as follows:
Sec. 52.36 What are the requirements of the Federal Implementation
Plans (FIPs) for the Clean Air Interstate Rule (CAIR) relating to
emissions of sulfur dioxide?
* * * * *
(e) Notwithstanding any provisions of paragraphs (a) through (c) of
this section, subparts AAA through III of part 97 of this chapter and
any State's SIP to the contrary:
(1) With regard to any control period that begins after December
31, 2011,
(i) The provisions of paragraphs (a) through (e) of this section
relating to SO2 emissions shall not be applicable; and
(ii) The Administrator will not carry out any of the functions set
forth for the Administrator in subparts AAA through III of part 97 of
this chapter; and
(2) The Administrator will not deduct for excess emissions any CAIR
SO2 allowances allocated for 2012 or any year thereafter.
9. Subpart A is amended by adding Sec. Sec. 52.37 and 52.38 to
read as follows:
Sec. 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, 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.
[[Page 45363]]
Sec. 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.
Subpart I--Delaware
10. Section 52.440 is amended by adding a new paragraph (c) to read
as follows:
Sec. 52.440 Interstate pollutant transport provisions; What are the
FIP requirements for decreases in emissions of nitrogen oxides?
* * * * *
(c) Notwithstanding any provisions of paragraphs (a) and (b) of
this section and subparts AA through II and AAAA through IIII of part
97 of this chapter to the contrary:
(1) With regard to any control period that begins after December
31, 2011,
(i) The provisions in paragraphs (a) and (b) of this section
relating to NOX annual or ozone season emissions shall not
be applicable; and
(ii) The Administrator will not carry out any of the functions set
forth for the Administrator in subparts AA through II and AAAA through
IIII of part 97 of this chapter; and
(2) The Administrator will not deduct for excess emissions any CAIR
NOX allowances or CAIR NOX Ozone Season
allowances allocated for 2012 or any year thereafter.
11. Section 52.441 is amended by designating the introductory text
as paragraph (a) and adding a new paragraph (b) to read as follows:
Sec. 52.441 Interstate pollutant transport provisions; What are the
FIP requirements for decreases in emissions of sulfur dioxide?
* * * * *
(b) Notwithstanding any provisions of paragraph (a) of this section
and subparts AAA through III of part 97 of this chapter and any State's
SIP to the contrary:
(1) With regard to any control period that begins after December
31, 2011,
(i) The provisions of paragraph (a) of this section relating to
SO2 emissions shall not be applicable; and
(ii) The Administrator will not carry out any of the functions set
forth for the Administrator in subparts AAA through III of part 97 of
this chapter; and
(2) The Administrator will not deduct for excess emissions any CAIR
SO2 allowances allocated for 2012 or any year thereafter.
Subpart J--District of Columbia
12. Section 52.484 is amended by adding a new paragraph (c) to read
as follows:
Sec. 52.484 Interstate pollutant transport provisions; What are the
FIP requirements for decreases in emissions of nitrogen oxides?
* * * * *
(c) Notwithstanding any provisions of paragraphs (a) and (b) of
this section and subparts AA through II and AAAA through IIII of part
97 of this chapter to the contrary:
(1) With regard to any control period that begins after December
31, 2011,
(i) The provisions in paragraphs (a) and (b) of this section
relating to NOX annual or ozone season emissions shall not
be applicable; and
(ii) The Administrator will not carry out any of the functions set
forth for the Administrator in subparts AA through II and AAAA through
IIII of part 97 of this chapter; and
(2) The Administrator will not deduct for excess emissions any CAIR
NOX allowances or CAIR NOX Ozone Season
allowances allocated for 2012 or any year thereafter.
13. Section 52.485 is amended by designating the introductory text
as paragraph (a) and adding a new paragraph (b) to read as follows:
Sec. 52.485 Interstate pollutant transport provisions; What are the
FIP requirements for decreases in emissions of sulfur dioxide?
* * * * *
(b) Notwithstanding any provisions of paragraph (a) of this section
and subparts AAA through III of part 97 of this chapter and any State's
SIP to the contrary:
(1) With regard to any control period that begins after December
31, 2011,
(i) The provisions of paragraph (a) of this section relating to
SO2 emissions shall not be applicable; and
(ii) The Administrator will not carry out any of the functions set
forth for the Administrator in subparts AAA through III of part 97 of
this chapter; and
(2) The Administrator will not deduct for excess emissions any CAIR
SO2 allowances allocated for 2012 or any year thereafter.
Subpart P--Indiana
14. Section 52.789 is amended by adding a new paragraph (c) to read
as follows:
Sec. 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
[[Page 45364]]
paragraph (a) and adding a new paragraph (b) to read as follows:
Sec. 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:
Sec. 52.984 Interstate pollutant transport provisions; What are the
FIP requirements for decreases in emissions of nitrogen oxides?
* * * * *
(c) Notwithstanding any provisions of paragraphs (a) and (b) of
this section and subparts AA through II and AAAA through IIII of part
97 of this chapter to the contrary:
(1) With regard to any control period that begins after December
31, 2011,
(i) The provisions in paragraphs (a) and (b) of this section
relating to NOX annual or ozone season emissions shall not
be applicable; and
(ii) The Administrator will not carry out any of the functions set
forth for the Administrator in subparts AA through II and AAAA through
IIII of part 97 of this chapter; 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.
Subpart X--Michigan
17. Section 52.1186 is amended by adding a new paragraph (c) to
read as follows:
Sec. 52.1186 Interstate pollutant transport provisions; What are the
FIP requirements for decreases in emissions of nitrogen oxides?
* * * * *
(c) Notwithstanding any provisions of paragraphs (a) and (b) of
this section and subparts AA through II and AAAA through IIII of part
97 of this chapter to the contrary:
(1) With regard to any control period that begins after December
31, 2011,
(i) The provisions in paragraphs (a) and (b) of this section
relating to NOX annual or ozone season emissions shall not
be applicable; and
(ii) The Administrator will not carry out any of the functions set
forth for the Administrator in subparts AA through II and AAAA through
IIII of part 97 of this chapter; 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:
Sec. 52.1187 Interstate pollutant transport provisions; What are the
FIP requirements for decreases in emissions of sulfur dioxide?
* * * * *
(b) Notwithstanding any provisions of paragraph (a) of this section
and subparts AAA through III of part 97 of this chapter and any State's
SIP to the contrary:
(1) With regard to any control period that begins after December
31, 2011,
(i) The provisions of paragraph (a) of this section relating to
SO2 emissions shall not be applicable; and
(ii) The Administrator will not carry out any of the functions set
forth for the Administrator in subparts AAA through III of part 97 of
this chapter; and
(2) The Administrator will not deduct for excess emissions any CAIR
SO2 allowances allocated for 2012 or any year thereafter.
Subpart FF--New Jersey
19. Section 52.1584 is amended by adding a new paragraph (c) to
read as follows:
Sec. 52.1584 Interstate pollutant transport provisions; What are the
FIP requirements for decreases in emissions of nitrogen oxides?
* * * * *
(c) Notwithstanding any provisions of paragraphs (a) and (b) of
this section and subparts AA through II and AAAA through IIII of part
97 of this chapter to the contrary:
(1) With regard to any control period that begins after December
31, 2011,
(i) The provisions in paragraphs (a) and (b) of this section
relating to NOX annual or ozone season emissions shall not
be applicable; and
(ii) The Administrator will not carry out any of the functions set
forth for the Administrator in subparts AA through II and AAAA through
IIII of part 97 of this chapter; 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:
Sec. 52.1585 Interstate pollutant transport provisions; What are the
FIP requirements for decreases in emissions of sulfur dioxide?
* * * * *
(b) Notwithstanding any provisions of paragraph (a) of this section
and subparts AAA through III of part 97 of this chapter and any State's
SIP to the contrary:
(1) With regard to any control period that begins after December
31, 2011,
(i) The provisions of paragraph (a) of this section relating to
SO2 emissions shall not be applicable; and
(ii) The Administrator will not carry out any of the functions set
forth for the Administrator in subparts AAA through III of part 97 of
this chapter; and
(2) The Administrator will not deduct for excess emissions any CAIR
SO2 allowances allocated for 2012 or any year thereafter.
Subpart RR--Tennessee
21. Section 52.2240 is amended by adding a new paragraph (c) to
read as follows:
Sec. 52.2240 Interstate pollutant transport provisions; What are the
FIP requirements for decreases in emissions of nitrogen oxides?
* * * * *
(c) Notwithstanding any provisions of paragraphs (a) and (b) of
this section and subparts AA through II and AAAA through IIII of part
97 of this chapter to the contrary:
(1) With regard to any control period that begins after December
31, 2011,
(i) The provisions in paragraphs (a) and (b) of this section
relating to NOX annual or ozone season emissions shall not
be applicable; and
(ii) The Administrator will not carry out any of the functions set
forth for the Administrator in subparts AA through II and AAAA through
IIII of part 97 of this chapter; and
(2) The Administrator will not deduct for excess emissions any CAIR
NOX
[[Page 45365]]
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:
Sec. 52.2241 Interstate pollutant transport provisions; What are the
FIP requirements for decreases in emissions of sulfur dioxide?
* * * * *
(b) Notwithstanding any provisions of paragraph (a) of this section
and subparts AAA through III of part 97 of this chapter and any State's
SIP to the contrary:
(1) With regard to any control period that begins after December
31, 2011,
(i) The provisions of paragraph (a) of this section relating to
SO2 emissions shall not be applicable; and
(ii) The Administrator will not carry out any of the functions set
forth for the Administrator in subparts AAA through III of part 97 of
this chapter; and
(2) The Administrator will not deduct for excess emissions any CAIR
SO2 allowances allocated for 2012 or any year thereafter.
Subpart SS--Texas
23. Section 52.2283 is amended by adding a new paragraph (c) to
read as follows:
Sec. 52.2283 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 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:
Sec. 52.2284 Interstate pollutant transport provisions; What are the
FIP requirements for decreases in emissions of sulfur dioxide?
* * * * *
(b) Notwithstanding any provisions of paragraph (a) of this section
and subparts AAA through III of part 97 of this chapter and any State's
SIP to the contrary:
(1) With regard to any control period that begins after December
31, 2011,
(i) The provisions of paragraph (a) of this section relating to
SO2 emissions shall not be applicable; and
(ii) The Administrator will not carry out any of the functions set
forth for the Administrator in subparts AAA through III of part 97 of
this chapter; and
(2) The Administrator will not deduct for excess emissions any CAIR
SO2 allowances allocated for 2012 or any year thereafter.
Subpart YY--Wisconsin
25. Section 52.8587 is amended by adding a new paragraph (c) to
read as follows:
Sec. 52.8587 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.
26. Section 52.8588 is amended by designating the introductory text
as paragraph (a) and adding a new paragraph (b) to read as follows:
Sec. 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 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.
Sec. 72.2 [Amended]
28. Section 72.2 is amended by removing the definition of
``interested person''.
PART 78--[AMENDED]
29. The authority citation for Part 78 continues to read as
follows:
Authority: 42 U.S.C. 7401, 7403, 7410, 7411, 7426, 7601, et seq.
Sec. 78.1 [Amended]
30. Section 78.1 is amended by adding paragraphs (b)(13) through
(b)(16) to read as follows:
Sec. 78.1 Purpose and scope.
* * * * *
(b) * * *
(13) Under subpart AAAAA of part 97 of this chapter,
(i) The decision on allocation of TR NOX Annual
allowances under Sec. 97.411(a)(2) and (b) of this chapter.
(ii) The decision on the transfer of TR NOX Annual
allowances under Sec. 97.423 of this chapter.
(iii) The decision on the deduction of TR NOX Annual
allowances under Sec. Sec. 97.424 and 97.425 of this chapter.
(iv) The correction of an error in an Allowance Management System
account under Sec. 97.427 of this chapter.
(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 Sec. 97.428 of this
chapter.
(vi) The finalization of control period emissions data, including
retroactive adjustment based on audit.
(vii) The approval or disapproval of a petition under Sec. 97.435
of this chapter.
(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 Sec. Sec.
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
[[Page 45366]]
allowances under Sec. 97.511(a)(2) and (b) of this chapter.
(ii) The decision on the transfer of TR NOX Ozone Season
allowances under Sec. 97.523 of this chapter.
(iii) The decision on the deduction of TR NOX Ozone
Season allowances under Sec. Sec. 97.524 and 97.525 of this chapter.
(iv) The correction of an error in an Allowance Management System
account under Sec. 97.527 of this chapter.
(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 Sec. 97.528 of
this chapter.
(vi) The finalization of control period emissions data, including
retroactive adjustment based on audit.
(vii) The approval or disapproval of a petition under Sec. 97.535
of this chapter.
(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 Sec. Sec. 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 Sec. 97.611(a)(2) and (b) of this chapter.
(ii) The decision on the transfer of TR SO2 Group 1
allowances under Sec. 97.623 of this chapter.
(iii) The decision on the deduction of TR SO2 Group 1
allowances under Sec. Sec. 97.624 and 97.625 of this chapter.
(iv) The correction of an error in an Allowance Management System
account under Sec. 97.627 of this chapter.
(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 Sec. 97.628 of this
chapter.
(vi) The finalization of control period emissions data, including
retroactive adjustment based on audit.
(vii) The approval or disapproval of a petition under Sec. 97.635
of this chapter.
(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 Sec. Sec.
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 Sec. 97.711(a)(2) and (b) of this chapter.
(ii) The decision on the transfer of TR SO2 Group 1
allowances under Sec. 97.723 of this chapter.
(iii) The decision on the deduction of TR SO2 Group 1
allowances under Sec. Sec. 97.724 and 97.725 of this chapter.
(iv) The correction of an error in an Allowance Management System
account under Sec. 97.727 of this chapter.
(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 Sec. 97.728 of this
chapter.
(vi) The finalization of control period emissions data, including
retroactive adjustment based on audit.
(vii) The approval or disapproval of a petition under Sec. 97.735
of this chapter.
(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 Sec. Sec.
97.741 through 97.744.
* * * * *
Sec. 78.2 [Amended]
31. Section 78.2 is revised to read as follows:
Sec. 78.2 General.
(a) Definitions. (1) The terms used in this subpart with regard to
a decision of the Administrator that is appealed under this section
shall have the meaning as set forth in the regulations under which the
Administrator made such decision and as set forth in paragraph (a)(2)
of this section.
(2) Interested person means, with regard to a decision of the
Administrator, 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 shall be governed by part 2 of this chapter.
(c) Computation of time. (1) In computing any period of time
prescribed or allowed under this part, except as otherwise provided,
the day of the event from which the period begins to run shall not be
included, and Saturdays, Sundays, and federal holidays shall be
included. When the period ends on a Saturday, Sunday, or Federal
holiday, the stated period shall be extended to include the next
business day.
(2) Where a document is served by first class mail or commercial
delivery service, but not by overnight or same-day delivery, 5 days
shall be added to the time prescribed or allowed under this part for
the filing of a responsive document or for otherwise responding.
Sec. 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:
Sec. 78.3 Petition for administrative review and request or
evidentiary hearing.
(a) * * *
(10) The following persons may petition for administrative review
of a decision of the Administrator that is made under subparts AAAAA,
BBBBB, CCCCC, and DDDDD of part 97 of this chapter:
(i) The designated representative for a unit or source, or the
authorized account representative for any Allowance Management System
account, covered by the decision; or
(ii) Any interested person with regard to the decision.
* * * * *
(d) * * *
(11) Any provision or requirement of subparts AAAAA, BBBBB, CCCCC,
or DDDDD of part 97 of this chapter, including the standard
requirements under Sec. 97.406, Sec. 97.506, Sec. 97.606, or Sec.
97.706 of this chapter and any emission monitoring or reporting
requirements.
Sec. 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;
[[Page 45367]]
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:
Sec. 78.4 Filings.
(a)(1) All original filings made under this part shall be signed by
the person making the filing or by an attorney or authorized
representative, in accordance with the following requirements:
(i) Any filings on behalf of owners and operators of a affected
unit or affected source, TR NOX Annual unit or TR
NOX Annual source, TR NOX Ozone Season unit or TR
NOX Ozone Season source, TR SO2 Group 1 unit or
TR SO2 Group 1 source, TR SO2 Group 2 unit or TR
SO2 Group 2 source, or a unit for which a TR opt-in
application is submitted and not withdrawn shall be signed by the
designated representative. Any filing on behalf of persons with an
ownership interest with respect to allowances, TR NOX Annual
allowances, TR NOX Ozone Season allowances, TR
SO2 Group 1 allowances, or TR SO2 Group 2
allowances in a general account shall be signed by the authorized
account representative.
(ii) Any filings on behalf of owners and operators of a
NOX Budget unit or NOX Budget source shall be
signed by the NOX authorized account representative. Any
filing on behalf of persons with an ownership interest with respect to
NOX allowances in a general account shall be signed by the
NOX authorized account representative.
* * * * *
(2) The name, address, e-mail address (if any), telephone number,
and facsimile number (if any) of the person making the filing shall be
provided with the filing.
* * * * *
PART 97--[AMENDED]
34. The authority citation for part 97 continues to read as
follows:
Authority: 42 U.S.C. 7401, 7403, 7410, 7426, 7601, and 7651, et
seq.
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.
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 opt-in 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
Sec. 97.401 Purpose.
This subpart sets forth the general, designated representative,
allowance, and monitoring provisions for the Transport Rule (TR)
NOX Annual Trading Program, under section 110 of the Clean
Air Act and Sec. 52.37(a) of this chapter, as a means of mitigating
interstate transport of fine particulates and nitrogen oxides.
Sec. 97.402 Definitions.
The terms used in this subpart shall have the meanings set forth in
this section as follows:
Acid Rain Program means a multi-state SO2 and
NOX air pollution control and emission reduction program
established by the Administrator under title IV of the Clean Air Act
and parts 72 through 78 of this chapter.
Administrator means the Administrator of the United States
Environmental Protection Agency or the Director of the Clean Air
Markets Division (or its successor) 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
[[Page 45368]]
Annual source's compliance account in order to be available for use in
complying with the source's TR NOX Annual emissions
limitation for such control period in accordance with Sec. 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 Sec. 72.2 of this chapter,
Sec. 97.502, Sec. 97.602, or Sec. 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 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
(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 system-wide basis the requirement in paragraph (2)(i)(B) of
this definition, the topping-cycle 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 Sec. 97.405.
(i) For a unit that is a TR NOX Annual unit under Sec.
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 Sec.
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
[[Page 45369]]
replacement unit shall be treated as a separate unit with a separate
date for commencement of commercial operation as defined in paragraph
(1) or (2) of this definition as appropriate.
(2) Notwithstanding paragraph (1) of this definition and except as
provided in Sec. 97.405, for a unit that is not a TR NOX
Annual unit under Sec. 97.404 on the later of 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 Sec. 97.404.
(i) For a unit with a date for commencement of commercial operation
as defined in the introductory text of paragraph (2) of this definition
and that subsequently undergoes a physical change (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.
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 Sec.
97.424 and the TR NOX Annual assurance provisions in
accordance with Sec. 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 Sec. Sec. 97.430 through 97.435. The following
systems are the principal types of continuous emission monitoring
systems:
(1) A flow monitoring system, consisting of a stack flow rate
monitor and an automated data acquisition and handling system and
providing a permanent, continuous record of stack gas volumetric flow
rate, in standard cubic feet per hour (scfh);
(2) A NOX concentration monitoring system, consisting of
a NOX pollutant concentration monitor and an automated data
acquisition and handling system and providing a permanent, continuous
record of NOX emissions, in parts per million (ppm);
(3) A NOX emission rate (or NOX-diluent)
monitoring system, consisting of a NOX pollutant
concentration monitor, a diluent gas (CO2 or O2)
monitor, and an automated data acquisition and handling system and
providing a permanent, continuous record of NOX
concentration, in parts per million (ppm), diluent gas concentration,
in percent CO2 or O2, and NOX emission
rate, in pounds per million British thermal units (lb/mmBtu);
(4) A moisture monitoring system, as defined in Sec. 75.11(b)(2)
of this chapter and providing a permanent, continuous record of the
stack gas moisture content, in percent H2O;
(5) A CO2 monitoring system, consisting of a
CO2 pollutant concentration monitor (or an O2
monitor plus suitable mathematical equations from which the
CO2 concentration is derived) and an automated data
acquisition and handling system and providing a permanent, continuous
record of CO2 emissions, in percent CO2; and
(6) An O2 monitoring system, consisting of an
O2 concentration monitor and an automated data acquisition
and handling system and providing a permanent, continuous record of
O2, in percent O2.
Control period means the period starting January 1 of a calendar
year, except as provided in Sec. 97.406(c)(3), and ending on December
31 of the same year, inclusive.
Designated representative means, for a TR NOX Annual
source and each TR NOX Annual unit at the source, the
natural person who is authorized by the owners and operators of the
source and all such units at the source, in accordance with this
subpart, to represent and legally bind each owner and operator in
matters pertaining to the TR NOX Annual Trading Program. If
the TR NOX Annual source is also subject to the Acid Rain
Program, TR NOX Ozone Season Trading Program, TR
SO2 Group 1 Trading Program, or TR SO2 Group 2
Trading Program, then this natural person shall be the same natural
person as the designated representative, as defined in Sec. 72.2 of
this chapter, Sec. 97.502, Sec. 97.602, or Sec. 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 Sec. Sec. 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
[[Page 45370]]
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 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-the-
unit, firm power contractual arrangement;
(4) Provided that, for purposes of applying the TR NOX
Annual assurance provisions in Sec. Sec. 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 Sec. 97.406(c)(2)(iii)(A)
and not as described in Sec. 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 Sec. 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 Sec. 97.410(a) and the State's one-year variability limit under
Sec. 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 Sec. 97.410(a) and the State's three-year variability limit
under Sec. 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
[[Page 45371]]
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
Sec. 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.
Permitting authority means ``permitting authority'' as defined in
Sec. Sec. 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 Sec. 75.22 of this
chapter.
Replacement, replace, or replaced means, with regard to a unit, the
demolishing of a unit, or the permanent retirement and permanent
disabling of a unit, and the construction of another unit (the
replacement unit) to be used instead of the demolished or retired unit
(the replaced unit).
Sequential use of energy means:
(1) 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 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
Sec. 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
[[Page 45372]]
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 Sec. 97.424(a) for such control period.
TR NOX Annual source means a source that includes one or more TR
NOX Annual units.
TR NOX Annual unit means a unit that is subject to the TR
NOX Annual Trading Program under Sec. 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-fuel-fired 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.
Sec. 97.403 Measurements, abbreviations, and acronyms.
Measurements, abbreviations, and acronyms used in this subpart are
defined as follows:
Btu--British thermal unit
CO2--carbon dioxide
H2O--water
hr--hour
kW--kilowatt electrical
kWh--kilowatt hour
lb--pound
mmBtu--million Btu
MWe--megawatt electrical
MWh--megawatt hour
NOX--nitrogen oxides
O2--oxygen
ppm--parts per million
scfh--standard cubic feet per hour
SO2--sulfur dioxide
yr--year
Sec. 97.404 Applicability.
(a) Except as provided in paragraph (b) of this section:
(1) The following units in a State 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.
(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 start-up 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 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:
[[Page 45373]]
(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 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.
Sec. 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 Sec. 97.406(b) and (c)(1), Sec. 97.424, and Sec. Sec.
97.430 through 97.435.
(2) The exemption under paragraph (a)(1) of this section shall
become effective the day on which the TR NOX Annual unit is
permanently retired. Within 30 days of the unit's permanent retirement,
the designated representative shall submit a statement to the
Administrator. The statement shall state, in a format prescribed by the
Administrator, that the unit was permanently retired on a specified
date and will comply with the requirements of paragraph (b) of this
section.
(b) Special provisions. (1) A unit exempt under paragraph (a) of
this section shall not emit any NOX, starting on the date
that the exemption takes effect.
(2) For a period of 5 years from the date the records are created,
the owners and operators of a unit exempt under paragraph (a) of this
section shall retain, at the source that includes the unit, records
demonstrating that the unit is permanently retired. The 5-year period
for keeping records may be extended for cause, at any time before the
end of the period, in writing by the Administrator. The owners and
operators bear the burden of proof that the unit is permanently
retired.
(3) The owners and operators and, to the extent applicable, the
designated representative of a unit exempt under paragraph (a) of this
section shall comply with the requirements of the TR NOX
Annual Trading Program concerning all periods for which the exemption
is not in effect, even if such requirements arise, or must be complied
with, after the exemption takes effect.
(4) A unit exempt under paragraph (a) of this section shall lose
its exemption on the first date on which the unit resumes operation.
Such unit shall be treated, for purposes of applying allocation,
monitoring, reporting, and recordkeeping requirements under this
subpart, as a unit that commences commercial operation on the first
date on which the unit resumes operation.
Sec. 97.406 Standard requirements.
(a) Designated representative requirements. The owners and
operators shall comply with the requirement to have a designated
representative, and may have an alternate designated representative, in
accordance with Sec. Sec. 97.413 through 97.418.
(b) Emissions monitoring, reporting, and recordkeeping
requirements. (1) The owners and operators, and the designated
representative, of each TR NOX Annual source and each TR
NOX Annual unit at the source shall comply with the
monitoring, reporting, and recordkeeping requirements of Sec. Sec.
97.430 through 97.435.
(2) The emissions data determined in accordance with Sec. Sec.
97.430 through 97.435 shall be used to calculate allocations of TR
NOX Annual allowances under Sec. Sec. 97.411(a)(2) and (b)
and 97.412 and to determine compliance with the TR NOX
Annual emissions limitation and assurance provisions under paragraph
(c) of this section, provided that, for each monitoring location from
which mass emissions are reported, the mass emissions amount used in
calculating such allocations and determining such compliance shall be
the mass emissions amount for the monitoring location determined in
accordance with Sec. Sec. 97.430 through 97.435 and rounded to the
nearest ton, with any fraction of a ton less than 0.50 being deemed to
be zero.
(c) NOX emissions requirements. (1) TR NOX Annual
emissions limitation. (i) As of the allowance transfer deadline for a
control period, the owners and operators of each TR NOX
Annual source and each TR NOX Annual unit at the source
shall hold, in the source's compliance account, TR NOX
Annual allowances available for deduction for such control period under
Sec. 97.424(a) in an amount not less than the tons of total
NOX emissions for such control period from all TR
NOX Annual units at the source.
(ii) If 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:
[[Page 45374]]
(A) The owners and operators of the source and each TR
NOX Annual unit at the source shall hold the TR
NOX Annual allowances required for deduction under Sec.
97.424(d) and 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 Sec.
97.425(b)(4)(ii), TR NOX Annual allowances available for
deduction for such control period under Sec. 97.425(a) in an amount
equal to the product, as determined by the Administrator in accordance
with Sec. 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 Sec.
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 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 Sec.
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 Sec. 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 Sec. 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.
(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
Sec. 75.19 of this chapter), or an alternative monitoring system
(under subpart E of part 75 of this chapter) in accordance with
Sec. Sec. 97.430 through 97.435 may be added to, or changed in, a
title V permit using minor permit modification procedures in accordance
with Sec. Sec. 70.7(e)(2) and 71.7(e)(1) of this chapter, provided
that the requirements applicable to the described monitoring and
reporting (as added or changed, respectively) are already incorporated
in such permit. This paragraph explicitly provides that the addition
of, or change to, a unit's description as described in the prior
sentence is eligible for minor permit modification procedures in
accordance with Sec. Sec. 70.7(e)(2)(i)(B) and 71.7(e)(1)(i)(B) of
this chapter.
(e) Additional recordkeeping and reporting requirements. (1) Unless
otherwise provided, the owners and operators of each TR NOX
Annual source and each TR NOX Annual unit at the source
shall keep on site at the source each of the following documents (in
hardcopy or electronic format) for a period of 5 years from the date
the document is created. This period may be extended for cause, at any
time
[[Page 45375]]
before the end of 5 years, in writing by the Administrator.
(i) The certificate of representation under Sec. 97.416 for the
designated representative for the source and each TR NOX
Annual unit at the source and all documents that demonstrate the truth
of the statements in the certificate of representation; provided that
the certificate and documents shall be retained on site at the source
beyond such 5-year period until such documents are superseded because
of the submission of a new certificate of representation under Sec.
97.416 changing the designated representative.
(ii) All emissions monitoring information, in accordance with this
subpart.
(iii) Copies of all reports, compliance certifications, and other
submissions and all records made or required under, or to demonstrate
compliance with the requirements of, the TR NOX Annual
Trading Program, 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 Sec. 97.405
shall be construed as exempting or excluding the owners and operators,
and the designated representative, of a TR NOX Annual source
or TR NOX Annual unit from compliance with any other
provision of the applicable, approved State implementation plan, a
federally enforceable permit, or the Clean Air Act.
Sec. 97.407 Computation of time.
(a) Unless otherwise stated, any time period scheduled, under the
TR NOX Annual Trading Program, to begin on the occurrence of
an act or event shall begin on the day the act or event occurs.
(b) Unless otherwise stated, any time period scheduled, under the
TR NOX Annual Trading Program, to begin before the
occurrence of an act or event shall be computed so that the period ends
the day before the act or event occurs.
(c) Unless otherwise stated, if the final day of any time period,
under the TR NOX Annual Trading Program, falls on a weekend
or a State or Federal holiday, the time period shall be extended to the
next business day.
Sec. 97.408 Administrative appeal procedures.
The administrative appeal procedures for decisions of the
Administrator under the TR NOX Annual Trading Program are
set forth in part 78 of this chapter.
Sec. 97.409 [Reserved]
Sec. 97.410 State NOX Annual trading budgets, new-unit set-asides,
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 New-unit set-
trading budget aside (tons)
(tons) * ---------------
State ----------------
For 2012 and For 2012 and
thereafter thereafter
------------------------------------------------------------------------
Alabama................................. 69,169 2,075
Connecticut............................. 2,775 83
Delaware................................ 6,206 186
District of Columbia.................... 170 5
Florida................................. 120,001 3,600
Georgia................................. 73,801 2,214
Illinois................................ 56,040 1,681
Indiana................................. 115,687 3,471
Iowa.................................... 46,068 1,382
Kansas.................................. 51,321 1,540
Kentucky................................ 74,117 2,224
Louisiana............................... 43,946 1,318
Maryland................................ 17,044 511
Massachusetts........................... 5,960 179
Michigan................................ 64,932 1,948
Minnesota............................... 41,322 1,240
Missouri................................ 57,681 1,730
Nebraska................................ 43,228 1,297
New Jersey.............................. 11,826 355
New York................................ 23,341 700
North Carolina.......................... 51,800 1,554
Ohio.................................... 97,313 2,919
Pennsylvania............................ 113,903 3,417
South Carolina.......................... 33,882 1,016
Tennessee............................... 28,362 851
Virginia................................ 29,581 887
West Virginia........................... 51,990 1,560
Wisconsin............................... 44,846 1,345
�����������������������������������������
[[Page 45376]]
Total............................... 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 Three-year
variability variability
limits limits
State -------------------------------
2014 and 2016 and
thereafter thereafter
(tons) (tons)
------------------------------------------------------------------------
Alabama................................. 6,917 3,993
Connecticut............................. 5,000 2,887
Delaware................................ 5,000 2,887
District of Columbia.................... 5,000 2,887
Florida................................. 12,000 6,928
Georgia................................. 7,380 4,261
Illinois................................ 5,604 3,235
Indiana................................. 11,569 6,679
Iowa.................................... 5,000 2,887
Kansas.................................. 5,132 2,963
Kentucky................................ 7,412 4,279
Louisiana............................... 5,000 2,887
Maryland................................ 5,000 2,887
Massachusetts........................... 5,000 2,887
Michigan................................ 6,493 3,749
Minnesota............................... 5,000 2,887
Missouri................................ 5,768 3,330
Nebraska................................ 5,000 2,887
New Jersey.............................. 5,000 2,887
New York................................ 5,000 2,887
North Carolina.......................... 5,180 2,991
Ohio.................................... 9,731 5,618
Pennsylvania............................ 11,390 6,576
South Carolina.......................... 5,000 2,887
Tennessee............................... 5,000 2,887
Virginia................................ 5,000 2,887
West Virginia........................... 5,199 3,002
Wisconsin............................... 5,000 2,887
------------------------------------------------------------------------
Sec. 97.411 Timing requirements for TR NOX Annual allowance
allocations.
(a) Existing units. (1) TR NOX Annual allowances are
allocated, for the control periods in 2012 and each year thereafter, as
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 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
accordance with Sec. 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 Sec. 97.412 and Sec. Sec. 97.406(b)(2) and 97.430
through 97.435.
[[Page 45377]]
(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 Sec. 97.404 as of January 1,
2012 or whose deadline for meeting monitor certification requirements
under Sec. 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 Sec. 97.412 for the
control period to a recipient that is not actually a TR NOX
Annual unit under Sec. 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 Sec. 97.421.
(2) If the Administrator already recorded such TR NOX
Annual allowances under Sec. 97.421 and if the Administrator makes
such determination before making deductions for the source that
includes such recipient under Sec. 97.424(b) for such control period,
then the Administrator will deduct from the account in which such TR
NOX Annual allowances were recorded an amount of TR
NOX Annual allowances allocated for the same or a prior
control period equal to the amount of such already recorded TR
NOX Annual allowances. The authorized account representative
shall ensure that there are sufficient TR NOX Annual
allowances in such account for completion of the deduction.
(3) If the Administrator already recorded such TR NOX
Annual allowances under Sec. 97.421 and if the Administrator makes
such determination after making deductions for the source that includes
such recipient under Sec. 97.424(b) for such control period, then the
Administrator will not make any deduction to take account of such
already recorded TR NOX Annual allowances.
(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 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.
Sec. 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 Sec. 97.411(c)(1) or (2), and to TR NOX
Annual units that are so listed and, pursuant to Sec. 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 Sec. 97.410(a). Each new unit set-aside will
be allocated additional TR NOX Annual allowances in
accordance with Sec. 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 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 Sec. 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
[[Page 45378]]
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 Sec.
97.411(a)(2), an amount of TR NOX Annual allowances equal to
the following: The total amount of such remaining unallocated TR
NOX Annual allowances in such new unit set-aside, multiplied
by the unit's allocation under Sec. 97.411(a) for such control period,
divided by the remainder of the amount of tons in the applicable State
NOX Annual trading budget minus the amount of tons in such
new unit set-aside, and rounded to the nearest allowance.
Sec. 97.413 Authorization of designated representative and alternate
designated representative.
(a) Except as provided under Sec. 97.415, each TR NOX
Annual source, including all TR NOX Annual units at the
source, shall have one and only one designated representative, with
regard to all matters under the TR NOX Annual Trading
Program.
(1) The designated representative shall be selected by an agreement
binding on the owners and operators of the source and all TR
NOX Annual units at the source and shall act in accordance
with the certification statement in Sec. 97.416(a)(4)(iii).
(2) Upon and after receipt by the Administrator of a complete
certificate of representation under Sec. 97.416:
(i) The designated representative shall be authorized and shall
represent and, by his or her representations, actions, inactions, or
submissions, legally bind each owner and operator of the source and
each TR NOX Annual unit at the source in all matters
pertaining to the TR NOX Annual Trading Program,
notwithstanding any agreement between the designated representative and
such owners and operators; and
(ii) The owners and operators of the source and each TR
NOX Annual unit at the source shall be bound by any decision
or order issued to the designated representative by the Administrator
regarding the source or any such unit.
(b) Except as provided under Sec. 97.415, each TR NOX
Annual source may have one and only one alternate designated
representative, who may act on behalf of the designated representative.
The agreement by which the alternate designated representative is
selected shall include a procedure for authorizing the alternate
designated representative to act in lieu of the designated
representative.
(1) The alternate designated representative shall be selected by an
agreement binding on the owners and operators of the source and all TR
NOX Annual units at the source and shall act in accordance
with the certification statement in Sec. 97.416(a)(4)(iii).
(2) Upon and after receipt by the Administrator of a complete
certificate of representation under Sec. 97.416:
(i) The alternate designated representative shall be authorized;
(ii) Any representation, action, inaction, or submission by the
alternate designated representative shall be deemed to be a
representation, action, inaction, or submission by the designated
representative; and
(iii) The owners and operators of the source and each TR
NOX Annual unit at the source shall be bound by any decision
or order issued to the alternate designated representative by the
Administrator regarding the source or any such unit.
(c) Except in this section, Sec. 97.402, and Sec. Sec. 97.414
through 97.418, whenever the term ``designated representative'' is used
in this subpart, the term shall be construed to include the designated
representative or any alternate designated representative.
Sec. 97.414 Responsibilities of designated representative and
alternate designated representative.
(a) Except as provided under Sec. 97.418 concerning delegation of
authority to make submissions, each submission under the TR
NOX Annual Trading Program shall be made, signed, and
certified by the designated representative or alternate designated
representative for each TR NOX Annual source and TR
NOX Annual unit for which the submission is made. Each such
submission shall include the following certification statement by the
designated representative or alternate designated representative: ``I
am authorized to make this submission on behalf of the owners and
operators of the source or units for which the submission is made. I
certify under penalty of law that I have personally examined, and am
familiar with, the statements and information submitted in this
document and all its attachments. Based on my inquiry of those
individuals with primary responsibility for obtaining the information,
I certify that the statements and information are to the best of my
knowledge and belief true, accurate, and complete. I am aware that
there are significant penalties for submitting false statements and
information or omitting required statements and information, including
the possibility of fine or imprisonment.''
(b) The Administrator will accept or act on a submission made for a
TR NOX Annual source or a TR NOX Annual unit only
if the submission has been made, signed, and certified in accordance
with paragraph (a) of this section and Sec. 97.418.
Sec. 97.415 Changing designated representative and alternate
designated representative; changes in owners and operators.
(a) Changing designated representative. The designated
representative may be changed at any time upon receipt by the
Administrator of a superseding complete certificate of representation
under Sec. 97.416. Notwithstanding any such change, all
representations, actions, inactions, and submissions by the previous
designated representative before the time and date when the
Administrator receives the superseding certificate of representation
shall be binding on the new designated representative and the owners
and operators of the TR NOX Annual source and the TR
NOX Annual units at the source.
(b) Changing alternate designated representative. The alternate
designated representative may be changed at any time upon receipt by
the Administrator of a superseding complete certificate of
representation under Sec. 97.416. Notwithstanding any such change, all
representations, actions, inactions, and submissions by the previous
alternate designated representative before the time and date when the
Administrator receives the superseding certificate of representation
shall be binding on the new alternate designated representative, the
designated representative, and the owners and operators of the TR
NOX Annual source and the TR NOX Annual units at
the source.
(c) Changes in owners and operators. (1) In the event an owner or
operator of a TR NOX Annual source or a TR NOX
Annual unit is not included in the list of owners and operators in the
certificate of representation under Sec. 97.416, such owner or
operator shall be deemed to be subject to and bound by the certificate
of representation, the representations, actions, inactions, and
submissions of the designated representative and any alternate
designated representative of the source or unit, and the decisions and
orders of the Administrator, as if the owner or operator were included
in such list.
(2) Within 30 days after any change in the owners and operators of
a TR NOX Annual source or a TR NOX Annual unit,
including the addition of a new
[[Page 45379]]
owner or operator, the designated representative or any alternate
designated representative shall submit a revision to the certificate of
representation under Sec. 97.416 amending the list of owners and
operators to include the change.
Sec. 97.416 Certificate of representation.
(a) A complete certificate of representation for a designated
representative or an alternate designated representative shall include
the following elements in a format prescribed by the Administrator:
(1) Identification of the TR NOX Annual source, and each
TR NOX Annual unit at the source, for which the certificate
of representation is submitted, including source name, source category
and NAICS code (or, in the absence of a NAICS code, an equivalent
code), State, plant code, county, latitude and longitude, unit
identification number and type, identification number and nameplate
capacity (in MWe rounded to the nearest tenth) of each generator served
by each such unit, 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-the-unit, firm power
contractual arrangement, I certify that: I have given a written notice
of my selection as the `designated representative' or `alternate
designated representative', as applicable, and of the agreement by
which I was selected to each owner and operator of the source and of
each TR NOX Annual unit at the source; and TR NOX
Annual allowances and proceeds of transactions involving TR
NOX Annual allowances will be deemed to be held or
distributed in proportion to each holder's legal, equitable, leasehold,
or contractual reservation or entitlement, except that, if such
multiple holders have expressly provided for a different distribution
of TR NOX Annual allowances by contract, TR NOX
Annual allowances and proceeds of transactions involving TR
NOX Annual allowances will be deemed to be held or
distributed in accordance with the contract.''
(5) The signature of the designated representative and any
alternate designated representative and the dates signed.
(b) Unless otherwise required by the Administrator, documents of
agreement referred to in the certificate of representation shall not be
submitted to the Administrator. The Administrator shall not be under
any obligation to review or evaluate the sufficiency of such documents,
if submitted.
Sec. 97.417 Objections concerning designated representative and
alternate designated representative.
(a) Once a complete certificate of representation under Sec.
97.416 has been submitted and received, the Administrator will rely on
the certificate of representation unless and until a superseding
complete certificate of representation under Sec. 97.416 is received
by the Administrator.
(b) Except as provided in Sec. 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.
Sec. 97.418 Delegation by designated representative and alternate
designated representative.
(a) A designated representative may delegate, to one or more
natural persons, his or her authority to make an electronic submission
to the Administrator provided for or required under this subpart.
(b) An alternate designated representative may delegate, to one or
more natural persons, his or her authority to make an electronic
submission to the Administrator provided for or required under this
subpart.
(c) In order to delegate authority to 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
[[Page 45380]]
be effective, with regard to the designated representative or alternate
designated representative identified in such notice, upon receipt of
such notice by the Administrator and until receipt by the Administrator
of a superseding notice of delegation submitted by such designated
representative or alternate designated representative, as appropriate.
The superseding notice of delegation may replace any previously
identified agent, add a new agent, or eliminate entirely any delegation
of authority.
(e) Any electronic submission covered by the certification in
paragraph (c)(4)(i) of this section and made in accordance with a
notice of delegation effective under paragraph (d) of this section
shall be deemed to be an electronic submission by the designated
representative or alternate designated representative submitting such
notice of delegation.
Sec. 97.419 [Reserved]
Sec. 97.420 Establishment of Allowance Management System accounts.
(a) Compliance accounts. Upon receipt of a complete certificate of
representation under Sec. 97.416, the Administrator will establish a
compliance account for the TR NOX Annual source for which
the certificate of representation was submitted, unless the source
already has a compliance account. The designated representative and any
alternate designated representative of the source shall be the
authorized account representative and the alternate authorized account
representative respectively of the compliance account.
(b) General accounts--(1) Application for general account.
(i) Any person may apply to open a general account, for the purpose
of holding and transferring TR NOX Annual allowances, by
submitting to the Administrator a complete application for a general
account. Such application shall designate one and only one authorized
account representative and may designate one and only one alternate
authorized account representative who may act on behalf of the
authorized account representative.
(A) The authorized account representative and alternate authorized
account representative shall be selected by an agreement binding on the
persons who have an ownership interest with respect to TR
NOX Annual allowances held in the general account.
(B) The agreement by which the alternate authorized account
representative is selected shall include a procedure for authorizing
the alternate authorized account representative to act in lieu of the
authorized account representative.
(ii) A complete application for a general account shall include the
following elements in a format prescribed by the Administrator:
(A) Name, mailing address, e-mail address (if any), telephone
number, and facsimile transmission number (if any) of the authorized
account representative and any alternate authorized account
representative;
(B) An identifying name for the general account;
(C) A list of all persons subject to a binding agreement for the
authorized account representative and any alternate authorized account
representative to represent their ownership interest with respect to
the TR NOX Annual allowances held in the general account;
(D) The following certification statement by the authorized account
representative and any alternate authorized account representative: ``I
certify that I was selected as the authorized account representative or
the alternate authorized account representative, as applicable, by an
agreement that is binding on all persons who have an ownership interest
with respect to TR NOX Annual allowances held in the general
account. I certify that I have all the necessary authority to carry out
my duties and responsibilities under the TR NOX Annual
Trading Program on behalf of such persons and that each such person
shall be fully bound by my representations, actions, inactions, or
submissions and by any 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 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
[[Page 45381]]
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 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:
(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
[[Page 45382]]
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 Sec. 97.422 for any TR NOX Annual allowances
in the account to one or more other Allowance Management System
accounts.
(ii) If a general account has no TR NOX Annual allowance
transfers to or from the account for a 12-month period or longer and
does not contain any TR NOX Annual allowances, the
Administrator may notify the authorized account representative for the
account that the account will be closed after 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 Annual allowance transfer under
Sec. 97.422 to the account or a statement submitted by the authorized
account representative or alternate authorized account representative
demonstrating to the satisfaction of the Administrator good cause as to
why the account should not be closed.
(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 Sec. Sec.
97.414(a) and 97.418 or paragraphs (b)(2)(ii) and (b)(5) of this
section.
Sec. 97.421 Recordation of TR NOX Annual allowance allocations.
(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 Sec. Sec. 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
compliance account the TR NOX Annual allowances allocated
for the TR NOX Annual units at the source in accordance with
Sec. 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
Sec. 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.
Sec. 97.422 Submission of TR NOX Annual allowance transfers.
(a) An authorized account representative seeking recordation of a
TR NOX Annual allowance transfer shall submit the transfer
to the Administrator.
(b) A TR NOX Annual allowance transfer shall be
correctly submitted if:
(1) The transfer includes the following elements, in a format
prescribed by the Administrator:
(i) The account numbers established by the Administrator for both
the transferor and transferee accounts;
(ii) The serial number of each TR NOX Annual allowance
that is in the transferor account and is to be transferred; and
(iii) The name and signature of the authorized account
representative of the transferor account and the date signed; and
(2) When the Administrator attempts to record the transfer, the
transferor account includes each TR NOX Annual allowance
identified by serial number in the transfer.
Sec. 97.423 Recordation of TR NOX Annual allowance transfers.
(a) Within 5 business days (except as provided in paragraph (b) of
this section) of receiving a TR NOX Annual allowance
transfer, 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
Sec. 97.422.
(b)(1) A TR NOX Annual allowance transfer that is
submitted for recordation after the allowance transfer deadline for a
control period and that includes any TR NOX Annual
allowances allocated for any control period before such allowance
transfer deadline will not be recorded until after the Administrator
completes the deductions under Sec. 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 Sec. 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 Sec. 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 Sec. 97.422, the Administrator will not
record such transfer.
(d) Within 5 business days of recordation of a TR NOX
Annual allowance transfer under paragraphs (a) and (b) of the section,
the Administrator will notify the authorized account representatives of
both the transferor and transferee accounts.
(e) Within 10 business days of receipt of a TR NOX
Annual allowance transfer that is not correctly submitted under Sec.
97.422, the Administrator will notify the authorized account
representatives of both accounts subject to the transfer of:
(1) A decision not to record the transfer, and
(2) The reasons for such non-recordation.
Sec. 97.424 Compliance with TR NOX Annual emissions limitation.
(a) Availability for deduction for compliance. TR NOX
Annual allowances are available to be deducted for compliance with a
source's TR NOX Annual emissions limitation for a control
period in a given year only if the TR NOX Annual allowances:
(1) Were allocated for 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 Sec. 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
[[Page 45383]]
(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.
(e) Recordation of deductions. The Administrator will record in the
appropriate compliance account all deductions from such an account
under paragraphs (b) and (d) of this section.
Sec. 97.425 Compliance with TR NOX Annual assurance provisions.
(a) Availability for deduction. TR NOX Annual allowances
are available to be deducted for compliance with the TR NOX
Annual assurance provisions for a control period in a given year by 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 Sec. 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 Sec. Sec.
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 Sec.
97.406(c)(2)(iii) and Sec. Sec. 97.406(b) and 97.430 through 97.435.
(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 Sec. 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 Sec.
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 Sec. 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
[[Page 45384]]
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 Sec. 97.402, and the
calculation formula in Sec. 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 allowance-holding 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 Sec.
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 Sec. 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 Sec. 97.406(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.
(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 Sec.
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
[[Page 45385]]
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 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.
Sec. 97.426 Banking.
(a) A TR NOX Annual allowance may be banked for future
use or transfer in a compliance account or a general account in
accordance with paragraph (b) of this section.
(b) Any TR NOX Annual allowance that is held in a
compliance account or a general account will remain in such account
unless and until the TR NOX Annual allowance is deducted or
transferred under Sec. 97.411(c), Sec. 97.423, Sec. 97.424, Sec.
97.425, 97.427, 97.428, 97.442, or 97.443.
Sec. 97.427 Account error.
The Administrator may, at his or her sole discretion and on his or
her own motion, correct any error in any Allowance Management System
account. Within 10 business days of making such correction, the
Administrator will notify the authorized account representative for the
account.
Sec. 97.428 Administrator's action on submissions.
(a) The Administrator may review and conduct independent audits
concerning any submission under the TR NOX Annual Trading
Program and make appropriate adjustments of the information in the
submission.
(b) The Administrator may deduct TR NOX Annual
allowances from or transfer TR NOX Annual allowances to a
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.
Sec. 97.429 [Reserved]
Sec. 97.430 General monitoring, recordkeeping, and reporting
requirements.
The owners and operators, and to the extent applicable, the
designated representative, of a TR NOX Annual unit, shall
comply with the monitoring, recordkeeping, and reporting requirements
as provided in this subpart and subpart H of part 75 of this chapter.
For purposes of applying such requirements, the definitions in Sec.
97.402 and in Sec. 72.2 of this chapter shall apply, the terms
``affected unit,'' ``designated representative,'' and ``continuous
emission monitoring system'' (or ``CEMS'') in part 75 of this chapter
shall be deemed to refer to the terms ``TR NOX Annual
unit,'' ``designated representative,'' and ``continuous emission
monitoring system'' (or ``CEMS'') respectively as defined in Sec.
97.402, and the term ``newly affected unit'' shall be deemed to mean
``newly affected TR NOX Annual unit''. The owner or operator
of a unit that is not a TR NOX Annual unit but that is
monitored under Sec. 75.72(b)(2)(ii) of this chapter shall comply with
the same monitoring, recordkeeping, and reporting requirements as a TR
NOX Annual unit.
(a) Requirements for installation, certification, and data
accounting. The owner or operator of each TR NOX Annual unit
shall:
(1) Install all monitoring systems required under this subpart for
monitoring NOX mass emissions and individual unit heat input
(including all systems required to monitor NOX emission
rate, NOX concentration, stack gas moisture content, stack
gas flow rate, CO2 or O2 concentration, and fuel
flow rate, as applicable, in accordance with Sec. Sec. 75.71 and 75.72
of this chapter);
(2) Successfully complete all certification tests required under
Sec. 97.431 and meet all other requirements of this subpart and part
75 of this chapter applicable to the monitoring systems under paragraph
(a)(1) of this section; and
(3) Record, report, and quality-assure the data from the monitoring
systems under paragraph (a)(1) of this section.
(b) Compliance deadlines. Except as provided in paragraph (e) of
this section, the owner or operator shall meet the monitoring system
certification and other requirements of paragraphs (a)(1) and (2) of
this section on or before the following dates and shall record, report,
and quality-assure the data from the monitoring systems under paragraph
(a)(1) of this section on and after the following dates.
(1) For the owner or operator of a TR NOX Annual unit
that commences commercial operation before July 1, 2011, January 1,
2012;
(2) For the owner or operator of a TR NOX Annual unit
that commences commercial operation on or after July 1, 2011, the later
of the following:
(i) January 1, 2012; or
(ii) 180 calendar days, 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
[[Page 45386]]
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 Sec. 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
Sec. 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 Sec. 75.31(b)(2) or (c)(3) of this chapter, section 2.4 of
appendix D to part 75 of this chapter, or section 2.5 of appendix E to
part 75 of this chapter, as applicable.
(d) Prohibitions. (1) No owner or operator of a TR NOX
Annual unit shall use any alternative monitoring system, alternative
reference method, or any other alternative to any requirement of this
subpart without having obtained prior written approval in accordance
with Sec. 97.435.
(2) No owner or operator of a TR NOX Annual unit shall
operate the unit so as to discharge, or allow to be discharged,
NOX 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 calibration, quality assurance testing, or maintenance is
performed in accordance with the applicable provisions of this subpart
and part 75 of this chapter.
(4) No owner or operator of a TR NOX Annual unit shall
retire or permanently discontinue use of the continuous emission
monitoring system, any component thereof, or any other approved
monitoring system under this subpart, except under any one of the
following circumstances:
(i) During the period that the unit is covered by an exemption
under Sec. 97.405 that is in effect;
(ii) The owner or operator is monitoring emissions from the unit
with another certified monitoring system approved, in accordance with
the applicable provisions of this subpart and part 75 of this chapter,
by the Administrator for use at that unit that provides emission data
for the same pollutant or parameter as the retired or discontinued
monitoring system; or
(iii) The designated representative submits notification of the
date of certification testing of a replacement monitoring system for
the retired or discontinued monitoring system in accordance with Sec.
97.431(d)(3)(i).
(e) Long-term cold storage. The owner or operator of a TR
NOX Annual unit is subject to the applicable provisions of
Sec. 75.4(d) of this chapter concerning units in long-term cold
storage.
Sec. 97.431 Initial monitoring system certification and
recertification procedures.
(a) The owner or operator of a TR NOX Annual unit shall
be exempt from the initial certification requirements of this section
for a monitoring system under Sec. 97.430(a)(1) if the following
conditions are met:
(1) The monitoring system has been previously certified in
accordance with part 75 of this chapter; and
(2) The applicable quality-assurance and quality-control
requirements of Sec. 75.21 of this chapter and appendices B, D, and E
to part 75 of this chapter are fully met for the certified monitoring
system described in paragraph (a)(1) of this section.
(b) The recertification provisions of this section shall apply to a
monitoring system under Sec. 97.430(a)(1) that is exempt from initial
certification requirements under paragraph (a) of this section.
(c) If the Administrator has previously approved a petition under
Sec. 75.17(a) or (b) of this chapter for apportioning the
NOX emission rate measured in a common stack or a petition
under Sec. 75.66 of this chapter for an alternative to a requirement
in Sec. 75.12 or Sec. 75.17 of this chapter, the designated
representative shall resubmit the petition to the Administrator under
Sec. 97.435 to determine whether the approval applies under the TR
NOX Annual Trading Program.
(d) Except as provided in paragraph (a) of this section, the owner
or operator of a TR NOX Annual unit shall comply with the
following initial certification and recertification procedures for a
continuous monitoring system (i.e., a continuous emission monitoring
system and an excepted monitoring system under appendices D and E to
part 75 of this chapter) under Sec. 97.430(a)(1). The owner or
operator of a unit that qualifies to use the low mass emissions
excepted monitoring methodology under Sec. 75.19 of this chapter or
that qualifies to use an alternative monitoring system under subpart E
of part 75 of this chapter shall comply with the procedures in
paragraph (e) or (f) of this section respectively.
(1) Requirements for initial certification. The owner or operator
shall ensure that each continuous monitoring system under Sec.
97.430(a)(1) (including the automated data acquisition and handling
system) successfully completes all of the initial certification testing
required under Sec. 75.20 of this chapter by the applicable deadline
in Sec. 97.430(b).
In addition, whenever the owner or operator installs a monitoring
system to meet the requirements of this subpart in a location where no
such monitoring system was previously installed, initial certification
in accordance with Sec. 75.20 of this chapter is required.
(2) Requirements for recertification. Whenever the owner or
operator makes a replacement, modification, or change in any certified
continuous emission monitoring system under Sec. 97.430(a)(1) that may
significantly affect the ability of the system to accurately measure or
record NOX mass emissions or heat input rate or to meet the
quality-assurance and quality-control requirements of Sec. 75.21 of
this chapter or appendix B to part 75 of this chapter, the owner or
operator shall recertify the monitoring system in accordance with Sec.
75.20(b) of this chapter. Furthermore, whenever the owner or operator
makes a replacement, modification, or change to the flue gas handling
system or the unit's operation that may significantly change the stack
flow or concentration profile, the owner or operator shall recertify
each continuous emission monitoring system whose accuracy is
potentially affected by the change, in accordance with Sec. 75.20(b)
of this chapter. Examples of changes to a continuous emission
monitoring system that require recertification include replacement of
the analyzer, complete
[[Page 45387]]
replacement of an existing continuous emission monitoring system, or
change in location or orientation of the sampling probe or site. Any
fuel flowmeter system, and any excepted NOX monitoring
system under appendix E to part 75 of this chapter, under Sec.
97.430(a)(1) are subject to the recertification requirements in Sec.
75.20(g)(6) of this chapter.
(3) Approval process for initial certification and recertification.
For initial certification of a continuous monitoring system under Sec.
97.430(a)(1), paragraphs (d)(3)(i) through (v) of this section apply.
For recertifications of such monitoring systems, paragraphs (d)(3)(i)
through (iv) of this section and the procedures in Sec. Sec.
75.20(b)(5) and (g)(7) of this chapter (in lieu of the procedures in
paragraph (d)(3)(v) of this section) apply, provided that in applying
paragraphs (d)(3)(i) through (iv) of this section, the words
``certification'' and ``initial certification'' are replaced by the
word ``recertification'' and the word ``certified'' is replaced by with
the word ``recertified''.
(i) Notification of certification. The designated representative
shall submit to the appropriate EPA Regional Office and the
Administrator written notice of the dates of certification testing, in
accordance with Sec. 97.433.
(ii) Certification application. The designated representative shall
submit to the Administrator a certification application for each
monitoring system. A complete certification application shall include
the information specified in Sec. 75.63 of this chapter.
(iii) Provisional certification date. The provisional certification
date for a monitoring system shall be determined in accordance with
Sec. 75.20(a)(3) of this chapter. A provisionally certified monitoring
system may be used under the TR NOX Annual Trading Program
for a period not to exceed 120 days after receipt by the Administrator
of the complete certification application for the monitoring system
under paragraph (d)(3)(ii) of this section. Data measured and recorded
by the provisionally certified monitoring system, in accordance with
the requirements of part 75 of this chapter, will be considered valid
quality-assured data (retroactive to the date and time of provisional
certification), provided that the Administrator does not invalidate the
provisional certification by issuing a notice of disapproval within 120
days of the date of receipt of the complete certification application
by the Administrator.
(iv) Certification application approval process. The Administrator
will issue a written notice of approval or disapproval of the
certification application to the owner or operator within 120 days of
receipt of the complete certification application under paragraph
(d)(3)(ii) of this section. In the event the Administrator does not
issue such a notice within such 120-day period, each monitoring system
that meets the applicable performance requirements of part 75 of this
chapter and is included in the certification application will be deemed
certified for use under the TR NOX Annual Trading Program.
(A) Approval notice. If the certification application is complete
and shows that each monitoring system meets the applicable performance
requirements of part 75 of this chapter, then the Administrator will
issue a written notice of approval of the certification application
within 120 days of receipt.
(B) Incomplete application notice. If the certification application
is not complete, then the Administrator will issue a written notice of
incompleteness that sets a reasonable date by which the designated
representative must submit the additional information required to
complete the certification application. If the designated
representative does not comply with the notice of incompleteness by the
specified date, then the Administrator may issue a notice of
disapproval under paragraph (d)(3)(iv)(C) of this section. 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 Sec. 75.20(a)(3) of this chapter).
(D) Audit decertification. The Administrator may issue a notice of
disapproval of the certification status of a monitor in accordance with
Sec. 97.432(b).
(v) Procedures for loss of certification. If the Administrator
issues a notice of disapproval of a certification application under
paragraph (d)(3)(iv)(C) of this section or a notice of disapproval of
certification status under paragraph (d)(3)(iv)(D) of this section,
then:
(A) The owner or operator shall substitute the following values,
for each disapproved monitoring system, for each hour of unit operation
during the period of invalid data specified under Sec.
75.20(a)(4)(iii), Sec. 75.20(g)(7), or Sec. 75.21(e) of this chapter
and continuing until the applicable date and hour specified under Sec.
75.20(a)(5)(i) or (g)(7) of this chapter:
(1) For a disapproved NOX emission rate (i.e.,
NOX-diluent) system, the maximum potential NOX
emission rate, as defined in Sec. 72.2 of this chapter.
(2) For a disapproved NOX pollutant concentration
monitor and disapproved flow monitor, respectively, the maximum
potential concentration of NOX and the maximum potential
flow rate, as defined in sections 2.1.2.1 and 2.1.4.1 of appendix A to
part 75 of this chapter.
(3) For a disapproved moisture monitoring system and disapproved
diluent gas monitoring system, respectively, the minimum potential
moisture percentage and either the maximum potential CO2
concentration or the minimum potential O2 concentration (as
applicable), as defined in sections 2.1.5, 2.1.3.1, and 2.1.3.2 of
appendix A to part 75 of this chapter.
(4) For a disapproved fuel flowmeter system, the maximum potential
fuel flow rate, as defined in section 2.4.2.1 of appendix D to part 75
of this chapter.
(5) For a disapproved excepted NOX monitoring system
under appendix E to part 75 of this chapter, the fuel-specific maximum
potential NOX emission rate, as defined in Sec. 72.2 of
this chapter.
(B) The designated representative shall submit a notification of
certification retest dates and a new certification application in
accordance with paragraphs (d)(3)(i) and (ii) of this section.
(C) The owner or operator shall repeat all certification tests or
other requirements that were failed by the monitoring system, as
indicated in the Administrator's notice of disapproval, no later than
30 unit operating days after the date of issuance of the notice of
disapproval.
(e) The owner or operator of a unit qualified to use the low mass
emissions (LME) excepted methodology under Sec. 75.19 of this chapter
shall meet the applicable certification and recertification
requirements in Sec. Sec. 75.19(a)(2) and 75.20(h) of this chapter. If
the owner or operator of such
[[Page 45388]]
a unit elects to certify a fuel flowmeter system for heat input
determination, the owner or operator shall also meet the certification
and recertification requirements in Sec. 75.20(g) of this chapter.
(f) The designated representative of each unit for which the owner
or operator intends to use an alternative monitoring system approved by
the Administrator under subpart E of part 75 of this chapter shall
comply with the applicable notification and application procedures of
Sec. 75.20(f) of this chapter.
Sec. 97.432 Monitoring system out-of-control periods.
(a) General provisions. Whenever any monitoring system fails to
meet the quality-assurance and quality-control requirements or data
validation requirements of part 75 of this chapter, data shall be
substituted using the applicable missing data procedures in subpart D
or subpart H of, or appendix D or appendix E to, part 75 of this
chapter.
(b) Audit decertification. Whenever both an audit of a monitoring
system and a review of the initial certification or recertification
application reveal that any monitoring system should not have been
certified or recertified because it did not meet a particular
performance specification or other requirement under Sec. 97.431 or
the applicable provisions of part 75 of this chapter, both at the time
of the initial certification or 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 Sec.
97.431 for each disapproved monitoring system.
Sec. 97.433 Notifications concerning monitoring.
The designated representative of a TR NOX Annual unit
shall submit written notice to the Administrator in accordance with
Sec. 75.61 of this chapter.
Sec. 97.434 Recordkeeping and reporting.
(a) General provisions. The designated representative shall comply
with all recordkeeping and reporting requirements in paragraphs (b)
through (e) of this section, the applicable recordkeeping and reporting
requirements under Sec. 75.73 of this chapter, and the requirements of
Sec. 97.414(a).
(b) Monitoring plans. The owner or operator of a TR NOX
Annual unit shall comply with requirements of Sec. 75.73(c) and (e) of
this chapter.
(c) Certification applications. The designated representative shall
submit an application to the Administrator within 45 days after
completing all initial certification or recertification tests required
under Sec. 97.431, including the information required under Sec.
75.63 of this chapter.
(d) Quarterly reports. The designated representative shall submit
quarterly reports, as follows:
(1) The designated representative shall report the NOX
mass emissions data and heat input data for the TR NOX
Annual unit, in an electronic quarterly report in a format prescribed
by the Administrator, for each calendar quarter beginning with:
(i) For a unit that commences commercial operation before July 1,
2011, the calendar quarter covering January 1, 2012 through March 31,
2012;
(ii) For a unit that commences commercial operation on or after
July 1, 2011, the calendar quarter corresponding to the earlier of the
date of provisional certification or the applicable deadline for
initial certification under Sec. 97.430(b), unless that quarter is the
third or fourth quarter of 2011, in which case reporting shall commence
in the quarter covering January 1, 2012 through March 31, 2012;
(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 Sec. 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
Sec. 97.441(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 Sec. 75.73(f) of this chapter.
(3) For TR NOX Annual units that are also subject to the
Acid Rain Program, TR NOX Ozone Season Trading Program, TR
SO2 Group 1 Trading Program, or TR SO2 Group 2
Trading Program, quarterly reports shall include the applicable data
and information required by subparts F through H of part 75 of this
chapter as applicable, in addition to the NOX mass emission
data, heat input data, and other information required by this subpart.
(4) The Administrator may review and conduct independent audits of
any quarterly report in order to determine whether the quarterly report
meets the requirements of this subpart and part 75 of this chapter,
including the requirement to use substitute data.
(i) The Administrator will notify the designated representative of
any determination that the quarterly report fails to meet any such
requirements and specify in such notification any corrections that the
Administrator believes are necessary to make through resubmission of
the quarterly report and a reasonable time period within which the
designated representative must respond. Upon request by the designated
representative, the Administrator may specify reasonable extensions of
such time period. Within the time period (including any such
extensions) specified by the Administrator, the designated
representative shall resubmit the quarterly report with the corrections
specified by the Administrator, except to the extent the designated
representative provides information demonstrating that a specified
correction is not necessary because the quarterly report already meets
the requirements of this subpart and part 75 of this chapter that are
relevant to the specified correction.
(ii) Any resubmission of a quarterly report shall meet the
requirements applicable to the submission of a quarterly report under
this subpart and part 75 of this chapter, except for the deadline set
forth in paragraph (d)(2) of this section.
(e) Compliance certification. The designated representative shall
submit to the Administrator a compliance certification (in a format
prescribed by the Administrator) in support of each quarterly report
based on reasonable inquiry of those persons with primary
responsibility for ensuring that all of the
[[Page 45389]]
unit's emissions are correctly and fully monitored. The certification
shall state that:
(1) The monitoring data submitted were recorded in accordance with
the applicable requirements of this subpart and part 75 of this
chapter, including the quality assurance procedures and specifications;
and
(2) For a unit with add-on NOX emission controls and for
all hours where NOX data are substituted in accordance with
Sec. 75.34(a)(1) of this chapter, the add-on emission controls were
operating within the range of parameters listed in the quality
assurance/quality control program under appendix B to part 75 of this
chapter and the substitute data values do not systematically
underestimate NOX emissions.
Sec. 97.435 Petitions for alternatives to monitoring, recordkeeping,
or reporting requirements.
(a) The designated representative of a TR NOX Annual
unit may submit a petition under Sec. 75.66 of this chapter to the
Administrator, requesting approval to apply an alternative to any
requirement of Sec. Sec. 97.430 through 97.434 or paragraph (5)(i) or
(ii) of the definition of ``owner's share'' in Sec. 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.
Sec. 97.440 General requirements for TR NOX Annual opt-in units.
(a) A TR NOX Annual opt-in unit must be a unit that:
(1) Is located in a State;
(2) Is not a TR NOX Annual unit under Sec. 97.404;
(3) Is not covered by a retired unit exemption under Sec. 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 Sec. Sec. 97.405, 97.411, and 97.412.
(c) Solely for purposes of applying the requirements of Sec. Sec.
97.413 through 97.418 and Sec. Sec. 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 Sec. 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 Sec. 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.
Sec. 97.441 Opt-In process.
A unit meeting the requirements for a TR NOX Annual opt-
in unit in Sec. 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 Sec. 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 Sec. 97.404;
(ii) Is not covered by a retired unit exemption under Sec. 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 Sec. Sec. 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 Sec. 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 Sec. 97.443;
(6) A complete certificate of representation under Sec. 97.416
consistent with Sec. 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 Sec. Sec. 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 Sec. Sec.
97.430 through 97.435, starting on the date of certification of the
necessary monitoring systems under Sec. Sec. 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 Sec. 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
[[Page 45390]]
be less than 98 percent under Sec. Sec. 97.430 through 97.435 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 emission rate and the heat
input of the unit are monitored and reported in accordance with
Sec. Sec. 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 Sec. Sec. 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 emissions-
related 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 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; 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 Sec.
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 opt-
in 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 opt-in
unit in Sec. 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.
Sec. 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 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 Sec.
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 Sec. Sec. 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
Sec. 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 Sec. Sec.
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
[[Page 45391]]
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 Sec. 97.441 for such
unit before the date that is 4 years after the date on which the
withdrawal became effective.
Sec. 97.443 Change in regulatory status.
(a) Notification. If a TR NOX Annual opt-in unit becomes
a TR NOX Annual unit under Sec. 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 Sec. 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 Sec. 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 Sec. 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 Sec. 97.404;
and
(ii) If the date on which the TR NOX Annual opt-in unit
becomes a TR NOX Annual unit under Sec. 97.404 is not
December 31, the TR NOX Annual allowances allocated to the
TR NOX Annual opt-in unit under Sec. 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 Sec.
97.404--
(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 Sec. 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 Sec. 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 Sec. 97.404, the TR NOX Annual opt-in unit will
be allocated TR NOX Annual allowances in accordance with
Sec. 97.412.
(ii) If the date on which the TR NOX Annual opt-in unit
becomes a TR NOX Annual unit under Sec. 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 Sec.
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 Sec. 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 Sec. 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 Sec. 97.404,
divided by the total number of days in the control period; and (C)
Rounded to the nearest allowance.
Sec. 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 Sec. 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 Sec. 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 Sec. 97.441(h) and
October 31 of each year thereafter, the Administrator will issue TR
NOX Annual allowances and allocate them to 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 Sec. 97.441(g); or
(ii) The TR NOX Annual opt-in unit's heat input, as
determined in accordance with Sec. Sec. 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
Sec. 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 Sec.
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 opt-in 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 Sec. 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
[[Page 45392]]
Annual opt-in unit under paragraph (a)(2) of this section.
36. Part 97 is amended by adding subpart BBBBB to read as follows:
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.
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 opt-in units.
Subpart BBBBB--TR NOX Ozone Season Trading Program
Sec. 97.501 Purpose.
This subpart sets forth the general, designated representative,
allowance, and monitoring provisions for the Transport Rule (TR)
NOX Ozone Season Trading Program, under section 110 of the
Clean Air Act and Sec. 52.37(b) of this chapter, as a means of
mitigating interstate transport of fine particulates and nitrogen
oxides.
Sec. 97.502 Definitions.
The terms used in this subpart shall have the meanings set forth in
this section as follows:
Acid Rain Program means a multi-state SO2 and
NOX air pollution control and emission reduction program
established by the Administrator under title IV of the Clean Air Act
and parts 72 through 78 of this chapter.
Administrator means the Administrator of the United States
Environmental Protection Agency or the Director of the Clean Air
Markets Division (or its successor) 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
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 Sec. 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 Sec.
72.2 of this chapter, Sec. 97.402, Sec. 97.602, or Sec. 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;
[[Page 45393]]
(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 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 system-wide basis the requirement in paragraph (2)(i)(B) of
this definition, the topping-cycle 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 Sec. 97.505.
(i) For a unit that is a TR NOX Ozone Season unit under
Sec. 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 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
Sec. 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 Sec. 97.505, for a unit that is not a TR NOX
Ozone Season unit under Sec. 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 Sec. 97.504.
(i) For a unit with a date for commencement of commercial operation
as defined in the introductory text of paragraph (2) of this definition
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)
[[Page 45394]]
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 Sec. 97.524 and the TR NOX
Ozone Season assurance provisions in accordance with Sec. 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 Sec. Sec. 97.530 through 97.535. The following
systems are the principal types of continuous emission monitoring
systems:
(1) A flow monitoring system, consisting of a stack flow rate
monitor and an automated data acquisition and handling system and
providing a permanent, continuous record of stack gas volumetric flow
rate, in standard cubic feet per hour (scfh);
(2) A NOX concentration monitoring system, consisting of
a NOX pollutant concentration monitor and an automated data
acquisition and handling system and providing a permanent, continuous
record of NOX emissions, in parts per million (ppm);
(3) A NOX emission rate (or NOX-diluent)
monitoring system, consisting of a NOX pollutant
concentration monitor, a diluent gas (CO2 or O2)
monitor, and an automated data acquisition and handling system and
providing a permanent, continuous record of NOX
concentration, in parts per million (ppm), diluent gas concentration,
in percent CO2 or O2, and NOX emission
rate, in pounds per million British thermal units (lb/mmBtu);
(4) A moisture monitoring system, as defined in Sec. 75.11(b)(2)
of this chapter and providing a permanent, continuous record of the
stack gas moisture content, in percent H2O;
(5) A CO2 monitoring system, consisting of a
CO2 pollutant concentration monitor (or an O2
monitor plus suitable mathematical equations from which the
CO2 concentration is derived) and an automated data
acquisition and handling system and providing a permanent, continuous
record of CO2 emissions, in percent CO2; and
(6) An O2 monitoring system, consisting of an
O2 concentration monitor and an automated data acquisition
and handling system and providing a permanent, continuous record of
O2, in percent O2.
Control period means the period starting May 1 of a calendar year,
except as provided in Sec. 97.506(c)(3), and 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 Sec. 72.2 of this chapter, Sec. 97.402, Sec. 97.602, or Sec.
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.
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 Sec. Sec. 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;
[[Page 45395]]
(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 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 Sec. Sec. 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 Sec. 97.506(c)(2)(iii)(A)
and not as described in Sec. 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 Sec. 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 Sec. 97.510(a) and the State's one-year
variability limit under Sec. 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 Sec. 97.510(a) and the State's three-year
variability limit under Sec. 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
Sec. 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--
[[Page 45396]]
(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
Sec. Sec. 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 Sec. 75.22 of this
chapter.
Replacement, replace, or replaced means, with regard to a unit, the
demolishing of a unit, or the permanent retirement and permanent
disabling of a unit, and the construction of another unit (the
replacement unit) to be used instead of the demolished or retired unit
(the replaced unit).
Sequential use of energy means:
(1) 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 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 Sec. 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.
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 Sec.
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.
[[Page 45397]]
TR NOX Ozone Season unit means a unit that is subject to the TR
NOX Ozone Season Trading Program under Sec. 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-fuel-fired 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.
Sec. 97.503 Measurements, abbreviations, and acronyms.
Measurements, abbreviations, and acronyms used in this subpart are
defined as follows:
Btu--British thermal unit
CO2--carbon dioxide
H2O--water
hr--hour
kW--kilowatt electrical
kWh--kilowatt hour
lb--pound
mmBtu--million Btu
MWe--megawatt electrical
MWh--megawatt hour
NOX--nitrogen oxides
O2--oxygen
ppm--parts per million
scfh--standard cubic feet per hour
SO2--sulfur dioxide
yr--year
Sec. 97.504 Applicability.
(a) Except as provided in paragraph (b) of this section:
(1) The following units in a State shall be TR NOX Ozone
Season units, and any source that includes one or more such units shall
be a TR NOX Ozone Season source, subject to the requirements
of this subpart: Any stationary, fossil-fuel-fired boiler or
stationary, fossil-fuel-fired combustion turbine serving at any time,
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 start-up 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 NOX Ozone Season unit starting on the earlier of
January 1 after the first calendar year during which the unit first no
longer qualifies as a cogeneration unit or January 1 after the first
calendar year during which the unit no longer meets the requirements of
paragraph (b)(1)(i)(B) of this section.
(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
[[Page 45398]]
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.
Sec. 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 Sec. 97.506(b) and (c)(1), Sec. 97.524, and Sec. Sec.
97.530 through 97.535.
(2) The exemption under paragraph (a)(1) of this section shall
become effective the day on which the TR NOX Ozone Season
unit is permanently retired. Within 30 days of the unit's permanent
retirement, the designated representative shall submit a statement to
the Administrator. The statement shall state, in a format prescribed by
the Administrator, that the unit was permanently retired on a specified
date and will comply with the requirements of paragraph (b) of this
section.
(b) Special provisions. (1) A unit exempt under paragraph (a) of
this section shall not emit any NOX, starting on the date
that the exemption takes effect.
(2) For a period of 5 years from the date the records are created,
the owners and operators of a unit exempt under paragraph (a) of this
section shall retain, at the source that includes the unit, records
demonstrating that the unit is permanently retired. The 5-year period
for keeping records may be extended for cause, at any time before the
end of the period, in writing by the Administrator. The owners and
operators bear the burden of proof that the unit is permanently
retired.
(3) The owners and operators and, to the extent applicable, the
designated representative of a unit exempt under paragraph (a) of this
section shall comply with the requirements of the TR NOX
Ozone Season Trading Program concerning all periods for which the
exemption is not in effect, even if such requirements arise, or must be
complied with, after the exemption takes effect.
(4) A unit exempt under paragraph (a) of this section shall lose
its exemption on the first date on which the unit resumes operation.
Such unit shall be treated, for purposes of applying allocation,
monitoring, reporting, and recordkeeping requirements under this
subpart, as a unit that commences commercial operation on the first
date on which the unit resumes operation.
Sec. 97.506 Standard requirements.
(a) Designated representative requirements. The owners and
operators shall comply with the requirement to have a designated
representative, and may have an alternate designated representative, in
accordance with Sec. Sec. 97.513 through 97.518.
(b) Emissions monitoring, reporting, and recordkeeping
requirements. (1) The owners and operators, and the designated
representative, of each TR NOX Ozone Season source and each
TR NOX Ozone Season unit at the source shall comply with the
monitoring, reporting, and recordkeeping requirements of Sec. Sec.
97.530 through 97.535.
(2) The emissions data determined in accordance with Sec. Sec.
97.530 through 97.535 shall be used to calculate allocations of TR
NOX Ozone Season allowances under Sec. Sec. 97.511(a)(2)
and (b) and 97.512 and to determine compliance with the TR
NOX Ozone Season emissions limitation and assurance
provisions under paragraph (c) of this section, provided that, for each
monitoring location from which mass emissions are reported, the mass
emissions amount used in calculating such allocations and determining
such compliance shall be the mass emissions amount for the monitoring
location determined in accordance with Sec. Sec. 97.530 through 97.535
and rounded to the nearest ton, with any fraction of a ton less than
0.50 being deemed to be zero.
(c) NOX emissions requirements--(1) TR NOX Ozone Season emissions
limitation. (i) As of the allowance transfer deadline for a control
period, the owners and operators of each TR NOX Ozone Season
source and each TR NOX Ozone Season unit at the source shall
hold, in the source's compliance account, TR NOX Ozone
Season allowances available for deduction for such control period under
Sec. 97.524(a) in an amount not less than the tons of total
NOX emissions for such control period from all TR
NOX Ozone Season units at the source.
(ii) If 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
Sec. 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 Sec. 97.525(b)(4)(ii), TR NOX Ozone Season allowances
available for deduction for such control period under Sec. 97.525(a)
in an amount equal to the product, as determined by the Administrator
in accordance with Sec. 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
[[Page 45399]]
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 Sec.
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 Sec. 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 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 Sec. 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 Sec. 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
Sec. 75.19 of this chapter), or an alternative monitoring system
(under subpart E of part 75 of this chapter) in accordance with
Sec. Sec. 97.530 through 97.535 may be added to, or changed in, a
title V permit using minor permit modification procedures in accordance
with Sec. Sec. 70.7(e)(2) and 71.7(e)(1) of this chapter, provided
that the requirements applicable to the described monitoring and
reporting (as added or changed, respectively) are already incorporated
in such permit. This paragraph explicitly provides that the addition
of, or change to, a unit's description as described in the prior
sentence is eligible for minor permit modification procedures in
accordance with Sec. Sec. 70.7(e)(2)(i)(B) and 71.7(e)(1)(i)(B) of
this chapter.
(e) Additional recordkeeping and reporting requirements.
(1) Unless otherwise provided, the owners and operators of each TR
NOX Ozone Season source and each TR NOX Ozone
Season unit at the source shall keep on site at the source each of the
following documents (in hardcopy or electronic format) for a period of
5 years from the date the document is created. This period may be
extended for cause, at any time before the end of 5 years, in writing
by the Administrator.
(i) The certificate of representation under Sec. 97.516 for the
designated representative for the source and each TR NOX
Ozone Season unit at the source and all documents that demonstrate the
truth of the statements in the certificate of representation; provided
that the certificate and documents shall be retained on site at the
source beyond such 5-year period until such documents are superseded
because of the submission of a new certificate of representation under
Sec. 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
[[Page 45400]]
permit program in parts 70 and 71 of this chapter.
(f) Liability. (1) Any provision of the TR NOX Ozone
Season Trading Program that applies to a TR NOX Ozone Season
source or the designated representative of a TR NOX Ozone
Season source shall also apply to the owners and operators of such
source and of the TR NOX Ozone Season units at the source.
(2) Any provision of the TR NOX Ozone Season Trading
Program that applies to a TR NOX Ozone Season unit or the
designated representative of a TR NOX Ozone Season unit
shall also apply to the owners and operators of such unit.
(g) Effect on other authorities. No provision of the TR
NOX Ozone Season Trading Program or exemption under Sec.
97.505 shall be construed as exempting or excluding the owners and
operators, and the designated representative, of a TR NOX
Ozone Season source or TR NOX Ozone Season unit from
compliance with any other provision of the applicable, approved State
implementation plan, a federally enforceable permit, or the Clean Air
Act.
Sec. 97.507 Computation of time.
(a) Unless otherwise stated, any time period scheduled, under the
TR NOX Ozone Season Trading Program, to begin on the
occurrence of an act or event shall begin on the day the act or event
occurs.
(b) Unless otherwise stated, any time period scheduled, under the
TR NOX Ozone Season Trading Program, to begin before the
occurrence of an act or event shall be computed so that the period ends
the day before the act or event occurs.
(c) Unless otherwise stated, if the final day of any time period,
under the TR NOX Ozone Season Trading Program, falls on a
weekend or a State or Federal holiday, the time period shall be
extended to the next business day.
Sec. 97.508 Administrative appeal procedures.
The administrative appeal procedures for decisions of the
Administrator under the TR NOX Ozone Season Trading Program
are set forth in part 78 of this chapter.
Sec. 97.509 [Reserved]
Sec. 97.510 State NOX Ozone Season trading budgets, new-unit set-
asides, 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 New-unit set-
trading budget aside (tons)
(tons)* ------------------
State -------------------
For 2012 and For 2012 and
thereafter thereafter
------------------------------------------------------------------------
Alabama........................... 29,738 892
Arkansas.......................... 16,660 500
Connecticut....................... 1,315 39
Delaware.......................... 2,450 74
District of Columbia.............. 105 3
Florida........................... 56,939 1,708
Georgia........................... 32,144 964
Illinois.......................... 23,570 707
Indiana........................... 49,987 1,500
Kansas............................ 21,433 643
Kentucky.......................... 30,908 927
Louisiana......................... 21,220 637
Maryland.......................... 7,232 217
Michigan.......................... 28,253 848
Mississippi....................... 16,530 496
New Jersey........................ 5,269 158
New York.......................... 11,090 333
North Carolina.................... 23,539 706
Ohio.............................. 40,661 1,220
Oklahoma.......................... 37,087 1,113
Pennsylvania...................... 48,271 1,448
South Carolina.................... 15,222 457
Tennessee......................... 11,575 347
Texas............................. 75,574 2,267
Virginia.......................... 12,608 378
West Virginia..................... 22,234 667
-------------------------------------
Total......................... 641,614 19,249
------------------------------------------------------------------------
* Without variability limits.
(b) The States' one-year and three-year variability limits for the
State NOX Ozone Season trading budgets for the control
periods in 2014 and thereafter are as follows:
[[Page 45401]]
------------------------------------------------------------------------
One-year Three-year
variability variability
limits limits
State -------------------------------------
2014 and 2016 and
thereafter (tons) thereafter (tons)
------------------------------------------------------------------------
Alabama........................... 2,974 1,717
Arkansas.......................... 2,100 1,212
Connecticut....................... 2,100 1,212
Delaware.......................... 2,100 1,212
District of Columbia.............. 2,100 1,212
Florida........................... 5,694 3,287
Georgia........................... 3,214 1,856
Illinois.......................... 2,357 1,361
Indiana........................... 4,999 2,886
Kansas............................ 2,143 1,237
Kentucky.......................... 3,091 1,784
Louisiana......................... 2,122 1,225
Maryland.......................... 2,100 1,212
Michigan.......................... 2,825 1,631
Mississippi....................... 2,100 1,212
New Jersey........................ 2,100 1,212
New York.......................... 2,100 1,212
North Carolina.................... 2,354 1,359
Ohio.............................. 4,066 2,348
Oklahoma.......................... 3,709 2,141
Pennsylvania...................... 4,827 2,787
South Carolina.................... 2,100 1,212
Tennessee......................... 2,100 1,212
Texas............................. 7,557 4,363
Virginia.......................... 2,100 1,212
West Virginia..................... 2,223 1,284
------------------------------------------------------------------------
Sec. 97.511 Timing requirements for TR NOX Ozone Season allowance
allocations.
(a) Existing units. (1) TR NOX Ozone Season allowances
are allocated, for the control periods in 2012 and each year
thereafter, as 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 Administrator will calculate the TR NOX
Ozone Season allowance allocation for each TR NOX Ozone
Season unit, in accordance with Sec. 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 Sec. 97.512 and Sec. Sec. 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 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 Sec. 97.504 as of
May 1, 2012 or whose deadline for meeting monitor certification
requirements under Sec. 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 Sec.
97.512 for the control period to a recipient that is not actually a TR
NOX Ozone Season unit under Sec. 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 Sec. 97.521.
(2) If the Administrator already recorded such TR NOX
Ozone Season allowances under Sec. 97.521 and if the Administrator
makes such determination before making deductions for the source that
includes such recipient under Sec. 97.524(b) for such control period,
then the Administrator will deduct from the account in which such TR
NOX Ozone Season allowances
[[Page 45402]]
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 Sec. 97.521 and if the Administrator
makes such determination after making deductions for the source that
includes such recipient under Sec. 97.524(b) for such control period,
then the Administrator will not make any deduction to take account of
such already recorded TR NOX Ozone Season allowances.
(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.
Sec. 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 Sec. 97.511(c)(1) or
(2), and to TR NOX Ozone Season units that are so listed
and, pursuant to Sec. 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 Sec. 97.510(a). Each new unit set-aside will
be allocated additional TR NOX Ozone Season allowances in
accordance with Sec. 97.511(a)(2) and (c)(4).
(2) The designated representative of such TR NOX Ozone
Season unit may 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 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 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 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 Ozone Season unit covered by an
accepted allowance allocation request the amount of the TR
NOX Ozone Season allowances 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 Sec. 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 set-aside 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 Sec. 97.511(a)(2), an amount of
TR NOX Ozone Season allowances equal to the following: The
total amount of such remaining unallocated TR NOX Ozone
Season allowances in such new unit set-aside, multiplied by the unit's
allocation under Sec. 97.511(a) for such control period, divided by
the remainder of the amount of tons in the applicable State
NOX Ozone Season trading budget minus the amount of tons in
such new unit set-aside, and rounded to the nearest allowance.
Sec. 97.513 Authorization of designated representative and alternate
designated representative.
(a) Except as provided under Sec. 97.515, each TR NOX
Ozone Season source, including all TR NOX Ozone Season units
at the source, shall have one and only one designated representative,
with regard to all matters under the TR NOX Ozone Season
Trading Program.
(1) The designated representative shall be selected by an agreement
binding on the owners and operators of the source and all TR
NOX Ozone Season units at the source and shall act in
accordance with the certification statement in Sec. 97.516(a)(4)(iii).
(2) Upon and after receipt by the Administrator of a complete
certificate of representation under Sec. 97.516:
(i) The designated representative shall be authorized and shall
represent and, by his or her representations, actions, inactions, or
submissions, legally bind each owner and operator of the source and
each TR NOX Ozone Season unit at
[[Page 45403]]
the source in all matters pertaining to the TR NOX Ozone
Season Trading Program, notwithstanding any agreement between the
designated representative and such owners and operators; and
(ii) The owners and operators of the source and each TR
NOX Ozone Season unit at the source shall be bound by any
decision or order issued to the designated representative by the
Administrator regarding the source or any such unit.
(b) Except as provided under Sec. 97.515, each TR NOX
Ozone Season source may have one and only one alternate designated
representative, who may act on behalf of the designated representative.
The agreement by which the alternate designated representative is
selected shall include a procedure for authorizing the alternate
designated representative to act in lieu of the designated
representative.
(1) The alternate designated representative shall be selected by an
agreement binding on the owners and operators of the source and all TR
NOX Ozone Season units at the source and shall act in
accordance with the certification statement in Sec. 97.516(a)(4)(iii).
(2) Upon and after receipt by the Administrator of a complete
certificate of representation under Sec. 97.516,
(i) The alternate designated representative shall be authorized;
(ii) Any representation, action, inaction, or submission by the
alternate designated representative shall be deemed to be a
representation, action, inaction, or submission by the designated
representative; and
(iii) The owners and operators of the source and each TR
NOX Ozone Season unit at the source shall be bound by any
decision or order issued to the alternate designated representative by
the Administrator regarding the source or any such unit.
(c) Except in this section, Sec. 97.502, and Sec. Sec. 97.514
through 97.518, whenever the term ``designated representative'' is used
in this subpart, the term shall be construed to include the designated
representative or any alternate designated representative.
Sec. 97.514 Responsibilities of designated representative and
alternate designated representative.
(a) Except as provided under Sec. 97.518 concerning delegation of
authority to make submissions, each submission under the TR
NOX Ozone Season Trading Program shall be made, signed, and
certified by the designated representative or alternate designated
representative for each TR NOX Ozone Season source and TR
NOX Ozone Season unit for which the submission is made. Each
such submission shall include the following certification statement by
the designated representative or alternate designated representative:
``I am authorized to make this submission on behalf of the owners and
operators of the source or units for which the submission is made. I
certify under penalty of law that I have personally examined, and am
familiar with, the statements and information submitted in this
document and all its attachments. Based on my inquiry of those
individuals with primary responsibility for obtaining the information,
I certify that the statements and information are to the best of my
knowledge and belief true, accurate, and complete. I am aware that
there are significant penalties for submitting false statements and
information or omitting required statements and information, including
the possibility of fine or imprisonment.''
(b) The Administrator will accept or act on a submission made for a
TR NOX Ozone Season source or a TR NOX Ozone
Season unit only if the submission has been made, signed, and certified
in accordance with paragraph (a) of this section and Sec. 97.518.
Sec. 97.515 Changing designated representative and alternate
designated representative; changes in owners and operators.
(a) Changing designated representative. The designated
representative may be changed at any time upon receipt by the
Administrator of a superseding complete certificate of representation
under Sec. 97.516. Notwithstanding any such change, all
representations, actions, inactions, and submissions by the previous
designated representative before the time and date when the
Administrator receives the superseding certificate of representation
shall be binding on the new designated representative and the owners
and operators of the TR NOX Ozone Season source and the TR
NOX Ozone Season units at the source.
(b) Changing alternate designated representative. The alternate
designated representative may be changed at any time upon receipt by
the Administrator of a superseding complete certificate of
representation under Sec. 97.516. Notwithstanding any such change, all
representations, actions, inactions, and submissions by the previous
alternate designated representative before the time and date when the
Administrator receives the superseding certificate of representation
shall be binding on the new alternate designated representative, the
designated representative, and the owners and operators of the TR
NOX Ozone Season source and the TR NOX Ozone
Season units at the source.
(c) Changes in owners and operators. (1) In the event an owner or
operator of a TR NOX Ozone Season source or a TR
NOX Ozone Season unit is not included in the list of owners
and operators in the certificate of representation under Sec. 97.516,
such owner or operator shall be deemed to be subject to and bound by
the certificate of representation, the representations, actions,
inactions, and submissions of the designated representative and any
alternate designated representative of the source or unit, and the
decisions and orders of the Administrator, as if the owner or operator
were included in such list.
(2) Within 30 days after any change in the owners and operators of
a TR NOX Ozone Season source or a TR NOX Ozone
Season unit, 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
Sec. 97.516 amending the list of owners and operators to include the
change.
Sec. 97.516 Certificate of representation.
(a) A complete certificate of representation for a designated
representative or an alternate designated representative shall include
the following elements in a format prescribed by the Administrator:
(1) Identification of the TR NOX Ozone Season source,
and each TR NOX Ozone Season unit at the source, for which
the certificate of representation is submitted, including source name,
source category and NAICS code (or, in the absence of a NAICS code, an
equivalent code), State, plant code, county, latitude and longitude,
unit identification number and type, identification number and
nameplate capacity (in MWe rounded to the nearest tenth) of each
generator served by each such unit, 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--
[[Page 45404]]
(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.
Sec. 97.517 Objections concerning designated representative and
alternate designated representative.
(a) Once a complete certificate of representation under Sec.
97.516 has been submitted and received, the Administrator will rely on
the certificate of representation unless and until a superseding
complete certificate of representation under Sec. 97.516 is received
by the Administrator.
(b) Except as provided in Sec. 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.
Sec. 97.518 Delegation by designated representative and alternate
designated representative.
(a) A designated representative may delegate, to one or more
natural persons, his or her authority to make an electronic submission
to the Administrator provided for or required under this subpart.
(b) An alternate designated representative may delegate, to one or
more natural persons, his or her authority to make an electronic
submission to the Administrator provided for or required under this
subpart.
(c) In order to delegate authority to 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 97.518(d) shall
be deemed to be an electronic submission by me.''
(ii) ``Until this notice of delegation is superseded by another
notice of delegation under 40 CFR 97.518(d), I agree to maintain an e-
mail account and to notify the Administrator immediately of any change
in my e-mail address unless all delegation of authority by me under 40
CFR 97.518 is terminated.''.
(d) A notice of delegation submitted under paragraph (c) of this
section shall be effective, with regard to the designated
representative or alternate designated representative identified in
such notice, upon receipt of such notice by the Administrator and until
receipt by the Administrator of a superseding notice of delegation
submitted by such designated representative or alternate designated
representative, as appropriate. The superseding notice of delegation
may replace any previously identified agent, add a new agent, or
eliminate entirely any delegation of authority.
(e) Any electronic submission covered by the certification in
paragraph (c)(4)(i) of this section and made in accordance with a
notice of delegation effective under paragraph (d) of this section
shall be deemed to be an electronic submission by the designated
representative or alternate designated representative submitting such
notice of delegation.
Sec. 97.519 [Reserved]
Sec. 97.520 Establishment of Allowance Management System accounts.
(a) Compliance accounts. Upon receipt of a complete certificate of
representation under Sec. 97.516, the Administrator will establish a
compliance account for the TR NOX Ozone Season source for
which the certificate of representation was submitted, unless the
source already has a compliance account. The designated representative
and any alternate designated representative of the source
[[Page 45405]]
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 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 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
[[Page 45406]]
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 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 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 Sec. 97.522 for any TR NOX Ozone Season
allowances in the account to one or more other Allowance Management
System accounts.
(ii) If a general account has no TR NOX Ozone Season
allowance transfers to or from the account for a 12-month period or
longer and does not contain any TR NOX Ozone Season
allowances, the Administrator may notify the authorized account
representative for the account that the account will be closed after 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 Sec. 97.522 to the account or a
statement submitted by the authorized account representative or
alternate authorized account representative demonstrating to the
satisfaction of the Administrator good
[[Page 45407]]
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
Sec. Sec. 97.514(a) and 97.518 or paragraphs (b)(2)(ii) and (b)(5) of
this section.
Sec. 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
Sec. Sec. 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 Sec. 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 Sec. 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.
Sec. 97.522 Submission of TR NOX Ozone Season allowance transfers.
(a) An authorized account representative seeking recordation of a
TR NOX Ozone Season allowance transfer shall submit the
transfer to the Administrator.
(b) A TR NOX Ozone Season allowance transfer shall be
correctly submitted if:
(1) The transfer includes the following elements, in a format
prescribed by the Administrator:
(i) The account numbers established by the Administrator for both
the transferor and transferee accounts;
(ii) The serial number of each TR NOX Ozone Season
allowance that is in the transferor account and is to be transferred;
and
(iii) The name and signature of the authorized account
representative of the transferor account and the date signed; and
(2) When the Administrator attempts to record the transfer, the
transferor account includes each TR NOX Ozone Season
allowance identified by serial number in the transfer.
Sec. 97.523 Recordation of TR NOX Ozone Season allowance transfers.
(a) Within 5 business days (except as provided in paragraph (b) of
this section) of receiving a TR NOX Ozone Season allowance
transfer, 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 Sec. 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 Sec. 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 Sec. 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 Sec. 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 Sec. 97.522, the Administrator will not
record such transfer.
(d) Within 5 business days of recordation of a TR NOX
Ozone Season allowance transfer under paragraphs (a) and (b) of the
section, the Administrator will notify the authorized account
representatives of both the transferor and transferee accounts.
(e) Within 10 business days of receipt of a TR NOX Ozone
Season allowance transfer that is not correctly submitted under Sec.
97.522, the Administrator will notify the authorized account
representatives of both accounts subject to the transfer of:
(1) A decision not to record the transfer, and
(2) The reasons for such non-recordation.
Sec. 97.524 Compliance with TR NOX Ozone Season emissions limitation.
(a) Availability for deduction for compliance. TR NOX
Ozone Season allowances are available to be deducted for compliance
with a source's TR NOX Ozone Season emissions limitation for
a control period in a given year only if the TR NOX Ozone
Season allowances:
(1) Were allocated for 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 Sec. 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
[[Page 45408]]
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.
Sec. 97.525 Compliance with TR NOX Ozone Season assurance provisions.
(a) Availability for deduction. TR NOX Ozone Season
allowances are available to be deducted for compliance with the TR
NOX Ozone Season assurance provisions for a control period
in a given year by 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
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 Sec. 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
Sec. Sec. 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 Sec.
97.506(c)(2)(iii) and Sec. Sec. 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 Sec. 97.506(c)(2)(iii):
(i) By May 15 immediately after the promulgation of such notice,
the 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
Sec. 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 Sec.
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 Sec. 97.502, and the
calculation formula in Sec. 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.
[[Page 45409]]
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 allowance-holding 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 Sec.
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 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 Sec.
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 Sec. 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.
(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 Sec.
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
[[Page 45410]]
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.
Sec. 97.526 Banking.
(a) A TR NOX Ozone Season allowance may be banked for
future use or transfer in a compliance account or a general account in
accordance with paragraph (b) of this section.
(b) Any TR NOX Ozone Season allowance that is held in a
compliance account or a general account will remain in such account
unless and until the TR NOX Ozone Season allowance is
deducted or transferred under Sec. 97.511(c), Sec. 97.523, Sec.
97.524, Sec. 97.525, 97.527, 97.528, 97.542, or 97.543.
Sec. 97.527 Account error.
The Administrator may, at his or her sole discretion and on his or
her own motion, correct any error in any Allowance Management System
account. Within 10 business days of making such correction, the
Administrator will notify the authorized account representative for the
account.
Sec. 97.528 Administrator's action on submissions.
(a) The Administrator may review and conduct independent audits
concerning any submission under the TR NOX Ozone Season
Trading Program and make appropriate adjustments of the information in
the submission.
(b) The Administrator may deduct TR NOX Ozone Season
allowances from or transfer TR NOX Ozone Season allowances
to a 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.
Sec. 97.529 [Reserved]
Sec. 97.530 General monitoring, recordkeeping, and reporting
requirements.
The owners and operators, and to the extent applicable, the
designated representative, of a TR NOX Ozone Season unit,
shall comply with the monitoring, recordkeeping, and reporting
requirements as provided in this subpart and subpart H of part 75 of
this chapter. For purposes of applying such requirements, the
definitions in Sec. 97.502 and in Sec. 72.2 of this chapter shall
apply, the terms ``affected unit,'' ``designated representative,'' and
``continuous emission monitoring system'' (or ``CEMS'') in part 75 of
this chapter shall be deemed to refer to the terms ``TR NOX
Ozone Season unit,'' ``designated representative,'' and ``continuous
emission monitoring system'' (or ``CEMS'') respectively as defined in
Sec. 97.502, and the term ``newly affected unit'' shall be deemed to
mean ``newly affected TR NOX Ozone Season unit''. The owner
or operator of a unit that is not a TR NOX Ozone Season unit
but that is monitored under Sec. 75.72(b)(2)(ii) of this chapter shall
comply with the same monitoring, recordkeeping, and reporting
requirements as a TR NOX Ozone Season unit.
(a) Requirements for installation, certification, and data
accounting. The owner or operator of each TR NOX Ozone
Season unit shall:
(1) Install all monitoring systems required under this subpart for
monitoring NOX mass emissions and individual unit heat input
(including all systems required to monitor NOX emission
rate, NOX concentration, stack gas moisture content, stack
gas flow rate, CO2 or O2 concentration, and fuel
flow rate, as applicable, in accordance with Sec. Sec. 75.71 and 75.72
of this chapter);
(2) Successfully complete all certification tests required under
Sec. 97.531 and meet all other requirements of this subpart and part
75 of this chapter applicable to the monitoring systems under paragraph
(a)(1) of this section; and
(3) Record, report, and quality-assure the data from the monitoring
systems under paragraph (a)(1) of this section.
(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 Sec. 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 Sec. 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
[[Page 45411]]
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 Sec. 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 Sec. 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 Sec. 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 Sec. 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 Sec. 75.31(b)(2) or (c)(3) of this chapter, section 2.4 of
appendix D to part 75 of this chapter, or section 2.5 of appendix E to
part 75 of this chapter, as applicable.
(d) Prohibitions. (1) No owner or operator of a TR NOX
Ozone Season unit shall use any alternative monitoring system,
alternative reference method, or any other alternative to any
requirement of this subpart without having obtained prior written
approval in accordance with Sec. 97.535.
(2) No owner or operator of a TR NOX Ozone Season unit
shall operate the unit so as to discharge, or allow to be discharged,
NOX 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 Sec. 97.505 that is in effect;
(ii) The owner or operator is monitoring emissions from the unit
with another certified monitoring system approved, in accordance with
the applicable provisions of this subpart and part 75 of this chapter,
by the Administrator for use at that unit that provides emission data
for the same pollutant or parameter as the retired or discontinued
monitoring system; or
(iii) The designated representative submits notification of the
date of certification testing of a replacement monitoring system for
the retired or discontinued monitoring system in accordance with Sec.
97.531(d)(3)(i).
(e) Long-term cold storage. The owner or operator of a TR
NOX Ozone Season unit is subject to the applicable
provisions of Sec. 75.4(d) of this chapter concerning units in long-
term cold storage.
Sec. 97.531 Initial monitoring system certification and
recertification procedures.
(a) The owner or operator of a TR NOX Ozone Season unit
shall be exempt from the initial certification requirements of this
section for a monitoring system under Sec. 97.530(a)(1) if the
following conditions are met:
(1) The monitoring system has been previously certified in
accordance with part 75 of this chapter; and
(2) The applicable quality-assurance and quality-control
requirements of Sec. 75.21 of this chapter and appendices B, D, and E
to part 75 of this chapter are fully met for the certified monitoring
system described in paragraph (a)(1) of this section.
(b) The recertification provisions of this section shall apply to a
monitoring system under Sec. 97.530(a)(1) exempt from initial
certification requirements under paragraph (a) of this section.
(c) If the Administrator has previously approved a petition under
Sec. 75.17(a) or (b) of this chapter for apportioning the
NOX emission rate measured in a common stack or a petition
under Sec. 75.66 of this chapter for an alternative to a requirement
in Sec. 75.12 or Sec. 75.17 of this chapter, the designated
representative shall resubmit the petition to the Administrator under
Sec. 97.535 to determine whether the approval applies under the TR
NOX Ozone Season Trading Program.
(d) Except as provided in paragraph (a) of this section, the owner
or operator of a TR NOX Ozone Season unit shall comply with
the following initial certification and recertification procedures for
a continuous monitoring system (i.e., a continuous emission monitoring
system and an excepted monitoring system under appendices D and E to
part 75 of this chapter) under Sec. 97.530(a)(1). The owner or
operator of a unit that qualifies to use the low mass emissions
excepted monitoring methodology under Sec. 75.19 of this chapter or
that qualifies to use an alternative monitoring system under subpart E
of part 75 of this chapter shall comply with the procedures in
paragraph (e) or (f) of this section respectively.
(1) Requirements for initial certification. The owner or operator
shall ensure that each continuous monitoring system under Sec.
97.530(a)(1) (including the automated data acquisition and handling
system) successfully completes all of the initial certification testing
required under Sec. 75.20 of this chapter by the applicable deadline
in Sec. 97.530(b). In addition, whenever the owner or operator
installs a monitoring system to meet the requirements of this subpart
in a location where no such monitoring system was previously installed,
initial certification in accordance with Sec. 75.20 of this chapter is
required.
[[Page 45412]]
(2) Requirements for recertification. Whenever the owner or
operator makes a replacement, modification, or change in any certified
continuous emission monitoring system under Sec. 97.530(a)(1) that may
significantly affect the ability of the system to accurately measure or
record NOX mass emissions or heat input rate or to meet the
quality-assurance and quality-control requirements of Sec. 75.21 of
this chapter or appendix B to part 75 of this chapter, the owner or
operator shall recertify the monitoring system in accordance with Sec.
75.20(b) of this chapter. Furthermore, whenever the owner or operator
makes a replacement, modification, or change to the flue gas handling
system or the unit's operation that may significantly change the stack
flow or concentration profile, the owner or operator shall recertify
each continuous emission monitoring system whose accuracy is
potentially affected by the change, in accordance with Sec. 75.20(b)
of this chapter. Examples of changes to a continuous emission
monitoring system that require recertification include: Replacement of
the analyzer, complete replacement of an existing continuous emission
monitoring system, or change in location or orientation of the sampling
probe or site. Any fuel flowmeter systems, and any excepted
NOX monitoring system under appendix E to part 75 of this
chapter, under Sec. 97.530(a)(1) are subject to the recertification
requirements in Sec. 75.20(g)(6) of this chapter.
(3) Approval process for initial certification and recertification.
For initial certification of a continuous monitoring system under Sec.
97.530(a)(1), paragraphs (d)(3)(i) through (v) of this section apply.
For recertifications of such monitoring systems, paragraphs (d)(3)(i)
through (iv) of this section and the procedures in Sec. Sec.
75.20(b)(5) and (g)(7) of this chapter (in lieu of the procedures in
paragraph (d)(3)(v) of this section) apply, provided that in applying
paragraphs (d)(3)(i) through (iv) of this section, the words
``certification'' and ``initial certification'' are replaced by the
word ``recertification'' and the word ``certified'' is replaced by with
the word ``recertified''.
(i) Notification of certification. The designated representative
shall submit to the appropriate EPA Regional Office and the
Administrator written notice of the dates of certification testing, in
accordance with Sec. 97.533.
(ii) Certification application. The designated representative shall
submit to the Administrator a certification application for each
monitoring system. A complete certification application shall include
the information specified in Sec. 75.63 of this chapter.
(iii) Provisional certification date. The provisional certification
date for a monitoring system shall be determined in accordance with
Sec. 75.20(a)(3) of this chapter. A provisionally certified monitoring
system may be used under the TR NOX Ozone Season Trading
Program for a period not to exceed 120 days after receipt by the
Administrator of the complete certification application for the
monitoring system under paragraph (d)(3)(ii) of this section. Data
measured and recorded by the provisionally certified monitoring system,
in accordance with the requirements of part 75 of this chapter, will be
considered valid quality-assured data (retroactive to the date and time
of provisional certification), provided that the Administrator does not
invalidate the provisional certification by issuing a notice of
disapproval within 120 days of the date of receipt of the complete
certification application by the Administrator.
(iv) Certification application approval process. The Administrator
will issue a written notice of approval or disapproval of the
certification application to the owner or operator within 120 days of
receipt of the complete certification application under paragraph
(d)(3)(ii) of this section. In the event the Administrator does not
issue such a notice within such 120-day period, each monitoring system
that meets the applicable performance requirements of part 75 of this
chapter and is included in the certification application will be deemed
certified for use under the TR NOX Ozone Season Trading
Program.
(A) Approval notice. If the certification application is complete
and shows that each monitoring system meets the applicable performance
requirements of part 75 of this chapter, then the Administrator will
issue a written notice of approval of the certification application
within 120 days of receipt.
(B) Incomplete application notice. If the certification application
is not complete, then the Administrator will issue a written notice of
incompleteness that sets a reasonable date by which the designated
representative must submit the additional information required to
complete the certification application. If the designated
representative does not comply with the notice of incompleteness by the
specified date, then the Administrator may issue a notice of
disapproval under paragraph (d)(3)(iv)(C) of this section. 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 Sec. 75.20(a)(3) of this chapter).
(D) Audit decertification. The Administrator may issue a notice of
disapproval of the certification status of a monitor in accordance with
Sec. 97.532(b).
(v) Procedures for loss of certification. If the Administrator
issues a notice of disapproval of a certification application under
paragraph (d)(3)(iv)(C) of this section or a notice of disapproval of
certification status under paragraph (d)(3)(iv)(D) of this section,
then:
(A) The owner or operator shall substitute the following values,
for each disapproved monitoring system, for each hour of unit operation
during the period of invalid data specified under Sec.
75.20(a)(4)(iii), Sec. 75.20(g)(7), or Sec. 75.21(e) of this chapter
and continuing until the applicable date and hour specified under Sec.
75.20(a)(5)(i) or (g)(7) of this chapter:
(1) For a disapproved NOX emission rate (i.e.,
NOX-diluent) system, the maximum potential NOX
emission rate, as defined in Sec. 72.2 of this chapter.
(2) For a disapproved NOX pollutant concentration
monitor and disapproved flow monitor, respectively, the maximum
potential concentration of NOX and the maximum potential
flow rate, as defined in sections 2.1.2.1 and 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
[[Page 45413]]
flow rate, as defined in section 2.4.2.1 of appendix D to part 75 of
this chapter.
(5) For a disapproved excepted NOX monitoring system
under appendix E to part 75 of this chapter, the fuel-specific maximum
potential NOX emission rate, as defined in Sec. 72.2 of
this chapter.
(B) The designated representative shall submit a notification of
certification retest dates and a new certification application in
accordance with paragraphs (d)(3)(i) and (ii) of this section.
(C) The owner or operator shall repeat all certification tests or
other requirements that were failed by the monitoring system, as
indicated in the Administrator's notice of disapproval, no later than
30 unit operating days after the date of issuance of the notice of
disapproval.
(e) The owner or operator of a unit qualified to use the low mass
emissions (LME) excepted methodology under Sec. 75.19 of this chapter
shall meet the applicable certification and recertification
requirements in Sec. Sec. 75.19(a)(2) and 75.20(h) of this chapter. If
the owner or operator of such a unit elects to certify a fuel flowmeter
system for heat input determination, the owner or operator shall also
meet the certification and recertification requirements in Sec.
75.20(g) of this chapter.
(f) The designated representative of each unit for which the owner
or operator intends to use an alternative monitoring system approved by
the Administrator under subpart E of part 75 of this chapter shall
comply with the applicable notification and application procedures of
Sec. 75.20(f) of this chapter.
Sec. 97.532 Monitoring system out-of-control periods.
(a) General provisions. Whenever any monitoring system fails to
meet the quality-assurance and quality-control requirements or data
validation requirements of part 75 of this chapter, data shall be
substituted using the applicable missing data procedures in subpart D
or subpart H of, or appendix D or appendix E to, part 75 of this
chapter.
(b) Audit decertification. Whenever both an audit of a monitoring
system and a review of the initial certification or recertification
application reveal that any monitoring system should not have been
certified or recertified because it did not meet a particular
performance specification or other requirement under Sec. 97.531 or
the applicable provisions of part 75 of this chapter, both at the time
of the initial certification or recertification application submission
and at the time of the audit, the Administrator will issue a notice of
disapproval of the certification status of such monitoring system. For
the purposes of this paragraph, an audit shall be either a field audit
or an audit of any information submitted to the Administrator or any
permitting authority. By issuing the notice of disapproval, the
Administrator revokes prospectively the certification status of the
monitoring system. The data measured and recorded by the monitoring
system shall not be considered valid quality-assured data from the date
of issuance of the notification of the revoked certification status
until the date and time that the owner or operator completes
subsequently approved initial certification or recertification tests
for the monitoring system. The owner or operator shall follow the
applicable initial certification or recertification procedures in Sec.
97.531 for each disapproved monitoring system.
Sec. 97.533 Notifications concerning monitoring.
The designated representative of a TR NOX Ozone Season
unit shall submit written notice to the Administrator in accordance
with Sec. 75.61 of this chapter.
Sec. 97.534 Recordkeeping and reporting.
(a) General provisions. The designated representative shall comply
with all recordkeeping and reporting requirements in this section, the
applicable recordkeeping and reporting requirements under Sec. 75.73
of this chapter, and the requirements of Sec. 97.514(a).
(b) Monitoring plans. The owner or operator of a TR NOX
Ozone Season unit shall comply with requirements of Sec. 75.73(c) and
(e) of this chapter.
(c) Certification applications. The designated representative shall
submit an application to the Administrator within 45 days after
completing all initial certification or recertification tests required
under Sec. 97.531, including the information required under Sec.
75.63 of this chapter.
(d) Quarterly reports. The designated representative shall submit
quarterly reports, as follows:
(1) If the TR NOX Ozone Season unit is subject to the
Acid Rain Program or a TR NOX Annual emissions limitation or
if the owner or operator of such unit chooses to report on an annual
basis under this subpart, the designated representative shall meet the
requirements of subpart H of part 75 of this chapter (concerning
monitoring of NOX mass emissions) for such unit for the
entire year and shall report the NOX mass emissions data and
heat input data for such unit, in an electronic quarterly report in a
format prescribed by the Administrator, for each calendar quarter
beginning with:
(i) For a unit that commences commercial operation before July 1,
2011, the calendar quarter covering May 1, 2012 through June 30, 2012;
(ii) For a unit that commences commercial operation on or after
July 1, 2011, the calendar quarter corresponding to the earlier of the
date of provisional certification or the applicable deadline for
initial certification under Sec. 97.530(b), unless that quarter is the
third or fourth quarter of 2011 or the first quarter of 2012, in which
case reporting shall commence in the quarter covering May 1, 2012
through June 30, 2012;
(2) If the TR NOX Ozone Season unit is not subject to
the Acid Rain Program or a TR NOX Annual emissions
limitation, then the designated representative shall either:
(i) Meet the requirements of subpart H of part 75 (concerning
monitoring of NOX mass emissions) for such unit for the
entire year and report the NOX mass emissions data and heat
input data for such unit in accordance with paragraph (d)(1) of this
section; or
(ii) Meet the requirements of subpart H of part 75 for the control
period (including the requirements in Sec. 75.74(c) of this chapter)
and report NOX mass emissions data and heat input data
(including the data described in Sec. 75.74(c)(6) of this chapter) for
such unit only for the control period of each year and report, in an
electronic quarterly report in a format prescribed by the
Administrator, for each calendar quarter beginning with:
(A) For a unit that commences commercial operation before July 1,
2011, the calendar quarter covering May 1, 2012 through June 30, 2012;
(B) For a unit that commences commercial operation on or after July
1, 2011, the calendar quarter corresponding to the earlier of the date
of provisional certification or the applicable deadline for initial
certification under Sec. 97.530(b), unless that date is not during a
control period, in which case reporting shall commence in the quarter
that includes May 1 through June 30 of the first control period after
such date;
(3) Notwithstanding paragraphs (d)(1) and (2) 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 Sec. 97.541(c); and
(4) Notwithstanding paragraphs (d)(1) and (2) of this section, for
a TR NOX
[[Page 45414]]
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 Sec.
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 Sec. 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 to the Administrator a compliance certification (in a format
prescribed by the Administrator) in support of each quarterly report
based on reasonable inquiry of those persons with primary
responsibility for ensuring that all of the unit's emissions are
correctly and fully monitored. The certification shall state that:
(1) The monitoring data submitted were recorded in accordance with
the applicable requirements of this subpart and part 75 of this
chapter, including the quality assurance procedures and specifications;
(2) For a unit with add-on NOX emission controls and for
all hours where NOX data are substituted in accordance with
Sec. 75.34(a)(1) of this chapter, the add-on emission controls were
operating within the range of parameters listed in the quality
assurance/quality control program under appendix B to part 75 of this
chapter and the substitute data values do not systematically
underestimate NOX emissions; and
(3) For a unit that is reporting on a control period basis under
paragraph (d)(2)(ii) of this section, the NOX emission rate
and NOX concentration values substituted for missing data
under subpart D of part 75 of this chapter are calculated using only
values from a control period and do not systematically underestimate
NOX emissions.
Sec. 97.535 Petitions for alternatives to monitoring, recordkeeping,
or reporting requirements.
(a) The designated representative of a TR NOX Ozone
Season unit may submit a petition under Sec. 75.66 of this chapter to
the Administrator, requesting approval to apply an alternative to any
requirement of Sec. Sec. 97.530 through 97.534 or paragraph (5)(i) or
(ii) of the definition of ``owner's share'' in Sec. 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 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.
Sec. 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 Sec.
97.504;
(3) Is not covered by a retired unit exemption under Sec. 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 Sec. Sec. 97.505, 97.511, and 97.512.
(c) Solely for purposes of applying the requirements of Sec. Sec.
97.513 through 97.518 and Sec. Sec. 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 Sec. 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 opt-in application is submitted and not withdrawn and is
not yet approved or disapproved under Sec. 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.
Sec. 97.541 Opt-in process.
A unit meeting the requirements for a TR NOX Ozone
Season opt-in unit in Sec. 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 Sec. 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,
[[Page 45415]]
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 Sec.
97.504;
(ii) Is not covered by a retired unit exemption under Sec. 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 Sec. Sec. 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 Sec. 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 Sec. 97.543;
(6) A complete certificate of representation under Sec. 97.516
consistent with Sec. 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 Sec. Sec. 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 Sec. Sec.
97.530 through 97.535, starting on the date of certification of the
necessary monitoring systems under Sec. Sec. 97.530 through 97.535 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 Ozone Season Trading Program in
accordance with Sec. 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 Sec. Sec. 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
Sec. Sec. 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 Sec. Sec. 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 emissions-
related 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.
(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 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; 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
Sec. 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 Sec. 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.
[[Page 45416]]
(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.
Sec. 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 Sec. 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 Sec. Sec. 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 opt-in 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 Sec. 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 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 Sec. Sec. 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 Sec.
97.541 for such unit before the date that is 4 years after the date on
which the withdrawal became effective.
Sec. 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 Sec. 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
Sec. 97.504, the Administrator will deduct, 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
Sec. 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 Sec. 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 Sec. 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 Sec. 97.504
is not September 30, the TR NOX Ozone Season allowances
allocated to the TR NOX Ozone Season opt-in unit under Sec.
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 Sec. 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
Sec. 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
Sec. 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 Sec. 97.504, the TR NOX Ozone
Season opt-in unit will be allocated TR NOX Ozone Season
allowances in accordance with Sec. 97.512.
(ii) If the date on which the TR NOX Ozone Season opt-in
unit becomes a TR NOX Ozone Season unit under Sec. 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 Sec. 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 Sec. 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 Sec.
97.512 for the control period;
[[Page 45417]]
(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
Sec. 97.504, divided by the total number of days in the control
period; and
(C) Rounded to the nearest allowance.
Sec. 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 Sec. 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 Sec. 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 Sec.
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 Sec. 97.541(g); or
(ii) The TR NOX Ozone Season opt-in unit's heat input,
as determined in accordance with Sec. Sec. 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 Sec. 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 Sec.
97.541(g) and multiplied by 70 percent; or
(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 Sec. 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 opt-in 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.
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 opt-in 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
Sec. 97.601 Purpose.
This subpart sets forth the general, designated representative,
allowance, and monitoring provisions for the Transport Rule (TR)
SO2 Group 1 Trading Program, under section 110 of the Clean
Air Act and Sec. 52.38(b) of this chapter, as a means of mitigating
interstate transport of fine particulates and nitrogen oxides.
Sec. 97.602 Definitions.
The terms used in this subpart shall have the meanings set forth in
this section as follows:
Acid Rain Program means a multi-state SO2 and
NOX air pollution control and emission reduction program
established by the Administrator under title IV of the Clean Air Act
and parts 72 through 78 of this chapter.
Administrator means the Administrator of the United States
Environmental Protection Agency or the Director of the Clean Air
Markets Division (or its successor) of the United
[[Page 45418]]
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 Sec. 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 Sec. 72.2 of this chapter, Sec. 97.402, or Sec. 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;
(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 system-wide basis the requirement in paragraph
[[Page 45419]]
(2)(i)(B) of this definition, the topping-cycle 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 Sec. 97.605.
(i) For a unit that is a TR SO2 Group 1 unit under Sec.
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
Sec. 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 Sec. 97.605, for a unit that is not a TR SO2
Group 1 unit under Sec. 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 Sec. 97.604.
(i) For a unit with a date for commencement of commercial operation
as defined in the introductory text of paragraph (2) of this definition
and that subsequently undergoes a physical change (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.
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 Sec.
97.624 and the TR SO2 Group 1 assurance provisions in
accordance with Sec. 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 automated data acquisition and handling system (DAHS), a permanent
record of SO2 emissions, stack gas volumetric flow rate,
stack gas moisture content, and O2 or CO2
concentration (as applicable), in a manner consistent with part 75 of
this chapter and Sec. Sec. 97.630 through 97.635. The following
systems are the principal types of continuous emission monitoring
systems:
(1) A flow monitoring system, consisting of a stack flow rate
monitor and an automated data acquisition and handling system and
providing a permanent, continuous record of stack gas volumetric flow
rate, in standard cubic feet per hour (scfh);
(2) A SO2 monitoring system, consisting of a
SO2 pollutant concentration monitor and an automated data
acquisition and handling system and providing a permanent, continuous
record of SO2 emissions, in parts per million (ppm);
(3) A moisture monitoring system, as defined in Sec. 75.11(b)(2)
of this chapter and providing a permanent, continuous record of the
stack gas moisture content, in percent H2O;
(4) A CO2 monitoring system, consisting of a
CO2 pollutant concentration monitor (or an O2
monitor plus suitable mathematical equations from which the
CO2 concentration is derived) and an automated data
acquisition and handling system and providing a permanent, continuous
record of CO2 emissions, in percent CO2; and
(5) An O2 monitoring system, consisting of an
O2 concentration monitor and an automated data acquisition
and handling system and providing a permanent, continuous record of
O2, in percent O2.
Control period means the period starting January 1 of a calendar
year, except as provided in Sec. 97.606(c)(3), and ending on December
31 of the same year, inclusive.
Designated representative means, for a TR SO2 Group 1
source and each TR SO2 Group 1 unit at the source, the
natural person who is authorized by the owners and operators of the
source and all such units at the source, in accordance with this
subpart, to represent and legally bind each owner and operator in
matters pertaining to the TR SO2 Group 1 Trading Program. If
the TR SO2 Group 1 source is also subject to the Acid Rain
Program, TR NOX Annual Trading Program, or TR NOX
Ozone Season Trading Program, then this natural person shall be the
same natural person as the designated representative, as defined in
Sec. 72.2 of this chapter, Sec. 97.402, or Sec. 97.502 respectively.
[[Page 45420]]
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 Sec. Sec. 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 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.
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-the-
unit, firm power contractual arrangement;
(4) Provided that, for purposes of applying the TR SO2
Group 1 assurance provisions in Sec. Sec. 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 Sec. 97.606(c)(2)(iii)(A)
and not as described in Sec. 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 Sec. 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
[[Page 45421]]
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 Sec. 97.610(a) and the State's one-year variability limit
under Sec. 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 Sec. 97.610(a) and the State's three-year variability
limit under Sec. 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
Sec. 97.635; and
(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
Sec. Sec. 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 Sec. 75.22 of this
chapter.
Replacement, replace, or replaced means, with regard to a unit, the
demolishing of a unit, or the permanent retirement and permanent
disabling of a unit, and the construction of another unit (the
replacement unit) to be used instead of the demolished or retired unit
(the replaced unit).
Sequential use of energy means:
(1) 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
Sec. 52.38(b) of this chapter.
Submit or serve means to send or transmit a document, information,
or correspondence to the person specified in accordance with the
applicable regulation:
(1) In person;
(2) By United States Postal Service; or
(3) By other means of dispatch or transmission and delivery;
(4) Provided that compliance with any ``submission'' or ``service''
deadline shall be determined by the date of dispatch, transmission, or
mailing and not the date of receipt.
Topping-cycle unit means a unit in which the energy input to the
unit is first used to produce useful power, including electricity,
where at least some of the reject heat from the electricity production
is then used to provide useful thermal energy.
Total energy input means 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,
[[Page 45422]]
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 Sec. 97.624(a) for such control
period.
TR SO2 Group 1 source means a source that includes one or more TR
SO2 Group 1 units.
TR SO2 Group 1 Trading Program means a multi-state SO2
air pollution control and emission reduction program established 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 Sec. 97.604.
Unit means a stationary, fossil-fuel-fired boiler, stationary,
fossil-fuel-fired combustion turbine, or other stationary, fossil-fuel-
fired combustion device.
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.
Sec. 97.603 Measurements, abbreviations, and acronyms.
Measurements, abbreviations, and acronyms used in this subpart are
defined as follows:
Btu--British thermal unit
CO2--carbon dioxide
H2O--water
hr--hour
kW--kilowatt electrical
kWh--kilowatt hour
lb--pound
mmBtu--million Btu
MWe--megawatt electrical
MWh--megawatt hour
NOX--nitrogen oxides
O2--oxygen
ppm--parts per million
scfh--standard cubic feet per hour
SO2--sulfur dioxide
yr--year
Sec. 97.604 Applicability.
(a) Except as provided in paragraph (b) of this section:
(1) The following units in a State 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 start-up 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 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.
[[Page 45423]]
(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 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.
Sec. 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 Sec. 97.606(b) and (c)(1), Sec. 97.624, and Sec. Sec.
97.630 through 97.635.
(2) The exemption under paragraph (a)(1) of this section shall
become effective the day on which the TR SO2 Group 1 unit is
permanently retired. Within 30 days of the unit's permanent retirement,
the designated representative shall submit a statement to the
Administrator. The statement shall state, in a format prescribed by the
Administrator, that the unit was permanently retired on a specified
date and will comply with the requirements of paragraph (b) of this
section.
(b) Special provisions. (1) A unit exempt under paragraph (a) of
this section shall not emit any SO2, starting on the date
that the exemption takes effect.
(2) For a period of 5 years from the date the records are created,
the owners and operators of a unit exempt under paragraph (a) of this
section shall retain, at the source that includes the unit, records
demonstrating that the unit is permanently retired. The 5-year period
for keeping records may be extended for cause, at any time before the
end of the period, in writing by the Administrator. The owners and
operators bear the burden of proof that the unit is permanently
retired.
(3) The owners and operators and, to the extent applicable, the
designated representative of a unit exempt under paragraph (a) of this
section shall comply with the requirements of the TR SO2
Group 1 Trading Program concerning all periods for which the exemption
is not in effect, even if such requirements arise, or must be complied
with, after the exemption takes effect.
(4) A unit exempt under paragraph (a) of this section shall lose
its exemption on the first date on which the unit resumes operation.
Such unit shall be treated, for purposes of applying allocation,
monitoring, reporting, and recordkeeping requirements under this
subpart, as a unit that commences commercial operation on the first
date on which the unit resumes operation.
Sec. 97.606 Standard requirements.
(a) Designated representative requirements. The owners and
operators shall comply with the requirement to have a designated
representative, and may have an alternate designated representative, in
accordance with Sec. Sec. 97.613 through 97.618.
(b) Emissions monitoring, reporting, and recordkeeping
requirements. (1) The owners and operators, and the designated
representative, of each TR SO2 Group 1 source and each TR
SO2 Group 1 unit at the source shall comply with the
monitoring, reporting, and recordkeeping requirements of Sec. Sec.
97.630 through 97.635.
(2) The emissions data determined in accordance with Sec. Sec.
97.630 through 97.635 shall be used to calculate allocations of TR
SO2 Group 1 allowances under Sec. Sec. 97.611(a)(2) and (b)
and 97.612 and to determine compliance with the TR SO2 Group
1 emissions limitation and assurance provisions under paragraph (c) of
this section, provided that, for each monitoring location from which
mass emissions are reported, the mass emissions amount used in
calculating such allocations and determining such compliance shall be
the mass emissions amount for the monitoring location determined in
accordance with Sec. Sec. 97.630 through 97.635 and rounded to the
nearest ton, with any fraction of a ton less than 0.50 being deemed to
be zero.
(c) SO2 emissions requirements--(1) TR SO2 Group 1 emissions
limitation. (i) As of the allowance transfer deadline for
[[Page 45424]]
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
Sec. 97.624(a) in an amount not less than the tons of total
SO2 emissions for such control period from all TR
SO2 Group 1 units at the source.
(ii) If 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 Sec.
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 Sec. 97.625(b)(4)(ii), TR
SO2 Group 1 allowances available for deduction for such
control period under Sec. 97.625(a) in an amount equal to the product,
as determined by the Administrator in accordance with Sec. 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 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 one-year variability limit under Sec.
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 three-year variability limit under Sec.
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 Sec. 97.630(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 Sec. 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 Sec. Sec. 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
Sec. 75.19 of this chapter), or an alternative monitoring system
(under subpart E of part 75 of this chapter) in accordance with
Sec. Sec. 97.630 through 97.635 may be added to, or changed in, a
title V permit using minor permit modification procedures in accordance
with Sec. Sec. 70.7(e)(2) and 71.7(e)(1) of this chapter, provided
that the requirements applicable to the described monitoring and
reporting (as added or changed, respectively) are already incorporated
in such permit. This paragraph explicitly provides that the addition
of, or change to, a unit's description as described in the prior
sentence is eligible for minor
[[Page 45425]]
permit modification procedures in accordance with Sec. Sec.
70.7(e)(2)(i)(B) and 71.7(e)(1)(i)(B) of this chapter.
(e) Additional recordkeeping and reporting requirements. (1) Unless
otherwise provided, the owners and operators of each TR SO2
Group 1 source and each TR SO2 Group 1 unit at the source
shall keep on site at the source each of the following documents (in
hardcopy or electronic format) for a period of 5 years from the date
the document is created. This period may be extended for cause, at any
time before the end of 5 years, in writing by the Administrator.
(i) The certificate of representation under Sec. 97.616 for the
designated representative for the source and each TR SO2
Group 1 unit at the source and all documents that demonstrate the truth
of the statements in the certificate of representation; provided that
the certificate and documents shall be retained on site at the source
beyond such 5-year period until such documents are superseded because
of the submission of a new certificate of representation under Sec.
97.616 changing the designated representative.
(ii) All emissions monitoring information, in accordance with this
subpart.
(iii) Copies of all reports, compliance certifications, and other
submissions and all records made or required under, or to demonstrate
compliance with the requirements of, the TR SO2 Group 1
Trading Program, 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 Sec. 97.605
shall be construed as exempting or excluding the owners and operators,
and the designated representative, of a TR SO2 Group 1
source or TR SO2 Group 1 unit from compliance with any other
provision of the applicable, approved State implementation plan, a
federally enforceable permit, or the Clean Air Act.
Sec. 97.607 Computation of time.
(a) Unless otherwise stated, any time period scheduled, under the
TR SO2 Group 1 Trading Program, to begin on the occurrence
of an act or event shall begin on the day the act or event occurs.
(b) Unless otherwise stated, any time period scheduled, under the
TR SO2 Group 1 Trading Program, to begin before the
occurrence of an act or event shall be computed so that the period ends
the day before the act or event occurs.
(c) Unless otherwise stated, if the final day of any time period,
under the TR SO2 Group 1 Trading Program, falls on a weekend
or a State or Federal holiday, the time period shall be extended to the
next business day.
Sec. 97.608 Administrative appeal procedures.
The administrative appeal procedures for decisions of the
Administrator under the TR SO2 Group 1 Trading Program are
set forth in part 78 of this chapter.
Sec. 97.609 [Reserved]
Sec. 97.610 State SO2 Group 1 trading budgets, new-unit set-asides,
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 New-unit set-aside (tons)
(tons) * ---------------------------------
State ----------------------------------
For 2014 and For 2012-2013 For 2014 and
For 2012-2013 thereafter thereafter
----------------------------------------------------------------------------------------------------------------
Georgia..................................... 233,260 85,717 6,998 2,572
Illinois.................................... 208,957 151,530 6,269 4,546
Indiana..................................... 400,378 201,412 12,011 6,042
Iowa........................................ 94,052 86,088 2,822 2,583
Kentucky.................................... 219,549 113,844 6,586 3,415
Michigan.................................... 251,337 155,675 7,540 4,670
Missouri.................................... 203,689 158,764 6,111 4,763
New York.................................... 66,542 42,041 1,996 1,261
North Carolina.............................. 111,485 81,859 3,345 2,456
Ohio........................................ 464,964 178,307 13,949 5,349
Pennsylvania................................ 388,612 141,693 11,658 4,251
Tennessee................................... 100,007 100,007 3,000 3,000
Virginia.................................... 72,595 40,785 2,178 1,224
West Virginia............................... 205,422 119,016 6,163 3,570
Wisconsin................................... 96,439 66,683 2,893 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 periods in
2014 and thereafter are as follows:
[[Page 45426]]
------------------------------------------------------------------------
One-year Three-year
variability limits variability limits
State -----------------------------------------
2014 and 2016 and
thereafter (tons) thereafter (tons)
------------------------------------------------------------------------
Georgia....................... 8,572 4,949
Illinois...................... 15,153 8,749
Indiana....................... 20,141 11,629
Iowa.......................... 8,609 4,970
Kentucky...................... 11,384 6,573
Michigan...................... 15,568 8,988
Missouri...................... 15,876 9,166
New York...................... 4,204 2,427
North Carolina................ 8,186 4,726
Ohio.......................... 17,831 10,295
Pennsylvania.................. 14,169 8,181
Tennessee..................... 10,001 5,774
Virginia...................... 4,079 2,355
West Virginia................. 11,902 6,871
Wisconsin..................... 6,668 3,850
------------------------------------------------------------------------
Sec. 97.611 Timing requirements for TR SO2 Group 1 allowance
allocations.
(a) Existing units. (1) TR SO2 Group 1 allowances are
allocated, for the control periods in 2012 and each year thereafter, as
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 Sec. 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 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 Sec. 97.612 and Sec. Sec. 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 Sec. 97.604 as of January 1,
2012 or whose deadline for meeting monitor certification requirements
under Sec. 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 Sec. 97.612 for the
control period to a recipient that is not actually a TR SO2
Group 1 unit under Sec. 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:
(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 Sec. 97.621.
(2) If the Administrator already recorded such TR SO2
Group 1 allowances under Sec. 97.621 and if the Administrator makes
such determination before making deductions for the source that
includes such recipient under Sec. 97.624(b) for such control period,
then the Administrator will deduct from the account in which such TR
SO2 Group 1 allowances were recorded an amount of TR
SO2 Group 1 allowances allocated for the same or a prior
control period equal to the amount of such already recorded TR
SO2 Group 1 allowances. The authorized account
representative shall ensure that there are sufficient TR SO2
Group 1 allowances in such account for completion of the deduction.
(3) If the Administrator already recorded such TR SO2
Group 1 allowances under Sec. 97.621 and if the Administrator makes
such determination after making deductions for the source that includes
such recipient under Sec. 97.624(b) for such control period, then the
Administrator will not make any deduction to take account of such
already recorded TR SO2 Group 1 allowances.
(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 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.
[[Page 45427]]
Sec. 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 Sec. 97.611(c)(1) or (2), and to TR
SO2 Group 1 units that are so listed and, pursuant to Sec.
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 Sec. 97.610(a). Each new unit set-aside will
be allocated additional TR SO2 Group 1 allowances in
accordance with Sec. 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 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 Sec. 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 Sec. 97.611(a)(2), an amount of TR SO2
Group 1 allowances equal to the following: The total amount of such
remaining unallocated TR SO2 Group 1 allowances in such new
unit set-aside, multiplied by the unit's allocation under Sec.
97.611(a) for such control period, divided by the remainder of the
amount of tons in the applicable State SO2 Group 1 trading
budget minus the amount of tons in such new unit set-aside, and rounded
to the nearest allowance.
Sec. 97.613 Authorization of designated representative and alternate
designated representative.
(a) Except as provided under Sec. 97.615, each TR SO2
Group 1 source, including all TR SO2 Group 1 units at the
source, shall have one and only one designated representative, with
regard to all matters under the TR SO2 Group 1 Trading
Program.
(1) The designated representative shall be selected by an agreement
binding on the owners and operators of the source and all TR
SO2 Group 1 units at the source and shall act in accordance
with the certification statement in Sec. 97.616(a)(4)(iii).
(2) Upon and after receipt by the Administrator of a complete
certificate of representation under Sec. 97.616:
(i) The designated representative shall be authorized and shall
represent and, by his or her representations, actions, inactions, or
submissions, legally bind each owner and operator of the source and
each TR SO2 Group 1 unit at the source in all matters
pertaining to the TR SO2 Group 1 Trading Program,
notwithstanding any agreement between the designated representative and
such owners and operators; and
(ii) The owners and operators of the source and each TR
SO2 Group 1 unit at the source shall be bound by any
decision or order issued to the designated representative by the
Administrator regarding the source or any such unit.
(b) Except as provided under Sec. 97.615, each TR SO2
Group 1 source may have one and only one alternate designated
representative, who may act on behalf of the designated representative.
The agreement by which the alternate designated representative is
selected shall include a procedure for authorizing the alternate
designated representative to act in lieu of the designated
representative.
(1) The alternate designated representative shall be selected by an
agreement binding on the owners and operators of the source and all TR
SO2 Group 1 units at the source and shall act in accordance
with the certification statement in Sec. 97.616(a)(4)(iii).
(2) Upon and after receipt by the Administrator of a complete
certificate of representation under Sec. 97.616,
(i) The alternate designated representative shall be authorized;
(ii) Any representation, action, inaction, or submission by the
alternate designated representative shall be deemed to be a
representation, action,
[[Page 45428]]
inaction, or submission by the designated representative; and
(iii) The owners and operators of the source and each TR
SO2 Group 1 unit at the source shall be bound by any
decision or order issued to the alternate designated representative by
the Administrator regarding the source or any such unit. (c) Except in
this section, Sec. 97.602, and Sec. Sec. 97.614 through 97.618,
whenever the term ``designated representative'' is used in this
subpart, the term shall be construed to include the designated
representative or any alternate designated representative.
Sec. 97.614 Responsibilities of designated representative and
alternate designated representative.
(a) Except as provided under Sec. 97.618 concerning delegation of
authority to make submissions, each submission under the TR
SO2 Group 1 Trading Program shall be made, signed, and
certified by the designated representative or alternate designated
representative for each TR SO2 Group 1 source and TR
SO2 Group 1 unit for which the submission is made. Each such
submission shall include the following certification statement by the
designated representative or alternate designated representative: ``I
am authorized to make this submission on behalf of the owners and
operators of the source or units for which the submission is made. I
certify under penalty of law that I have personally examined, and am
familiar with, the statements and information submitted in this
document and all its attachments. Based on my inquiry of those
individuals with primary responsibility for obtaining the information,
I certify that the statements and information are to the best of my
knowledge and belief true, accurate, and complete. I am aware that
there are significant penalties for submitting false statements and
information or omitting required statements and information, including
the possibility of fine or imprisonment.''
(b) The Administrator will accept or act on a submission made for a
TR SO2 Group 1 source or a TR SO2 Group 1 unit
only if the submission has been made, signed, and certified in
accordance with paragraph (a) of this section and Sec. 97.618.
Sec. 97.615 Changing designated representative and alternate
designated representative; changes in owners and operators.
(a) Changing designated representative. The designated
representative may be changed at any time upon receipt by the
Administrator of a superseding complete certificate of representation
under Sec. 97.616. Notwithstanding any such change, all
representations, actions, inactions, and submissions by the previous
designated representative before the time and date when the
Administrator receives the superseding certificate of representation
shall be binding on the new designated representative and the owners
and operators of the TR SO2 Group 1 source and the TR
SO2 Group 1 units at the source.
(b) Changing alternate designated representative. The alternate
designated representative may be changed at any time upon receipt by
the Administrator of a superseding complete certificate of
representation under Sec. 97.616. Notwithstanding any such change, all
representations, actions, inactions, and submissions by the previous
alternate designated representative before the time and date when the
Administrator receives the superseding certificate of representation
shall be binding on the new alternate designated representative, the
designated representative, and the owners and operators of the TR
SO2 Group 1 source and the TR SO2 Group 1 units
at the source.
(c) Changes in owners and operators. (1) In the event an owner or
operator of a TR SO2 Group 1 source or a TR SO2
Group 1 unit is not included in the list of owners and operators in the
certificate of representation under Sec. 97.616, such owner or
operator shall be deemed to be subject to and bound by the certificate
of representation, the representations, actions, inactions, and
submissions of the designated representative and any alternate
designated representative of the source or unit, and the decisions and
orders of the Administrator, as if the owner or operator were included
in such list.
(2) Within 30 days after any change in the owners and operators of
a TR SO2 Group 1 source or a TR SO2 Group 1 unit,
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 Sec. 97.616
amending the list of owners and operators to include the change.
Sec. 97.616 Certificate of representation.
(a) A complete certificate of representation for a designated
representative or an alternate designated representative shall include
the following elements in a format prescribed by the Administrator:
(1) Identification of the TR SO2 Group 1 source, and
each TR SO2 Group 1 unit at the source, for which the
certificate of representation is submitted, including source name,
source category and NAICS code (or, in the absence of a NAICS code, an
equivalent code), State, plant code, county, latitude and longitude,
unit identification number and type, identification number and
nameplate capacity (in MWe rounded to the nearest tenth) of each
generator served by each such unit, 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-the-unit, firm power
contractual arrangement, I certify that: I have given a written notice
of my selection as the `designated representative' or `alternate
designated representative', as applicable, and of the agreement by
which I was selected to each owner and operator of the source and of
each TR SO2 Group 1 unit at the source; and TR
SO2 Group 1 allowances and proceeds of transactions
involving TR SO2 Group 1 allowances will be deemed to be
held or distributed in proportion to each 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
[[Page 45429]]
distributed in accordance with the contract.''
(5) The signature of the designated representative and any
alternate designated representative and the dates signed.
(b) Unless otherwise required by the Administrator, documents of
agreement referred to in the certificate of representation shall not be
submitted to the Administrator. The Administrator shall not be under
any obligation to review or evaluate the sufficiency of such documents,
if submitted.
Sec. 97.617 Objections concerning designated representative and
alternate designated representative.
(a) Once a complete certificate of representation under Sec.
97.616 has been submitted and received, the Administrator will rely on
the certificate of representation unless and until a superseding
complete certificate of representation under Sec. 97.616 is received
by the Administrator.
(b) Except as provided in Sec. 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.
Sec. 97.618 Delegation by designated representative and alternate
designated representative.
(a) A designated representative may delegate, to one or more
natural persons, his or her authority to make an electronic submission
to the Administrator provided for or required under this subpart.
(b) An alternate designated representative may delegate, to one or
more natural persons, his or her authority to make an electronic
submission to the Administrator provided for or required under this
subpart.
(c) In order to delegate authority to 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 97.618(d) shall
be deemed to be an electronic submission by me.''
(ii) ``Until this notice of delegation is superseded by another
notice of delegation under 40 CFR 97.618(d), I agree to maintain an e-
mail account and to notify the Administrator immediately of any change
in my e-mail address unless all delegation of authority by me under 40
CFR 97.618 is terminated.''.
(d) A notice of delegation submitted under paragraph (c) of this
section shall be effective, with regard to the designated
representative or alternate designated representative identified in
such notice, upon receipt of such notice by the Administrator and until
receipt by the Administrator of a superseding notice of delegation
submitted by such designated representative or alternate designated
representative, as appropriate. The superseding notice of delegation
may replace any previously identified agent, add a new agent, or
eliminate entirely any delegation of authority.
(e) Any electronic submission covered by the certification in
paragraph (c)(4)(i) of this section and made in accordance with a
notice of delegation effective under paragraph (d) of this section
shall be deemed to be an electronic submission by the designated
representative or alternate designated representative submitting such
notice of delegation.
Sec. 97.619 [Reserved]
Sec. 97.620 Establishment of Allowance Management System accounts.
(a) Compliance accounts. Upon receipt of a complete certificate of
representation under Sec. 97.616, the Administrator will establish a
compliance account for the TR SO2 Group 1 source for which
the certificate of representation was submitted, unless the source
already has a compliance account. The designated representative and any
alternate designated representative of the source shall be the
authorized account representative and the alternate authorized account
representative respectively of the compliance account.
(b) 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
[[Page 45430]]
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.
(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 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
[[Page 45431]]
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 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 Sec. 97.622 for any TR SO2 Group 1
allowances in the account to one or more other Allowance Management
System accounts.
(ii) If a general account has no TR SO2 Group 1
allowance transfers to or from the account for a 12-month period or
longer and does not contain any TR SO2 Group 1 allowances,
the Administrator may notify the authorized account representative for
the account that the account will be closed after 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 1 allowance
transfer under Sec. 97.622 to the account or a statement submitted by
the authorized account representative or alternate authorized account
representative demonstrating to the satisfaction of the Administrator
good cause as to why the account should not be closed.
(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
Sec. Sec. 97.614(a) and 97.618 or paragraphs (b)(2)(ii) and (b)(5) of
this section.
Sec. 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 Sec. Sec. 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 Sec. 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 Sec. 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
[[Page 45432]]
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.
Sec. 97.622 Submission of TR SO2 Group 1 allowance transfers.
(a) An authorized account representative seeking recordation of a
TR SO2 Group 1 allowance transfer shall submit the transfer
to the Administrator.
(b) A TR SO2 Group 1 allowance transfer shall be
correctly submitted if:
(1) The transfer includes the following elements, in a format
prescribed by the Administrator:
(i) The account numbers established by the Administrator for both
the transferor and transferee accounts;
(ii) The serial number of each TR SO2 Group 1 allowance
that is in the transferor account and is to be transferred; and
(iii) The name and signature of the authorized account
representative of the transferor account and the date signed; and
(2) When the Administrator attempts to record the transfer, the
transferor account includes each TR SO2 Group 1 allowance
identified by serial number in the transfer.
Sec. 97.623 Recordation of TR SO2 Group 1 allowance transfers.
(a) Within 5 business days (except as provided in paragraph (b) of
this section) of receiving a TR SO2 Group 1 allowance
transfer, 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
Sec. 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 Sec. 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 Sec. 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 deductions under Sec.
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 Sec. 97.622, the Administrator will not
record such transfer.
(d) Within 5 business days of recordation of a TR SO2
Group 1 allowance transfer under paragraphs (a) and (b) of the section,
the Administrator will notify the authorized account representatives of
both the transferor and transferee accounts.
(e) Within 10 business days of receipt of a TR SO2 Group
1 allowance transfer that is not correctly submitted under Sec.
97.622, the Administrator will notify the authorized account
representatives of both accounts subject to the transfer of:
(1) A decision not to record the transfer, and
(2) The reasons for such non-recordation.
Sec. 97.624 Compliance with TR SO2 Group 1 emissions limitation.
(a) Availability for deduction for compliance. TR SO2
Group 1 allowances are available to be deducted for compliance with a
source's TR SO2 Group 1 emissions limitation for a control
period in a given year only if the TR SO2 Group 1
allowances:
(1) Were allocated for 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 Sec. 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 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.
Sec. 97.625 Compliance with TR SO2 Group 1 assurance provisions.
(a) Availability for deduction. TR SO2 Group 1
allowances are available to be deducted for compliance with the TR
SO2 Group 1 assurance provisions for a control period in a
given year by 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
[[Page 45433]]
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 Sec. 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 Sec. Sec.
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 Sec.
97.606(c)(2)(iii) and Sec. Sec. 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 Sec. 97.606(c)(2)(iii):
(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 Sec.
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 Sec. 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 Sec. 97.602, and the
calculation formula in Sec. 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 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 allowance-holding 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 Sec.
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
[[Page 45434]]
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 Sec. 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 Sec. 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.
(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 Sec.
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.
(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.
Sec. 97.626 Banking.
(a) A TR SO2 Group 1 allowance may be banked for future
use or transfer in a compliance account or a general account in
accordance with paragraph (b) of this section.
(b) Any TR SO2 Group 1 allowance that is held in a
compliance account or a general account will remain in such
[[Page 45435]]
account unless and until the TR SO2 Group 1 allowance is
deducted or transferred under Sec. 97.611(c), Sec. 97.623, Sec.
97.624, Sec. 97.625, 97.627, 97.628, 97.642, or 97.643.
Sec. 97.627 Account error.
The Administrator may, at his or her sole discretion and on his or
her own motion, correct any error in any Allowance Management System
account. Within 10 business days of making such correction, the
Administrator will notify the authorized account representative for the
account.
Sec. 97.628 Administrator's action on submissions.
(a) The Administrator may review and conduct independent audits
concerning any submission under the TR SO2 Group 1 Trading
Program and make appropriate adjustments of the information in the
submission.
(b) The Administrator may deduct TR SO2 Group 1
allowances from or transfer TR SO2 Group 1 allowances to a
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.
Sec. 97.629 [Reserved]
Sec. 97.630 General monitoring, recordkeeping, and reporting
requirements.
The owners and operators, and to the extent applicable, the
designated representative, of a TR SO2 Group 1 unit, shall
comply with the monitoring, recordkeeping, and reporting requirements
as provided in this subpart and subparts F and G of part 75 of this
chapter. For purposes of applying such requirements, the definitions in
Sec. 97.602 and in Sec. 72.2 of this chapter shall apply, the terms
``affected unit,'' ``designated representative,'' and ``continuous
emission monitoring system'' (or ``CEMS'') in part 75 of this chapter
shall be deemed to refer to the terms ``TR SO2 Group 1
unit,'' ``designated representative,'' and ``continuous emission
monitoring system'' (or ``CEMS'') respectively as defined in Sec.
97.602, and the term ``newly affected unit'' shall be deemed to mean
``newly affected TR SO2 Group 1 unit.'' The owner or
operator of a unit that is not a TR SO2 Group 1 unit but
that is monitored under Sec. 75.16(b)(2) of this chapter shall comply
with the same monitoring, recordkeeping, and reporting requirements as
a TR SO2 Group 1 unit.
(a) Requirements for installation, certification, and data
accounting. The owner or operator of each TR SO2 Group 1
unit shall:
(1) Install all monitoring systems required under this subpart for
monitoring SO2 mass emissions and individual unit heat input
(including all systems required to monitor SO2
concentration, stack gas moisture content, stack gas flow rate,
CO2 or O2 concentration, and fuel flow rate, as
applicable, in accordance with Sec. Sec. 75.11 and 75.16 of this
chapter);
(2) Successfully complete all certification tests required under
Sec. 97.631 and meet all other requirements of this subpart and part
75 of this chapter applicable to the monitoring systems under paragraph
(a)(1) of this section; and
(3) Record, report, and quality-assure the data from the monitoring
systems under paragraph (a)(1) of this section.
(b) Compliance deadlines. Except as provided in paragraph (e) of
this section, the owner or operator shall meet the monitoring system
certification and other requirements of paragraphs (a)(1) and (2) of
this section on or before the following dates. 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 Sec. 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
enters the TR SO2 Group 1 Trading Program as provided in
Sec. 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 Sec.
75.31(b)(2) or (c)(3) of this chapter or section 2.4 of appendix D to
part 75 of this chapter, as applicable.
(d) Prohibitions. (1) No owner or operator of a TR SO2
Group 1 unit shall use any alternative monitoring system, alternative
reference method, or any other alternative to any requirement of this
subpart without having obtained prior written approval in accordance
with Sec. 97.635.
(2) No owner or operator of a TR SO2 Group 1 unit shall
operate the unit so as to discharge, or allow to be discharged,
SO2 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 Sec. 97.605 that is in effect;
(ii) The owner or operator is monitoring emissions from the unit
with another certified monitoring system approved, in accordance with
the applicable provisions of this subpart and part 75 of this chapter,
by the Administrator for use at that unit that provides emission data
for the same
[[Page 45436]]
pollutant or parameter as the retired or discontinued monitoring
system; or
(iii) The designated representative submits notification of the
date of certification testing of a replacement monitoring system for
the retired or discontinued monitoring system in accordance with Sec.
97.631(d)(3)(i).
(e) Long-term cold storage. The owner or operator of a TR
SO2 Group 1 unit is subject to the applicable provisions of
Sec. 75.4(d) of this chapter concerning units in long-term cold
storage.
Sec. 97.631 Initial monitoring system certification and
recertification procedures.
(a) The owner or operator of a TR SO2 Group 1 unit shall
be exempt from the initial certification requirements of this section
for a monitoring system under Sec. 97.630(a)(1) if the following
conditions are met:
(1) The monitoring system has been previously certified in
accordance with part 75 of this chapter; and
(2) The applicable quality-assurance and quality-control
requirements of Sec. 75.21 of this chapter and appendices B and D to
part 75 of this chapter are fully met for the certified monitoring
system described in paragraph (a)(1) of this section.
(b) The recertification provisions of this section shall apply to a
monitoring system under Sec. 97.630(a)(1) exempt from initial
certification requirements under paragraph (a) of this section.
(c) [Reserved]
(d) Except as provided in paragraph (a) of this section, the owner
or operator of a TR SO2 Group 1 unit shall comply with the
following initial certification and recertification procedures, for a
continuous monitoring system (i.e., a continuous emission monitoring
system and an excepted monitoring system under appendix D to part 75 of
this chapter) under Sec. 97.630(a)(1). The owner or operator of a unit
that qualifies to use the low mass emissions excepted monitoring
methodology under Sec. 75.19 of this chapter or that qualifies to use
an alternative monitoring system under subpart E of part 75 of this
chapter shall comply with the procedures in paragraph (e) or (f) of
this section respectively.
(1) Requirements for initial certification. The owner or operator
shall ensure that each continuous monitoring system under Sec.
97.630(a)(1) (including the automated data acquisition and handling
system) successfully completes all of the initial certification testing
required under Sec. 75.20 of this chapter by the applicable deadline
in Sec. 97.630(b). In addition, whenever the owner or operator
installs a monitoring system to meet the requirements of this subpart
in a location where no such monitoring system was previously installed,
initial certification in accordance with Sec. 75.20 of this chapter is
required.
(2) Requirements for recertification. Whenever the owner or
operator makes a replacement, modification, or change in any certified
continuous emission monitoring system under Sec. 97.630(a)(1) that may
significantly affect the ability of the system to accurately measure or
record SO2 mass emissions or heat input rate or to meet the
quality-assurance and quality-control requirements of Sec. 75.21 of
this chapter or appendix B to part 75 of this chapter, the owner or
operator shall recertify the monitoring system in accordance with Sec.
75.20(b) of this chapter. Furthermore, whenever the owner or operator
makes a replacement, modification, or change to the flue gas handling
system or the unit's operation that may significantly change the stack
flow or concentration profile, the owner or operator shall recertify
each continuous emission monitoring system whose accuracy is
potentially affected by the change, in accordance with Sec. 75.20(b)
of this chapter. Examples of changes to a continuous emission
monitoring system that require recertification include: Replacement of
the analyzer, complete replacement of an existing continuous emission
monitoring system, or change in location or orientation of the sampling
probe or site. Any fuel flowmeter system under Sec. 97.630(a)(1) is
subject to the recertification requirements in Sec. 75.20(g)(6) of
this chapter.
(3) Approval process for initial certification and recertification.
For initial certification of a continuous monitoring system under Sec.
97.630(a)(1), paragraphs (d)(3)(i) through (v) of this section apply.
For recertifications of such monitoring systems, paragraphs (d)(3)(i)
through (iv) of this section and the procedures in Sec. Sec.
75.20(b)(5) and (g)(7) of this chapter (in lieu of the procedures in
paragraph (d)(3)(v) of this section) apply, provided that in applying
paragraphs (d)(3)(i) through (iv) of this section, the words
``certification'' and ``initial certification'' are replaced by the
word ``recertification'' and the word ``certified'' is replaced by with
the word ``recertified''.
(i) Notification of certification. The designated representative
shall submit to the appropriate EPA Regional Office and the
Administrator written notice of the dates of certification testing, in
accordance with Sec. 97.633.
(ii) Certification application. The designated representative shall
submit to the Administrator a certification application for each
monitoring system. A complete certification application shall include
the information specified in Sec. 75.63 of this chapter.
(iii) Provisional certification date. The provisional certification
date for a monitoring system shall be determined in accordance with
Sec. 75.20(a)(3) of this chapter. A provisionally certified monitoring
system may be used under the TR SO2 Group 1 Trading Program
for a period not to exceed 120 days after receipt by the Administrator
of the complete certification application for the monitoring system
under paragraph (d)(3)(ii) of this section. Data measured and recorded
by the provisionally certified monitoring system, in accordance with
the requirements of part 75 of this chapter, will be considered valid
quality-assured data (retroactive to the date and time of provisional
certification), provided that the Administrator does not invalidate the
provisional certification by issuing a notice of disapproval within 120
days of the date of receipt of the complete certification application
by the Administrator.
(iv) Certification application approval process. The Administrator
will issue a written notice of approval or disapproval of the
certification application to the owner or operator within 120 days of
receipt of the complete certification application under paragraph
(d)(3)(ii) of this section. In the event the Administrator does not
issue such a notice within such 120-day period, each monitoring system
that meets the applicable performance requirements of part 75 of this
chapter and is included in the certification application will be deemed
certified for use under the TR SO2 Group 1 Trading Program.
(A) Approval notice. If the certification application is complete
and shows that each monitoring system meets the applicable performance
requirements of part 75 of this chapter, then the Administrator will
issue a written notice of approval of the certification application
within 120 days of receipt.
(B) Incomplete application notice. If the certification application
is not complete, then the Administrator will issue a written notice of
incompleteness that sets a reasonable date by which the designated
representative must submit the additional information required to
complete the certification application. If the designated
representative does not comply with the notice of incompleteness by the
specified date, then the Administrator may issue a notice of
disapproval under paragraph (d)(3)(iv)(C) of this section. The 120-day
[[Page 45437]]
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 Sec. 75.20(a)(3) of this chapter).
(D) Audit decertification. The Administrator may issue a notice of
disapproval of the certification status of a monitor in accordance with
Sec. 97.632(b).
(v) Procedures for loss of certification. If the Administrator
issues a notice of disapproval of a certification application under
paragraph (d)(3)(iv)(C) of this section or a notice of disapproval of
certification status under paragraph (d)(3)(iv)(D) of this section,
then:
(A) The owner or operator shall substitute the following values,
for each disapproved monitoring system, for each hour of unit operation
during the period of invalid data specified under Sec.
75.20(a)(4)(iii), Sec. 75.20(g)(7), or Sec. 75.21(e) of this chapter
and continuing until the applicable date and hour specified under Sec.
75.20(a)(5)(i) or (g)(7) of this chapter:
(1) For a disapproved SO2 pollutant concentration
monitor and disapproved flow monitor, respectively, the maximum
potential concentration of SO2 and the maximum potential
flow rate, as defined in sections 2.1.1.1 and 2.1.4.1 of appendix A to
part 75 of this chapter.
(2) For a disapproved moisture monitoring system and disapproved
diluent gas monitoring system, respectively, the minimum potential
moisture percentage and either the maximum potential CO2
concentration or the minimum potential O2 concentration (as
applicable), as defined in sections 2.1.5, 2.1.3.1, and 2.1.3.2 of
appendix A to part 75 of this chapter.
(3) For a disapproved fuel flowmeter system, the maximum potential
fuel flow rate, as defined in section 2.4.2.1 of appendix D to part 75
of this chapter.
(B) The designated representative shall submit a notification of
certification retest dates and a new certification application in
accordance with paragraphs (d)(3)(i) and (ii) of this section.
(C) The owner or operator shall repeat all certification tests or
other requirements that were failed by the monitoring system, as
indicated in the Administrator's notice of disapproval, no later than
30 unit operating days after the date of issuance of the notice of
disapproval.
(e) The owner or operator of a unit qualified to use the low mass
emissions (LME) excepted methodology under Sec. 75.19 of this chapter
shall meet the applicable certification and recertification
requirements in Sec. Sec. 75.19(a)(2) and 75.20(h) of this chapter. If
the owner or operator of such a unit elects to certify a fuel flowmeter
system for heat input determination, the owner or operator shall also
meet the certification and recertification requirements in Sec.
75.20(g) of this chapter.
(f) The designated representative of each unit for which the owner
or operator intends to use an alternative monitoring system approved by
the Administrator under subpart E of part 75 of this chapter shall
comply with the applicable notification and application procedures of
Sec. 75.20(f) of this chapter.
Sec. 97.632 Monitoring system out-of-control periods.
(a) General provisions. Whenever any monitoring system fails to
meet the quality-assurance and quality-control requirements or data
validation requirements of part 75 of this chapter, data shall be
substituted using the applicable missing data procedures in subpart D
or appendix D to part 75 of this chapter.
(b) Audit decertification. Whenever both an audit of a monitoring
system and a review of the initial certification or recertification
application reveal that any monitoring system should not have been
certified or recertified because it did not meet a particular
performance specification or other requirement under Sec. 97.631 or
the applicable provisions of part 75 of this chapter, both at the time
of the initial certification or recertification application submission
and at the time of the audit, the Administrator will issue a notice of
disapproval of the certification status of such monitoring system. For
the purposes of this paragraph, an audit shall be either a field audit
or an audit of any information submitted to the Administrator or any
permitting authority. By issuing the notice of disapproval, the
Administrator revokes prospectively the certification status of the
monitoring system. The data measured and recorded by the monitoring
system shall not be considered valid quality-assured data from the date
of issuance of the notification of the revoked certification status
until the date and time that the owner or operator completes
subsequently approved initial certification or recertification tests
for the monitoring system. The owner or operator shall follow the
applicable initial certification or recertification procedures in Sec.
97.631 for each disapproved monitoring system.
Sec. 97.633 Notifications concerning monitoring.
The designated representative of a TR SO2 Group 1 unit
shall submit written notice to the Administrator in accordance with
Sec. 75.61 of this chapter.
Sec. 97.634 Recordkeeping and reporting.
(a) General provisions. The designated representative shall comply
with all recordkeeping and reporting requirements in this section, the
applicable recordkeeping and reporting requirements in subparts F and G
of part 75 of this chapter, and the requirements of Sec. 97.614(a).
(b) Monitoring plans. The owner or operator of a TR SO2
Group 1 unit shall comply with requirements of Sec. 75.62 of this
chapter.
(c) Certification applications. The designated representative shall
submit an application to the Administrator within 45 days after
completing all initial certification or recertification tests required
under Sec. 97.631, including the information required under Sec.
75.63 of this chapter.
(d) Quarterly reports. The designated representative shall submit
quarterly reports, as follows:
(1) The designated representative shall report the SO2
mass emissions data and heat input data for the TR SO2 Group
1 unit, in an electronic quarterly report in a format prescribed by the
Administrator, for each calendar quarter beginning with:
(i) For a unit that commences commercial operation before July 1,
2011, the calendar quarter covering January 1, 2012 through March 31,
2012;
(ii) For a unit that commences commercial operation on or after
July 1, 2011, the calendar quarter corresponding to the earlier of the
date of provisional certification or the applicable deadline for
initial certification under Sec. 97.630(b), unless that quarter is the
third or fourth quarter of 2011, in which case reporting shall
[[Page 45438]]
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 Sec. 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 Sec. 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 Sec. 75.64 of this chapter.
(3) For TR SO2 Group 1 units that are also subject to
the Acid Rain Program, TR NOX Annual Trading Program, or TR
NOX Ozone Season Trading Program, quarterly reports shall
include the applicable data and information required by subparts F
through H of part 75 of this chapter as applicable, in addition to the
SO2 mass emission data, heat input data, and other
information required by this subpart.
(4) The Administrator may review and conduct independent audits of
any quarterly report in order to determine whether the quarterly report
meets the requirements of this subpart and part 75 of this chapter,
including the requirement to use substitute data.
(i) The Administrator will notify the designated representative of
any determination that the quarterly report fails to meet any such
requirements and specify in such notification any corrections that the
Administrator believes are necessary to make through resubmission of
the quarterly report and a reasonable time period within which the
designated representative must respond. Upon request by the designated
representative, the Administrator may specify reasonable extensions of
such time period. Within the time period (including any such
extensions) specified by the Administrator, the designated
representative shall resubmit the quarterly report with the corrections
specified by the Administrator, except to the extent the designated
representative provides information demonstrating that a specified
correction is not necessary because the quarterly report already meets
the requirements of this subpart and part 75 of this chapter that are
relevant to the specified correction.
(ii) Any resubmission of a quarterly report shall meet the
requirements applicable to the submission of a quarterly report under
this subpart and part 75 of this chapter, except for the deadline set
forth in paragraph (d)(2) of this section.
(e) Compliance certification. The designated representative shall
submit to the Administrator a compliance certification (in a format
prescribed by the Administrator) in support of each quarterly report
based on reasonable inquiry of those persons with primary
responsibility for ensuring that all of the unit's emissions are
correctly and fully monitored. The certification shall state that:
(1) The monitoring data submitted were recorded in accordance with
the applicable requirements of this subpart and part 75 of this
chapter, including the quality assurance procedures and specifications;
and
(2) For a unit with add-on SO2 emission controls and for
all hours where SO2 data are substituted in accordance with
Sec. 75.34(a)(1) of this chapter, the add-on emission controls were
operating within the range of parameters listed in the quality
assurance/quality control program under appendix B to part 75 of this
chapter and the substitute data values do not systematically
underestimate SO2 emissions.
Sec. 97.635 Petitions for alternatives to monitoring, recordkeeping,
or reporting requirements.
(a) The designated representative of a TR SO2 Group 1
unit may submit a petition under Sec. 75.66 of this chapter to the
Administrator, requesting approval to apply an alternative to any
requirement of Sec. Sec. 97.630 through 97.634 or paragraph (5)(i) or
(ii) of the definition of ``owner's share'' in Sec. 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 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.
Sec. 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 Sec. 97.604;
(3) Is not covered by a retired unit exemption under Sec. 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 Sec. Sec. 97.605, 97.611, and 97.612.
(c) Solely for purposes of applying the requirements of Sec. Sec.
97.613 through 97.618 and Sec. Sec. 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 Sec. 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 Sec. 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.
Sec. 97.641 Opt-in process.
A unit meeting the requirements for a TR SO2 Group 1
opt-in unit in Sec. 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 Sec. 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,
[[Page 45439]]
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 Sec. 97.604;
(ii) Is not covered by a retired unit exemption under Sec. 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 Sec. Sec. 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 Sec. 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 Sec. 97.643;
(6) A complete certificate of representation under Sec. 97.616
consistent with Sec. 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 Sec. Sec. 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 Sec. Sec.
97.630 through 97.635, starting on the date of certification of the
necessary monitoring systems under Sec. Sec. 97.630 through 97.635 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 SO2 Group 1 Trading Program in
accordance with Sec. 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
Sec. Sec. 97.630 through 97.635 and the unit must be in full
compliance with any applicable State or Federal emissions or emissions-
related requirements.
(2) To the extent the SO2 emission rate and the heat
input of the unit are monitored and reported in accordance with
Sec. Sec. 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 Sec. Sec. 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 emissions-
related 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.
(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 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; 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 Sec.
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 opt-
in 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 Sec. 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
[[Page 45440]]
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.
Sec. 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 Sec.
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 Sec. Sec. 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
Sec. 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 to another Allowance Management System account in accordance
with Sec. Sec. 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 Sec. 97.641 for such
unit before the date that is 4 years after the date on which the
withdrawal became effective.
Sec. 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 Sec. 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 Sec.
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 Sec. 97.604, TR
SO2 Group 1 allowances equal in amount to and allocated for
the same or a prior control period as:
(i) Any TR SO2 Group 1 allowances allocated to the TR
SO2 Group 1 opt-in unit under Sec. 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 Sec.
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 Sec. 97.604 is not
December 31, the TR SO2 Group 1 allowances allocated to the
TR SO2 Group 1 opt-in unit under Sec. 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
Sec. 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 Sec.
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 Sec.
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 Sec. 97.604, the TR SO2 Group 1 opt-in unit will
be allocated TR SO2 Group 1 allowances in accordance with
Sec. 97.612.
(ii) If the date on which the TR SO2 Group 1 opt-in unit
becomes a TR SO2 Group 1 unit under Sec. 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 Sec.
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 Sec. 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 Sec. 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 Sec.
97.604, divided by the total number of days in the control period; and
(C) Rounded to the nearest allowance.
[[Page 45441]]
Sec. 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 Sec. 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 Sec. 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 Sec. 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 Sec. 97.641(g); or
(ii) The TR SO2 Group 1 opt-in unit's heat input, as
determined in accordance with Sec. Sec. 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 Sec. 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 Sec.
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 opt-in 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 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 Sec. 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.
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 opt-in 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
Sec. 97.701 Purpose.
This subpart sets forth the general, designated representative,
allowance, and monitoring provisions for the Transport Rule (TR)
SO2 Group 2 Trading Program, under section 110 of the Clean
Air Act and Sec. 52.38(b) of this chapter, as a means of mitigating
interstate transport of fine particulates and nitrogen oxides.
Sec. 97.702 Definitions.
The terms used in this subpart shall have the meanings set forth in
this section as follows:
Acid Rain Program means a multi-state SO2 and
NOX air pollution control and emission reduction program
established by the Administrator under title IV of the Clean Air Act
and parts 72 through 78 of this chapter.
Administrator means the Administrator of the United States
Environmental Protection Agency or the Director of the Clean Air
Markets Division (or its successor) 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
[[Page 45442]]
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 Sec. 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 Sec. 72.2 of this chapter, Sec. 97.402, or Sec. 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
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 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 system-wide basis the requirement in paragraph (2)(i)(B) of
this definition, the topping-cycle 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
[[Page 45443]]
duct burner, heat recovery steam generator, and steam turbine.
Commence commercial operation means, with regard to a unit:
(1) To have begun to produce steam, gas, or other heated medium
used to generate electricity for sale or use, including test
generation, except as provided in Sec. 97.705.
(i) For a unit that is a TR SO2 Group 2 unit under Sec.
97.704 on the later of 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
Sec. 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 Sec. 97.705, for a unit that is not a TR SO2
Group 2 unit under Sec. 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 Sec. 97.704.
(i) For a unit with a date for commencement of commercial operation
as defined in the introductory text of paragraph (2) of this definition
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.
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 Sec.
97.724 and the TR SO2 Group 2 assurance provisions in
accordance with Sec. 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 Sec. Sec. 97.730 through 97.735. The following
systems are the principal types of continuous emission monitoring
systems:
(1) A flow monitoring system, consisting of a stack flow rate
monitor and an automated data acquisition and handling system and
providing a permanent, continuous record of stack gas volumetric flow
rate, in standard cubic feet per hour (scfh);
(2) A SO2 monitoring system, consisting of a
SO2 pollutant concentration monitor and an automated data
acquisition and handling system and providing a permanent, continuous
record of SO2 emissions, in parts per million (ppm);
(3) A moisture monitoring system, as defined in Sec. 75.11(b)(2)
of this chapter and providing a permanent, continuous record of the
stack gas moisture content, in percent H2O;
(4) A CO2 monitoring system, consisting of a
CO2 pollutant concentration monitor (or an O2
monitor plus suitable mathematical equations from which the
CO2 concentration is derived) and an automated data
acquisition and handling system and providing a permanent, continuous
record of CO2 emissions, in percent CO2; and
(5) An O2 monitoring system, consisting of an
O2 concentration monitor and an automated data acquisition
and handling system and providing a permanent, continuous record of
O2, in percent O2.
Control period means the period starting January 1 of a calendar
year, except as provided in Sec. 97.706(c)(3), and ending on December
31 of the same year, inclusive.
Designated representative means, for a TR SO2 Group 2
source and each TR SO2 Group 2 unit at the source, the
natural person who is authorized by the owners and operators of the
source and all such units at the source, in accordance with this
subpart, to represent and legally bind each owner and operator in
matters pertaining to the TR SO2 Group 2 Trading Program. If
the TR SO2 Group 2 source is also subject to the Acid Rain
Program, TR NOX Annual Trading Program, or TR NOX
Ozone Season Trading Program, then this natural person shall be the
same natural person as the designated representative, as defined in
Sec. 72.2 of this chapter, Sec. 97.402, or Sec. 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--
[[Page 45444]]
(1) Natural gas, petroleum, coal, or any form of solid, liquid, or
gaseous fuel derived from such material; or
(2) For purposes of applying Sec. Sec. 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;
(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 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-the-
unit, firm power contractual arrangement;
(4) Provided that, for purposes of applying the TR SO2
Group 2 assurance provisions in Sec. Sec. 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 Sec. 97.706(c)(2)(iii)(A)
and not as described in Sec. 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 Sec. 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 Sec. 97.710(a) and the State's one-year variability limit
under Sec. 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
[[Page 45445]]
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 Sec. 97.710(a) and
the State's three-year variability limit under Sec. 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
Sec. 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 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
Sec. Sec. 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 Sec. 75.22 of this
chapter.
Replacement, replace, or replaced means, with regard to a unit, the
demolishing of a unit, or the permanent retirement and permanent
disabling of a unit, and the construction of another unit (the
replacement unit) to be used instead of the demolished or retired unit
(the replaced unit).
Sequential use of energy means:
(1) 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 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
Sec. 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
[[Page 45446]]
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 Sec. 97.724(a) for such control
period.
TR SO2 Group 2 source means a source that includes one or more TR
SO2 Group 2 units.
TR SO2 Group 2 Trading Program means a multi-state SO2
air pollution control and emission reduction program established 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.
TR SO2 Group 2 unit means a unit that is subject to the TR
SO2 Group 2 Trading Program under Sec. 97.704.
Unit means a stationary, fossil-fuel-fired boiler, stationary,
fossil-fuel-fired combustion turbine, or other stationary, fossil-fuel-
fired combustion device.
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.
Sec. 97.703 Measurements, abbreviations, and acronyms.
Measurements, abbreviations, and acronyms used in this subpart are
defined as follows:
Btu--British thermal unit
CO2--carbon dioxide
H2O--water
hr--hour
kW--kilowatt electrical
kWh--kilowatt hour
lb--pound
mmBtu--million Btu
MWe--megawatt electrical
MWh--megawatt hour
NOX--nitrogen oxides
O2--oxygen
ppm--parts per million
scfh--standard cubic feet per hour
SO2--sulfur dioxide
yr--year
Sec. 97.704 Applicability.
(a) Except as provided in paragraph (b) of this section:
(1) The following units in a State shall be TR SO2 Group
2 units, and any source that includes one or more such units shall be a
TR SO2 Group 2 source, subject to the requirements of this
subpart: Any stationary, fossil-fuel-fired boiler or stationary,
fossil-fuel-fired combustion turbine serving at any time, 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 start-up 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
[[Page 45447]]
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 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.
Sec. 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 Sec. 97.706(b) and (c)(1), Sec. 97.724, and Sec. Sec.
97.730 through 97.735.
(2) The exemption under paragraph (a)(1) of this section shall
become effective the day on which the TR SO2 Group 2 unit is
permanently retired. Within 30 days of the unit's permanent retirement,
the designated representative shall submit a statement to the
Administrator. The statement shall state, in a format prescribed by the
Administrator, that the unit was permanently retired on a specified
date and will comply with the requirements of paragraph (b) of this
section.
(b) Special provisions. (1) A unit exempt under paragraph (a) of
this section shall not emit any SO2, starting on the date
that the exemption takes effect.
(2) For a period of 5 years from the date the records are created,
the owners and operators of a unit exempt under paragraph (a) of this
section shall retain, at the source that includes the unit, records
demonstrating that the unit is permanently retired. The 5-year period
for keeping records may be extended for cause, at any time before the
end of the period, in writing by the Administrator. The owners and
operators bear the burden of proof that the unit is permanently
retired.
(3) The owners and operators and, to the extent applicable, the
designated representative of a unit exempt under paragraph (a) of this
section shall comply with the requirements of the TR SO2
Group 2 Trading Program concerning all periods for which the exemption
is not in effect, even if such requirements arise, or must be complied
with, after the exemption takes effect.
(4) A unit exempt under paragraph (a) of this section shall lose
its exemption on the first date on which the unit resumes operation.
Such unit shall be treated, for purposes of applying allocation,
monitoring, reporting, and recordkeeping requirements under this
subpart, as a unit that commences commercial operation on the first
date on which the unit resumes operation.
Sec. 97.706 Standard requirements.
(a) Designated representative requirements. The owners and
operators shall comply with the requirement to have a designated
representative, and may have an alternate designated representative, in
accordance with Sec. Sec. 97.713 through 97.718.
(b) Emissions monitoring, reporting, and recordkeeping
requirements. (1) The owners and operators, and the designated
representative, of each TR SO2 Group 2 source and each TR
SO2 Group 2 unit at the source shall comply with the
monitoring, reporting, and recordkeeping requirements of Sec. Sec.
97.730 through 97.735.
(2) The emissions data determined in accordance with Sec. Sec.
97.730 through 97.735 shall be used to calculate allocations of TR
SO2 Group 2 allowances under Sec. Sec. 97.711(a)(2) and (b)
and 97.712 and to determine compliance with the TR SO2 Group
2 emissions limitation and assurance provisions under paragraph (c) of
this section, provided that, for each monitoring location from which
mass emissions are reported, the mass emissions amount used in
calculating such allocations and determining such compliance shall be
the mass emissions amount for the monitoring location determined in
accordance with Sec. Sec. 97.730 through 97.735 and rounded to the
nearest ton, with any fraction of a ton less than 0.50 being deemed to
be zero.
(c) SO2 emissions requirements. (1) TR SO2 Group 2
emissions limitation. (i) As of the allowance transfer deadline for a
control period, the owners and operators of each TR SO2
Group 2 source and each TR SO2 Group 2 unit at the source
shall hold, in the source's compliance account, TR SO2 Group
2 allowances available for deduction for such control period under
Sec. 97.724(a) in an amount not less than the tons of total
SO2 emissions for such control period from all TR
SO2 Group 2 units at the source.
[[Page 45448]]
(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 Sec.
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 Sec. 97.725(b)(4)(ii), TR
SO2 Group 2 allowances available for deduction for such
control period under Sec. 97.725(a) in an amount equal to the product,
as determined by the Administrator in accordance with Sec. 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 2
trading budget and the State's one-year variability limit under Sec.
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 three-year variability limit under Sec.
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 Sec. 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 Sec. 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) 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 Sec. Sec. 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
Sec. 75.19 of this chapter), or an alternative monitoring system
(under subpart E of part 75 of this chapter) in accordance with
Sec. Sec. 97.730 through 97.735 may be added to, or changed in, a
title V permit using minor permit modification procedures in accordance
with Sec. Sec. 70.7(e)(2) and 71.7(e)(1) of this chapter, provided
that the requirements applicable to the described monitoring and
reporting (as added or changed, respectively) are already incorporated
in such permit. This paragraph explicitly provides that the addition
of, or change to, a unit's description as described in the prior
sentence is eligible for minor permit modification procedures in
accordance with Sec. Sec. 70.7(e)(2)(i)(B) and 71.7(e)(1)(i)(B) of
this chapter.
(e) Additional recordkeeping and reporting requirements. (1) Unless
otherwise provided, the owners and operators of each TR SO2
Group 2 source and each TR SO2 Group 2 unit at the source
shall keep on site at the source each of the following documents (in
hardcopy or electronic format) for a
[[Page 45449]]
period of 5 years from the date the document is created. This period
may be extended for cause, at any time before the end of 5 years, in
writing by the Administrator.
(i) The certificate of representation under Sec. 97.716 for the
designated representative for the source and each TR SO2
Group 2 unit at the source and all documents that demonstrate the truth
of the statements in the certificate of representation; provided that
the certificate and documents shall be retained on site at the source
beyond such 5-year period until such documents are superseded because
of the submission of a new certificate of representation under Sec.
97.716 changing the designated representative.
(ii) All emissions monitoring information, in accordance with this
subpart.
(iii) Copies of all reports, compliance certifications, and other
submissions and all records made or required under, or to demonstrate
compliance with the requirements of, the TR SO2 Group 2
Trading Program, 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 Sec. 97.705
shall be construed as exempting or excluding the owners and operators,
and the designated representative, of a TR SO2 Group 2
source or TR SO2 Group 2 unit from compliance with any other
provision of the applicable, approved State implementation plan, a
federally enforceable permit, or the Clean Air Act.
Sec. 97.707 Computation of time.
(a) Unless otherwise stated, any time period scheduled, under the
TR SO2 Group 2 Trading Program, to begin on the occurrence
of an act or event shall begin on the day the act or event occurs.
(b) Unless otherwise stated, any time period scheduled, under the
TR SO2 Group 2 Trading Program, to begin before the
occurrence of an act or event shall be computed so that the period ends
the day before the act or event occurs.
(c) Unless otherwise stated, if the final day of any time period,
under the TR SO2 Group 2 Trading Program, falls on a weekend
or a State or Federal holiday, the time period shall be extended to the
next business day.
Sec. 97.708 Administrative appeal procedures.
The administrative appeal procedures for decisions of the
Administrator under the TR SO2 Group 2 Trading Program are
set forth in part 78 of this chapter.
Sec. 97.709 [Reserved]
Sec. 97.710 State SO2 Group 2 trading budgets, new-unit set-asides,
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 New-unit set-
trading budget aside (tons)
(tons) * -----------------
State ------------------
For 2012 and For 2012 and
thereafter thereafter
------------------------------------------------------------------------
Alabama............................. 161,871 4,856
Connecticut......................... 3,059 92
Delaware............................ 7,784 234
District of Columbia................ 337 10
Florida............................. 161,739 4,852
Kansas.............................. 57,275 1,718
Louisiana........................... 90,477 2,714
Maryland............................ 39,665 1,190
Massachusetts....................... 7,902 237
Minnesota........................... 47,101 1,413
Nebraska............................ 71,598 2,148
New Jersey.......................... 11,291 339
South Carolina...................... 116,483 3,494
-----------------------------------
Total........................... 776,582 23,297
------------------------------------------------------------------------
* Without variability limits.
(b) The States' one-year and three-year variability limits for the
State SO2 Group 2 trading budgets for the control periods in
2014 and thereafter are as follows:
[[Page 45450]]
------------------------------------------------------------------------
One-year Three-year
variability variability
limits limits
State -----------------------------------
2014 and 2016 and
thereafter thereafter
(tons) (tons)
------------------------------------------------------------------------
Alabama............................. 16,187 9,346
Connecticut......................... 1,700 981
Delaware............................ 1,700 981
District of Columbia................ 1,700 981
Florida............................. 16,174 9,338
Kansas.............................. 5,728 3,307
Louisiana........................... 9,048 5,224
Maryland............................ 3,967 2,290
Massachusetts....................... 1,700 981
Minnesota........................... 4,710 2,719
Nebraska............................ 7,160 4,134
New Jersey.......................... 1,700 981
South Carolina...................... 11,648 6,725
------------------------------------------------------------------------
Sec. 97.711 Timing requirements for TR SO2 Group 2 allowance
allocations.
(a) Existing units. (1) TR SO2 Group 2 allowances are
allocated, for the control periods in 2012 and each year thereafter, as
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 Sec. 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 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 Sec. 97.712 and Sec. Sec. 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 Sec. 97.704 as of January 1,
2012, or whose deadline for meeting monitor certification requirements
under Sec. 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 Sec. 97.712 for the
control period to a recipient that is not actually a TR SO2
Group 2 unit under Sec. 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 Administrator will not record such TR SO2 Group 2
allowances under Sec. 97.721.
(2) If the Administrator already recorded such TR SO2
Group 2 allowances under Sec. 97.721 and if the Administrator makes
such determination before making deductions for the source that
includes such recipient under Sec. 97.724(b) for such control period,
then the Administrator will deduct from the account in which such TR
SO2 Group 2 allowances were recorded an amount of TR
SO2 Group 2 allowances allocated for the same or a prior
control period equal to the amount of such already recorded TR
SO2 Group 2 allowances. The authorized account
representative shall ensure that there are sufficient TR SO2
Group 2 allowances in such account for completion of the deduction.
(3) If the Administrator already recorded such TR SO2
Group 2 allowances under Sec. 97.721 and if the Administrator makes
such determination after making deductions for the source that includes
such recipient under Sec. 97.724(b) for such control period, then the
Administrator will not make any deduction to take account of such
already recorded TR SO2 Group 2 allowances.
(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 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, such notice has been promulgated, in the
next year.
[[Page 45451]]
Sec. 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 Sec. 97.711(c)(1) or (2), and to TR
SO2 Group 2 units that are so listed and, pursuant to Sec.
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 Sec. 97.710(a). Each new unit set-aside will
be allocated additional TR SO2 Group 2 allowances in
accordance with Sec. 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 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 Sec. 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 Sec. 97.711(a)(2), an amount of TR SO2
Group 2 allowances equal to the following: The total amount of such
remaining unallocated TR SO2 Group 2 allowances in such new
unit set-aside, multiplied by the unit's allocation under Sec.
97.711(a) for such control period, divided by the remainder of the
amount of tons in the applicable State SO2 Group 2 trading
budget minus the amount of tons in such new unit set-aside, and rounded
to the nearest allowance.
Sec. 97.713 Authorization of designated representative and alternate
designated representative.
(a) Except as provided under Sec. 97.715, each TR SO2
Group 2 source, including all TR SO2 Group 2 units at the
source, shall have one and only one designated representative, with
regard to all matters under the TR SO2 Group 2 Trading
Program.
(1) The designated representative shall be selected by an agreement
binding on the owners and operators of the source and all TR
SO2 Group 2 units at the source and shall act in accordance
with the certification statement in Sec. 97.716(a)(4)(iii).
(2) Upon and after receipt by the Administrator of a complete
certificate of representation under Sec. 97.716:
(i) The designated representative shall be authorized and shall
represent and, by his or her representations, actions, inactions, or
submissions, legally bind each owner and operator of the source and
each TR SO2 Group 2 unit at the source in all matters
pertaining to the TR SO2 Group 2 Trading Program,
notwithstanding any agreement between the designated representative and
such owners and operators; and
(ii) The owners and operators of the source and each TR
SO2 Group 2 unit at the source shall be bound by any
decision or order issued to the designated representative by the
Administrator regarding the source or any such unit.
(b) Except as provided under Sec. 97.715, each TR SO2
Group 2 source may have one and only one alternate designated
representative, who may act on behalf of the designated representative.
The agreement by which the alternate designated representative is
selected shall include a procedure for authorizing the alternate
designated representative to act in lieu of the designated
representative.
(1) The alternate designated representative shall be selected by an
agreement binding on the owners and operators of the source and all TR
SO2 Group 2 units at the source and shall act in accordance
with the certification statement in Sec. 97.716(a)(4)(iii).
(2) Upon and after receipt by the Administrator of a complete
certificate of representation under Sec. 97.716,
(i) The alternate designated representative shall be authorized;
(ii) Any representation, action, inaction, or submission by the
alternate designated representative shall be deemed to be a
representation, action,
[[Page 45452]]
inaction, or submission by the designated representative; and
(iii) The owners and operators of the source and each TR
SO2 Group 2 unit at the source shall be bound by any
decision or order issued to the alternate designated representative by
the Administrator regarding the source or any such unit.
(c) Except in this section, Sec. 97.702, and Sec. Sec. 97.714
through 97.718, whenever the term ``designated representative'' is used
in this subpart, the term shall be construed to include the designated
representative or any alternate designated representative.
Sec. 97.714 Responsibilities of designated representative and
alternate designated representative.
(a) Except as provided under Sec. 97.718 concerning delegation of
authority to make submissions, each submission under the TR
SO2 Group 2 Trading Program shall be made, signed, and
certified by the designated representative or alternate designated
representative for each TR SO2 Group 2 source and TR
SO2 Group 2 unit for which the submission is made. Each such
submission shall include the following certification statement by the
designated representative or alternate designated representative: ``I
am authorized to make this submission on behalf of the owners and
operators of the source or units for which the submission is made. I
certify under penalty of law that I have personally examined, and am
familiar with, the statements and information submitted in this
document and all its attachments. Based on my inquiry of those
individuals with primary responsibility for obtaining the information,
I certify that the statements and information are to the best of my
knowledge and belief true, accurate, and complete. I am aware that
there are significant penalties for submitting false statements and
information or omitting required statements and information, including
the possibility of fine or imprisonment.''
(b) The Administrator will accept or act on a submission made for a
TR SO2 Group 2 source or a TR SO2 Group 2 unit
only if the submission has been made, signed, and certified in
accordance with paragraph (a) of this section and Sec. 97.718.
Sec. 97.715 Changing designated representative and alternate
designated representative; changes in owners and operators.
(a) Changing designated representative. The designated
representative may be changed at any time upon receipt by the
Administrator of a superseding complete certificate of representation
under Sec. 97.716. Notwithstanding any such change, all
representations, actions, inactions, and submissions by the previous
designated representative before the time and date when the
Administrator receives the superseding certificate of representation
shall be binding on the new designated representative and the owners
and operators of the TR SO2 Group 2 source and the TR
SO2 Group 2 units at the source.
(b) Changing alternate designated representative. The alternate
designated representative may be changed at any time upon receipt by
the Administrator of a superseding complete certificate of
representation under Sec. 97.716. Notwithstanding any such change, all
representations, actions, inactions, and submissions by the previous
alternate designated representative before the time and date when the
Administrator receives the superseding certificate of representation
shall be binding on the new alternate designated representative, the
designated representative, and the owners and operators of the TR
SO2 Group 2 source and the TR SO2 Group 2 units
at the source.
(c) Changes in owners and operators. (1) In the event an owner or
operator of a TR SO2 Group 2 source or a TR SO2
Group 2 unit is not included in the list of owners and operators in the
certificate of representation under Sec. 97.716, such owner or
operator shall be deemed to be subject to and bound by the certificate
of representation, the representations, actions, inactions, and
submissions of the designated representative and any alternate
designated representative of the source or unit, and the decisions and
orders of the Administrator, as if the owner or operator were included
in such list.
(2) Within 30 days after any change in the owners and operators of
a TR SO2 Group 2 source or a TR SO2 Group 2 unit,
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 Sec. 97.716
amending the list of owners and operators to include the change.
Sec. 97.716 Certificate of representation.
(a) A complete certificate of representation for a designated
representative or an alternate designated representative shall include
the following elements in a format prescribed by the Administrator:
(1) Identification of the TR SO2 Group 2 source, and
each TR SO2 Group 2 unit at the source, for which the
certificate of representation is submitted, including source name,
source category and NAICS code (or, in the absence of a NAICS code, an
equivalent code), State, plant code, county, latitude and longitude,
unit identification number and type, identification number and
nameplate capacity (in MWe rounded to the nearest tenth) of each
generator served by each such unit, 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-the-unit, firm power
contractual arrangement, I certify that: I have given a written notice
of my selection as the `designated representative' or `alternate
designated representative', as applicable, and of the agreement by
which I was selected to each owner and operator of the source and of
each TR SO2 Group 2 unit at the source; and TR
SO2 Group 2 allowances and proceeds of transactions
involving TR SO2 Group 2 allowances will be deemed to be
held or distributed in proportion to each holder's legal, equitable,
leasehold, or contractual reservation or entitlement, except that, if
such multiple holders have expressly provided for a different
distribution of TR SO2 Group 2 allowances by contract, TR
SO2 Group 2 allowances and proceeds of transactions
involving TR SO2 Group 2
[[Page 45453]]
allowances will be deemed to be held or distributed in accordance with
the contract.''
(5) The signature of the designated representative and any
alternate designated representative and the dates signed.
(b) Unless otherwise required by the Administrator, documents of
agreement referred to in the certificate of representation shall not be
submitted to the Administrator. The Administrator shall not be under
any obligation to review or evaluate the sufficiency of such documents,
if submitted.
Sec. 97.717 Objections concerning designated representative and
alternate designated representative.
(a) Once a complete certificate of representation under Sec.
97.716 has been submitted and received, the Administrator will rely on
the certificate of representation unless and until a superseding
complete certificate of representation under Sec. 97.716 is received
by the Administrator.
(b) Except as provided in Sec. 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.
Sec. 97.718 Delegation by designated representative and alternate
designated representative.
(a) A designated representative may delegate, to one or more
natural persons, his or her authority to make an electronic submission
to the Administrator provided for or required under this subpart.
(b) An alternate designated representative may delegate, to one or
more natural persons, his or her authority to make an electronic
submission to the Administrator provided for or required under this
subpart.
(c) In order to delegate authority to 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 97.718(d) shall
be deemed to be an electronic submission by me.''
(ii) ``Until this notice of delegation is superseded by another
notice of delegation under 40 CFR 97.718(d), I agree to maintain an e-
mail account and to notify the Administrator immediately of any change
in my e-mail address unless all delegation of authority by me under 40
CFR 97.718 is terminated.''.
(d) A notice of delegation submitted under paragraph (c) of this
section shall be effective, with regard to the designated
representative or alternate designated representative identified in
such notice, upon receipt of such notice by the Administrator and until
receipt by the Administrator of a superseding notice of delegation
submitted by such designated representative or alternate designated
representative, as appropriate. The superseding notice of delegation
may replace any previously identified agent, add a new agent, or
eliminate entirely any delegation of authority.
(e) Any electronic submission covered by the certification in
paragraph (c)(4)(i) of this section and made in accordance with a
notice of delegation effective under paragraph (d) of this section
shall be deemed to be an electronic submission by the designated
representative or alternate designated representative submitting such
notice of delegation.
Sec. 97.719 [Reserved]
Sec. 97.720 Establishment of Allowance Management System accounts.
(a) Compliance accounts. Upon receipt of a complete certificate of
representation under Sec. 97.716, the Administrator will establish a
compliance account for the TR SO2 Group 2 source for which
the certificate of representation was submitted, unless the source
already has a compliance account. The designated representative and any
alternate designated representative of the source shall be the
authorized account representative and the alternate authorized account
representative respectively of the compliance account.
(b) 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
[[Page 45454]]
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.
(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 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
[[Page 45455]]
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 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 Sec. 97.722 for any TR SO2 Group 2
allowances in the account to one or more other Allowance Management
System accounts.
(ii) If a general account has no TR SO2 Group 2
allowance transfers to or from the account for a 12-month period or
longer and does not contain any TR SO2 Group 2 allowances,
the Administrator may notify the authorized account representative for
the account that the account will be closed 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 Sec. 97.722 to the account or a statement submitted by the
authorized account representative or alternate authorized account
representative demonstrating to the satisfaction of the Administrator
good cause as to why the account should not be closed.
(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
Sec. Sec. 97.714(a) and 97.718 or paragraphs (b)(2)(ii) and (b)(5) of
this section.
Sec. 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 Sec. Sec. 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 Sec. 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 Sec. 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
[[Page 45456]]
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.
Sec. 97.722 Submission of TR SO2 Group 2 allowance transfers.
(a) An authorized account representative seeking recordation of a
TR SO2 Group 2 allowance transfer shall submit the transfer
to the Administrator.
(b) A TR SO2 Group 2 allowance transfer shall be
correctly submitted if:
(1) The transfer includes the following elements, in a format
prescribed by the Administrator:
(i) The account numbers established by the Administrator for both
the transferor and transferee accounts;
(ii) The serial number of each TR SO2 Group 2 allowance
that is in the transferor account and is to be transferred; and
(iii) The name and signature of the authorized account
representative of the transferor account and the date signed; and
(2) When the Administrator attempts to record the transfer, the
transferor account includes each TR SO2 Group 2 allowance
identified by serial number in the transfer.
Sec. 97.723 Recordation of TR SO2 Group 2 allowance transfers.
(a) Within 5 business days (except as provided in paragraph (b) of
this section) of receiving a TR SO2 Group 2 allowance
transfer, 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
Sec. 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 Sec. 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 Sec. 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 Sec.
97.725 for the control period immediately before the year of such
deadline.
(c) Where a TR SO2 Group 2 allowance transfer is not
correctly submitted under Sec. 97.722, the Administrator will not
record such transfer.
(d) Within 5 business days of recordation of a TR SO2
Group 2 allowance transfer under paragraphs (a) and (b) of the section,
the Administrator will notify the authorized account representatives of
both the transferor and transferee accounts.
(e) Within 10 business days of receipt of a TR SO2 Group
2 allowance transfer that is not correctly submitted under Sec.
97.722, the Administrator will notify the authorized account
representatives of both accounts subject to the transfer of:
(1) A decision not to record the transfer, and
(2) The reasons for such non-recordation.
Sec. 97.724 Compliance with TR SO2 Group 2 emissions limitation.
(a) Availability for deduction for compliance. TR SO2
Group 2 allowances are available to be deducted for compliance with a
source's TR SO2 Group 2 emissions limitation for a control
period in a given year only if the TR SO2 Group 2
allowances:
(1) Were allocated for 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 Sec. 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 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.
Sec. 97.725 Compliance with TR SO2 Group 2 assurance provisions.
(a) Availability for deduction. TR SO2 Group 2
allowances are available to be deducted for compliance with the TR
SO2 Group 2 assurance provisions for a control period in a
given year by 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,
[[Page 45457]]
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 Sec. 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 Sec. Sec.
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 Sec.
97.706(c)(2)(iii) and Sec. Sec. 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 Sec. 97.706(c)(2)(iii):
(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 Sec.
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 Sec. 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 Sec. 97.702, and the
calculation formula in Sec. 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 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 allowance-holding 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 Sec.
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
[[Page 45458]]
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 Sec. 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 Sec. 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.
(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 Sec.
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.
(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.
Sec. 97.726 Banking.
(a) A TR SO2 Group 2 allowance may be banked for future
use or transfer in a compliance account or a general account in
accordance with paragraph (b) of this section.
(b) Any TR SO2 Group 2 allowance that is held in a
compliance account or a general account will remain in such
[[Page 45459]]
account unless and until the TR SO2 Group 2 allowance is
deducted or transferred under Sec. 97.711(c), Sec. 97.723, Sec.
97.724, Sec. 97.725, 97.727, 97.728, 97.742, or 97.743.
Sec. 97.727 Account error.
The Administrator may, at his or her sole discretion and on his or
her own motion, correct any error in any Allowance Management System
account. Within 10 business days of making such correction, the
Administrator will notify the authorized account representative for the
account.
Sec. 97.728 Administrator's action on submissions.
(a) The Administrator may review and conduct independent audits
concerning any submission under the TR SO2 Group 2 Trading
Program and make appropriate adjustments of the information in the
submission.
(b) The Administrator may deduct TR SO2 Group 2
allowances from or transfer TR SO2 Group 2 allowances to a
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.
Sec. 97.729 [Reserved]
Sec. 97.730 General monitoring, recordkeeping, and reporting
requirements.
The owners and operators, and to the extent applicable, the
designated representative, of a TR SO2 Group 2 unit, shall
comply with the monitoring, recordkeeping, and reporting requirements
as provided in this subpart and subparts F and G of part 75 of this
chapter. For purposes of applying such requirements, the definitions in
Sec. 97.702 and in Sec. 72.2 of this chapter shall apply, the terms
``affected unit,'' ``designated representative,'' and ``continuous
emission monitoring system'' (or ``CEMS'') in part 75 of this chapter
shall be deemed to refer to the terms ``TR SO2 Group 2
unit,'' ``designated representative,'' and ``continuous emission
monitoring system'' (or ``CEMS'') respectively as defined in Sec.
97.702, and the term ``newly affected unit'' shall be deemed to mean
``newly affected TR SO2 Group 2 unit''. The owner or
operator of a unit that is not a TR SO2 Group 2 unit but
that is monitored under Sec. 75.16(b)(2) of this chapter shall comply
with the same monitoring, recordkeeping, and reporting requirements as
a TR SO2 Group 2 unit.
(a) Requirements for installation, certification, and data
accounting. The owner or operator of each TR SO2 Group 2
unit shall:
(1) Install all monitoring systems required under this subpart for
monitoring SO2 mass emissions and individual unit heat input
(including all systems required to monitor SO2
concentration, stack gas moisture content, stack gas flow rate,
CO2 or O2 concentration, and fuel flow rate, as
applicable, in accordance with Sec. Sec. 75.11 and 75.16 of this
chapter);
(2) Successfully complete all certification tests required under
Sec. 97.731 and meet all other requirements of this subpart and part
75 of this chapter applicable to the monitoring systems under paragraph
(a)(1) of this section; and
(3) Record, report, and quality-assure the data from the monitoring
systems under paragraph (a)(1) of this section.
(b) Compliance deadlines. Except as provided in paragraph (e) of
this section, the owner or operator shall meet the monitoring system
certification and other requirements of paragraphs (a)(1) and (2) of
this section on or before the following dates. 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 Sec. 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
enters the TR SO2 Group 2 Trading Program as provided in
Sec. 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 Sec.
75.31(b)(2) or (c)(3) of this chapter or section 2.4 of appendix D to
part 75 of this chapter, as applicable.
(d) Prohibitions. (1) No owner or operator of a TR SO2
Group 2 unit shall use any alternative monitoring system, alternative
reference method, or any other alternative to any requirement of this
subpart without having obtained prior written approval in accordance
with Sec. 97.735.
(2) No owner or operator of a TR SO2 Group 2 unit shall
operate the unit so as to discharge, or allow to be discharged,
SO2 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 Sec. 97.705 that is in effect;
(ii) The owner or operator is monitoring emissions from the unit
with another certified monitoring system approved, in accordance with
the applicable provisions of this subpart and part 75 of this chapter,
by the Administrator for use at that unit that provides emission data
for the same
[[Page 45460]]
pollutant or parameter as the retired or discontinued monitoring
system; or
(iii) The designated representative submits notification of the
date of certification testing of a replacement monitoring system for
the retired or discontinued monitoring system in accordance with Sec.
97.731(d)(3)(i).
(e) Long-term cold storage. The owner or operator of a TR
SO2 Group 2 unit is subject to the applicable provisions of
Sec. 75.4(d) of this chapter concerning units in long-term cold
storage.
Sec. 97.731 Initial monitoring system certification and
recertification procedures.
(a) The owner or operator of a TR SO2 Group 2 unit shall
be exempt from the initial certification requirements of this section
for a monitoring system under Sec. 97.730(a)(1) if the following
conditions are met:
(1) The monitoring system has been previously certified in
accordance with part 75 of this chapter; and
(2) The applicable quality-assurance and quality-control
requirements of Sec. 75.21 of this chapter and appendices B and D to
part 75 of this chapter are fully met for the certified monitoring
system described in paragraph (a)(1) of this section.
(b) The recertification provisions of this section shall apply to a
monitoring system under Sec. 97.730(a)(1) exempt from initial
certification requirements under paragraph (a) of this section.
(c) [Reserved]
(d) Except as provided in paragraph (a) of this section, the owner
or operator of a TR SO2 Group 2 unit shall comply with the
following initial certification and recertification procedures, for a
continuous monitoring system (i.e., a continuous emission monitoring
system and an excepted monitoring system under appendix D to part 75 of
this chapter) under Sec. 97.730(a)(1). The owner or operator of a unit
that qualifies to use the low mass emissions excepted monitoring
methodology under Sec. 75.19 of this chapter or that qualifies to use
an alternative monitoring system under subpart E of part 75 of this
chapter shall comply with the procedures in paragraph (e) or (f) of
this section respectively.
(1) Requirements for initial certification. The owner or operator
shall ensure that each continuous monitoring system under Sec.
97.730(a)(1) (including the automated data acquisition and handling
system) successfully completes all of the initial certification testing
required under Sec. 75.20 of this chapter by the applicable deadline
in Sec. 97.730(b). In addition, whenever the owner or operator
installs a monitoring system to meet the requirements of this subpart
in a location where no such monitoring system was previously installed,
initial certification in accordance with Sec. 75.20 of this chapter is
required.
(2) Requirements for recertification. Whenever the owner or
operator makes a replacement, modification, or change in any certified
continuous emission monitoring system under Sec. 97.730(a)(1) that may
significantly affect the ability of the system to accurately measure or
record SO2 mass emissions or heat input rate or to meet the
quality-assurance and quality-control requirements of Sec. 75.21 of
this chapter or appendix B to part 75 of this chapter, the owner or
operator shall recertify the monitoring system in accordance with Sec.
75.20(b) of this chapter. Furthermore, whenever the owner or operator
makes a replacement, modification, or change to the flue gas handling
system or the unit's operation that may significantly change the stack
flow or concentration profile, the owner or operator shall recertify
each continuous emission monitoring system whose accuracy is
potentially affected by the change, in accordance with Sec. 75.20(b)
of this chapter. Examples of changes to a continuous emission
monitoring system that require recertification include: Replacement of
the analyzer, complete replacement of an existing continuous emission
monitoring system, or change in location or orientation of the sampling
probe or site. Any fuel flowmeter system under Sec. 97.730(a)(1) is
subject to the recertification requirements in Sec. 75.20(g)(6) of
this chapter.
(3) Approval process for initial certification and recertification.
For initial certification of a continuous monitoring system under Sec.
97.730(a)(1), paragraphs (d)(3)(i) through (v) of this section apply.
For recertifications of such monitoring systems, paragraphs (d)(3)(i)
through (iv) of this section and the procedures in Sec. Sec.
75.20(b)(5) and (g)(7) of this chapter (in lieu of the procedures in
paragraph (d)(3)(v) of this section) apply, provided that in applying
paragraphs (d)(3)(i) through (iv) of this section, the words
``certification'' and ``initial certification'' are replaced by the
word ``recertification'' and the word ``certified'' is replaced by the
word ``recertified''.
(i) Notification of certification. The designated representative
shall submit to the appropriate EPA Regional Office and the
Administrator written notice of the dates of certification testing, in
accordance with Sec. 97.733.
(ii) Certification application. The designated representative shall
submit to the Administrator a certification application for each
monitoring system. A complete certification application shall include
the information specified in Sec. 75.63 of this chapter.
(iii) Provisional certification date. The provisional certification
date for a monitoring system shall be determined in accordance with
Sec. 75.20(a)(3) of this chapter. A provisionally certified monitoring
system may be used under the TR SO2 Group 2 Trading Program
for a period not to exceed 120 days after receipt by the Administrator
of the complete certification application for the monitoring system
under paragraph (d)(3)(ii) of this section. Data measured and recorded
by the provisionally certified monitoring system, in accordance with
the requirements of part 75 of this chapter, will be considered valid
quality-assured data (retroactive to the date and time of provisional
certification), provided that the Administrator does not invalidate the
provisional certification by issuing a notice of disapproval within 120
days of the date of receipt of the complete certification application
by the Administrator.
(iv) Certification application approval process. The Administrator
will issue a written notice of approval or disapproval of the
certification application to the owner or operator within 120 days of
receipt of the complete certification application under paragraph
(d)(3)(ii) of this section. In the event the Administrator does not
issue such a notice within such 120-day period, each monitoring system
that meets the applicable performance requirements of part 75 of this
chapter and is included in the certification application will be deemed
certified for use under the TR SO2 Group 2 Trading Program.
(A) Approval notice. If the certification application is complete
and shows that each monitoring system meets the applicable performance
requirements of part 75 of this chapter, then the Administrator will
issue a written notice of approval of the certification application
within 120 days of receipt.
(B) Incomplete application notice. If the certification application
is not complete, then the Administrator will issue a written notice of
incompleteness that sets a reasonable date by which the designated
representative must submit the additional information required to
complete the certification application. If the designated
representative does not comply with the notice of incompleteness by the
specified date, then the Administrator may issue a notice of
disapproval under paragraph (d)(3)(iv)(C) of this section. The 120-day
review period specified in paragraph
[[Page 45461]]
(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 Sec. 75.20(a)(3) of this chapter).
(D) Audit decertification. The Administrator may issue a notice of
disapproval of the certification status of a monitor in accordance with
Sec. 97.732(b).
(v) Procedures for loss of certification. If the Administrator
issues a notice of disapproval of a certification application under
paragraph (d)(3)(iv)(C) of this section or a notice of disapproval of
certification status under paragraph (d)(3)(iv)(D) of this section,
then:
(A) The owner or operator shall substitute the following values,
for each disapproved monitoring system, for each hour of unit operation
during the period of invalid data specified under Sec.
75.20(a)(4)(iii), Sec. 75.20(g)(7), or Sec. 75.21(e) of this chapter
and continuing until the applicable date and hour specified under Sec.
75.20(a)(5)(i) or (g)(7) of this chapter:
(1) For a disapproved SO2 pollutant concentration
monitor and disapproved flow monitor, respectively, the maximum
potential concentration of SO2 and the maximum potential
flow rate, as defined in sections 2.1.1.1 and 2.1.4.1 of appendix A to
part 75 of this chapter.
(2) For a disapproved moisture monitoring system and disapproved
diluent gas monitoring system, respectively, the minimum potential
moisture percentage and either the maximum potential CO2
concentration or the minimum potential O2 concentration (as
applicable), as defined in sections 2.1.5, 2.1.3.1, and 2.1.3.2 of
appendix A to part 75 of this chapter.
(3) For a disapproved fuel flowmeter system, the maximum potential
fuel flow rate, as defined in section 2.4.2.1 of appendix D to part 75
of this chapter.
(B) The designated representative shall submit a notification of
certification retest dates and a new certification application in
accordance with paragraphs (d)(3)(i) and (ii) of this section.
(C) The owner or operator shall repeat all certification tests or
other requirements that were failed by the monitoring system, as
indicated in the Administrator's notice of disapproval, no later than
30 unit operating days after the date of issuance of the notice of
disapproval.
(e) The owner or operator of a unit qualified to use the low mass
emissions (LME) excepted methodology under Sec. 75.19 of this chapter
shall meet the applicable certification and recertification
requirements in Sec. Sec. 75.19(a)(2) and 75.20(h) of this chapter. If
the owner or operator of such a unit elects to certify a fuel flowmeter
system for heat input determination, the owner or operator shall also
meet the certification and recertification requirements in Sec.
75.20(g) of this chapter.
(f) The designated representative of each unit for which the owner
or operator intends to use an alternative monitoring system approved by
the Administrator under subpart E of part 75 of this chapter shall
comply with the applicable notification and application procedures of
Sec. 75.20(f) of this chapter.
Sec. 97.732 Monitoring system out-of-control periods.
(a) General provisions. Whenever any monitoring system fails to
meet the quality-assurance and quality-control requirements or data
validation requirements of part 75 of this chapter, data shall be
substituted using the applicable missing data procedures in subpart D
or appendix D to part 75 of this chapter.
(b) Audit decertification. Whenever both an audit of a monitoring
system and a review of the initial certification or recertification
application reveal that any monitoring system should not have been
certified or recertified because it did not meet a particular
performance specification or other requirement under Sec. 97.731 or
the applicable provisions of part 75 of this chapter, both at the time
of the initial certification or recertification application submission
and at the time of the audit, the Administrator will issue a notice of
disapproval of the certification status of such monitoring system. For
the purposes of this paragraph, an audit shall be either a field audit
or an audit of any information submitted to the Administrator or any
permitting authority. By issuing the notice of disapproval, the
Administrator revokes prospectively the certification status of the
monitoring system. The data measured and recorded by the monitoring
system shall not be considered valid quality-assured data from the date
of issuance of the notification of the revoked certification status
until the date and time that the owner or operator completes
subsequently approved initial certification or recertification tests
for the monitoring system. The owner or operator shall follow the
applicable initial certification or recertification procedures in Sec.
97.731 for each disapproved monitoring system.
Sec. 97.733 Notifications concerning monitoring.
The designated representative of a TR SO2 Group 2 unit
shall submit written notice to the Administrator in accordance with
Sec. 75.61 of this chapter.
Sec. 97.734 Recordkeeping and reporting.
(a) General provisions. The designated representative shall comply
with all recordkeeping and reporting requirements in this section, the
applicable recordkeeping and reporting requirements in subparts F and G
of part 75 of this chapter, and the requirements of Sec. 97.714(a).
(b) Monitoring plans. The owner or operator of a TR SO2
Group 2 unit shall comply with requirements of Sec. 75.62 of this
chapter.
(c) Certification applications. The designated representative shall
submit an application to the Administrator within 45 days after
completing all initial certification or recertification tests required
under Sec. 97.731, including the information required under Sec.
75.63 of this chapter.
(d) Quarterly reports. The designated representative shall submit
quarterly reports, as follows:
(1) The designated representative shall report the SO2
mass emissions data and heat input data for the TR SO2 Group
2 unit, in an electronic quarterly report in a format prescribed by the
Administrator, for each calendar quarter beginning with:
(i) For a unit that commences commercial operation before July 1,
2011, the calendar quarter covering January 1, 2012 through March 31,
2012;
(ii) For a unit that commences commercial operation on or after
July 1, 2011, the calendar quarter corresponding to the earlier of the
date of provisional certification or the applicable deadline for
initial certification under Sec. 97.730(b), unless that quarter is the
third or fourth quarter of 2011, in which case reporting shall
[[Page 45462]]
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 Sec. 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 Sec. 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 Sec. 75.64 of this chapter.
(3) For TR SO2 Group 2 units that are also subject to
the Acid Rain Program, TR NOX Annual Trading Program, or TR
NOX Ozone Season Trading Program, quarterly reports shall
include the applicable data and information required by subparts F
through H of part 75 of this chapter as applicable, in addition to the
SO2 mass emission data, heat input data, and other
information required by this subpart.
(4) The Administrator may review and conduct independent audits of
any quarterly report in order to determine whether the quarterly report
meets the requirements of this subpart and part 75 of this chapter,
including the requirement to use substitute data.
(i) The Administrator will notify the designated representative of
any determination that the quarterly report fails to meet any such
requirements and specify in such notification any corrections that the
Administrator believes are necessary to make through resubmission of
the quarterly report and a reasonable time period within which the
designated representative must respond. Upon request by the designated
representative, the Administrator may specify reasonable extensions of
such time period. Within the time period (including any such
extensions) specified by the Administrator, the designated
representative shall resubmit the quarterly report with the corrections
specified by the Administrator, except to the extent the designated
representative provides information demonstrating that a specified
correction is not necessary because the quarterly report already meets
the requirements of this subpart and part 75 of this chapter that are
relevant to the specified correction.
(ii) Any resubmission of a quarterly report shall meet the
requirements applicable to the submission of a quarterly report under
this subpart and part 75 of this chapter, except for the deadline set
forth in paragraph (d)(2) of this section.
(e) Compliance certification. The designated representative shall
submit to the Administrator a compliance certification (in a format
prescribed by the Administrator) in support of each quarterly report
based on reasonable inquiry of those persons with primary
responsibility for ensuring that all of the unit's emissions are
correctly and fully monitored. The certification shall state that:
(1) The monitoring data submitted were recorded in accordance with
the applicable requirements of this subpart and part 75 of this
chapter, including the quality assurance procedures and specifications;
and
(2) For a unit with add-on SO2 emission controls and for
all hours where SO2 data are substituted in accordance with
Sec. 75.34(a)(1) of this chapter, the add-on emission controls were
operating within the range of parameters listed in the quality
assurance/quality control program under appendix B to part 75 of this
chapter and the substitute data values do not systematically
underestimate SO2 emissions.
Sec. 97.735 Petitions for alternatives to monitoring, recordkeeping,
or reporting requirements.
(a) The designated representative of a TR SO2 Group 2
unit may submit a petition under Sec. 75.66 of this chapter to the
Administrator, requesting approval to apply an alternative to any
requirement of Sec. Sec. 97.730 through 97.734 or paragraph (5)(i) or
(ii) of the definition of ``owner's share'' in Sec. 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 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.
Sec. 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 Sec. 97.704;
(3) Is not covered by a retired unit exemption under Sec. 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 Sec. Sec. 97.705, 97.711, and 97.712.
(c) Solely for purposes of applying the requirements of Sec. Sec.
97.713 through 97.718 and Sec. Sec. 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 Sec. 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 Sec. 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.
Sec. 97.741 Opt-in process.
A unit meeting the requirements for a TR SO2 Group 2
opt-in unit in Sec. 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 Sec. 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,
[[Page 45463]]
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 Sec. 97.704;
(ii) Is not covered by a retired unit exemption under Sec. 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 Sec. Sec. 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 Sec. 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 Sec. 97.743;
(6) A complete certificate of representation under Sec. 97.716
consistent with Sec. 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 Sec. Sec. 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 Sec. Sec.
97.730 through 97.735, starting on the date of certification of the
necessary monitoring systems under Sec. Sec. 97.730 through 97.735 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 SO2 Group 2 Trading Program in
accordance with Sec. 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
Sec. Sec. 97.730 through 97.735 and the unit must be in full
compliance with any applicable State or Federal emissions or emissions-
related requirements.
(2) To the extent the SO2 emission rate and the heat
input of the unit are monitored and reported in accordance with
Sec. Sec. 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 Sec. Sec. 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 emissions-
related 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.
(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 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; 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 Sec.
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 opt-
in 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 opt-
in unit in Sec. 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
[[Page 45464]]
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.
Sec. 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 Sec.
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 Sec. Sec. 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
Sec. 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 to another Allowance Management System account in accordance
with Sec. Sec. 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 Sec. 97.741 for such
unit before the date that is 4 years after the date on which the
withdrawal became effective.
Sec. 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 Sec. 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 Sec.
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 Sec. 97.704, TR
SO2 Group 2 allowances equal in amount to and allocated for
the same or a prior control period as:
(i) Any TR SO2 Group 2 allowances allocated to the TR
SO2 Group 2 opt-in unit under Sec. 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 Sec.
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 Sec. 97.704 is not
December 31, the TR SO2 Group 2 allowances allocated to the
TR SO2 Group 2 opt-in unit under Sec. 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
Sec. 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 Sec.
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 Sec.
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 Sec. 97.704, the TR SO2 Group 2 opt-in unit will
be allocated TR SO2 Group 2 allowances in accordance with
Sec. 97.712.
(ii) If the date on which the TR SO2 Group 2 opt-in unit
becomes a TR SO2 Group 2 unit under Sec. 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 Sec.
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 Sec. 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 Sec. 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 Sec.
97.704, divided by the total number of days in the control period; and
(C) Rounded to the nearest allowance.
[[Page 45465]]
Sec. 97.744 TR SO2 Group 2 allowance allocations to TR SO2 Group 2
opt-in units.
(a) Timing requirements. (1) When the TR opt-in application is
approved for a unit under Sec. 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 Sec. 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 Sec. 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 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 Sec. 97.741(g); or
(ii) The TR SO2 Group 2 opt-in unit's heat input, as
determined in accordance with Sec. Sec. 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 Sec. 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 Sec.
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 opt-in unit at
any time during the control period for which TR SO2 Group 2
allowances are to be allocated.
(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 Sec. 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