[Federal Register: June 10, 2004 (Volume 69, Number 112)]
[Proposed Rules]
[Page 32683-32772]
From the Federal Register Online via GPO Access [wais.access.gpo.gov]
[DOCID:fr10jn04-17]
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Part III
Environmental Protection Agency
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40 CFR Parts 51, et al.
Supplemental Proposal for the Rule To Reduce Interstate Transport of
Fine Particulate Matter and Ozone (Clean Air Interstate Rule); Proposed
Rule
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ENVIRONMENTAL PROTECTION AGENCY
40 CFR Parts 51, 72, 73, 74, 77, 78 and 96
[OAR-2003-0053; FRL-7667-1]
RIN 2060-AL76
Supplemental Proposal for the Rule To Reduce Interstate Transport
of Fine Particulate Matter and Ozone (Clean Air Interstate Rule)
AGENCY: Environmental Protection Agency (EPA).
ACTION: Supplemental notice of proposed rulemaking.
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SUMMARY: Today's action is a supplemental notice of proposed rulemaking
(SNPR) to EPA's January 30, 2004 (69 FR 4566) notice of proposed
rulemaking (NPR). The NPR requires certain States to submit State
implementation plan (SIP) measures to ensure that emissions reductions
are achieved as needed to mitigate transport of fine particulate matter
(PM2.5) and/or ozone pollution and its main precursors--emissions of
sulfur dioxide (SO2) and oxides of nitrogen
(NOX)--across State boundaries. Today's action includes
proposed rule language and supplemental information for the January
2004 proposal, consisting of further discussion on establishing State-
level emissions budgets, proposed State reporting requirements and SIP
approvability criteria, proposed model cap-and-trade rules, and a more
thorough discussion of how this proposal interacts with existing Clean
Air Act (CAA) programs and requirements.
The EPA intends to produce a final rule by the end of calendar year
2004.
DATES: Comments must be received on or before July 26, 2004. A public
hearing will be held on June 3, 2004 in Alexandria, Virginia. Please
refer to SUPPLEMENTARY INFORMATION for additional information on the
comment period and the public hearing.
ADDRESSES: Submit your comments, identified by Docket ID No. OAR-2003-
0053, by one of the following methods:
Federal eRulemaking Portal: http://www.regulations.gov.
Follow the on-line instructions for submitting comments.
Agency Web site: http://www.epa.gov/edocket. EDOCKET,
EPA's electronic public docket and comment system, is EPA's preferred
method for receiving comments. Follow the on-line instructions for
submitting comments.
E-mail: A-and-R-Docket@epa.gov.
Mail: Air Docket, Clean Air Interstate Rule.
Environmental Protection Agency, Mailcode: 6102T, 1200
Pennsylvania Ave., NW., Washington, DC 20460.
Hand Delivery: EPA Docket Center, 1301 Constitution
Avenue, NW., Room B108, Washington, DC. 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. OAR-2003-0053.
The 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.epa.gov/edocket
, 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 EDOCKET, regulations.gov, or e-
mail. The EPA EDOCKET and the Federal regulations.gov websites are
``anonymous access'' systems, 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 EDOCKET or 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, any form of encryption, and be free of
any defects or viruses. For additional information about EPA's public
docket visit EDOCKET on-line or see the Federal Register of May 31,
2002 (67 FR 38102). For additional instructions on submitting comments,
go to Unit I of the SUPPLEMENTARY INFORMATION section of this document.
Docket: All documents in the docket are listed in the EDOCKET index
at http://www.epa.gov/edocket. Although listed in the index, some
information is not publicly available, i.e., CBI or other information
whose disclosure is restricted by statute. Certain other material, such
as copyrighted material, is not placed on the Internet and will be
publicly available only in hard copy form. Publicly available docket
materials are available either electronically in EDOCKET or in hard
copy at the EPA Docket Center, EPA West, Room B102, 1301 Constitution
Avenue, NW., Washington, DC. The Public Reading Room is open from 8:30
a.m. to 4:30 p.m., Monday through Friday, excluding legal holidays. The
telephone number for the Public Reading Room is (202) 566-1744, and the
telephone number for the Air Docket is (202) 566-1742.
FOR FURTHER INFORMATION CONTACT: For general questions concerning
today's action, please contact Scott Mathias, U.S. EPA, Office of Air
Quality Planning and Standards, Air Quality Strategies and Standards
Division, C539-01, Research Triangle Park, NC, 27711, telephone (919)
541-5310, e-mail at mathias.scott@epa.gov. For legal questions, please
contact Howard J. Hoffman, U.S. EPA, Office of General Counsel, Mail
Code 2344A, 1200 Pennsylvania Avenue, NW., Washington, DC, 20460,
telephone (202) 564-5582, e-mail at hoffman.howard@epa.gov. For
questions regarding air quality analyses, please contact Brian Timin,
U.S. EPA, Office of Air Quality Planning and Standards, Emissions
Modeling and Analysis Division, D243-01, Research Triangle Park, NC,
27711, telephone (919) 541-1850, e-mail at timin.brian@epa.gov. For
questions regarding emissions reporting requirements, please contact
Bill Kuykendal, U.S. EPA, Office of Air Quality Planning and Standards,
Emissions Modeling and Analysis Division, Mail Code D205-01, Research
Triangle Park, NC, 27711, telephone (919) 541-5372, e-mail at
kuykendal.bill@epa.gov. For questions regarding the model cap-and-trade
programs, please contact Sam Waltzer, U.S. EPA, Office of Atmospheric
Programs, Clean Air Markets Division, Mail Code 6204J, 1200
Pennsylvania Avenue, NW., Washington, DC, 20460, telephone (202) 343-
9175, e-mail at waltzer.sam@epa.gov. For questions regarding analyses
required by statutes and executive orders, please contact Linda
Chappell, U.S. EPA, Office of Air Quality Planning and Standards, Air
Quality Strategies and Standards Division, Mail Code C339-01, Research
Triangle Park, NC, 27711, telephone (919) 541-2864, e-mail at
chappell.linda@epa.gov.
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SUPPLEMENTARY INFORMATION:
I. Additional Information on Submitting Comments
A. How Can I Help EPA Ensure That My Comments Are Reviewed Quickly?
To expedite review of your comments by Agency staff, you are
encouraged to send a separate copy of your comments, in addition to the
copy you submit to the official docket, to Douglas Solomon, U.S. EPA,
Office of Air Quality Planning and Standards, Emissions Modeling and
Analysis Division, Mail Code C304-01, Research Triangle Park, NC,
27711, telephone (919) 541-4132, e-mail iaqrcomments@epa.gov.
B. What Should I Consider as I Prepare My Comments for EPA?
1. Submitting CBI. Do not submit this information to EPA through
EDOCKET, 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, U.S.
EPA, Office of Air Quality Planning and Standards, Mail Code C404-02,
Research Triangle Park, NC 27711, telephone (919) 541-0880, e-mail at
morales.roberto@epa.gov, Attention Docket ID No. OAR-2003-0053.
2. Tips for Preparing Your Comments. When submitting comments,
remember to:
i. Identify the rulemaking by docket number and other identifying
information (subject heading, Federal Register date and page number).
ii. 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.
iii. Explain why you agree or disagree; suggest alternatives and
substitute language for your requested changes.
iv. Describe any assumptions and provide any technical information
and/or data that you used.
v. If you estimate potential costs or burdens, explain how you
arrived at your estimate in sufficient detail to allow for it to be
reproduced.
vi. Provide specific examples to illustrate your concerns, and
suggest alternatives.
vii. Explain your views as clearly as possible, avoiding the use of
profanity or personal threats.
viii. Make sure to submit your comments by the comment period
deadline identified.
II. Regulated Entities
This action does not propose to directly regulate emissions
sources. Instead, it proposes to require States to revise their SIPs to
include control measures to reduce emissions of NOX and
SO2. The proposed emissions reductions requirements that
would be assigned to the States are based on controls that are known to
be highly cost effective for EGUs.
III. Website for Rulemaking Information
The EPA has also established a web site for this rulemaking at
http://www.epa.gov/interstateairquality/ which will include the
rulemaking actions and certain other related information that the
public may find useful.
IV. Public Hearing
The EPA will hold a public hearing on today's proposal on June 3,
2004. The hearing will be held at the following location: Holiday Inn
Select, Old Town Alexandria, 480 King Street, Alexandria, Virginia
22314, Telephone: (703) 549-6080.
The public hearing will begin at 9 a.m. and continue until 5 p.m.,
or later if necessary depending on the number of speakers. Oral
testimony will be limited to 5 minutes per commenter. The EPA
encourages commenters to provide written versions of their oral
testimonies either electronically (on computer disk or CD-ROM) 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 the hearing, please notify Joann Allman, U.S. EPA, Office
of Air Quality Planning and Standards, C539-02, Research Triangle Park,
NC 27711, telephone (919) 541-1815, email allman.joann@epa.gov, by May
31, 2004. For updates and additional information on the public hearing
please check EPA's website for this rulemaking.
The public hearing will provide interested parties the opportunity
to present data, views, or arguments concerning the proposed rule. The
EPA 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 a public hearing.
Outline
I. Background
II. State-by-State Emissions Reduction Requirements and EGU Budgets
A. SO2 Emissions Budgets
B. NOX Emissions Budgets
III. Integration With Clean Air Act Programs
A. SIP Criteria
B. What Changes are EPA Proposing for Emissions Reporting
Requirements?
C. Acid Rain Program
D. NOX SIP Call
E. How Would Emissions Trading Under This Proposed Rule Relate
to Regional Haze?
F. Tribal Issues
IV. Model Cap-and-Trade Rules
A. Background and Purpose of the Model Rules
B. Elements of the Proposed NOX and SO2
Model Trading Rules, Subparts AA through HH and AAA through HHH
V. Clarifications to January 30, 2004 Proposal
A. Scope of the Proposed Action
B. Summary of Control Costs
C. Source of Cost Information
D. Judicial Review Under Clean Air Act Section 307
VI. Statutory and Executive Order Reviews
VII. Proposed Rule Text
I. Background
The EPA's January 30, 2004 proposal (69 FR 4566-4650) \1\ proposed
to find that emissions of SO2 and NOX from 28
States and DC, and emissions of NOX alone from 25 States and
DC, violate the provisions of CAA section 110(a)(2)(D) by contributing
significantly to nonattainment downwind of, respectively, the annual
PM2.5 and the 8-hour ozone national ambient air quality standards
(NAAQS).
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\1\ The EPA signed the January 30, 2004 proposal on December 17,
2003 and made it immediately available to the public on EPA's Web
site at http://www.epa.gov/interstateairquality.
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As a result, EPA proposed to require SIP revisions containing
measures to ensure that necessary emissions reductions are achieved.
The EPA proposed SIP submittal deadlines and other aspects of the SIP
submittals. Further, the January 2004 proposal identified the
appropriate NOX and SO2 emissions that each of
the affected jurisdictions would be required to eliminate. The January
2004 proposal explained that the affected States could choose to
control any sources they wish to achieve those emissions reductions,
and generally discussed the methodologies for determining the
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appropriate amount of emissions reductions on a State-by-State basis.
The January 2004 proposal further explained that the emissions
reductions may most cost effectively be achieved by controls on
electric generating units (EGUs), and, in particular, through
regionwide cap-and-trade programs for EGUs. Accordingly, the January
2004 proposal indicated the methods for determining the allowable
amounts of SO2 and NOX emissions from EGUs, and
offered a sketch of the model cap-and-trade programs, which EPA would
offer to administer, that States may choose to adopt.
This supplemental proposal fills in certain gaps in the January
2004 proposal and revises it or its supporting information in specific
ways. This section of the SNPR provides background on this supplemental
proposal and summarizes its contents.
Section II of the SNPR provides additional detail on establishing
State emissions budgets (i.e., emissions reduction requirements) on
which we are requesting comment.
Section III discusses the interaction of the January 2004 proposal
with existing CAA programs and requirements. It includes discussion of
specific SIP criteria and emissions reporting requirements. It also
discusses the interactions of the Clean Air Interstate Rule (CAIR) with
the Acid Rain Program that also requires SO2 and
NOX emissions reductions--and the NOX SIP Call,
which was a 1998 rulemaking that required States in the eastern U.S. to
submit SIPs reducing NOX emissions to eliminate adverse
impacts on the 1-hour ozone NAAQS. Section III also discusses the
implications of the CAIR for compliance with regional haze
requirements. It also discusses Tribal issues in more detail than was
contained in the January 2004 proposal.
Section IV provides significant additional details concerning the
EPA's model cap-and-trade program for EGUs.
Section V includes clarifications to the January 2004 proposal with
respect to preamble language that was unclear, incomplete,
inadvertently omitted, or inadvertently incorrect.
Section VI addresses the required statutory and executive order
reviews for this SNPR.
Section VII lists the sections of proposed regulatory language that
are included in today's supplemental proposal. (The January 2004
proposal was not accompanied by proposed regulatory language).
Under CAA section 307(d)(1)(J), the procedural requirements of
section 307(d) apply to this proposal. In addition, under section
307(d)(1)(U), the Administrator is authorized to include any other
actions as covered under section 307(d). The EPA is including the
proposals in today's SNPR and in the January 2004 proposal under
section 307(d)(1)(U). Therefore, section 307(d) applies to all
components of the rulemaking of which this action is a component.
II. State-by-State Emissions Reductions Requirements and EGU Budgets
In the January 2004 proposal, EPA proposed methods for determining
the SO2 and NOX emission reduction requirements
or budgets for each affected State. Today, EPA proposes corrections to
the proposals in the NPR. Additional details are included in a
technical support document.\2\
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\2\ See, ``State Emission Budget Calculation Technical Support
Document for the Proposed Clean Air Interstate Rule (May 2004).''
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Also, in the January 2004 proposal, EPA proposed methods for
determining regionwide budgets. Today, EPA is not proposing any
revisions to this methodology. However, in this SNPR, EPA used updated
heat input data to develop the regionwide NOX budgets,
yielding a slight difference.
The choice of method to impose State-by-State emissions reduction
requirements makes little difference in terms of the overall cost of
the regionwide SO2 and NOX reductions. Assuming
that allowances can be freely traded, the cap-and-trade framework would
encourage least-cost compliance over the entire region, an outcome that
does not depend on the relative levels of individual State budgets.
A. SO2 Emissions Budgets
1. Approaches for Integrating SO2 Title IV Program with CAIR
As described in the January 2004 proposal and other places in
today's preamble, EPA is proposing to integrate the title IV Acid Rain
SO2 program with the trading program proposed in today's
notice by requiring facilities to comply with this rule using title IV
allowances at a greater retirement ratio than one allowance for every
one ton of emissions. In the January 2004 proposal, EPA proposed that,
to meet the 65 percent reduction required under Phase II (which begins
in 2015), EPA could require an affected EGU to retire three 2015 and
beyond allowances for every ton of SO2 that it emits.
However, this 3-to-1 ratio results in slightly more reductions than EPA
has proposed are necessary to eliminate the significant contribution of
an upwind State. This section of today's SNPR proposes two basic
alternatives for addressing this issue.
Under the first alternative EPA solicits comment on requiring
affected EGUs to retire vintage 2015 and beyond title IV allowances at
a rate of 2.86-to-1 rather than 3-to-1. This alternative effectively
eliminates the difference between the proposed cap levels and the
resulting reductions. The EPA solicits comment on the use of this
retirement ratio and specifically on whether the use of a fractional
retirement ratio (2.86-to-1 instead of 3-to-1) raises practical
implementation concerns for States or affected EGUs or whether a
fractional retirement ratio is preferable to the two-step process
described below.
Alternatively, EPA proposes requiring the retirement of 2015 and
beyond vintage allowances at a 3-to-1 ratio, and permitting States to
convert these additional reductions into allowances in their rules.
That is, the States would retain special ``CAIR SO2
allowances'' equivalent to the difference between the 3-to-1 retirement
ratio and the effective 2015 cap. Thus, an amount of allowances
(assuming allowances would be retired at a 3-to-1 ratio) equivalent to
three times the number that represents the margin of difference in the
retirement ratio for 2015 would then be made available to States. Under
this approach, these reserved allowances would be distributed to the
States based on the same methodology used to distribute title IV
allowances, and States would have flexibility to further distribute
them however they deem appropriate. The States might choose, for
example, to distribute them to EGUs using the same methodology that had
been used for distributing the original title IV allowances, or use
them as a set-aside for new sources or for sources that did not receive
title IV allowances originally, or they might distribute them as
incentives for achieving other policy goals each State may have.
Some States may want to use these reserved allowances to create an
incentive for additional local emission reductions that will be needed
to bring all areas into attainment with the PM2.5 NAAQS. The EPA
projects that the proposed CAIR, along with other Federal and State
programs already in place, will bring most areas of the country into
attainment with the PM2.5 NAAQS by 2015 without the need for additional
local controls. These regional and national programs, however, are not
designed to deal with all local pollution problems, and we expect that
there will be a small number of areas that will need additional local
emissions reductions to reach attainment. In such cases, States could
use their reserved
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allowances to create an incentive for additional local reductions--
perhaps by providing reserved allowances to affected EGUs based on
their proposals for achieving additional reductions in areas that are
projected to need further local emissions reductions to come into
attainment with the PM2.5 NAAQS.
Mechanisms that States could use for allocating these reserved
allowances could range from basic financial incentives to more
aggressive and innovative approaches. In its simplest form, the EGUs
could choose to complement or expand existing control measures, or
perhaps fund new ones. Under the latter approach, a specific value
could be applied to a ton of local emissions to be reduced depending on
one or more specific criteria such as: The accuracy and technical
validity of emissions monitoring used to characterize emissions or
demonstrate compliance, seasonal timing or location of the reductions,
population exposure, or other considerations.
For example, reducing PM2.5 from a sector in a nonattainment area
might receive a greater allowance value than reductions from a sector
that is downwind of the nonattainment area most of the year, due to the
relative effectiveness of the measures at reducing population exposure
and monitoring of PM2.5. Another example could be one in which the EGUs
receive allowances in exchange for reductions in other pollutants
causing PM2.5, based on using technically appropriate air quality
models to demonstrate superior environmental results. Nevertheless,
States would have discretion on whether and how to use any reserved
allowances to achieve additional local emission reductions.
2. Proposed SO2 State Emission Budget Methodology
a. Overview. In this section, EPA discusses the methodology for
apportioning regionwide SO2 emissions reductions
requirements or budgets to the individual States. In the January 2004
proposal we proposed State EGU SO2 budgets based on each
State's allowances under title IV of the CAA Amendments with specified
retirement ratios. This continues to be EPA's proposal for determining
State SO2 budgets. In addition, we discussed an alternate
method of relying on Title IV allowances that would provide for some
EGU allowances that could be redistributed to account for changes to
the electric generation sector since the title IV allocations were
created (using a two-part budget methodology). In this SNPR, EPA
identifies some problems with the two-part method as described in the
January 2004 proposal, withdraws the January 2004 proposal on this
point, and is re-proposing that all States use the same retirement
ratios for Title IV allowances.
b. NPR discussion. The EPA discussed its proposed SO2
emission budget methodology at length in the January 2004 proposal. In
that discussion, EPA outlined the various reasons for tying the
SO2 requirements of the proposed CAIR to the title IV
program. Without carefully integrating the CAIR and title IV programs,
emissions may increase prior to implementation of the CAIR and
emissions may shift to outside the control region. In addition, because
the regulated community has relied on the title IV program in the past,
and is planning on continued reliance for the future, lack of
integration could give rise to concerns about the stability of EPA's
regulatory efforts and the accompanying allowance market.
Under the approach proposed for SO2, the State budgets
would be based on the initial allocation of allowances to individual
sources established by title IV of the 1990 CAA Amendments. The budgets
are shown in Table II-1, revised to correct a slight calculation error
in the January 2004 proposal,\3\ as explained in the technical support
document.\4\
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\3\ As in the SO2 State budgets included in the
January 2004 proposal, these budgets include the 250,000 allowances
in the Special Allowance Reserve, prorated to the individual States
in proportion to the sum of the 2010 individual units allocations
for the State.
\4\ See, ``State Emission Budget Calculation Technical Support
Document for the Proposed Clean Air Interstate Rule (May 2004).''
Table II-1.--28-State and District of Columbia Annual EGU SO2 Budgets
------------------------------------------------------------------------
28-State SO2 28-State SO2
State Budget 2010 Budget 2015
(tons) (tons)
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Alabama................................. 157,582 110,307
Arkansas................................ 48,702 34,091
Delaware................................ 22,411 15,687
District of Columbia.................... 708 495
Florida................................. 253,450 177,415
Georgia................................. 213,057 149,140
Illinois................................ 192,671 134,869
Indiana................................. 254,599 178,219
Iowa.................................... 64,095 44,866
Kansas.................................. 58,304 40,812
Kentucky................................ 188,773 132,141
Louisiana............................... 59,948 41,963
Maryland................................ 70,697 49,488
Massachusetts........................... 82,561 57,792
Michigan................................ 178,605 125,024
Minnesota............................... 49,987 34,991
Mississippi............................. 33,763 23,634
Missouri................................ 137,214 96,050
New Jersey.............................. 32,392 22,674
New York................................ 135,139 94,597
North Carolina.......................... 137,342 96,139
Ohio.................................... 333,520 233,464
Pennsylvania............................ 275,990 193,193
South Carolina.......................... 57,271 40,089
Tennessee............................... 137,216 96,051
Texas................................... 320,946 224,662
Virginia................................ 63,478 44,435
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West Virginia........................... 215,881 151,117
Wisconsin............................... 87,264 61,085
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Total Regional Budget............... 3,863,566 2,704,490
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Note: As explained in the proposed January 2004 proposal (69 FR 4618)
the regionwide budgets for the years 2010-2014 are based on a 50
percent reduction from title IV allocations for all units in affected
States. The regionwide budget for 2015 and beyond is based on a 65
percent reduction.
c. Problems with the methodology proposed in the NPR. In the Model
Trading section of the January 2004 proposal, EPA proposed giving
States the option of deciding whether to adopt a two-part budget
approach, making available additional SO2 allowances through
the use of higher retirement ratios (69 FR 4620,4632). However, upon
further assessment, it has become evident that problems could arise if
various States implemented this approach differently. Specifically, the
level of the regional cap on SO2 emissions could increase or
decrease, depending on which individual States tightened the retirement
ratios.
An example could best illustrate this point. Assume State A in the
proposed CAIR region has a State SO2 budget of 300,000 tons
in 2010, reflecting a 50 percent reduction from its 600,000 2010 title
IV SO2 allowances. Assume also that State A decides to
implement a 3-to-1 retirement ratio for its 600,000 title IV
SO2 allowances in 2010, but all other States in the proposed
CAIR region continue requiring 2-to-1 retirement ratios. Assume further
that EPA allocates State A additional CAIR allowances for 100,000 tons
of emissions, which reflect the difference between State A's 3-to-1
retirement ratio (200,000 tons) and the overall 2-to-1 retirement ratio
(300,000 tons). With one CAIR allowance equivalent to one title IV
allowance, State A, with its 3-to-1 ratio, would thus receive 300,000
CAIR allowances. Assume that State A allocates all of these new CAIR
allowances to its sources. To illustrate most vividly the problem that
may result, assume the extreme case in which State A's emissions in
2010 approach zero (due to efficiencies in implementing controls or
lower generation levels) and therefore that its sources sell all their
title IV allowances as well as its additional CAIR allowances to
sources in other States. In this example, the total amount of State A's
allowances (600,000 title IV allowance plus 300,000 CAIR allowances)
would be available for complying with the 2-to-1 ratio required by the
other States. Consequently, the additional CAIR allowances allocated by
EPA would effectively raise the overall regional cap by 150,000 tons,
reflecting the 300,000 CAIR allowances retired at a 2-to-1 ratio.
To illustrate how this same case could lead to the opposite problem
of a lower regional cap, assume that State A's emissions were to remain
very high or to increase, so that its sources purchase allowances from
other States and then retire them at a 3-to-1 ratio in 2010. State A
sources would have to purchase more allowances than the amount State A
had redistributed as additional CAIR allowances. This would mean the
total amount of allowances for 2010, and thus the total regional cap,
would in effect be lower.
In fact, in these examples, in any year that State A's emissions
are not exactly one-third of their title IV allocations, the level of
the overall regional cap would be impacted. This lack of certainty
about the cap is unacceptable for a cap-and-trade program, as it
undermines both the environmental certainty and economic stability of
the program. Therefore, EPA is withdrawing the January 2004 proposal on
this point and re-proposing that all States use the same retirement
ratio.
3. SIP Approvability
In section III.A, EPA outlines the proposed SIP approvability
criteria if EPA adopts a requirement to retire allowances at ratios of
greater than 1-to-1. Specifically, (1) all States must use the same
retirement ratios whether or not they participate in the trading
program and whether or not they achieve all the required emissions
reductions through controls on EGUs, (2) if a State does not require
all of the emissions reductions through requirements on EGUs, they may
create extra CAIR allowances which would be calculated by multiplying
the reductions required from the other sources by the required
retirement ratio for that given year, and (3) the overall reduction
requirement for a State would be set at the difference between a
State's 2010 title IV allowance allocations and the EPA-determined CAIR
SO2 State budgets for the two phases. Please note, as
described in section IV, that if a State chooses to achieve emissions
reductions from non-EGUs, then that State's EGUs may not participate in
the EPA administered cap-and-trade program.
B. NOX Emissions Budgets
1. Overview
In this section, EPA discusses the apportioning of proposed
regionwide NOX emission reduction requirements or budgets to
the individual States. In the January 2004 proposal we proposed State
EGU NOX budgets based on each State's average share of
recent historic heat input. In today's SNPR, we propose the same heat
input based methodology, but we propose revised budgets based on more
complete heat input data.
In addition to the proposed heat input based method, in this SNPR
we also discuss a different approach suggested by commenters for
apportioning regionwide NOX budgets to the States. As
discussed in section IV of this SNPR, we propose that States have the
discretion in choosing a methodology to distribute allowances from
their NOX budgets to individual sources.
2. NOX Emission Budget Methodology Proposed in the NPR
a. NPR discussion. In the January 2004 proposal, we proposed annual
NOX budgets for a 28-State (and D.C.) region based on each
jurisdiction's average heat input--using heat input data from Acid Rain
Program units--over the years 1999 through 2002. We summed the average
heat input from each of the applicable jurisdictions to obtain a
regional total average annual heat input. Then, each State received a
pro rata share of the regional NOX emissions budget based on
the ratio of its average annual heat input to the regional total
average annual heat input.
b. Today's revised proposal. In this SNPR, the use of average heat
inputs is still our preferred approach. However, State budgets based on
heat input data
[[Page 32689]]
from Acid Rain Program units only would not reflect the heat input of
non-Acid Rain units. For example, a State with a large number of non-
Acid Rain units would not have the heat input from those units
reflected in the percent of regional average annual heat input that the
State's generation represents. Therefore, today EPA proposes to revise
its determination of State NOX budgets by supplementing Acid
Rain Program unit data with annual heat input data from the U.S. Energy
Information Administration (EIA), for the non-Acid Rain unit data.
Table II-2 contains the proposed revised annual State NOX
budgets. Note that the Acid Rain Program data for 2002 has been updated
since our analysis for the January 2004 proposal was completed and was
included in the calculation of these budgets.
Table II-2.--28-States and District of Columbia Annual EGU NOX Budgets--
Based on Heat Input
------------------------------------------------------------------------
State NOX State NOX
State Budget 2010 Budget 2015
(tons) (tons)
------------------------------------------------------------------------
Alabama................................. 67,422 56,185
Arkansas................................ 24,919 20,765
Delaware................................ 5,089 4,241
District of Columbia.................... 215 179
Florida................................. 115,503 96,253
Georgia................................. 63,575 52,979
Illinois................................ 73,622 61,352
Indiana................................. 102,295 85,246
Iowa.................................... 30,458 25,381
Kansas.................................. 32,436 27,030
Kentucky................................ 77,938 64,948
Louisiana............................... 47,339 39,449
Maryland................................ 26,607 22,173
Massachusetts........................... 19,630 16,358
Michigan................................ 60,212 50,177
Minnesota............................... 29,303 24,420
Mississippi............................. 21,932 18,277
Missouri................................ 56,571 47,143
New Jersey.............................. 9,895 8,246
New York................................ 52,503 43,753
North Carolina.......................... 55,763 46,469
Ohio.................................... 101,704 84,753
Pennsylvania............................ 84,552 70,460
South Carolina.......................... 30,895 25,746
Tennessee............................... 47,739 39,783
Texas................................... 224,314 186,928
Virginia................................ 31,087 25,906
West Virginia........................... 68,235 56,863
Wisconsin............................... 39,044 32,537
-----------------
Total Regional Budget............... 1,600,799 1,333,999
------------------------------------------------------------------------
Note: NOX control requirements for Connecticut were
discussed in the January 2004 proposal.
Commenters have also suggested adjusting the heat input data for
existing units used to determine State budgets by multiplying it by
different factors, established regionwide based on fuel type. The
factors would reflect the inherently higher emissions rate of coal-
fired plants, and consequently the greater burden on coal plants to
control emissions. In contrast to allocations based on historic
emissions, the factors would also not penalize coal-fired plants that
have already installed pollution controls. States shares would be
determined by the amount of State heat input, as adjusted, in
proportion to the total regional heat input. The factors could be based
on average historic emissions rates (in lbs/mmBtu) by fuel type (coal,
gas, and oil) for the years 1999-2002.
The EPA also discussed in the January 2004 proposal a methodology
used in the NOX SIP Call (67 FR 21868) that applied State-
specific growth rates for heat input in setting State budgets. With a
methodology similar to that used in the NOX SIP Call, annual
NOX budgets would be set by using a base heat input data,
then adjusting it by a calculated growth rate for each jurisdiction's
annual EGU heat inputs. The EPA is not proposing to use this method for
the CAIR because we believe that the other methods that we are
proposing (or taking comment on) are more reasonable due to the
inherent difficulties in predicting growth in heat input over a lengthy
period, especially for jurisdictions that are only a part of a larger
regional electric power dispatch region.
III. Integration With Clean Air Act Programs
This section details how the rules that States develop to meet the
requirements of the proposed CAIR must be structured to conform with
CAA programs. It proposes: Specific criteria that SIPs submitted to
meet the requirements of the proposed CAIR must meet; emissions
inventory reporting requirements; revisions to the title IV Acid Rain
regulations to integrate them with the proposed CAIR emissions trading
programs; requirements to ensure that requirements of the existing
NOX SIP Call continue to be met; that BART-eligible EGUs in
any State affected by CAIR may be exempted from BART if that State
complies with the CAIR requirements through adoption of the CAIR cap-
and-trade program for SO2 and NOX emissions. Finally, this
section
[[Page 32690]]
provides additional discussion on the implications of the CAIR for
tribes.
A. SIP Criteria
1. Introduction
This section describes (1) the dates for submittal and
implementation of the SIPs that we propose to require under the CAIR,
and (2) the criteria we propose to use in determining completeness and
approvability of such SIPs.
2. Schedule for Submission and Implementation of SIPs
a. SIP submission schedule. In the January 2004 proposal, EPA
proposed that States must submit the SIP revisions required under the
CAIR as expeditiously as practicable but no later than 18 months from
the date of promulgation of the final rule. The proposed regulatory
text at the end of this SNPR, 40 CFR 51.123 (for NOX
emissions) and 40 CFR 51.124 (for SO2 emissions), contains this
proposed submittal date.
b. Implementation Schedule. In the January 2004 proposal, EPA
proposed that States must implement the control measures in their CAIR
SIP revisions by January 1, 2010. The proposed regulatory text at the
end of this SNPR, 40 CFR 51.123 (for NOX emissions) and 40
CFR 51.124 (for SO2 emissions), contains this proposed
implementation date.
i. Relationship to attainment dates. On April 15, 2004, the
Administrator signed a rule to designate and classify areas under the
8-hour ozone NAAQS. (69 FR 23858, April 30, 2004). Under the CAA, all
areas designated as nonattainment are required to come into attainment
with the NAAQS ``as expeditiously as practicable.'' In addition,
specific maximum attainment dates apply to different areas depending on
their classification. In the Eastern U.S., all 8-hour ozone areas are
classified as subpart 1 areas, marginal areas, or moderate areas. For
subpart 1 areas, the attainment date is no later than June 2009,
although EPA can extend this date by up to five years based on certain
statutory criteria. The attainment dates for marginal and moderate
areas are June 2007 and June 2010, respectively. State implementation
plans must achieve reductions required for attainment by the beginning
of the complete ozone season prior to the attainment date (e.g., the
2009 ozone season for moderate areas).
In response to the January 2004 proposal, some commenters have
expressed concern that the CAIR compliance dates (January 1, 2010, for
Phase I, and January 1, 2015, for Phase 2) come too late for Eastern
States to meet their deadlines for coming into attainment with the 8-
hour ozone NAAQS. In making ozone designations, however, EPA recognized
that certain areas may find it difficult to adopt plans showing
attainment by their initial attainment dates, and would choose to be
reclassified to higher classifications with longer attainment dates.
For example, an area reclassified to serious would have a June 2013
attainment deadline, and would be required to achieve reductions
required for attainment by the 2012 ozone season. It is also possible
that some subpart 1 areas will qualify for an extension and receive an
attainment date later than June 2009. In addition, an area failing to
attain on time can qualify for up to two one-year extensions if it
meets statutory criteria. Therefore, CAIR implementation by the 2013 or
2014 ozone season could facilitate attainment by a serious area
receiving one-year extensions.
Some commenters also asserted that a similar timing issue arises
for PM2.5. Assuming PM2.5 designations by the statutory deadline of
December 2004, the PM2.5 attainment deadlines would be no later than
early 2010, or no later than early 2015 for areas receiving a maximum
5-year extension. To influence whether an area attains by those dates,
reductions would have to occur one to three years earlier. Because of
the structure of the proposed program, which creates a strong financial
incentive for early reductions, EPA projects substantial early
reductions in SO2. Thus, although the Phase I cap does not
come into place until 2010, the proposed program would achieve
substantial reductions in SO2 emissions. In addition, the
same opportunity for one-year extensions mentioned for ozone exists for
PM2.5 areas.
In light of the discussion above, EPA requests comment on all
aspects of the issues concerning the timing of the proposed CAIR
compliance dates in relation to NAAQS attainment dates.
ii. Implementation date and beginning of calendar year. The EPA
believes that it is most straightforward for EPA to develop and
implement the requirements of the proposed CAIR, for sources to comply
with the proposed CAIR, and to ensure the environmental effectiveness
of the proposed CAIR, if the compliance date for sources is the
beginning of a calendar year (or for requirements that pertain only to
ozone, at the beginning of the ozone season). There are several reasons
for this approach. First, the proposed requirements for States are
annual emissions reductions. Beginning the program at any point other
than the start of a calendar year would require the development and
implementation of different Federal requirements for the first year of
the program.
Second, different State rules to meet these requirements would also
be necessary for the first, partial year portion of a program. States
would have to develop partial year allocations. Additionally, States
would have to modify monitoring and reporting requirements to address
partial year reporting. Further, for SO2 emissions
reductions requirements, because of the interactions with title IV
(which is an annual program), provisions would be needed to address
both the annual requirements of title IV and the partial year
requirements of the CAIR.
For these administrative feasibility reasons, EPA proposes that the
emissions reductions requirements begin at the start of the calendar
year, and not at any other time during a calendar year. However, EPA
solicits comment on the administrative feasibility issues of
implementing these requirements on a partial year basis for the first
year of the program.
In particular, EPA solicits comment on the appropriate budget
allocation method, and, to promote discussion, offers the following
observations for both NOX and SO2 partial year
budgets. For the NOX EGU emissions budget, partial year
allocation could be accomplished by pro-rating to account for the fact
that the program would be implemented for less than a full year. The
simplest method would be to pro-rate by the number of days that the
program would be implemented. For example, if the program began on
January 31, 2010, budgets would be pro-rated by the factor 335/365,
where 335 equals the number of days in the year in which States will be
required to comply with the program.
At least in theory, more complex methodologies could be developed
to account for the fact that the amount of generation--and therefore
the amount of NOX emissions--varies throughout the year
(e.g., in many areas, summer generation is higher due to air
conditioning load; in other areas that are heavily dependent on hydro
power, fossil-fuel generation can vary seasonally with availability of
hydro power). However, because factors that affect peak generation vary
by region, EPA believes it would be very difficult to develop a
methodology that reasonably addresses these many variations. Therefore,
we believe that
[[Page 32691]]
the simplest pro-rata methodology described above would be appropriate
for a partial year allocation.
Budgets for SO2 could be set in a similar way. A State's
SO2 budget could be pro-rated by the number of days that the
program would be in place. Because of the interactions with title IV
(an annual program), implementation of a partial year budget for
SO2 would be somewhat more complicated. For emissions from
the first portion of the year in which the State was not required to
comply with the CAIR, the Acid Rain sources would still be subject to
the 1-to-1 retirement ratio required under title IV. For emissions from
the second part of the year, all EGUs affected by the CAIR would be
required to turn in allowances of that vintage year at a ratio of 2-to-
1.
3. Completeness Determination
Any SIP submittal that is made with respect to the final CAIR
requirements first would be determined to be either incomplete or
complete. A finding of completeness means that EPA would proceed to
review the submittal to determine whether it is approvable. It is not a
determination that the submittal is approvable; rather, it means the
submittal is administratively and technically sufficient for EPA to
determine whether it meets the statutory and regulatory requirements
for approval. Under 40 CFR 51.123 and 40 CFR 51.124 (the proposed new
regulations for NOX and SO2 SIP requirements,
respectively), a submittal, to be complete, must meet the criteria
described in 40 CFR, part 51, appendix V, ``Criteria for Determining
the Completeness of Plan Submissions.'' These criteria apply generally
to SIP submissions.
Under CAA section 110(k)(1) and section 1.2 of appendix V, EPA must
notify States whether a submittal meets the requirements of appendix V
within 60 days of, but no later than 6 months after, EPA's receipt of
the submittal. If a completeness determination is not made within 6
months after submission, the submittal is deemed complete by operation
of law. For rules submitted in response to the CAIR, EPA intends to
make completeness determinations expeditiously. In addition, if a State
fails to make any submission by the required submission date, EPA
expects to make a finding of failure to submit within the same period
that would apply to making a completeness determination had a SIP been
submitted on time.
A finding of failure to submit or incompleteness triggers the
requirement that EPA promulgate a Federal implementation plan (FIP)
within 2 years of the date of the finding. In addition, if a complete
SIP is submitted in a timely fashion but EPA disapproves it, the
requirement to promulgate a FIP within 2 years would be triggered by
EPA's disapproval. The EPA's obligation to promulgate a FIP in either
instance would terminate upon EPA's approval of a SIP as meeting the
requirements of the CAIR.
4. Approvability Criteria
a. Introduction. The approvability criteria for CAIR SIP
submissions appear in the proposed 40 CFR 51.123 (NOX
emissions reductions) and in the proposed 40 CFR 51.124 (SO2
emissions reductions). Most of the criteria are substantially similar
to those that currently apply to SIP submissions under CAA section 110
or part D (nonattainment). For example, each submission must describe
the control measures that the State intends to employ, identify the
enforcement methods for monitoring compliance and handling violations,
and demonstrate that the State has legal authority to carry out its
plan.
This part of the section III preamble explains additional
approvability criteria specific to the CAIR that were proposed in the
January 2004 proposal, or are being proposed in today's SNPR. As
explained in the January 2004 proposal, EPA proposed that each affected
State must submit SIP revisions containing control measures that assure
a specified amount of NOX and SO2 emissions
reductions by specified dates.
Although EPA determined the required amount of emissions reductions
by identifying specified control levels for EGUs that are highly cost
effective, EPA explained in the January 2004 proposal that States have
flexibility in choosing the sources to control in order to achieve the
required emissions reductions. As long as the State's emissions
reductions requirements are met, a State may impose controls on EGUs
only, on non-EGUs only, or on a combination of EGUs and non-EGUs. The
EPA's proposed SIP approvability criteria are intended to provide as
much certainty as possible that, whichever sources a State chooses to
control, the controls will result in the required amount of emissions
reductions.
In the January 2004 proposal, EPA proposed a ``hybrid'' approach
for the mechanisms used to ensure emissions reductions from sources.
This approach incorporates elements of an emissions ``budget'' approach
(requiring an emissions cap on affected sources) and an ``emissions
reductions'' approach (not requiring an emissions cap). In this hybrid
approach, if States impose control measures on EGUs, they would be
required to impose an emissions cap on all EGUs, which would
effectively be an emissions budget. However, as stated in the January
2004 proposal, if States impose control measures on non-EGUs, they
would be encouraged but not required to impose an emissions cap on non-
EGUs. In the January 2004 proposal, we requested comment on the issue
of requiring States to impose caps on any source categories the State
chooses to regulate.
Today, we propose to modify this hybrid approach so that States
choosing to impose control measures on large industrial boilers and/or
turbines must do so by imposing an emissions cap on all such sources
within their State. This is similar to EPA's approach in the
NOX SIP Call which required States to include an emissions
cap on such sources as well as on EGUs if the SIP submittals included
controls on such sources. (See 40 CFR 51.121(f)(2)(ii), referenced at
63 FR 57494, October 27, 1998.)
Below, EPA describes specific criteria, depending on which sources
States choose to control.
b. Requirements if States Choose To Control EGUs.
i. Emissions caps. As explained in the January 2004 proposal (69 FR
4626), EPA proposed that States must apply the ``budget'' approach if
they choose to control EGUs; that is, States must cap EGU emissions at
the level that assures the appropriate amount of reductions. These caps
constitute the State EGU budgets for SO2 and NOX.
Additionally, EPA proposed that, if States choose to control EGUs, they
must require EGUs to follow part 75 monitoring, recordkeeping, and
reporting requirements.
If States choose to allow their EGUs to participate in EPA-
administered interstate NOX and SO2 emissions
trading programs, States must adopt EPA's model trading rules, as
described in section IV below and as proposed in 40 CFR part 96, Sec.
96.101-Sec. 96.176 and Sec. 96.201-Sec. 96.276, below. States
adopting EPA's model trading rules, with only those modifications
specifically allowed by EPA, will meet the requirements for applying an
emissions cap as well as part 75 monitoring, recordkeeping, and
reporting requirements to EGUs.
If States choose to control EGUs but not to allow them to
participate in EPA-administered NOX and SO2
emissions trading programs, States must still impose an emissions cap
as well as part
[[Page 32692]]
75 monitoring, recordkeeping, and reporting requirements on all EGUs.
Additionally, States must use the same definition of EGU as EPA uses in
its model trading rules, i.e., the sources described as ``CAIR units''
in proposed 40 CFR 96.102 and 40 CFR 96.202. If a State chooses to
design its own NOX and SO2 emissions trading
programs, regardless of whether they are for intrastate or interstate
trading, in addition to meeting the requirements of these rules, they
should consider EPA's guidance, ``Improving Air Quality with Economic
Incentive Programs,'' January 2001 (EPA-452/R-01-001) (available on
EPA's Web site at: http://www.epa.gov/ttn/ecas/incentiv.html), and the
rules must be approved by EPA. It should be noted that EPA would not
administer a State-designed program, so the State (or States) would
need to administer such programs.
ii. Retirement Ratios. The January 2004 proposal required each
State to assure that the title IV SO2 allowances for vintage
year 2010 and beyond for the State's EGUs that exceed the State's CAIR
EGU SO2 emissions budget cannot be used in a manner that
would lead to emissions increases in areas not affected by the CAIR.
Additionally, EPA was concerned that a devaluation of title IV
allowances (because of the more stringent requirements of the CAIR)
could lead to emissions increases prior to implementation of the CAIR.
The EPA's concerns regarding these allowances are described in the
January 2004 proposal at 69 FR 4630. To avoid these significant
problems, the January 2004 proposal in effect would require the State
to include a mechanism for retirement of the allowances in excess of
the State's budget.
The number of retired allowances must be at least equal to the
difference between the number of title IV allowances allocated to EGUs
in a State and the SO2 budget the State sets for EGUs under
this rule. This requirement to retire allowances in excess of a State's
budget applies regardless of whether or not a State participates in the
EPA-administered trading programs. If a State chooses to participate in
the EPA-administered trading programs, the State must follow the
provisions of the model trading rules, described in section IV below,
that require that vintage 2010 through 2014 title IV allowances be
retired at a ratio of 2 allowances for every ton of emissions and that
vintage 2015 and beyond title IV allowances be retired at a ratio of
three allowances for every ton of emissions. Pre-2010 vintage
allowances would be retired at a ratio of one allowance for every ton
of emissions. (See section IV.B.1 of this SNPR.)
In the January 2004 proposal, EPA stated that if a State does not
choose to participate in the EPA-administered trading programs, the
State may choose the specific method to retire allowances in excess of
its budget. The EPA has further considered alternative ways for
retiring these excess allowances and believes that if different States
use different means to address this concern, it could undermine the
regionwide emission reduction goals of the proposed CAIR. The EPA's
concerns are further described in Section II of today's preamble.
Because of these concerns, EPA is withdrawing the January 2004 proposal
on this point and re-proposing that all States use a 2-for-1 retirement
ratio for vintage 2010 through 2014 allowances and a 3-for-1 retirement
ratio for vintage 2015 allowances and beyond to address concerns about
title IV allowances that exceed State budgets.
State rules may also allow sources currently subject to title IV
and to the NOX SIP Call trading program to use allowances
banked from those programs before 2010 for compliance with the CAIR,
provided that States which participate in EPA's CAIR trading programs
must allow this, in accordance with EPA's model trading rules. For
further discussion of banking of NOX SIP Call allowances,
see the January 2004 proposal (69 FR 4633).
c. Requirements if States Choose to Control Sources Other Than EGUs
i. Overview of requirements. As noted in the January 2004 proposal,
if a State chooses to require emissions reductions from non-EGUs, the
State must adopt and submit SIP revisions and supporting documentation
designed to quantify the amount of reductions from the non-EGU sources
and to assure that the controls will achieve that amount. Although EPA
did not propose that States be required to impose an emissions cap on
those sources but instead solicited comment on the issue, EPA proposes
today that States be required to impose an emissions cap in certain
cases on non-EGU sources.
If a State chooses to obtain some but not all of its required
emissions reductions from non-EGUs, it would still be required to set
an EGU SO2 budget and/or an EGU NOX budget, but
at some level higher than shown in Tables VI-9 and VI-10 in the January
2004 proposal (69 FR 4619-4620), thus allowing more emissions from its
EGUs. The difference between the amount of a State's SO2 EGU
budget in Table VI-9 and a State's selected higher EGU SO2
budget would be the amount of SO2 emissions reductions the
State must demonstrate it will achieve from non-EGU sources. By the
same token, the difference between the amount of a State's
NOX EGU budget in Table VI-10 and a State's selected higher
EGU NOX budget would be the amount of NOX
emissions reductions the State must demonstrate it will achieve from
non-EGU sources.
If States require SO2 emissions reductions from non-EGU
sources, States should still use the same retirement ratio (i.e., 2-
for-1 for vintage 2010 through 2014 allowances and 3-for-1 for vintage
2015 allowances and beyond) for title IV allowances. To account for the
fact that the State is not requiring its EGUs to reduce as much, the
State can allocate additional allowances. The number of these
allowances will be calculated by multiplying the emissions reductions
required for the non-EGU source category by the title IV retirement
ratio.
The demonstration of emissions reductions from non-EGUs is a
critical requirement of the SIP revision due from a State that chooses
to control non-EGUs. As noted in the January 2004 proposal, the State
must take into account the amount of emissions attributable to the
source category in both (i) the base case, in the implementation years
2010 and 2015, i.e., without assuming SIP-required reductions from that
source category under the final CAIR, and (ii) in the control case, in
the implementation years 2010 and 2015, i.e., with assuming SIP-
required reductions from that source category under the CAIR SIP. We
are proposing an alternative methodology for calculating the base case
for certain large non-EGU sources, as described below, but generally
the difference between emissions in the base case and emissions in the
control case equals the amount of emissions reductions that can be
claimed from application of the controls on non-EGUs. (See below for
criteria applicable to development of the baseline and projected
control emissions inventories.)
Additionally, if a State chooses to obtain some or all of its
required emission reductions from non-EGUs, EGUs in that State could
not participate in the EPA administered multi-State trading programs.
ii. Eligibility of non-EGU reductions. In evaluating whether
emissions reductions from non-EGUs would count towards the emissions
reductions required under the CAIR, States may include only reductions
attributable to measures that are not otherwise required under the CAA.
This exclusion
[[Page 32693]]
of credit is consistent with the NOX SIP Call. For the most
part, the measures that are mandated by the CAA, and that EPA proposes
be excluded from credit towards the emission reduction requirements of
the CAIR, were assumed to be in place in the emissions projections and
air quality contribution analysis used in the proposed findings
regarding significant contribution to nonattainment in 2010.\5\
---------------------------------------------------------------------------
\5\ The 2010 emissions projections did not account for
requirements for reasonably available control technology (RACT),
reasonably available control measures (RACM), and vehicle
inspection/maintenance in any new 8-hour ozone or PM2.5
nonattainment areas, as these areas had not been designated at the
time of the modeling. However, we believe that not accounting for
these requirements did not distort the proposed findings for each
State because the aggregate reductions in NOX and
SO2 emissions from these measures would be at most a
small percentage of overall emissions.
---------------------------------------------------------------------------
Specifically, States must exclude reductions attributable to
measures otherwise required by the CAA, including: (1) Measures already
in place at the date of promulgation of the final CAIR, such as adopted
State rules, SIP revisions approved by EPA, and settlement agreements;
(2) measures adopted and implemented by EPA (or other Federal agencies)
such as emissions reductions required pursuant to the Federal Motor
Vehicle Control Program for mobile sources (vehicles or engines) or
mobile source fuels, or pursuant to the requirements for National
Emissions Standards for Hazardous Air Pollutants; and (3) specific
measures that are mandated under the CAA (which may have been further
defined by EPA rulemaking) based on the classification of an area which
has been designated nonattainment for a NAAQS, such as vehicle
inspection and maintenance programs. If a State can demonstrate that a
new or modified measure is more stringent than what is required, e.g.,
due to broader geographic coverage or more stringent emissions
reductions levels, the State may count toward the CAIR requirement the
reductions attributable to the more stringent requirement. The
exclusion of credit for ineligible measures is accomplished by
including those measures in both the base and control cases, if they
have already been adopted; or by excluding them from both the base and
control cases if they have not yet been adopted.
States required to make CAIR SIP submittals may also be required to
make other SIP submittals to meet other requirements applicable to non-
EGUs, e.g., nonattainment SIPs required for areas designated
nonattainment under the PM2.5 or 8-hour ozone NAAQS. These SIPs could
include, for example, measures to be adopted such as Reasonably
Available Control Technology (RACT) measures pursuant to CAA section
182.
It is likely that CAIR SIP submittals will be due before or at the
same time that some of these other SIP submittals are due. States
relying on reductions from controls on non-EGUs must commit in the CAIR
SIP revisions to replace the emissions reductions attributable to any
CAIR SIP measure if that measure is subsequently determined to be
required in meeting any other SIP requirement related to adoption of
control measures. The State could make this replacement by decreasing
its EGU emissions cap or a non-EGU emissions cap, if applicable, by the
appropriate amount.
iii. Emissions controls and monitoring. As noted above, we are
modifying the ``hybrid'' approach described in the January 2004
proposal as it applies to non-EGUs. For States that choose to impose
controls on certain non-EGUs, namely large industrial boilers and
turbines, i.e., those whose maximum design heat input is greater than
250 mmBtu/hr, to meet part or all of their emissions reductions
requirements under the CAIR, EPA proposes that State requirements must
include an emissions cap on all such sources in their State.
Additionally, EPA proposes that in this situation, States must require
those large industrial boilers and turbines to meet part 75
requirements for monitoring and reporting emissions as well as
recordkeeping. The EPA proposes that if a State chooses to control non-
EGUs other than large industrial boilers and turbines to obtain the
required emissions reductions, the States must either (i) impose the
same requirements, i.e., an emissions cap on all the non-EGUs in the
source category and Part 75 monitoring, reporting and recordkeeping
requirements, or (ii) must demonstrate why such requirements are not
practicable. In the latter case, the State must adopt appropriate
alternative requirements to ensure to the maximum practicable degree
that the required emissions reductions will be achieved. Further, if a
State adopts alternative requirements that do not apply to all non-EGUs
in a particular source category (defined to include all sources where
any aspect of production is reasonably interchangeable), the State must
demonstrate that it has analyzed the potential for shifts in production
from the regulated sources to lesser regulated sources in the same
State as well as in other States, and that the State is not including
reductions attributable to sources that may shift emissions to such
non-regulated or not as stringently regulated sources.
iv. Emissions inventories and demonstrating reductions. Quantifying
emissions reductions attributable to controls on non-EGUs requires that
the States submit both baseline and projected control emissions
inventories for the applicable implementation years. We have issued
many guidance documents and tools for preparing such emissions
inventories, some of which apply to specific sectors States may choose
to control. While much of that guidance is applicable to the proposed
CAIR, there are some key differences between quantification of emission
reduction requirements under a SIP designed to help achieve attainment
with a NAAQS and emission reduction requirements under a SIP designed
to reduce emissions that contribute to a downwind State's nonattainment
problem. When addressing its own nonattainment problem, a State has an
incentive not to overestimate emission reductions. If a State
overestimates emission reductions, the potential consequence is that
the State would remain out of attainment. Missing an attainment
deadline has adverse impacts upon a State. Among other things, the area
may be ``bumped up'' to a higher classification with more stringent
requirements.
Under transport requirements, however, overestimating emission
reductions has fewer intrastate consequences (because it is the
downwind State that would pay the price of remaining in nonattainment).
For this reason, EPA believes that it is appropriate to have more
stringent guidelines with respect to quantification of emission
reductions under a program designed to reduce transported pollutants
than are currently used with respect to SIPs addressing intrastate air
pollution problems. We discuss below more stringent requirements both
for developing baseline emission rates and for projecting future
emission levels.
When we review CAIR SIPs for approvability, we intend to closely
review the emissions inventory projections for non-EGUs to evaluate
whether the emissions reductions estimates are correct. We intend to
review the accuracy of baseline historical emissions for the subject
sources, assumptions regarding activity and emissions growth between
the baseline year and 2010 and 2015, and assumptions about the
effectiveness of control measures.
To quantify non-EGU reductions, as the first step, a historical
baseline must be established for emissions of SO2 and/or
NOX from the non-EGU source(s) in
[[Page 32694]]
a recent year. The historical baseline inventory should represent
actual emissions from the substitute sources prior to the application
of the emissions controls. We expect that States will choose a
representative year (or average of several years) falling between 2002
and 2005, inclusively, for this purpose.
The proposed requirements that follow for estimating the historical
baseline inventory reflect EPA's belief that, when States assign
emissions reductions to non-EGU sources, those reductions should have a
high degree of certainty of actually being achieved similar to EGU
reductions which can be quantified with a high degree of certainty in
accordance with part 75 monitoring requirements that apply to EGUs. For
non-EGU sources which are subject to part 75 monitoring requirements,
historical baselines must be derived from actual emissions obtained
from part 75 monitored data.
For non-EGU sources that do not have part 75 monitoring data to use
as a baseline, a historical baseline must be established that estimates
actual emissions in a way that matches or approaches as closely as
possible the certainty provided by the part 75 measured data for EGUs.
In the absence of part 75 measured data, EPA proposes that States be
required to estimate historical baseline emissions using assumptions
that ensure a source's or source category's actual emissions are not
overestimated; source-specific or category-specific data are required.
Because the substitute emissions reductions are estimated by
subtracting controlled emissions from a projected baseline, if the
historical baseline overestimates actual emissions, the estimated
reductions could be higher than the actual reductions achieved. As
explained above, the use of historical baselines that do not
overestimate emissions helps to ensure that upwind emissions reductions
are actually achieved.
To achieve this baseline, States must use emission factors that
ensure that emissions are not overestimated (e.g., emission factors at
the low end of a range when EPA guidance presents a range) or the State
must provide additional information that shows with reasonable
confidence that another value is more appropriate for estimating actual
emissions. Other monitoring or stack testing data can be considered but
care must be taken not to overestimate baselines. If a production or
utilization factor is part of the historical baseline emissions
calculation, again, a factor that ensures that emissions are not
overestimated must be used, or additional data must be provided.
Similarly, if a control-efficiency factor and/or rule-effectiveness
factor enters into the estimate of historical baseline emissions, it
must be realistic and supported by facts or analysis. For these
factors, a high value (closer to 100 percent control and effectiveness)
ensures that emissions are not overestimated.
Once the historical baseline is established for SO2 and/
or NOX emissions from the substitute sources, the second
step is to project these emissions to conditions expected in 2010 and
2015. This step results in the 2010 and 2015 baseline emissions
estimates. This step must be done with state-of-the-art methods for
projecting the source's or source category's economic output. Economic
and population forecasts must be as specific as possible to the
applicable industry, State, and county of the source, and must be
consistent with both national projections and relevant official
planning assumptions including estimates of population and vehicle
miles traveled developed through consultation between State and local
transportation and air quality agencies. However, if these official
planning assumptions are themselves inconsistent with official U.S.
Census projections of population and energy consumption projections
contained in the Annual Energy Outlook published by the U.S. Department
of Energy, adjustments must be made to correct the inconsistency, or
the SIP must demonstrate how the official planning assumptions are more
accurate. Where changes in production method, materials, fuels, or
efficiency are expected to occur between the baseline year and 2010 or
2015, these must be accounted for in the projected 2010 and 2015
baseline emissions. The projection must also account for any adopted
regulations that will affect source emissions, not including the
measures adopted for purposes of meeting the requirements of the
proposed CAIR and eligible for that purpose. (See discussion above
regarding eligibility of reductions from non-EGU sources.)
The EPA is also proposing an alternative methodology for the use of
projected 2010 and 2015 emissions. In this alternative, instead of
using the projected 2010 and 2015 emissions as the 2010 and 2015
baselines, States must use the lower of historical baseline emissions
for a source category or projected 2010 or 2015 emissions, as
applicable, for a source category. This is because, as explained above,
changes in production method, materials, fuels, or efficiency often
play a key role in changes in emissions. Because of factors such as
these, emissions can often stay the same or even decrease as
productivity within a sector increases. These factors that contribute
to emission decreases can be very difficult to quantify.
Underestimating the impact of these types of factors can easily result
in a projection for increased emissions within a sector, when a correct
estimate would result in a projection for decreased emissions within
the sector.
The third step is to develop the 2010 and 2015 controlled emissions
estimates by assuming the same changes in economic output and other
factors listed above but adding the effects of the new regulations
adopted for the purpose of meeting the CAIR. The regulations may take
the form of emissions caps, emission rate limits, technology
requirements, work practice requirements, etc. The State's estimate of
the effect of the regulations must be realistic in light of the
specific provisions for monitoring, reporting, and enforcement and
experience with similar regulatory approaches. The State's analysis
must examine the possibility that these new regulations may cause
production and emissions to shift to non-regulated or less stringently
regulated sources in the same State or another State. If all sources of
an industrial or other type (where any aspect of production is
reasonably interchangeable) within the State are regulated with the
same stringency and compliance assurance provisions, the analysis of
production and emissions shifts need only consider the possibility of
shifts to other States. In estimating controlled emissions in 2010 and
2015, assumptions regarding ineligible control measures must be the
same as in the 2010 baseline estimates. For example, if a federally
adopted and implemented measure for the source type is assumed in one
estimate, it must be assumed in the other.
Thus, EPA proposes two alternative methodologies for calculating
the 2010 and 2015 emissions reductions from non-EGUs which can be
counted toward satisfying the CAIR. In the first alternative, the 2010
and 2015 emissions reductions which can be counted toward satisfying
the CAIR are the differences between (i) for 2010, the 2010 baseline
emissions estimates and the 2010 controlled emissions estimates, and
(ii) for 2015, the 2015 baseline emissions estimates and the 2015
controlled emissions estimates, minus in each case any emissions that
may shift to other sources rather than be eliminated.
In the second alternative, the 2010 and 2015 emissions reductions
which can be counted toward satisfying the
[[Page 32695]]
CAIR are the differences between (i) for 2010, the lower of historical
baseline or 2010 baseline emissions estimates and the 2010 controlled
emissions estimates, and (ii) for 2015, the lower of historical
baseline or 2015 baseline emissions estimates and the 2015 controlled
emissions estimates, minus in each case any emissions that may shift to
other sources rather than be eliminated.
v. Controls on non-EGUs only. In the January 2004 proposal, we
stated that we believe it is unlikely States will choose to control
only non-EGUs, but we also said we would propose in this SNPR
provisions for determining the specified emissions reductions that must
be obtained if States pursue this alternative. In this SNPR, EPA
proposes that States choosing this path must ensure the amount of non-
EGU reductions is greater than or equivalent to all of the emissions
reductions that would have been required from EGUs had the State chosen
to assign all the emissions reductions to EGUs, for example by
participating in EPA-administered trading programs. For SO2
emissions, this amount in 2010 would be 50 percent of a State's title
IV SO2 allocations for all affected sources in the State
and, for 2015, 65 percent of that amount. For NOX emissions,
this amount would be the difference between a State's EGU budget for
NOX under the CAIR and its NOX baseline EGU
emissions inventory as projected in the Integrated Planning Model (IPM)
for 2010 and 2015, respectively. The proposed rule text provides tables
of these amounts for both SO2 and NOX.
In addition, EPA proposes that the same requirements described
above (in section III.A.4.c of this preamble) regarding the eligibility
of non-EGU reductions, emissions control and monitoring, emissions
inventories and demonstrations of reductions, will apply to the
situation where a State chooses to control only non-EGUs.
B. What Changes Are EPA Proposing for Emissions Reporting Requirements?
1. Purpose and Authority
The EPA believes that it is essential that achievement of the
emissions reductions required by the proposed CAIR be verified on a
regular basis. Emissions reporting is the principal mechanism to verify
these reductions and to assure the downwind affected States and EPA
that the ozone and PM2.5 transport problems are being mitigated as
required by the proposed CAIR. Also, EPA intends to reassess from time
to time whether the requirements of the CAIR are effective in achieving
the protections intended by CAA section 110(a)(2)(D)(i) for downwind
PM2.5 and ozone nonattainment areas. To this end, EPA is proposing
certain, limited new emissions reporting requirements for States.
Proposed rule language for these requirements appears at the end of
this SNPR. The rule language also would remove or simplify some current
emissions reporting requirements which we believe are not necessary or
appropriate, for reasons explained below.
Because we are proposing to consolidate and harmonize the new
emissions reporting requirements proposed today with two pre-existing
sets of emissions reporting requirements, we review here the purpose
and authority for emissions reporting requirements in general.
Emissions inventories are critical for the efforts of State, local,
and Federal agencies to attain and maintain the NAAQS that EPA has
established for criteria pollutants such as ozone, particulate matter
(PM), and carbon monoxide (CO). Pursuant to its authority under
sections 110 and 172 of the CAA, EPA has long required SIPs to provide
for the submission by States to EPA of emissions inventories containing
information regarding the emissions of criteria pollutants and their
precursors (e.g., volatile organic compounds (VOC)). The EPA codified
these requirements in subpart Q of 40 CFR part 51, in 1979 and amended
them in 1987.
The 1990 Amendments to the CAA revised many of the provisions of
the CAA related to the attainment of the NAAQS and the protection of
visibility in Class I areas. These revisions established new periodic
emissions inventory requirements applicable to certain areas that were
designated nonattainment for certain pollutants. For example, section
182(a)(3)(A) required States to submit an emissions inventory every 3
years for ozone nonattainment areas beginning in 1993. Similarly,
section 187(a)(5) required States to submit an inventory every 3 years
for CO nonattainment areas. The EPA, however, did not immediately
codify these statutory requirements in the CFR, but simply relied on
the statutory language to implement them.
In 1998, EPA promulgated the NOX SIP Call which requires
the affected States and the District of Columbia to submit SIP
revisions providing for NOX reductions to reduce their
adverse impact on downwind ozone nonattainment areas. (63 FR 57356,
October 27, 1998). As part of that rule, codified in 40 CFR 51.122, EPA
established emissions reporting requirements to be included in the SIP
revisions required under that action.
Another set of emissions reporting requirements, termed the
Consolidated Emissions Reporting Rule (CERR), was promulgated by EPA in
2002, and is codified at 40 CFR part 51 subpart A. (67 FR 39602, June
10, 2002). These requirements replaced the requirements previously
contained in subpart Q, expanding their geographic and pollutant
coverages while simplifying them in other ways.
The principal statutory authority for the emissions inventory
reporting requirements outlined in this SNPR is found in CAA section
110(a)(2)(F), which provides that SIPs must require ``as may be
prescribed by the Administrator * * * (ii) periodic reports on the
nature and amounts of emissions and emissions-related data from such
sources.'' Section 301(a) of the CAA provides authority for EPA to
promulgate regulations under this provision.\6\
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\6\ Other CAA provisions relevant to this SNPR include section
172(c)(3) (provides that SIPs for nonattainment areas must include
comprehensive, current inventory of actual emissions, including
periodic revisions); section 182(a)(3)(A) (emissions inventories
from ozone nonattainment areas); and section 187(a)(5) (emissions
inventories from CO nonattainment areas).
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2. Existing Emission Reporting Requirements
As noted above, at present, two sections of title 40 of the CFR
contain emissions reporting requirements applicable to States: Subpart
A of part 51 (the CERR) and section 51.122 in subpart G of part 51 (the
NOX SIP Call reporting requirements). This SNPR would
consolidate these, with modifications as proposed below. The
modifications are intended to achieve the additional reporting needed
to verify the reductions required by the proposed CAIR, to harmonize
the emissions reporting requirements, to reduce and simplify them, and
to make them more easily understood.
Under the NOX SIP Call requirements in section 51.122,
emissions of NOX for a defined 5-month ozone season (May 1
through September 30) from sources that the State has subjected to
emissions control to comply with the requirements of the NOX
SIP Call are required to be reported by the affected States to EPA
every year. However, emissions of sources reporting directly to EPA as
part of the NOX trading program are not required to be
reported by the State to EPA every year. The affected States are also
required to report ozone season emissions and typical summer daily
emissions of NOX from all sources every
[[Page 32696]]
third year (2002, 2005, etc.) and in 2007. This triennial reporting
process does not have an exemption for sources participating in the
emissions trading programs. Section 51.122 also requires that a number
of data elements be reported in addition to ozone season NOX
emissions. These data elements describe certain of the source's
physical and operational parameters.
Emissions reporting under the NOX SIP Call as first
promulgated was required starting for the emissions reporting year
2002, the year prior to the start of the required emissions reductions.
The reports are due to EPA on December 31 of the calendar year
following the inventory year. For example, emissions from all sources
and types in the 2002 ozone season were required to be reported on
December 31, 2003. However, because the Court which heard challenges to
the NOX SIP Call delayed the implementation by 1 year to
2004, no State was required to start reporting until the 2003 inventory
year. In addition, EPA recently promulgated a rule to subject Georgia
and Missouri to the NOX SIP Call with an implementation date
of 2007. (See 69 FR 21604, April 21, 2004.) For them, emissions
reporting begins with 2006. These emissions reporting requirements
under the NOX SIP Call affect the District of Columbia and
22 of the 29 States affected by the proposed CAIR.
As noted above, the other set of emissions reporting requirements
is codified at subpart A of part 51. Although entitled the CERR, this
rule left in place the separate Sec. 51.122 for the NOX SIP
Call reporting. The CERR requirements were aimed at obtaining emissions
information to support a broader set of purposes under the CAA than
were the reporting requirements under the NOX SIP Call. The
CERR requirements apply to all States.
Like the requirements under the NOX SIP Call, the CERR
requires reporting of all sources at 3-year intervals (2002, 2005,
etc.). It requires reporting of certain large sources every year.
However, the required reporting date under the CERR is 5 months later
than under the NOX SIP Call reporting requirements. Also,
emissions must be reported for the whole year, for a typical day in
winter, and a typical day in summer, but not for the 5-month ozone
season as is required by the NOX SIP Call. Finally, the CERR
and the NOX SIP Call differ in what non-emissions data
elements must be reported.
3. Proposed Emissions Reporting Requirements
The EPA proposes to further consolidate the detailed requirements
for emissions reporting by States entirely into subpart A, while adding
limited new requirements for emissions reports to serve the additional
purposes of verifying the CAIR-required emissions reductions. This will
allow EPA to monitor compliance with the CAIR, as well as assess from
time to time progress in mitigating the interstate transport of ozone
and PM2.5 precursors.
This SNPR would also harmonize the reporting requirements, and
reduce and simplify them in several ways. The major changes included in
the proposed rule text are described below. A technical support
document in the docket provides a detailed explanation of every change
and its purpose.\7\
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\7\ ``Technical Support Document on Emissions Inventory
Reporting Requirements for the Proposed Clean Air Interstate Rule
(May 2004)'' can be obtained from the docket for today's proposed
rule: OAR-2003-0053.
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Amendments are proposed to subpart A, which contains Sec. 51.1
through 51.45 and an appendix, and to Sec. 51.122 in particular. We
also propose to add a new Sec. 51.125.
In Sec. 51.122, we propose to abolish certain
requirements entirely, and to replace certain requirements with a cross
reference to subpart A so that detailed lists of required data elements
appear only in subpart A. As amended, Sec. 51.122 will specify what
pollutants, sources, and time periods the States subject to the
NOX SIP Call must report and when, but will no longer list
the detailed data elements required for those reports.
The new Sec. 51.125 will be functionally parallel to
Sec. 51.122, specifying what pollutants, sources, and time periods the
States subject to the proposed CAIR must report and when, referencing
subpart A for the detailed data elements required.
The amended subpart A will list the detailed data elements
as well as provide information on submittal procedures, definitions,
and other generally applicable provisions.
Taken together, the existing emissions reporting requirements under
the NOX SIP Call and CERR are already rather comprehensive
in terms of the States covered and the information required. Therefore,
the practical impact of the changes proposed today is to impose only
three new requirements.
First, in Arkansas, Iowa, Louisiana, Mississippi, and Wisconsin,
for which we have proposed a finding of significant contribution to
ozone nonattainment in another State but which were not among the 22
States subject to the NOX SIP Call, the required emissions
reporting will be expanded to match those of the 22 States. The change
requires that they report NOX emissions during the 5-month
ozone season, in addition to the existing requirement for reporting
emissions for the full year. We are proposing that this new requirement
begin with the triennial inventory year prior to the CAIR
implementation date. This will be the 2008 inventory year, the report
for which will be due to EPA by June 1, 2010.
Second, under the existing CERR, yearly reporting is required only
for sources whose emissions exceed specified amounts. Under this SNPR,
the 28 States and the District of Columbia subject to the CAIR for
reasons of PM2.5 must report to EPA each year a set of
specified data elements for all sources subject to new controls adopted
specifically to meet the CAIR requirements related to PM2.5,
unless the sources participate in an EPA-administered emissions trading
program. This is like the every-year reporting requirement for
controlled sources under the NOX SIP Call, but covering SO2
in addition to NOX and covering the whole year--since the
PM2.5 NAAQS at issue is the annual NAAQS--rather than only
the ozone season. This proposal could increase the number of sources
for which States must submit reports each year rather than only every
third year, if a State chooses to control non-EGU sources under this
SNPR or if the State does not join the EPA trading programs for EGUs.
We are proposing that this new requirement begin with the 2009
inventory year, the report for which will be due to EPA by June 1,
2011. After the 2009 reporting year, this new requirement will have no
effect on States that fully comply with the CAIR by requiring their
EGUs to participate in the EPA model cap-and-trade programs.
Third, in all States, we are proposing to expand the definition of
what sources must report in point source format, so that fewer sources
would be included in non-point source emissions.\8\ We are proposing to
base the requirement for point source format reporting on whether the
source is a major source under 40 CFR part 70 for the pollutants
[[Page 32697]]
for which reporting is required, i.e., for CO, VOC, NOX,
SO2, PM2.5, PM10 and ammonia but
without regard to emissions of hazardous air pollutants. Currently, the
requirement for point source reporting is based on actual emissions in
the year of the inventory report. This change may require more sources
than at present to be reported as point sources every third year. The
new approach will make it possible to better track source emissions
changes, shutdowns, and start ups over time. It will result in a more
stable universe of reporting point sources, which in turn will
facilitate elimination of overlaps and gaps in estimating point source,
as compared to non-point source, emissions. Under this proposal, States
will know well in advance of the start of the inventory year which
sources will need to be reported. We are proposing that these new
requirements begin with the 2008 inventory year, the report for which
will be due to EPA by June 1, 2010. We invite comment on whether this
change could instead be practically implemented for the 2005 inventory
year, which we believe is desirable if it is practicable. We intend to
finalize this proposed change even if for some reason the new emissions
reductions requirements of the proposed CAIR and the above two changes
in emission reporting requirements are not finalized as proposed,
because this change is appropriate for the purposes of monitoring the
effectiveness of current SIP programs.
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\8\ We use the term ``non-point source'' to refer to a
stationary source that is treated for inventory purposes as part of
an aggregated source category rather than as individual facility. In
the existing subpart A of part 51, such emissions sources are
referred to as ``area sources.'' However, the term ``area source''
is used in section 112 of the CAA to indicate a non-major source of
hazardous air pollutants, which could be a point source. As
emissions inventory activities increasingly encompass both NAAQS-
related pollutants and hazardous air pollutants, the differing uses
of ``area source'' can cause confusion. Accordingly, EPA proposes to
substitute the term ``non-point source'' for the term ``area
source'' in subpart A, Sec. 51.122, and the new Sec. 51.125 to
avoid confusion.
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A number of proposed changes will reduce reporting requirements on
States or provide them with additional options:
The NOX SIP Call rule required the affected
States to submit emissions inventory reports for a given ozone season
to EPA by December 31 of the following year. The CERR requires similar
but not identical reports from all States by the following June 1, 5
months later. The EPA believes that harmonizing these dates would be
efficient for both States and EPA. We are proposing to move the
December 31 reporting requirement to the following June 1, the more
generally applicable submission date affecting all 50 States. We invite
comment on whether allowing this 5-month delay is consistent with the
air quality goals served by the emissions reporting requirements.
However, we also invite comment on the alternative of moving forward to
December 31 all or part of the June 1 reporting for all 50 States. In
particular, we solicit comment on requiring that point sources be
reported on December 31 and other sources on June 1. This approach
would eliminate the problem of States having to make two submissions
for point sources within a 5-month period, and would result in more
timely submission of the emissions information for point sources. More
timely submission would be particularly useful for point sources
because point sources generally are the primary subject of control
measures in SIPs. The later June 1 submission date for non-point
sources and mobile sources would allow more time for estimating these
emissions sources, which in some cases may require vehicle miles
traveled or business activity data not available in time for a December
31 submission. In addition, estimating emissions of some types of non-
point sources requires prior knowledge of emissions and activity levels
at point sources of the same industrial type; therefore, it makes sense
to stagger the submission deadlines for those different sources.
We also propose to eliminate a requirement of the
NOX SIP Call for a special all-sources report by affected
States for the year 2007, due December 31, 2008. The normal cycle of
every-third-year reporting would also produce the same type of all-
sources reports for 2005 and 2008. The EPA originally intended to use
the information on 2007 emissions to re-assess the effectiveness of the
NOX SIP Call in eliminating upwind NOX emissions
that contribute significantly to downwind ozone nonattainment as of the
latest 1-hour ozone attainment date within the region. The large
majority of the emissions reductions required by the NOX SIP
Call have been assigned to sources that participate in the EPA-
administered trading program, which has independent procedures to
ensure that emissions reductions are achieved. We now believe that
examining 2005 and 2008 inventory submissions and the annual reporting
on controlled sources will permit us to evaluate the effectiveness of
individual State rules or implementation practices in reducing
emissions. We no longer need the special 2007 emissions inventory
information to broadly revisit the NOX SIP Call, and we
recognize that preparing that inventory could draw resources away from
more important work by State air agencies.
We propose to remove a requirement in the existing CERR
for reporting annual and typical ozone season day biogenic emissions.
Because biogenic emissions vary greatly with daily weather conditions
and because there are other practical methods for obtaining hourly
estimates across whole regions when needed by EPA, States, or others,
we believe this requirement for reporting biogenic emissions serves no
useful purpose. This change does not affect our expectation that
biogenic emissions be appropriately considered in ozone and
PM2.5 attainment demonstrations.
We are proposing a new provision which would allow States
the option of providing emissions inventory estimation model inputs in
lieu of actual emissions estimates, for source categories for which
prior to the submission deadline EPA develops or adopts suitable
emissions inventory estimation models and by guidance defines their
necessary inputs. This provision will allow source reporting to evolve
to take advantage of new emissions estimation tools for greater
efficiency, although the States will remain required to provide inputs
representative of their conditions. We propose this option be available
starting with the reports on 2003 emissions.
We are proposing to delete the existing requirement that
all States report emissions for a winter work weekday. This requirement
was originally aimed at tracking progress towards attainment of the CO
NAAQS. We believe applying this requirement to all States is no longer
warranted given that CO violations are currently observed in few areas.
We believe we can work directly with the remaining affected States to
monitor efforts to attain, without requiring formal submission of CO
inventories.
The NOX SIP Call rule and the CERR contain detailed
lists of required data elements in addition to emissions, and each rule
has its own set of definitions. The two sets of data elements overlap
but are not identical. Generally, the NOX SIP Call rule
required more data elements to be reported. The EPA has reviewed both
lists in light of more recent experiences and insight into the
difficulty States face in collecting and submitting these data elements
and their utility to EPA, other States, and other users. We are
proposing to combine the separate lists of required elements into a
single new list of required data elements. A few data elements are
proposed to be eliminated, as explained in the technical support
document for inventory reporting. We propose that these relatively
minor changes become applicable starting with the first required
emissions reports following the promulgation of the final CAIR, which
we expect to be the reports regarding emissions during 2003, due June
1, 2005.
There are a number of currently required data elements that have
been kept in the proposed rule text, but on which we invite comment as
to whether
[[Page 32698]]
they should be dropped in the final rule. These are heat content
(fuel), ash content (fuel), sulfur content (fuel) for fuels other than
coal, activity/throughput, hours per day in operation, days per week in
operation, weeks per year in operation, and start time in the day.
These data elements have been carried forward from emissions reporting
systems dating back many years. We believe it is appropriate to take
comment on their current usefulness.
We also invite comment on whether the current data elements that
describe emissions control equipment type and efficiency are adequate.
We believe it is important for States to report on the manner in which
sources are currently controlled so that opportunities for additional
highly cost-effective controls can be assessed from time to time, but
the existing data elements may not be adequate and appropriate for that
purpose. The present data elements related to control measures are
primary control efficiency, secondary control efficiency, control
device type, and rule effectiveness for point sources; and total
capture/control efficiency, rule effectiveness, and rule penetration
for non-point sources and nonroad mobile sources.\9\
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\9\ Additional information on emissions data elements and the
formats and valid codes presently in use for State reporting to EPA
is available on the EPA Web site http://www.epa.gov/ttn/chief/nif/index.html
.
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We are proposing to retain the requirement for reporting of summer
day emissions from all sources (except biogenic sources) at 3-year
intervals, but to restrict it to only States with ozone nonattainment
areas or for which we are proposing a finding of significant
contribution to ozone nonattainment in another State. The
NOX SIP Call requires reporting only of NOX
emissions for a typical summer day, while the CERR requires reporting
of all pollutants. We propose to restrict the requirement to VOC and
NOX emissions, but we invite comment on whether CO emissions
should be required also.
At present, States are required to report three particular data
elements for point source stacks: Stack diameter, exit gas velocity,
and exit gas flow rate. This is a redundant requirement, since any one
of these can be calculated from the other two. We invite comment on
which of these to drop from the required list of data elements, if any.
Our preference would be to collect the data element that is most
closely tied to an actual operating measurement. Alternatively, we may
allow States to report either exit gas flow or exit gas velocity, at
their option.
Finally, we propose to modify section 51.35 of subpart A, to
provide that if States obtain one-third of their necessary emissions
estimates from point sources and/or prepare one-third of their non-
point or mobile source emissions estimates each year on a rolling
basis, they should submit their data as a single package on the
required every-third-year submission date.
C. Acid Rain Program
In this SNPR, EPA proposes several revisions of the Acid Rain
Program regulations (40 CFR parts 72 through 78). Most of the proposed
revisions would affect the provisions in the regulations concerning the
requirement to hold allowances sufficient to authorize annual
SO2 emissions. These proposed revisions would facilitate the
interaction of the Acid Rain Program with the proposed CAIR trading
program. However, because these proposed modifications also would
benefit the implementation of the existing Acid Rain Program, EPA is
proposing to adopt them regardless of whether other rules proposed in
the CAIR are adopted.
As the basis for these proposed revisions of the Acid Rain Program
regulations, EPA proposes to modify its interpretation of title IV of
the CAA and, specifically, provisions in sections 403, 404, 405, 408,
409, 411, and 414, concerning the requirement to hold allowances.
Provisions in each of these sections address the allowance-holding
requirement by: Stating the requirement that sufficient allowances be
held for a unit after a calendar year to authorize emissions at least
equal to the unit's tonnage of SO2 emissions during that
year; referencing this requirement; or establishing the penalties and
offsets for violation of this requirement.
The following is a description of these statutory provisions.
Section 403(g) is a general prohibition barring each affected unit from
emitting SO2 in excess of the number of allowances ``held
for that unit for that year by the owner or operator of the unit'' (42
U.S.C. 7651b(g)). Various provisions in sections 404 and 405 refer to
existing units (those commencing commercial operation before November
15, 1990) and state that a unit's emissions may not exceed its
allowance allocation unless the owner or operator of such unit ``holds
allowances to emit not less than the unit's total annual emissions''
(42 U.S.C. 7651c(a), 7651c(c)(2), 7651c(d)(1) and (5), 7651d(b)(1) and
(3), 7651d(c)(1) through (3) and (5), 7651d(d)(1) and (2), 7651d(e),
7651d(f)(1), 7651d(h)(1)).\10\ Section 403(e) refers to new units and
States that it is unlawful for such a unit ``to emit an annual tonnage
of sulfur dioxide in excess of the number of allowances to emit held
for the unit by the unit's owner or operator'' (42 U.S.C.
7651b(e)).\11\ Section 403(d)(1) provides that ``the total tonnage of
emissions in any calendar year (calculated at the end thereof) from all
units in such a utility system, power pool, or allowance pool
agreements shall not exceed the total allowances for such units for the
calendar year concerned'' (42 U.S.C. 7651b(d)(2)). Section 403(f)
states that each permit under titles IV and V of the CAA must provide
that ``the affected unit may not emit an annual tonnage of sulfur
dioxide in excess of the allowances held for that unit'' (42 U.S.C.
7651b(f)).\12\ Section 411(a) establishes the owner or operator's
liability for an excess emissions penalty if SO2 is emitted
at the unit in excess of the ``allowances the owner or operator holds
for use for the unit for that calendar year'' (42 U.S.C. 7651j(a)).\13\
Finally, section 414 provides that the operation of an affected unit to
emit SO2 in excess of ``allowances held for such unit'' is a
violation of the CAA, with each ton emitted in excess of allowances
held constituting a separate violation (42 U.S.C. 7651m).
---------------------------------------------------------------------------
\10\ See also 42 U.S.C. 7651h(f) (section 409(f), referring to
repowered sources and the ``prohibition against emitting sulfur
dioxide in excess of allowances held'').
\11\ See also 42 U.S.C. 7651d(g)(1) (section 405(g)(1),
referring to certain new units and stating that a unit's emissions
may not exceed its allowance allocation unless the owner or operator
of such unit ``holds allowances to emit not less than the unit's
total annual emissions'').
\12\ See also 42 U.S.C. 7651g(a) (section 408(a)(1), stating
that each permit must prohibit ``annual emissions of sulfur dioxide
in excess of the number of allowance to emit sulfur dioxide the
owner or operator, or the designated representative of the owners or
operators, of the unit hold for the unit''); and 42 U.S.C.
7651g(d)(4) (section 408(d)(4), stating that each Phase II permit
must bar ``affected units at the affected source'' from emitting
``in excess of the number of allowances to emit sulfur dioxide the
owner or operator or designated representative hold for the unit'').
\13\ See also 42 U.S.C. 7651j(b) (section 411(b), stating that
the owner or operator of ``any affected source that emits sulfur
dioxide during any calendar year in excess of * * * the allowances
held for the unit for the calendar year'' is liable for an equal
tonnage offset of the excess emissions).
---------------------------------------------------------------------------
In summary, sections 403(e) through (g), 408(a) and (d), 411(a) and
(b), and 414 all state that the owner or operator must hold allowances
``for the unit'' at least equal to the unit's SO2 emissions.
While section 403(d)(2) refers to ``all units'' on a ``utility system's
power pool, or allowance pool agreements,'' EPA interprets this
provision as consistent with the requirement that
[[Page 32699]]
allowances must be held for each such unit at least equaling the unit's
emissions.\14\ The remaining provisions cited above contain a more
shorthand reference to the allowance-holding requirement by simply
stating that the owner or operator must hold sufficient allowances for
a unit's emissions.
---------------------------------------------------------------------------
\14\ See 64 FR 25835-25837 (explaining that the legislative
history of section 403(d)(2) indicates that the provision was not
intended to require or authorize aggregation of such units'
allowances to determine compliance with the allowance-holding
requirement).
---------------------------------------------------------------------------
Moreover, section 403(b) of the CAA requires the Administrator to
establish by regulation the allowance tracking system, including the
requirements for ``allocation, transfer, and use of allowances'' (e.g.,
for the holding of allowances). 42 U.S.C. 7651b(b). For example, in
establishing the allowance tracking system, the regulations must
specify which accounts in the allowance tracking system must contain
allowances used to meet the allowance-holding requirement. However,
none of the above-described statutory provisions on the allowance-
holding requirement specifically identify the type of account in which
a unit's owner or operator must hold allowances in order to meet that
requirement. In particular, these statutory provisions do not state,
and thus are ambiguous concerning, whether the account must be an
account unique to the unit ``for'' which allowances are held (i.e., a
unit-level account) or whether the account can be ``for'' all units at
a given source (i.e., a source-level account).
The EPA has exercised its authority under section 403(b) in several
prior rulemakings, in which EPA considered the question of what type of
account could be used to hold allowances ``for'' a unit to meet the
allowance-holding requirement. In the initial rulemaking for the Acid
Rain Program that resulted in the January 11, 1993 core rules for the
program, EPA interpreted the statutory provisions on allowance holding
to mean that, in general, allowances ``for'' a unit could be held only
in an account unique to that unit (referred to in the regulations as a
``unit account''). (See 63 FR 41358, 41362, August 3, 1998) (discussing
that allowances had to be held in a subaccount (the ``compliance
subaccount'') of the unit account). Even so, the January 11, 1993 rules
include an exception, continued in the existing rules, for affected
units that share a common stack and monitor at the stack, not at the
individual units. For such common-stack units, the designated
representative has the option to assign (before the allowance transfer
deadline) a percentage of allowances to be deducted from the unit
account for each unit so that the total deduction for all the common-
stack units equals the total annual emissions from these units. If the
option is not exercised, an equal percentage of the allowances is
deducted from the unit account of each unit. The assigned, or the
default, deductions need not have any relationship to the actual
distribution of emissions among the common-stack units. Consequently,
the treatment of common-stack units effectively allows the allowances
in a unit's unit account to be used to cover emissions from another
unit at the same source. (See 63 FR 41362.)
In a rulemaking completed in May 1999, EPA reconsidered and revised
its interpretation of title IV, and revised the Acid Rain Program
regulations, in order to allow a unit to use some allowances in the
unit account of another unit at the source to meet the allowance-
holding requirement. (64 FR 25834, May 13, 1999). This revision applied
to units at the same source even if they were not common-stack units.
The revised regulations resulting from that rulemaking allow a unit to
use allowances in the unit account of another unit at the same source
up to a limit equal to the greater of: 95 percent of the difference
between the first unit's emissions and the allowances in its own unit
account; or 10 tons. See 40 CFR 73.35(b)(3) (Sec. 73.35(b)(3)). This
approach effectively allows the owner or operator to approach source-
wide compliance in that, except for the above-described limit,
allowances at one unit are considered to be held ``for'' another unit
at the same source and can be used to meet the allowance-holding
requirement. The EPA explained that the limit on using another unit's
allowances would ``provide owners and operators with a strong incentive
to hold sufficient allowances in an affected unit's account'' and that
compliance would ``routinely'' be achieved on a unit-by-unit basis. (64
FR 25837). In adopting this interpretation of the ambiguous language in
title IV concerning the allowance-holding requirement, EPA stated that
it was balancing the general unit-by-unit orientation of title IV and
the need for ``compliance flexibility.'' Compliance flexibility is
necessary to reduce excess emission penalties where there are
insufficient allowances in the unit's unit account due to
``inadvertent, minor errors'' but enough allowances in the account of
another unit at the same source.
In today's SNPR, EPA is reconsidering the extent to which
allowances in the account of one unit at a source can be used to meet
the allowance-holding requirement for another unit at the same source.
There are several factors relevant to this reconsideration. The first
factor is that, as discussed above, the statutory provisions setting
forth the allowance-holding requirement do not specifically refer to
allowance accounts, much less dictate the type of account in which
allowances must be held ``for the unit'' in meeting this requirement.
To the extent only allowances held in a unit-level account are treated
as being held ``for'' the unit involved, compliance must be met on an
individual-unit basis. To the extent all allowances held in a source-
level account are treated as being held ``for'' all units at the source
involved, compliance may be met on a source-wide basis. In light of the
ambiguity in the statutory allowance-holding-requirement provisions,
EPA believes that it has discretion in determining whether to apply the
allowance-holding requirement at the unit level or the source level.
Indeed, EPA maintains that the degree of compliance flexibility that
was provided in the May 13, 1999 rulemaking did not exhaust EPA's
discretion in moving toward source-level compliance.
The second factor considered by EPA is that it is important to
provide compliance flexibility by allowing one unit at a source to use,
for compliance, allowances from other units at that source. The
statutory excess emissions penalty of $2,000 (adjusted for inflation
since 1990 to about $2,900) per ton is over ten times the current
market value of an allowance. Moreover, unlike the general civil
penalties under section 113 for violations of the CAA, section 411
makes the excess emission penalty automatic (not discretionary) and
therefore applicable to all excess emissions at a unit, even if they
result from inadvertent, minor errors by the owner or operator.
Consequently, companies have potential liability for large excess
emissions penalty payments for what may be inadvertent, minor errors.
For example, a company may have acquired enough allowances to authorize
all the annual emissions from units at a source but incorrectly
distributed the allowances among the unit accounts for those units. The
distribution may be incorrect because of something as simple as: An
error by the owner or operator in calculating how many allowances will
remain in each unit account after allowance transfers submitted just
before the allowance transfer deadline are recorded; an error in the
allowance amount, or in the account number of the transferee, listed
[[Page 32700]]
in an allowance transfer form; or an error in identifying the unit for
which collected emission data are reported.
In the May 13, 1999 rulemaking, EPA partially addressed this
problem by allowing a unit with fewer allowances in its unit account
than emissions to use allowances in the unit accounts of other units at
the source, but with a limit on that use. (See 63 FR 41360 and 64 FR
25838-25839). Under the current Sec. 73.35(b)(3), the unit may use
allowances from other units at the source to eliminate up to the
greater of: 95 percent of that unit's allowance deficit; or 10 tons.
While this can significantly reduce a unit's potential liability for
excess emission penalty payments, the excess emission penalty payments
can still be quite large, particularly when the allowance deficit is
large enough that the 95 percent limit, rather then the 10-ton limit,
applies. The 95 percent limit applies whenever the allowance deficit
exceeds 200. An error, such as reversing digits in the allowance amount
in a transfer form or misidentifying the unit for which collected
emission data are reported, can easily result in a very large allowance
deficit and therefore in a large penalty payment when the 95 percent
limit on use of other units' allowances applies. In short, the current
provisions in Sec. 73.35(b)(3) do not fully (and in EPA's view do not
sufficiently) address the problem of excess emission penalty payments
that potentially are far out of proportion to the errors involved.
The third factor considered by EPA is that, as noted in prior
rulemakings, title IV evidences in language addressing matters beyond
the allowance-holding requirement a ``pervasive unit-by-unit
orientation.'' (See 63 FR 41360). For example, the applicability of
title IV is determined on a unit-by-unit basis under sections 402
(definitions of ``unit,'' ``existing unit,'' ``new unit,'' ``utility
unit,'' and ``affected unit''), 403(e), 404(a)(1), and 405. Allowances
are allocated, and annual SO2 emission limitations are set,
for individual units. Under section 411(a), excess emissions penalties
are imposed on owners and operators of units that have excess
emissions, while, under section 411(b), offsets of excess emissions are
imposed on owners and operators of sources with units that have excess
emissions. Section 412(a) requires unit-by-unit monitoring of
emissions, except that, in the case of units at a common stack,
separate monitors for each unit are not required if sufficient
information for compliance determinations is provided.
Balancing the three above-described factors, EPA proposes to revise
the Acid Rain regulations to allow a unit to use for compliance any
allowances from other units at the same source.\15\ This approach
limits the extent of deviation from the unit-by-unit orientation
evidenced in the non-allowance-holding provisions of title IV in that a
unit may only use allowances held for other units that are at
essentially the same geographic location as that unit, i.e., other
units that are at the same source. Moreover, there are no significant
environmental consequences to shifting from unit- to source-level
compliance. This approach is also feasible in that it does not require
any dramatic changes in the operation of the Acid Rain Program. For
example, only one designated representative (i.e., the designated
representative of the source at which the units are located) will be
involved in ensuring that there are sufficient allowances to cover
emissions as of the allowance transfer deadline. It also appears that
this approach will result in a minimum of changes to existing contracts
involving allowance agreements among different owners of units at a
source. This is because Sec. 73.35(b)(2) already allows a unit to use
allowances from other units at the same source within certain limits
(i.e., the 95 percent and 10 ton limits described above), and today's
SNPR simply removes those limits.
---------------------------------------------------------------------------
\15\ For the reasons set forth in the preamble of the May 13,
1999 final rule, EPA maintains that allowing company-level
compliance or compliance at any other, higher level is neither
required by title IV nor appropriate. See 64 FR 25835-25837.
---------------------------------------------------------------------------
In order to implement the proposal to allow a unit to use
allowances from other units at the same source without limit, EPA is
proposing the following specific changes to the Acid Rain Program
regulations. The EPA's objective is to implement the proposal, but with
a minimum of changes to the language of the Acid Rain Program
regulations. Other than implementing the proposed shift from unit- to
source-level compliance, these proposed revisions are not intended to
make any substantive changes to the revised provisions.
1. The term ``unit account'' is replaced by ``compliance account''
in Sec. 72.2 and, as appropriate, in every other provision of the Acid
Rain Program regulations in which the term appears. Similarly,
references to a ``unit's'' account in the Allowance Tracking System are
replaced by references to a ``source's'' account. In addition,
references to allowances held by a ``unit'' are changed to refer to
allowances held by a ``source.''
2. References to a ``unit's'' Acid Rain emissions limitation for
SO2 are replaced by references to a ``source's'' Acid Rain
emissions limitation for SO2 throughout the Acid Rain
Program regulations. Similarly, references to a ``unit's''
SO2 emissions for purposes of applying the SO2
emissions limitation (or a ``unit's'' excess emissions) are replaced,
where appropriate, by references to the SO2 emissions of the
``affected units at a source'' or to a ``source's'' excess emissions.
It should be noted that the proposed rule language accompanying this
preamble attempts to list every instance in which the terms ``unit's''
Acid Rain emissions limitation for SO2 and ``unit's''
SO2 emissions or excess emissions (as well as the terms
``unit account,'' a ``unit's'' account, and allowances held by a
``unit'') appear and should be replaced. However, even if some
instances were missed, EPA proposes to replace the term in all
instances necessary to implement source-level compliance with the
allowance-holding requirement and requests comment on, among other
things, what other instances may have been missed.
3. The provisions in Sec. Sec. 72.90(b)(5) and 73.35(e) concerning
the assignment of allowance deductions among units at a common stack
are removed. These provisions are unnecessary with the shift from unit-
to source-level compliance.
4. The terms ``compliance subaccount,'' ``future year subaccount,''
and ``current year subaccount'' (and their definitions) are removed or
replaced, as appropriate, throughout the Acid Rain Program regulations.
The current regulations distinguish between two subaccounts in each
unit account, i.e., the ``compliance subaccount'' for allowances usable
for compliance in a given year and a ``future year subaccount'' for
allowances not usable until a future year. Similarly, the current
regulations refer to a ``current year subaccount'' of a general
account. The electronic Allowance Tracking System does not currently
use or refer to these subaccounts. Moreover there is also no need to
use or refer to them when compliance is on a source-level basis. The
proposed rule language accompanying this preamble attempts to list
every provision in which the terms ``compliance subaccount,'' ``future
year subaccount,'' and ``current year subaccount'' appear and to modify
the provision as necessary to remove these terms without changing the
substance of the provision. However, even if some instances were
missed, EPA proposes to replace the terms in all instances and requests
comment on, among other things, what other instances may have been
missed.
[[Page 32701]]
5. The provision in Sec. 73.35(b)(3) limiting the use of
allowances from another unit at the same source for compliance is
removed.
The EPA notes, in addition to the above-described rule changes,
shifting from unit- to source-level compliance under the Acid Rain
Program would require revisions to the software used to operate the
Allowance Tracking System and to reconcile allowances and emissions
after the end of each calendar year. For example, one approach might be
to revise the software to aggregate and convert unit accounts in the
Allowance Tracking System to source-level compliance accounts. The
system would need to move the allowances in the unit accounts of all
affected units at a given source to the new source-level compliance
account and ensure recordation in the compliance account of the
allowances allocated to such units. In addition, annual emissions for
the affected units at a source would have to be summed and then
compared with the allowances in that source's compliance account.
Because of the time necessary to revise the software and to conduct
testing to ensure that the Allowance Tracking System operates properly,
EPA believes that the rule changes implementing source-level
compliance, if adopted in a final rule, should not become effective
before July 1, 2005. Under that approach, compliance under the Acid
Rain Program for the 2004 calendar year (which is determined after the
allowance transfer deadline for 2004, i.e., March 1 or the next
business day if March 1 is not a business day) would remain at the
unit-level, and compliance would shift to the source-level for the 2005
calendar year. An effective date of July 1, 2005 would ensure that the
source-level rule changes would take effect after completion of the
process of determining compliance for 2004. The EPA's experience is
that the compliance determination process is generally completed
several months after the end of the year for which emissions and
allowances are compared. The July 1, 2005 effective date would give
owners and operators, as well as EPA, the opportunity to adjust
internal procedures to take account of source-level compliance. The EPA
requests comment on a July 1, 2005 effective date for the Acid Rain
Program rule changes discussed in today's notice and on any alternative
effective dates for such rule changes.
The EPA further notes that not only is the proposed shift to
source-level compliance consistent with title IV and an improvement to
the operation of the Acid Rain Program, but also this change would
facilitate the coordination of this program with the proposed CAIR
trading program. The latter program, of course, requires source-level
compliance.
The EPA is also proposing other revisions of the Acid Rain Program
that do not address the allowance-holding requirement but that are
focused on facilitating the interaction of the Acid Rain Program and
the proposed CAIR trading program. For example, certain language in the
definition of ``cogeneration unit'' in Sec. 72.2, which definition was
recently changed (See 67 FR 40420, June 12, 2002), is changed back to
the original language so that it is consistent with certain language in
the proposed definition of ``cogeneration unit'' in the CAIR model
trading rules. See section IV below.
Further, the language required in Sec. 72.21(b)(1) for the
certification that must be in each submission by the designated
representative in the Acid Rain Program would be revised so that the
same submission-certification language can be used for submissions for
units whether the units are in both the CAIR trading program and the
Acid Rain Program or in only one of the programs. Similarly, certain
language required in Sec. 72.24 (paragraphs (a)(5), (a)(7), and
(a)(10)) for the certificate of representation for the designated
representative in the Acid Rain Program would be removed so that the
same, standard certificate can be used for units that are in one or
both programs. This would remove requirements (e.g., for a 1-day
newspaper notice of the designation of a designated representative)
that EPA believes have proved to be unnecessary. For the same reason,
certain language required in Sec. 73.31(c)(v) for the certificate of
representation for an authorized account representative in the Acid
Rain Program would be removed as unnecessary. With the proposed changes
in Sec. Sec. 72.24 and 73.31, the language for certificates of
representation in the Acid Rain Program and the CAIR trading program
would be the same as the language in the certificates of representation
in the NOX Budget Trading Program under the NOX
SIP Call.
A further example is that the general requirement for all affected
sources to submit compliance certification reports at the end of each
year is removed as superfluous. Sources already are required to submit
compliance certification reports under title V of the CAA that cover
compliance with CAA requirements, including the Acid Rain Program
requirements. Moreover, the quarterly emissions reports that each unit
must submit already include a certification of compliance with the
monitoring and reporting requirements under part 75 of the Acid Rain
Program regulations. The proposed CAIR trading programs do not require
submission of annual compliance certification reports.
In addition, several provisions in the Acid Rain Program
regulations concerning the allowance tracking system are proposed to be
removed or revised in order to make the allowance tracking systems in
the Acid Rain Program, the NOX Budget Trading Program, and
the proposed CAIR trading program as similar as possible. For example,
Sec. 73.32 has proved to be superfluous (and includes obsolete
references to compliance and current year subaccounts) and would be
removed. Section 73.33(c) imposes a one-day newspaper notice
requirement for authorized account representatives that has proved to
be unnecessary and would be removed. Sections 73.37(a) through (d)
would be removed since the claim of error procedure has proved to be
superfluous and has not been used. Similarly, Sec. Sec. 73.50 and
73.52 would be revised to remove superfluous language and to conform to
the provisions under the NOX Budget Trading Program and the
proposed CAIR trading program. For instance, language referencing
allowance transfers in perpetuity is removed as superfluous since such
transfers are allowed under these sections (and in the NOX
Budget Trading Program) even without such language.
D. NOX SIP Call
1. Emissions Reduction Requirements
Today's SNPR requires additional reductions in NOX from
States affected by the NOX SIP Call. However, this SNPR
would not relieve those States from the requirements of the
NOX SIP Call. Except as explained below, States should
retain all of the SIP provisions that they adopted to meet the
requirements of the NOX SIP Call.
All of the States subject to the NOX SIP Call (with the
exception of Georgia and Missouri, which are not required to submit
SIPs until 2005) chose to meet at least part of their emission
reduction requirement by including their EGUs in a multi-State ozone
season NOX trading program. The EPA has performed modeling
of expected NOX emissions from EGUs assuming that all States
affected by the proposed CAIR achieve all of their required
NOX reductions under the CAIR by including their EGUs in a
regionwide annual NOX cap-and-trade program. Based on that
modeling, EPA has proposed that if States achieve all of the mandated
NOX reductions by
[[Page 32702]]
including their EGUs in the regionwide, annual NOX cap-and-
trade program managed by EPA, EPA will consider the reductions from
that program to also meet the ozone season reduction requirements that
States were previously achieving from EGUs participating in a
regionwide ozone season NOX cap-and-trade program. Under
these circumstances, EGUs in a State achieving all of the required
NOX reductions from only EGUs would not be subject to a
seasonal NOX cap-and-trade program unless the State elects
to retain such a program. The EPA believes this approach would simplify
compliance for sources and avoid the potential administrative burden of
implementing both a seasonal and annual cap-and-trade program for EGUs.
2. NOX SIP Call Cap-and-Trade Program for Non-EGUs
The EPA is proposing to continue administering an ozone season only
NOX cap-and-trade program for non-EGUs that are subject to
the requirements of the regionwide NOX SIP Call cap-and-
trade program. In today's SNPR, EPA proposes modifications to part 51
of the NOX SIP Call to reflect the continued participation
of non-EGUs in the ozone season NOX cap-and-trade program
and the removal of EGUs from their ozone season NOX
limitations.
Maintaining the ozone season reductions from non-EGUs in the
NOX SIP Call is important for limiting their interstate
contribution to ozone nonattainment. The EPA considered whether it
would be appropriate to allow States to include non-EGUs in the annual
CAIR trading program and relieve them from the requirements of the
ozone season NOX trading program. However, EPA does not have
sufficient information to project whether non-EGUs would continue to
meet their ozone season NOX reduction requirements if they
were subject to an annual limitation only. Therefore, EPA is proposing
to continue to run the NOX SIP Call cap-and-trade program
for non-EGUs.
The EPA acknowledges that, if non-EGUs are only permitted to trade
with other non-EGUs, the robustness of the existing NOX SIP
Call allowance market must be maintained to provide incentives for non-
EGUs to find cost-effective emissions reductions. States that are
concerned for the future health of the market may choose to revise
their SIPs to achieve the non-EGU NOX emissions reductions
using an alternate approach. The EPA solicits comment on the potential
effects that removing EGUs from the NOX SIP Call trading
market may have on the robustness of the market and any alternative
mechanisms for addressing these concerns.
The EPA solicits comment on the above proposal and any other
approaches.
3. NOX Early Reduction Credits \16\
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\16\ Sulfur dioxide emission reduction credits (ERCs) are not
proposed because the CAIR sources already have incentive to make
early, annual reductions to bank Acid Rain Program SO2
allowances into the CAIR cap-and-trade program.
---------------------------------------------------------------------------
Today's SNPR does not propose to allow the generation and use of
early NOX emission reduction credits (``ERCs'') but does
solicit comment on whether NOX ERCs should be included in
the CAIR and, if so, how a NOX ERC program should be
structured.
If NOX ERCs are included, EPA expects that they would
primarily be generated by sources already subject to the NOX
SIP Call that would choose to operate already installed selective
catalytic reduction (SCR) technology during the 7-month ``non-ozone
season.'' These reductions in non-ozone season NOX
reductions would provide some additional, early environmental benefit
by reducing the atmospheric loading of NOX, acid
precipitation, and fine PM precursors prior to the implementation of
the CAIR. That said, EPA analysis projects that over 3.7 million tons
of NOX ERCs could be created (between 2006 and 2010) and
banked into the CAIR if unlimited non-ozone season ERCs were permitted
in the program. Allowing these ERCs to be used for compliance with the
CAIR NOX emission cap would delay progress towards achieving
both the annual NOX reduction goals and could potentially
reduce the ozone season reductions that are necessary for EPA to
justify removing the NOX SIP Call constraint for EGUs.
If EPA were to include ERCs, several approaches could be utilized:
(1) EPA could maintain the NOX SIP Call requirements and
allow sources to use ERCs only for compliance with the annual
limitation, to ensure that seasonal NOX limitations are met.
Under this scenario, the additional States subject to the CAIR that
have been found to significantly contribute to ozone nonattainment may
also have to be included in the ozone season cap; (2) EPA could limit
the period of time during which ERCs could be created and banked; (3)
EPA could cap the amount of ERCs that can be created; and (4) EPA could
apply a discount rate to ERCs.
The EPA solicits comment on today's SNPR to not include
NOX ERCs and, if ERCs were included, how the mechanism for
including ERCs should be structured.
E. How Would Emissions Trading Under the Proposed CAIR Relate to
Regional Haze?
This section addresses the relationship between the CAIR and the
CAA visibility-impairment provisions, in particular the Best Available
Retrofit Technology (BART) requirements under the Regional Haze Rule.
These provisions, under CAA Section 169A-B, require certain existing
sources, including electric generating units (EGUs) that may be
affected by SIPs required under CAIR, to install BART. However, the
Regional Haze Rule further provides that sources otherwise subject to
BART may be exempt if they are subject to alternative controls
demonstrated to provide greater reasonable progress toward the national
visibility goal. Today, EPA proposes that BART-eligible EGUs in any
State affected by CAIR may be exempted from BART for controls for
SO2 and NOX if that State complies with the CAIR
requirements through adoption of the CAIR cap-and-trade programs for
SO2 and NOX emissions.
1. Background: Nature of Regional Haze and Visibility Impairment;
Statutory and Regulatory Requirements
The EPA has discussed the science and legal background for
visibility impairment and regional haze elsewhere, most recently in the
re-proposed Guidelines for BART Determinations (69 FR 25184, May 5,
2004). Readers are referred to that preamble for a detailed description
of the background. The following is a brief summary.
a. What is regional haze? ``Regional Haze'' refers to air pollution
that impairs visibility over a widespread area that may encompass
several States. Regional haze occurs to varying degrees throughout the
United States, including at national parks that may be as far as
hundreds of miles from major pollution sources.\17\ Under sections
169A-B of the CAA, special protection is afforded to larger national
parks and wilderness areas, which are termed ``Class I areas.''\18\
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\17\ National Research Council, Protecting Visibility in
National Parks and Wilderness Areas, National Academy Press
(Washington, DC, 1993).
\18\ A ``Class I area'' is defined as any one of the 156
mandatory Class I Federal areas identified in part 81, subpart D of
title I of the CAA.
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Visibility in Class I areas, measured as visual range, is observed
to be on average one-half to two-thirds of the natural visual range
that would exist in the absence of anthropogenic pollution.
[[Page 32703]]
Observations show that visibility is lowest in Class I areas in the
eastern U.S., and significant impairment in visibility is also observed
in the Midwest and on the Pacific coast. The best visibility occurs in
the Central Rockies and in Alaska, but even in these locations,
visibility is worse than would be expected without anthropogenic
pollution.
Most visibility impairment is caused by fine particulate substances
and associated water. While natural sources of fine particles, such as
forest fires and windblown dust, can affect visibility significantly,
anthropogenic emissions are usually the major source of regional
haze.\19\
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\19\ NARSTO, Particulate Matter Science for Policy Makers--A
NARSTO Assessment. February 2003.
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b. Major chemical components of particles that contribute to
regional haze; EGUs as the major source of those components. The major
chemical classes of fine particles that affect visibility include
sulfates, organic matter, elemental carbon (soot), nitrates, and soil
dust. The major sources and important aspects of the chemistry of these
fine particle components as they affect PM 2.5 mass were
summarized in EPA's January 2004 proposal. (69 FR 4566, January 30,
2004).
As discussed in the January 2004 proposal, sulfate particles
comprise a major portion of PM2.5 mass. The relative
contribution of sulfates to visibility impairment is usually even
greater than their contribution to particle mass, largely because
sulfates absorb water, which enhances their capabilities to impair.\20\
Nitrates, which also generally contribute proportionally more to
visibility impairment than they do to fine particle mass, on average
caused 5-10 percent of visibility impairment over much of the U.S.\21\
Further, as discussed in section II of the January 2004 proposal, the
chemical interplay between ammonium sulfate and ammonium nitrate
particles is important in determining the effectiveness of
SO2 and NOX reductions in reducing fine particles
and in improving visibility. Because of this ``nitrate replacement,''
SO2 controls that reduce sulfates will be more effective at
improving visibility if complemented by NOX controls that
reduce nitrates, particularly in the winter.
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\20\ Malm, W. C., et al. (2000) Spatial and Seasonal Patterns
and Temporal Variability of Haze and its Constituents in the United
States: Report III, Cooperative Institute for Research in the
Atmosphere, Colorado State University, Fort Collins, CO.
\21\ Vimont, J. ``Nitrates: Contribution to Visibility'',
National Park Service, Presentation to the Western Regional Air
Partnership Workshop on NOX, July, 2003.
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c. Interstate transport and regional haze. A wealth of air quality
observations and modeling data clearly demonstrate that
PM2.5 and its precursors are transported across State
boundaries. This body of evidence--particularly, EPA air quality
modeling results--was summarized in the January 2004 proposal. Sulfur
dioxide and NOX emissions have been demonstrated to affect
ambient PM2.5 concentrations over a wide interstate area. In
addition, observations show that sulfate and nitrate make a large
contribution to visibility impairment.\22\
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\22\ Malm, W. C., et al. (2000) Spatial and Seasonal Patterns
and Temporal Variability of Haze and its Constituents in the United
States: Report III, Cooperative Institute for Research in the
Atmosphere, Colorado State University, Fort Collins, CO.
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A large fraction of current and future SO2 and
NOX emissions are attributable to EGUs. In the lower 48
States, the fraction of SO2 emissions from EGUs is a
consistent percentage of emissions from all sources, ranging from 62 to
65 percent over time; and EGU NOX emissions as a percent of
emissions from all sources is projected to grow slightly from 21 to 25
percent.
d. What are the Clean Air Act requirements for addressing regional
haze? In the 1977 CAA, Congress added the first provisions to protect
visibility in Class I areas. Subsection (a)(1) of CAA section 169A
establishes the following national visibility goal: ``The prevention of
any future, and the remedying of any existing, impairment of visibility
in mandatory Class I Federal areas which impairment results from
manmade air pollution.'' Subsection (a)(4) of this provision requires
EPA to promulgate regulations to assure ``reasonable progress toward
meeting [this] national goal. * * *'' In addition, the CAA visibility
provisions contain a specific requirement for the installation of BART
at certain existing sources, discussed below.
In 1980, EPA issued regulations addressing visibility impairment
``that can be traced to a single existing stationary facility or small
group of existing facilities.'' (45 FR 80085, December 2, 1980). In
that rulemaking, the Agency explicitly deferred national rules
addressing regional haze impairment.
In 1990, Congress added section 169B to the CAA to prompt EPA to
address regional haze. These provisions specifically establish a
commission for Grand Canyon National Park--the Grand Canyon Visibility
Transport Commission (GCVTC)--and require the Commission to issue a
report to EPA recommending measures to remedy visibility impairment.
CAA Section 169B(a)-(d) and (f). In the 1990 CAA Amendments, Congress
further provided that within 18 months after receiving this final
report, EPA must ``carry out the Administrator's regulatory
responsibilities under [section 169A], including criteria for measuring
`reasonable progress' toward the national goal.'' CAA Section
169B(e)(1).
The EPA published a rule in 1999 to address various aspects of
regional haze (the Regional Haze Rule). (64 FR 35714, July 1, 1999).
The Regional Haze Rule calls for the States to play the lead role in
designing and implementing regional haze programs for Class I areas.
Each State must establish goals that provide for reasonable progress,
over the period covered by the SIP, toward achieving natural visibility
conditions in the Class I areas in that State. 40 CFR 51.308(d)(1).
States must also submit a long-term strategy, as well as measures
necessary to implement that strategy, addressing visibility impairment
due to regional haze for each Class I area in the State and for each
Class I area located outside the State which may be affected by
emissions from the State. 40 CFR 51.308(d)(1), (3).
The EPA provided the States with considerable flexibility in
selecting the reasonable progress goals. The Regional Haze Rule
requires that these goals both provide for improvement during the 20
percent most impaired days and ensure no degradation in visibility
during the 20 percent clearest days. The baseline period for assessing
improvement and degradation is 2000-2004. In addition, for each Class I
area within its borders, a State must determine the appropriate, annual
rate of visibility improvement that would lead to ``natural
visibility'' conditions. The rule includes a presumption that States
can reach this goal in 60 years. 40 CFR 51.308(d)(1)(ii). Under the
regulations, this 60-year period extends to 2064, with the first long-
term strategy period ending in 2018. 40 CFR 51.308(f). States must
submit their long-term strategies each 10-year period. The first
strategy is due in early 2008 and must provide for reasonable progress
through 2018.
The 1999 Regional Haze Rule also addressed the BART requirements,
in 40 CFR 51.308(e)(1), and provided for the use of alternative
measures in lieu of BART in 40 CFR 51.308(e)(2) (discussed more fully
in section III.E.1.e. of this preamble below). The Regional Haze Rule
was challenged by several petitioners in the U.S. Court of Appeals for
the DC Circuit. American Corn
[[Page 32704]]
Growers et al. v. EPA, 291 F.3d 1 (DC Cir., 2002). The Court generally
upheld EPA's approach to improving visibility. However, the Court
vacated and remanded the provisions of the rule addressing the
determination of BART on a case-by-case basis.
In addition to these nationally applicable reasonable progress
requirements, the Regional Haze Rule contains a special rule for the
nine-State region \23\ (including tribes) included in the GCVTC, with
respect to the Grand Canyon and 15 other Class I areas located on the
Colorado Plateau. Under this provision, these States (and tribes) may
meet their reasonable progress requirements for the first, long-term
strategy period (ending in 2018) with respect to these 16 Class I areas
either by (i) meeting the nationally applicable reasonable progress
requirements (40 CFR 51.308), or (ii) adopting the recommendations of
the GCVTC, once those recommendations were approved by EPA. 40 CFR
51.309. This section also provided that, before the GCVTC
recommendations could be approved, an ``Annex'' to those
recommendations pertaining to stationary sources must be submitted to
EPA, providing quantitative emissions reduction goals and detailed
implementation strategies. The successor organization to the GCVTC--the
Western Regional Air Partnership (WRAP)--submitted such an Annex in
September, 2000, and EPA approved it in a final rule by notice dated
June 5, 2003. (68 FR 33764).
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\23\ The nine States are Arizona, California, Colorado, Idaho,
Nevada, New Mexico, Oregon, Utah, and Wyoming.
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e. Statutory and regulatory background for BART requirement. Under
CAA Section 169A(b)(2)(A), an existing source must install BART if the
source was constructed between 1962 and 1977,\24\ falls within one of
26 categories, has a potential to emit 250 tons or more of any
pollutant, and emits ``any air pollutant which may reasonably be
anticipated to cause or contribute to any impairment of visibility'' at
a Class I area. The 1999 Regional Haze Rule, among other things,
established requirements for implementing BART on a source-by-source
basis, in order to address the contribution of BART-eligible sources to
regional haze. 40 CFR 51.308(e)(1).
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\24\ Specifically, a source is subject to the BART requirement
if it came on-line after August 7, 1962 and construction commenced
prior to August 7, 1977.
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In addition to requirements for implementing BART on a source-by-
source basis, the 1999 rule provides States with an option of using an
emissions trading program or alternative measure in lieu of requiring
source-by-source BART. 40 CFR 51.308(e)(2). States may utilize this
trading or alternative option if they demonstrate that it would achieve
greater reasonable progress than source-by-source BART. To make this
demonstration, States would compare the estimated emissions reductions
available from requiring BART on all BART-eligible sources, and the
resulting degree of visibility improvement expected. Under the existing
section 308(e)(2) States would also have to ensure that the trading or
alternative measure applied to all BART-eligible sources in all 26
categories, within the State.\25\
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\25\ In section III.E.3 in this supplemental proposal, EPA is
proposing to amend section 308(e) to eliminate the requirement to
address all 26 categories simultaneously under specific conditions
relating to the proposed CAIR.
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In July 2001, we proposed guidelines for implementing BART on a
source-specific basis. These guidelines also contained guidance on how
to demonstrate that a proposed alternative to BART would result in
greater progress than source-specific BART. (66 FR 38108, Friday, July
20, 2001).
By notice dated May 5, 2004, we re-proposed the BART regulations
and guidelines, to comport with the court's findings regarding source-
specific BART. The portions of the BART guidelines related to
demonstrating that an alternative is better than BART are largely
unchanged from the 2001 proposal. (69 FR 25184, 25186).
2. What Is the Basis for This SNPR That the Cap-and-Trade Program is
``Better Than BART'' for Affected EGUs?
In today's SNPR, EPA proposes to apply the better-than-BART
requirements to the CAIR proposal, as it may affect the 29 States and
DC in the eastern part of the country. Specifically, EPA proposes that
BART-eligible EGUs in any State affected by CAIR may be exempted from
BART if that State complies with the CAIR requirements through adoption
of the CAIR cap-and-trade programs for SO2 and
NOX for affected EGUs.
a. Better-than-BART two-pronged test. In our recently re-proposed
Guidelines for BART Determinations, we propose a methodology for
determining whether a trading program will provide greater reasonable
progress than BART. If the geographic distribution of emissions
reductions is similar under either program a State may demonstrate the
trading program is better than BART by showing that the trading program
achieves greater emissions reductions than the source-specific BART
program. If it is expected that the trading program would result in a
different geographic distribution of emissions reductions than would
source-specific BART, visibility impacts must be assessed through a
two-pronged test. (69 FR 25184, 25231, May 5, 2004). Although under
CAIR the total emissions reductions are greater than source-specific
BART would achieve in the CAIR States, our modeling indicates that CAIR
would produce greater emissions reductions than BART in most States,
but lesser reductions in a few States. Because of this potential for a
different geographic distribution of emission reductions, we have
assessed the difference between the two programs under the two-pronged
visibility impact test.
The first prong is designed to address the ``prevention of any
future'' impairment element of the CAA section 169A(a)(1) national
visibility goal. Under this prong, visibility must not decline at any
Class I area, as determined by comparing the predicted visibility
impacts at each affected Class I area under the trading program with
existing visibility conditions. This prong also protects against the
creation of visibility impairment ``hot spots'' that could conceivably
occur as the result of local emissions increases under a trading
program.
The second prong of the test is designed to address the ``remedying
of any existing'' impairment element of the CAA section 169A(a)(1)
national visibility goal. Under this prong, at the end of the first
long-term strategy period in 2018, overall visibility, as measured by
the average improvement at all affected Class I areas, must be better
under the trading program than under source-specific BART.
We also note that the two-pronged test does not require that the
comparison be limited to BART-eligible sources affected by the
alternative-to-BART programs. In other words, one way the alternative
program may be better than source-specific BART is by controlling
emissions from non-BART eligible sources within the affected source
categories. This was the case in our approval of the WRAP Annex as
better than BART under Regional Haze Rule section 40 CFR 51.309. (See
68 FR 33769).
b. Application of the two-pronged test to the CAIR proposal. To
determine whether CAIR is better than BART, the analysis must address
the two main elements of the test. First, we compare the existing
visibility situation (using data from the baseline period 2000-2004) to
a future where CAIR is in effect to see if any degradation occurs.
Second, we compare the visibility
[[Page 32705]]
improvements resulting from the CAIR cap-and-trade program to
visibility improvements expected from the application of source-
specific BART in 2015, near the end of the first long-term strategy
period in 2018.
In applying the two prongs of the test, we faced some shortcomings
in currently available modeling. Under both prongs, we would ideally
perform air quality modeling for the situation where CAIR is in effect
only in the CAIR region, and source-specific BART is in effect in the
rest of the country. This would reflect the best currently available
prediction of future emissions, because BART is a federally enforceable
requirement of the CAA, and therefore appropriately assumed to be in
effect outside the CAIR region.\26\
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\26\ The existence of BART outside the CAIR region would also
mitigate concerns of emissions leakage caused by production and
emissions shifts from the CAIR region, which might occur if non-CAIR
States are subject to substantially less stringent requirements.
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However, the CAIR air quality modeling was based on the simplifying
assumption that SO2 emission reductions would be required
nationwide and did not include BART SO2 controls in place
for the non-CAIR region. Additionally, NOX was controlled in
a 31\1/2\ State region rather than the 29 State region that is covered
in the proposed CAIR.\27\ Finally, because the recently re-proposed
BART guidelines are applicable nationally, for that rulemaking we
estimated emissions after application of source-specific BART on a
nationwide basis. We therefore currently lack modeling of a scenario
where BART is applied only outside the CAIR region.
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\27\ The modeling assumed NOX reductions in 5 States
where they are not required (Maine, New Hampshire, Rhode Island and
Vermont). Additionally it does not require controls in Kansas and
the western half of Texas. Kansas and the all of Texas are covered
by CAIR.
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Despite these limitations in currently available modeling, we
believe the ideal scenario and the modeling we conducted using
available information are similar enough to serve as the basis of this
``better than BART'' determination. In fact, we anticipate that when we
model a scenario combining CAIR requirements in the CAIR region with
source-specific BART in the rest of the country, we will project fewer
SO2 and NOX emissions than our current modeling
indicates. The full rationale for this belief is given in a technical
support document (SAQMTSD)\28\. The remainder of this section gives a
brief overview of key aspects of the methodology we used and the
results.
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\28\ See ``Supplemental Air Quality Modeling Technical Support
Document for the Clean Air Interstate Rule (May 2004),'' available
in the docket.
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We used the Integrated Planning Model (IPM) to estimate emissions
expected after implementation of a source-specific BART approach and
after implementation of the CAIR cap-and-trade programs for EGUs. This
analysis indicates that implementing BART on a source-specific basis
would result in SO2 emissions falling to approximately 6.9
million tons nationally in 2015, then increasing, thereafter \29\.
Under the CAIR trading program, however, SO2 emissions in
2015 would fall to about 5.3 million tons nationwide, and would
continue declining to 4.3 million tons in 2020 \30\. Notably, CAIR
leads to SO2 emission reductions when it starts in 2007 that
grow over time. Nationwide, NOX emissions under a source-
specific BART approach would be reduced to 2.7 million tons per year in
2015 and do not decrease thereafter \31\, while under the proposed CAIR
trading program NOX emissions would be 2.2 million tons
nationwide in 2015 and 2.3 million tons in 2020.\32\ Notably,
substantial NO reductions actually begin in 2010 under the CAIR rule.
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\29\ As discussed in the SAQMTSD, the amount of SO2
emissions remaining after the application of BART on all BART-
eligible EGUs may be somewhat less than 6.9 million tons by 2015.
This is so because we modeled emissions reductions only for BART-
eligible EGUs over 250 MW and did not include BART-eligible EGUs
between 25 and 250 MW. We anticipate that even with any additional
SO2 reductions from these smaller EGUs the amount of
remaining SO2 emissions under the CAIR cap-and-trade
program will be sufficiently less than under BART to support our
proposed determination that CAIR provides greater visibility
improvement than BART for EGUs. We intend to do further analysis of
the effect of applying BART controls to EGUs between 25 and 250 MW.
\30\ Under the cap-and-trade program, SOX emissions
do not reach their minimum until after the 2015 Phase-2
implementation date because the availability of an existing title IV
allowance bank. Sources may use allowances from this bank to emit at
higher levels until sometime after 2020 when all of the banked
allowances have been used.
\31\ As in the case of SO2 emissions noted above, the
SAQMTSD explains that the application of BART on all BART-eligible
EGUs may result in somewhat fewer NOX emissions than 2.7
million tons by 2015, once emission reductions from BART-eligible
EGUs between 25-250 MW are considered. As with SO2, we
anticipate that CAIR would nonetheless provide greater
NOX emission reductions than BART, and we intend to do
further analysis of the effect of including BART-eligible EGUs
between 25-250 MW.
\32\ There is much less incentive to bank allowances under the
NOX program so the emissions caps should be met in 2015.
Since the emissions cap is not nationwide there is an increase in
NOX emissions in the non-affected States after 2015.
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We then used the REMSAD air quality model \33\ to project the
visibility impact of these IPM emissions predictions for both the CAIR
and the nationwide source-specific BART scenario. Specifically, EPA
evaluated the model results for the 20 percent best days (that is,
least visibility impaired) and the 20 percent worst days at 44 Class I
areas.\34\ These 44 areas are broadly representative of national
visibility conditions, as they are found in States throughout the
country, including California and Texas, States on the continental
divide, the Pacific Northwest, the Southwest, the Southeast, the Mid-
Atlantic, and New England. Thirteen of these Class I areas are within
States affected by the CAIR proposal, and 31 Class I areas are outside
the CAIR region--29 in States to the west of the proposed CAIR region,
and 2 in New England States northeast of the CAIR region. We also
modeled expected visibility for the future base case, which has lower
emissions than we have today overall (that is, we examined expected
emissions levels in 2015 without either BART or the trading program,
but including emissions reductions anticipated from other
requirements.) This is a more stringent way of considering degradation,
given we are primarily concerned about degradation relative to the
existing visibility situation.
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\33\ Changes in future visibility were predicted by using the
REMSAD model to generate relative visibility changes, then applying
those changes to measured current visibility data. Details of the
visibility modeling and calculations can be found in SAQMTSD.
\34\ Ambient PM2.5 data for the purposes of calculating
visibility degradation at Class I areas is collected by the IMPROVE
network. There are currently 110 IMPROVE monitoring sites operating
at Class I areas. For this analysis, future year visibility values
were calculated at the 44 IMPROVE sites which had complete data in
1996. Since the base year meteorology used in the REMSAD modeling is
from 1996, ambient data from 1996 is needed to be able to apply the
model results. It is necessary to know which days make up the 20
percent best and worst days so that the model outputs can be
calculated on the same days. For a Class I area without ambient data
in 1996, there is no way to match up the model predicted changes in
visibility with the ambient data from the 20 percent best and worst
days. There were only 44 IMPROVE sites (at Class I areas) with
complete data for 1996.
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i. First prong: Visibility will not decline at any class I area.
The modeling predicts that the CAIR cap-and-trade program will not
result in degradation of visibility, compared to existing visibility
conditions, at any of the 44 Class I areas considered. In each of the
44 areas--the 13 within the proposed CAIR region and the 31 outside of
it--visibility is expected to improve or at worst remain unchanged.
Details of these results, for the 20 percent worst days and the 20
percent best days are contained in SAQMTSD. We only had modeling
representing nationwide SO2 emission reductions, including
some
[[Page 32706]]
relatively small amount of SO2 emission reductions occurring
in the West \35\. Since the western SO2 emissions reductions
are relatively small, EPA believes they will not significantly impact
the conclusions of this analysis.
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\35\ Although the CAIR proposal would not include emissions
reductions requirements for western States, BART requirements will
otherwise apply in these States and achieve some level of
SO2 reductions.
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Based on these results and other analysis presented in the SAQMTSD,
we believe the CAIR impact on emissions passes the first prong of the
two-pronged test by not causing degradation of visibility at any Class
I area.
ii. Second prong: Average visibility for all affected Class I areas
will improve. The second prong of the better-than-BART test is to
analyze whether the CAIR cap-and-trade programs result in greater
overall improvement in visibility, as compared to source-specific BART.
For Class I areas in the proposed CAIR region, our analysis
indicates that proposed CAIR emissions reductions in the East produce
significantly greater visibility improvements than source-specific
BART. Specifically, for the 15 Eastern Class I areas analyzed, the
average visibility improvement (on the 20 percent worst days) expected
solely as a result of the CAIR is 2.0 deciviews (dv), and the average
degree of improvement predicted for source-specific BART is 1.0 dv.
Therefore, the proposed CAIR is substantially better than BART--indeed,
the proposed CAIR provides more than twice the visibility improvement
benefits--for Eastern Class I areas.\36\
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\36\ We note that the modeling we used to represent the CAIR
proposal was more stringent than the proposed CAIR in some ways
(because it assumed SO2 reductions in the West and
NOX reductions in the Northeast, which the proposed CAIR
does not require) and less stringent in others (because it does not
include NOX controls for Kansas and western Texas, which
are required in the proposed CAIR). As explained in the SAQMTSD, we
anticipate that these differences are either too small to affect the
analysis, or are mitigated by the fact that source-specific BART
will produce SO2 and NOX reductions in the
non-CAIR States in which our modeling attributed emissions
reductions to CAIR. Therefore, we believe that the air quality
modeling supports our better-than-BART determination.
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Similarly, on a national basis, the visibility modeling shows that
for the 44 class I areas evaluated, the average visibility improvement,
on the 20 percent worst days, in 2015 was 0.7 dv under the proposed
CAIR cap-and-trade programs, but only 0.4 dv under the source-specific
BART approach.
We therefore believe that these results, in combination with the
other analysis in the SAQMTSD, demonstrate that the second prong of the
better-than-BART test is met.
Because both prongs of the test are met, EPA proposes to conclude
that the proposed CAIR cap-and-trade program is better than BART for
BART eligible EGUs within the proposed CAIR region. Therefore, States
that adopt the model cap-and-trade programs would not be required to
implement source-specific BART for their EGUs.
3. What Changes to the Regional Haze Rule Provisions for Alternatives
to BART Are Proposed?
The preceding discussion applied the provisions of section 40 CFR
51.308(e)(2) of the Regional Haze Rule which allows States to determine
that a trading program or other alternative measure may be substituted
for individual BART applications for all sources subject to the BART
requirement.
Because the proposed CAIR allows States to choose how to achieve
the required emissions reductions, and does not mandate participation
in the EPA-administered cap-and-trade program for EGUs, some States may
wish to satisfy their proposed CAIR requirements through controls on
sources other than EGUs, or through controls on EGUs without using the
CAIR cap-and-trade programs (such as through an in-State only trading
program). To the extent that these control obligations fall on BART-
eligible sources, the State may wish to demonstrate that these controls
are better than BART, and therefore satisfy the source-specific BART
requirements for those sources.
To accommodate the various approaches States may wish to take in
complying with the proposed CAIR and making the better-than-BART
determinations, we propose to add a new section to the alternative-to-
BART provisions of the Regional Haze Rule. We are not proposing to
change or revise the provisions contained in section 308(e)(2), which
apply to States that develop their own cap-and-trade program or other
alternative measure to BART. Therefore, we are retaining 308(e)(2)
without revision, except for the addition of a proposed cross-reference
to the new provision for these BART-alternative rules proposed today.
Section 308(e)(2) will continue to apply to trading programs or other
alternatives to BART which do not involve the proposed CAIR cap-and-
trade programs. These might include in-State only trading programs, or
future regional trading programs developed by States and tribes through
Regional Planning Organizations.
We propose to add a new section 308(e)(3), which provides that for
any of the 29 States and DC in the CAIR region, implementation of the
CAIR cap-and-trade programs to fulfill the proposed State emissions
reduction obligations under the CAIR qualifies as a ``better than
BART'' alternative. This alternative is available only to States that
subject all of their EGUs to the cap-and-trade programs. As explained
above, modeling to support the proposed determination establishes that
the cap-and-trade programs would result in greater reasonable progress
than would source-specific BART for EGUs. Therefore, a better-than-BART
demonstration would not be required of States that choose this option.
We also propose to renumber current sections 308(e)(3) and (4) to
read 308(e)(4) and (5), respectively. These sections provide for
continuing regulation of BART-eligible sources under the general
regional haze provisions after BART is satisfied, and for source-
specific exemptions from the Administrator.
4. What Effect Does the CAIR Cap-and-Trade Program Have on Source-
specific BART Based on Reasonably Attributable Visibility Impairment?
As we explained in our recent re-proposal of the BART guidelines
(69 FR 25184, May 5, 2004), when a State utilizes an alternative
measure such as an emissions trading program in lieu of requiring BART
on specific sources, the requirement for BART is not satisfied until
the alternative measure reduces emissions sufficiently to make ``more
reasonable progress than BART.'' Thus, in that period between
implementation of an emissions trading program and the satisfaction of
the overall BART requirement, an individual source could be required to
install BART for reasonably attributable impairment under 40 CFR
51.302. The Regional Haze Rule contains a provision allowing for
``geographic enhancements'' to address the interface between a regional
trading program and the requirement under 40 CFR 51.302 regarding BART
for reasonably attributable visibility impairment. (See 40 CFR
51.308(e)(2)(v)).
We note that the same framework applies in the context of the
proposed CAIR cap-and-trade programs. That is, until the emissions
reductions requirements in today's SNPR are fully implemented in 2015,
the possibility exists that a certification of impairment by a Federal
Land Manager (FLM) could trigger a requirement for a State to determine
whether the impairment is ``reasonably attributable'' to a single
[[Page 32707]]
source or small group of sources, and if so to make a source-specific
BART determination. We request comments on whether a ``geographic
enhancement'' (for example, an adjustment to the State's allowance
budget) would be appropriate, and whether such enhancement mechanisms
should be determined by EPA on a national basis, or individually by
affected States.
We also note that the WRAP, as part of its voluntary emissions
milestones and backstop SO2 cap-and-trade program under
Regional Haze Rule section 309 has adopted policies which target use of
the Sec. 51.302 provisions by the FLMs. In this case, for the five
States in the WRAP program, the FLMs have agreed that they will certify
reasonable attributable impairment only under certain specific
conditions. Under this approach, the FLMs would certify under 40 CFR
51.302 only if the regional trading program is not decreasing or has
not decreased sulfate concentrations in a Class I area within the
region. Moreover, the FLMs will certify impairment under 40 CFR 51.302
only where: (1) BART-eligible sources are located ``near'' that class I
area and (2) those sources have not implemented BART controls. In
addition, the WRAP is investigating other procedures for States to
follow in responding to a certification of reasonably attributable
impairment if an emissions trading approach is adopted to address the
BART requirement based on the sources' impact on regional haze.
We request comment on whether such an approach would be appropriate
for the proposed CAIR cap-and-trade programs.
F. Tribal Issues
As discussed in our January 2004 proposal, tribal implementation of
approved CAA programs is optional. That is, under CAA section 301(d) as
implemented by the Tribal Authority Rule (TAR), eligible Indian tribes
may implement all, but are not required to implement any, programs
under the CAA for which EPA has determined that it is appropriate to
treat tribes similarly to States. Tribes may also implement
``reasonably severable'' elements of programs. (40 CFR 49.7(c)). In the
absence of tribal implementation of a CAA program or programs, EPA will
utilize Federal implementation for the relevant area of Indian country
as necessary or appropriate to protect air quality, in consultation
with the tribal government. State implementation plans are generally
not applicable in Indian country.
With very few exceptions, Indian country is not home to the types
of air pollution sources potentially affected by this rule--neither
EGUs, nor other large sources of NOX or SO2 that
could be controlled in order to meet emission reduction requirements.
Despite these legal and factual considerations which indicate that
today's proposal would not generally immediately affect tribes, tribes
have raised valid concerns about the rule's future implications. These
implications arise from the fact that the cap-and-trade program by
definition is designed to cap emissions over a broad geographic area
and constrain these emissions into the future. Indian country lands are
included within these broad areas. Some tribes may choose to pursue a
path of economic development which may include future sources of air
pollution.
The TAR contains a list of provisions for which it is not
appropriate to treat tribes in the same manner as States. 40 CFR 49.4.
The CAIR proposal is based on the States' obligations under CAA
110(a)(2)(D) to prohibit emissions which would contribute significantly
to non-attainment in other States due to pollution transport. Because
CAA 110(a)(2)(D) is not among the provisions we determined to be not
appropriate to apply to tribes in the same manner as States, the CAIR
is applicable to tribes. However, among the CAA provisions not
appropriate for tribes are ``[s]pecific plan submittal and
implementation deadlines for NAAQS-related requirements * * *'' 40 CFR
49.4(a). Therefore, tribes are not required to submit implementation
plans under the CAIR. Instead, the CAIR will be implemented as
necessary or appropriate in Indian country, either through voluntary
Tribal Implementation Plans or Federal Implementation Plans developed
in consultation with affected tribes.
The EPA believes new sources that locate in Indian country should
be subject to the program in the same manner as any new source located
outside of Indian country. If they were not, emissions from new Indian
country sources could jeopardize the environmental goals of PM2.5 and
ozone attainment on which today's rule is based. It could also
conceivably result in undue pressure for energy and economic
development in Indian country, depending on allowances, prices and a
variety of other economic and regulatory factors.
At the same time, some tribal representatives have voiced another
set of concerns to EPA. In their view, requiring new sources in Indian
country (which may be tribally owned) to either obtain an allocation of
allowances from the State where the tribe is located, or to purchase
allowances in order to operate is unfair, for several reasons. These
include: (1) That the concept that budgets for Indian country should be
derivative from State budgets may offend notions of tribal sovereignty
and autonomy; (2) that Federal policy over the course of U.S. history
has hindered tribal economic development and this inequity should not
be continued by basing allocations on existing source emissions; (3)
that some of the tribes that have contributed substantially to the
economy through extractive industries have not shared in the economic
benefits, including residential electrification; and (4) that Indian
country areas may have suffered the detrimental effects of air
pollution from the sources from which they would be required to buy
allowances in order to construct new sources.
One approach that might be used to address these concerns would be
to develop a Federal set-aside of allowances for new sources in Indian
country. The WRAP, in developing a backstop cap-and-trade program for
SO2 under section 40 CFR 51.309 of the Regional Haze Rule,
addressed this same set of concerns. The WRAP is a unique partnership
of 13 western States, tribes, and Federal agencies. The WRAP Board
comprises equal numbers of State governors and tribal leaders, or their
designees, and decisions are made by consensus.
Based on tribal input, the WRAP included provisions to address the
tribal concerns delineated above including a tribal set-aside of 20,000
tons of SO2 per year. This amount was not the product of any
single formula, but was negotiated within the WRAP based on a number of
factors. One important consideration was that because new EGUs and
other major sources would be subject to pre-construction permitting
under New Source Review (NSR) or Prevention of Significant
Deterioration (PSD) rules, as well as New Source Performance Standards
(NSPS) or Maximum Achievable Control Technology (MACT), SO2
emissions per MW or other unit of production would be considerably
lower than for older, less efficient plants. Therefore, although 20,000
tons represents only about 4 percent of the 9-State cap for 2018, it
would enable the installation of a much larger percentage of new
capacity.
The WRAP's cap-and-trade program will only come into existence if
voluntary efforts and current requirements fail to meet the agreed upon
emissions reduction ``milestones.'' Therefore, the tribal set-aside,
like all tradable allowances under this program,
[[Page 32708]]
will only exist if the milestones are not met sometime between 2003 and
the end of the first long-term strategy period in 2018. In light of the
uncertainty of this event, and of the difficulty of reaching consensus
among the more than 200 tribes in the affected region, the WRAP did not
attempt to establish the mechanism by which the tribal set-aside would
be allocated among tribes. Rather, it was agreed that this mechanism
would be determined within one year of the date the trading program was
triggered, by a determination that the milestones had been exceeded.
This would provide for the distribution of all allowances by the time
of trading program implementation.
Tribal participants in the WRAP stipulated that the tribal set-
aside allocations would be available to tribes for use by new sources,
for sale to generate revenue, or to retire for the benefit of the
environment. The EPA concurred with these uses in the preamble to the
final WRAP Annex rule (68 FR 33778, June 5, 2003). We also agreed that
tribal participation in the Annex, including the tribal set-aside, is
not dependent on whether the State in which the tribe is located
participates. For the few sources currently in existence in Indian
country within the WRAP region which are eligible for the program based
on SO2 emissions, the WRAP would provide for allowance
allocations within the existing-source cap. These sources would not
need to draw upon the tribal set-aside for the allowances to cover
their emissions.
There are no emission sources in Indian country of which we are
aware in the 29-State region that could be affected by the January 2004
proposal. (We request comment regarding the existence of any such
sources of which we are unaware). Therefore, the only way tribes in
this region could receive allowances would be through a set-aside.
The approach used by the WRAP could provide a template for the CAIR
for both SO2 and COX set-asides for tribes. This
would raise a number of issues, some identical to those faced by the
WRAP and some with different considerations. For example, one
difference is that because the CAIR is not a backstop cap-and-trade
program, any allowance set-aside for tribes would either result in a
corresponding decrease in the present allowances of existing sources,
or increase the overall level of the cap.
The WRAP example of establishing a tribal set-aside provides one
possible approach to addressing tribal concerns. If EPA were to
determine that a tribal set-aside were appropriate, some issues raised
in developing the set-aside would include: (1) What method to use to
determine the SO2 and NOX set-asides, for example
through negotiation or by a formula, (2) whether the set-aside would be
in addition to or part of the allocations proposed in our January 2004
proposal, and (3) how the tribal set-aside would be allocated or
distributed among tribes, for example on a first-come first-served
basis, by an allocation formula, or some combination of approaches.
We seek comment on whether a tribal set-aside is necessary or
appropriate; if so, how it should be structured; whether other
approaches might better address the tribal concerns identified above.
We also seek comment on any other implications the proposed CAIR may
have for tribes. We remain committed to fulfilling our obligation to
consult with tribes, and will continue to do so as we address these
issues.
IV. Model Cap-and-Trade Rule
A. Background and Purpose of the Model Rules
This section of today's action proposes model trading rules--one
for SO2 and one for NOX--that States will adopt
if they wish to participate in the EPA-managed, EGU cap-and-trade
program to achieve the emissions reductions of the proposed CAIR. This
fulfills the commitment made in the January 2004 proposal.
Today's action proposes a NOX and a SO2 model
cap-and-trade rule for public comment. At the time of signature of
today's SNPR, EPA had not yet reviewed full public comment on the
January 2004 proposal, which solicited comment on some model rule
concepts. The EPA intends to respond to comments received on the
January 2004 proposal and today's SNPR when it promulgates the final
rule.
The NOX and SO2 model rules incorporate the
experience gained through the implementation of several cap-and-trade
programs (i.e., the CAA title IV SO2 Acid Rain Program, the
Ozone Transport Commission Regional NOX Program, and the
NOX SIP Call), lessons learned from other trading programs
like the Regional Clean Air Incentives Market (RECLAIM), as well as two
workshops which EPA held to inform this rulemaking. These workshops,
held in July and August of 2003, provided a forum for States and multi-
State air planning organizations to share with EPA what has worked
well, what may not have worked well, and what could be improved. (The
EPA Web site provides a summary of the comments received from these
workshops at http://www.epa.gov/airmarkets/business/noxsip/atlanta/atl03.html
). Workshops such as these played an important role in the
development and implementation of the NOX SIP Call and aided
in the development of this proposed rule.
This section describes: The advantages of adopting the model
trading rules; the requirements for those who choose to adopt the model
rules; the flexibility that States have in developing their cap-and-
trade rules; and, lastly, a subpart-by-subpart explanation of the model
rule provisions that highlights key elements and aspects unique to
either the SO2 or NOX programs.
1. Who May Adopt the Model Rules and What Are the Advantages of
Adopting New Model Rules?
States may choose to participate in the EPA-managed cap-and-trade
programs, which are a fully approvable control strategy for achieving
all of the emissions reductions required under today's proposed
rulemaking, in order to achieve the mandated emission reductions in a
highly cost-effective manner. States that wish to reduce emissions by
controlling EGUs (which modeling shows can make additional highly cost-
effective emission reductions) through a regionwide cap-and-trade
approach may simply adopt the model rules and comply with the
requirements for Statewide budget demonstrations detailed in section
III. States that elect to achieve the required reductions by regulating
other sources or using other approaches, should refer to section III
for alternate State requirements.
Today's action proposes that States that choose to achieve the
mandated emission reductions through the EPA-managed cap-and-trade
programs are also required to adopt both the SO2 and
NOX model rules. Requiring States to participate in both the
SO2 and NOX programs assures that compliance is
more readily determinable, and creates incentives for sources to
develop comprehensive control strategies for both pollutants.\37\
---------------------------------------------------------------------------
\37\ Note that under the proposed CAIR, because Connecticut is
only required to reduce NOX emissions in the summertime
to address its impact on downwind 8-hour ozone nonattainment areas,
Connecticut would not be required to adopt the CAIR NOX
model rule--which focuses on annual NOX reductions--
unless the State volunteers to make annual NOX
reductions.
---------------------------------------------------------------------------
[[Page 32709]]
Advantages of Adopting the Model Rules
EPA is proposing the use of regionwide cap-and-trade programs
because market-based approaches have proven to be both environmentally
effective and cost-effective. The advantages of a well-designed cap-
and-trade system include:
Control of emissions to desired levels under a fixed cap
that is not compromised by future growth;
High compliance rates;
Lower cost of compliance for individual sources and the
regulated community as a whole;
Incentives for early emissions reductions;
Promotion of innovative compliance solutions and continued
evolution of electricity generation and pollution control technology;
Flexibility for the regulated community (without resorting
to waivers, exemptions and other forms of administrative relief that
can delay emissions reductions);
Direct legal accountability by sources for compliance;
Coordinated program implementation that efficiently
applies administrative resources while enhancing compliance; and
Transparent, complete, and accurate recording of
emissions.
These benefits result primarily from the interplay of a rigorous
cap-and-trade framework, flexibility in compliance options, and the
monetary incentives associated with avoided emissions in a market-based
system. The model rules are designed around elements that are essential
to a successful cap-and-trade program. These include:
Simplicity (e.g., clear applicability thresholds,
allocation formulas, trading rules and restrictions, measurement
options and procedure, reporting requirements, and penalty assessment);
Accountability (e.g., accurate measurement of emissions,
complete and timely emission reporting, and automatic penalties for
noncompliance);
Transparency (e.g., full and open disclosure of
programmatic elements, compliance data, allowance ownership, and
environmental progress); and
Predictability and Consistency (e.g., to provide
consistent program implementation over time and a long compliance
planning horizon that allows long-term, innovative strategies).
States collectively benefit from the adoption of the model rules by
improving the efficiency and clarity of the CAIR's implementation.
In addition, States adopting the CAIR NOX and
SO2 model rules will benefit from improvements to the rule
mechanics that originated from the stakeholder input during the
implementation of the Title IV, OTC, and NOX SIP Call cap-
and-trade programs, as well as the EPA-managed ``lessons learned''
workshops held in 2003. Today's proposed NOX and
SO2 model rules not only incorporate these refinements, but
are designed to parallel the existing rules in parts 96 and 97 (see
sections IV.A.4 and IV.B below) to allow States that have already
codified all or part of these regulations to transition smoothly into
both the CAIR NOX and SO2 programs.
2. Requirements for Adopting the Model Cap-and-Trade Rules
Except as noted in section IV.A.3, States that choose to
participate in the EPA-managed cap-and-trade programs must adopt the
complete model cap-and-trade rules in order to participate in the
program and to have it constitute an approvable remedy for achieving
the mandated SO2 and NOX emission reductions.
(Section III discusses the requirements for States, including those
that wish to comply with the CAIR through alternatives other than the
EGU-based emission reduction approach proposed in today's action.) This
ensures that all participating sources, regardless of which State in
the CAIR region they are located, are subject to the same rules.
Further, requiring States to use the complete model rules provides for
accurate and certain quantification of emissions, which are--when
reflected in allowances--a valuable commodity on the trading market,
and thereby maintains the financial integrity of the allowance trading
market. In turn, the integrity of this emissions measurement system and
the trading market ensures that the environmental goals are met.
States are required to achieve all of the mandated emissions
reductions from large EGUs if they wish to participate in the EPA-
managed cap-and-trade programs. (In other words, States that achieve
all or part of the emissions reductions from large non-EGUs, may not
participate in the EPA-managed cap-and-trade programs.) More
specifically, the rules must apply to all fossil fuel-fired boilers and
turbines serving an electrical generator with a nameplate capacity
greater than 25MW and producing electricity for sale (except for
certain cogeneration units). All units that meet this generation size
threshold would be affected by the proposed CAIR with no exemptions for
small, low-emitting units. (The EPA is not proposing an exemption for
units that meet the generation applicability threshold but emit less
than 25 tons of NOX, as done in the NOX SIP
Call.) The EPA anticipates that these small, low-emitting units will
take advantage of special monitoring and reporting procedures in part
75 that simplify the requirements for low mass emitting (``LME'')
units. In general, these procedures relieve much of the administrative
burden and, therefore, compliance costs, for LME units by allowing them
to use conservative emissions estimates in lieu of continuous emissions
monitoring. In providing streamlined monitoring and reporting options,
EPA can accurately and cost-effectively account for the emissions, even
at low emission levels, and allow them to participate in the cap-and-
trade programs.
Sources that produce usable thermal energy, such as steam, in
addition to generating electricity are known as ``cogeneration units.''
Only a cogeneration unit that (i) serves a generator greater than 25
MW, (ii) sells at least \1/3\ of its potential electrical output
capacity and at least 25 MW of electricity, and (iii) meets certain
operating and efficiency criteria is considered an EGU and covered by
the EPA-managed cap-and-trade programs. (See section IV.B.1 for a
proposed clarification to the definition of a cogeneration unit.)
Once a unit is classified as an EGU for purposes of this rule, the
unit will remain classified as an EGU regardless of any future
modifications to the unit. If a unit serving a generator that initially
does not qualify as an EGU (based on the nameplate capacity) is later
modified to increase the capacity of the generator to the extent that
the unit meets the definition of EGU, this unit will become an EGU for
purposes of this rule. This approach is proposed to prevent avoidance
of regulation by initially constructing units that are below the size
threshold, and then upgrading above the size criteria.
3. Flexibility in Adopting the Model Cap-and-Trade Rules
It is important to have consistency from State-to-State when
implementing a multi-State cap-and-trade program to ensure that the
intended emissions reductions are achieved and that the compliance and
administrative costs are minimized. However, EPA believes that some
differences, such as allowance allocation methodologies for
NOX allowances, are possible without jeopardizing the
environmental goals of the program.
a. Allocation of NOX and SO2 allowances. Each
State participating in the EPA-managed cap-and-trade
[[Page 32710]]
programs must develop a method for allocating, or distributing, (to the
extent that the State has allowances available to allocate)
NOX allowances equal to its CAIR EGU budget. For
NOX allowances, States have the flexibility to allocate
their EGU NOX budget to individual units however they
choose. For SO2, as noted in the approach outlined in the
January 2004 proposal, States do not have discretion in their
allocation approach since the proposal relies on title IV
SO2 allowances which have been already allocated in
perpetuity to individual units by title IV of the CAA. Today's action
proposes essential elements that would be required for each State's
NOX allocation method (e.g., the deadlines by which each
State must complete and submit to EPA their unit-by-unit allocations
for inclusion into the electronic data systems), describes areas in
which States have flexibility, and provides an example allocation
approach.
i. Aspects unique to SO2 allowance allocations. The CAIR
SO2 allocations differ from the NOX approach
because the title IV SO2 allowances--the proposed basis for
the CAIR--have already been allocated in perpetuity to specific units.
Only units that were listed or described in the 1990 CAA Amendments are
allocated allowances. Some units that are currently affected by the
today's proposed rule title IV Acid Rain Program are not allocated
title IV SO2 allowances and instead must acquire all of the
allowances they need in the marketplace.
ii. Required aspects of a State allocation approach. While it is
EPA's intent to provide States with as much flexibility as possible in
developing allocation approaches, there are some aspects of State
allocations that must be consistent for all States. Today's SNPR
proposes that all State allocation systems are required to include
specific provisions that establish when States notify EPA and sources
of the unit-by-unit allocations. These provisions would create: (1) The
minimum lead-time for a State to notify a source of its allocations;
and (2) the deadline for each State to submit to EPA its unit-by-unit
allocations for processing into the electronic data systems.
Today's action proposes to require States to submit unit-by-unit
allocations no less than 3 years prior to January 1 of the allowance
vintage year. Requiring States to provide a minimum amount of
notification ensures that an affected source--regardless of the State
in the CAIR region in which the unit is located--would have sufficient
time to plan for compliance. Finalizing allowance allocations less than
3 years in advance of the compliance year may reduce a CAIR unit's
ability to plan for compliance and, consequently, increase compliance
costs. Shorter notification periods may also prevent CAIR units from
participating in allowance futures markets, a mechanism for hedging
risk and lowering costs. (Note: New units will not have allowances 3
years in advance of their first year of operation.) In addition, States
would be required to submit the unit-by-unit allocations to EPA by a
specific date for sources in their State. This allows EPA to
efficiently administer the program and ensure a fair and competitive
market for allowances across the region.
These minimum requirements would apply to the NOX
allocation approach and would not be relevant for SO2, which
relies on title IV allowances.
iii. Flexibility and options for a state allowance allocations
approach. Allowance allocation decisions in a cap-and-trade program are
largely distributional issues, as economic forces would be expected to
result in economically efficient and environmentally similar outcomes.
Consequently, for CAIR NOX allowances, States would be given
latitude in developing their allocation approach. Allocation
methodology elements for which States will have flexibility include:
The cost of the allowance distribution (e.g., free
distribution or auction);
The frequency of allocations (e.g., permanent or
periodically updated);
The basis for distributing the allowances (e.g., actual
heat-input or actual power output); and,
The use of allowance set-asides (e.g., new unit set-asides
or energy efficiency set-asides).
These points are discussed immediately below.
Cost of Allowance Distribution
Allowances may be distributed by either providing them at no cost
(i.e., a ``free distribution''), offering them for sale to bidders
(i.e., an ``auction''), or some combination of the two. Today's
proposal allows the State to decide which approach is best for their
circumstances.
Auctions: In general, auctions ensure all parties, including the
general public, have access to allowances and are considered to be
economically efficient since sources would bid their perceived values
for allowances. It is possible to auction all allowances under a cap,
or have a hybrid approach that auctions some portion of the pool that
could change over time. The title IV Acid Rain Program is an example of
a hybrid in that it reserves 2.8 percent of available allowances for an
auction and distributes the remainder for free. Auctions may also vary
in the frequency with which they are held. Strict procedures must be
established for auctions and, in the context of the proposed CAIR,
States would be responsible for implementing these rules. Allowance
auctions are typically, but are not required to be, open to any person,
including sources or third-party entities, that can comply with the
auction protocols. (In general, auction protocols establish key
procedures for bidding, the bidding schedule, a bidding mechanism, and
requirements for financial guarantees.)
Auctions treat existing and new sources in a similar fashion.
Sources performing costly retrofits to reduce emissions would then also
have to pay for allowances for their remaining emissions. Some other
benefits of auctions include the fact that they eliminate the permanent
right to emit and can provide distortion-free revenues to States.
Free Distribution: A free distribution system provides allowances
to any entity, typically the affected sources, as determined by the
State. When using a free distribution, it is necessary to establish
both (1) the basis for determining each unit's share of the allowance
pool, and (2) the frequency with which the allowances are allocated.
The title IV Acid Rain Program is an example of a free, one-time
distribution (with a small percentage reserved for auction, as
mentioned above) that uses the product of historical heat input and
specified emission rates (i.e., a permanent, heat input-based system)
to determine each unit's share of the pool.
Allocating allowances for free could lessen the financial impact of
the program on the affected sources which already bear the compliance
costs, but would not be expected to affect the sources' output
decisions, or labor and pricing decisions. It would also give States
the ability to determine the initial allowance recipients.
Frequency of Allocating Allowances
Allowances may be allocated once (i.e., a ``permanent'' allocation)
or periodically recalculated (i.e., ``updated'') based upon some
protocol. When deciding upon the frequency of the allocations, any of
the options concerning the cost of distribution and the basis for
apportioning the pool may be used. However, it is important to consider
the practical implications of using complex protocols, such as data
that must undergo time-consuming
[[Page 32711]]
quality assurance, when frequently updating.
Permanent Systems: Permanent systems allocate all of the allowances
at the beginning of the program. They provide long planning horizons
for affected sources that receive an allocation.
Permanent allocations do not create additional incentives for those
units that receive allowances to change their future behavior to garner
more allowances (e.g., increase utilization). Furthermore, because
permanent systems are based on a historic baseline, they would not
reflect changes in the industry going forward. For instance, retired
units would continue receiving allowances. Additionally, a pure
permanent allocation system would not provide for allowances to new
affected units that begin operations after the allocation of allowances
and instead would require them to obtain allowances from the market.
The title IV Acid Rain Program is an example of a primarily permanent
approach that auctioned 2.8 percent of the allowances to provide new
sources an additional mechanism for obtaining allowances.
Updating Systems: Updating systems periodically recalculate and
reallocate allowances. These include: The ability to reflect future
changes in the power sector; the ability to impact the future
generation mix; and, an inherent mechanism for new generators to gain
access to free allowances. An updating system that bases the allowance
distribution on power output provides an additional incentive beyond
the inherent reward for efficiency provided by the market for existing
units to improve their generation efficiency and for new units to
employ the most efficient technology available.
Updating methods may provide a slight subsidy for units to either
generate (for output-based systems) or consume more fuel (for input-
based systems). Should this potential subsidy result in an increase in
electricity production, there would be a corresponding slight
distortion (lowering) of the price of electricity as well as an
incentive for older units to continue generating. (Note that under a
capped program, incentives to generate will not impact the total
emissions of the capped pollutants.)
There are additional aspects of the allocation frequency that are
significant in an updating system. These include:
The length of the period for which allocations are
determined (e.g., the allocations may be calculated for one year or for
5 years at a time); and
The length of the notification time (e.g., allocations are
determined and announced 3 years into the future, 5 years into the
future).
In general, the longer the allocation period (i.e., the less
frequent the updating), the more the system will resemble a permanent
approach.
Allowance Set-Asides
Allocation methodologies may include a reserve of a certain number
allowances from within the cap to create a ``set-aside'' of allowances.
This reduces the number of allowances available to the existing
affected sources. Set-asides may be used for a variety of purposes
including encouraging certain behaviors (e.g., demand-side energy
efficiency and renewable energy set-asides) and mitigating potential
disadvantages in the marketplace (e.g., auction set-asides or, as
discussed below, set-asides available to units that come online after
the program implementation date). In the context of the proposed CAIR,
States (if they choose to have set-asides) would be responsible for
developing and implementing protocols to distribute set-asides. Set-
asides may have provisions that distribute unused allowances back to
affected sources should the set-asides not be fully utilized.
New unit set-asides create a pool of allowances that are available
to units that come online after the allowances have been allocated.
This may mitigate potential barriers to entering the market for new
units. Should a new unit be included in an allocation approach, it is
necessary to determine how the allowances will be distributed to the
new units from the pool. Common approaches include basing each unit's
share on either heat input or power output. Depending upon the type of
performance measurement used, slightly different incentives may be
created. For example, if the new unit's power output were used to
distribute the set-aside, sources would find an additional incentive--
beyond the incentive for efficiency inherent in the market--to employ
more efficient generation technology. (Note that the allocation example
provided below includes a new unit set-aside with a hybrid input/output
distribution metric.)
Basis for Determining Share of Allowance Pool
For any allocation option, other than an allowance auction, it is
necessary to establish the primary parameter that will be used to
determine each unit's share of the allowance pool. This parameter is
typically a performance measure such as:
Measured or potential emissions (in tons ) from the unit;
Historical or current measured heat input (in mmBtu) of the
unit; or
Measured or potential production output (in terms of
electricity generation and/or steam energy) of the unit.
Any of these parameters may be used to distribute allowances,
regardless of whether it is a permanent or updated system. Other
factors, such as fuel type or emission rates (e.g., pounds of pollutant
per mmBtu heat input or pounds of pollutant per MWhr of power output)
may be used with the above parameters. As mentioned earlier in this
discussion of allocation options, the choice of the parameter for
distributing allowances can influence the behavior of affected sources
in an updating system.
iv. Example allowance allocation system. Included below is an
example (offered for informational guidance) of an allocation
methodology that includes allowances for new generation and is
administratively straightforward. The method involves input-based
allocations for existing fossil units, with updating to take into
account new generation on a modified output basis. This methodology is
offered as an example, as individual States would make their own choice
regarding what type of allocation method to adopt for NOX
allowances.
Initial allocations for existing sources could be made for the
first control periods at the start of the program on the basis of heat
input. After the first 5 years, the budget would be distributed on an
annual basis, taking into account data from new units.
As new units enter into service and establish a baseline, they
begin to pick up allowances in proportion to their share of the
generation. Allowances allocated to existing plants slowly decline as
their share of total heat input decreases with the entry of new plants.
In this EPA example methodology, existing units as a group would not
update their heat input. This would eliminate the potential for a
generation subsidy (and efficiency loss) as well as any potential
incentive for less efficient units to generate more. This methodology
would also be easier to implement since it would not require the
updating of existing units' baseline data. Retired units would continue
to receive allowances indefinitely, thereby creating an incentive to
retire less efficient units.
Through this EPA example methodology, new units as a group would
only update their heat input
[[Page 32712]]
numbers once--in the initial baseline period when they start operating.
This would eliminate any potential generation subsidy and be easier to
implement, since it would not require the collection and processing of
data needed for regular updating.
The EPA believes that allocating based on heat input data (rather
than output data) for existing units is desirable because accurate
protocols exist for monitoring this data and reporting it to EPA, and
several years of certified data are available for most of the affected
sources. This heat input data for existing units could be adjusted by
multiplying it by different factors based on fuel-type, reflecting the
inherent higher emissions of coal-fired plants. For example, factors
could be calculated based on average historic NOX emissions
rates by fuel type (i.e., coal, gas and oil) throughout the proposed
CAIR region for the years 1999-2002 at 1.0 for coal, 0.4 for gas and
0.6 for oil.
However, allocating on the basis of input for new sources would
serve to subsidize less-efficient new generation. For a given
generation capacity, the most efficient unit would have the lowest fuel
input or heat input. Allocating to new units based on heat input may
encourage the building of less efficient units since they would get
more allowances than an efficient, lower heat input unit. The modified
output approach, as described below, would encourage new, clean
generation and would not reward inefficient or higher emitting new
units.
Allowances would be allocated to new units on a ``modified output''
basis. The new unit's modified output would be calculated by
multiplying its gross output by a heat rate conversion factor of 8,000
btu/kWh. The 8,000 btu/kWh value for the conversion factor is a mid-
point between expected heat-rates for new gas-fired combined cycle
plants, new pulverized coal plants, and new IGCC coal plants (based
upon assumptions in EPA's economic modeling analysis. See documentation
for IPM at http://www.epa.gov/airmarkets/epa-ipm/attachment-h.pdf). In
addition, this would create consistent incentives for efficient
generation (rather than favoring new units with higher heat-rates). For
new cogeneration units, their share of the allowances would be
calculated by multiplying (1) the sum of their electric output and one
half of their equivalent electrical output energy for the unit's
process steam, times (2) 8,000 btu/kWh conversion factor.
Five years after entering the CAIR cap-and-trade programs, new
units would be incorporated into the calculations for allocations to
all affected units. After 5 years of participating in the cap-and-trade
programs, new units would have an adequate operating baseline of heat
input data. The average of the highest 3 years from these 5 years would
be used to calculate the heat input value that the new unit would use
to receive allowances from the pool of allowances for all sources.
In this example, only fossil units would be included in the
updating process. This is administratively more straightforward and
would comprise the vast majority of expected new generation.
Alternately, all new generating units could be included in the updating
process, which would provide incentives for all new generation (such as
renewables, hydro, nuclear). To include such non-fossil units as part
of the program would involve clearly defining the entities which could
participate (e.g., application procedures, size requirements, and
boundaries of included generation, since there is no clear analog to
discrete fossil ``units'').
New units that have entered service, but have not yet established a
baseline output and have not yet started receiving allowances through
the update, could receive allowances each year from a new source set-
aside. In this example methodology, EPA has described a new source set-
aside representing 2 percent of the State's emission budget.
Allowances in the new source set-aside could be distributed in a
number of different ways. For example, as described in today's proposed
model rules, the new source allowances could be distributed based on a
unit's utilization/output and the unit's NSPS rate limitation as
proposed in the Clear Skies Act of 2003. Because the proposed NSPS
rates vary across fuel types, this allocation method could provide new
plant investors with varying incentives depending upon the fuel type.
While this set-aside would help new sources relative to a situation
with no set-aside, because the demand for allowances for future sources
is unknown, it is difficult to know beforehand what should be the
appropriate size of the set-aside pool.
Another potential approach for distributing allowances from a new
source set-aside is using a single emissions rate for all new plants
and a plant specific utilization or power output level to calculate
allowance allocations for new units before they begin receiving
allowances through the update. Alternatively, the lower of the NSPS
rates for the respective fuel types and a rate representing the
proposed caps in 2010 and 2015 divided by projected 2010 and 2015 total
affected unit generation may be used to calculate allowance allocations
for new units before they begin receiving allowances through the
update. This alternative would ensure that new sources would receive
allowances at the same rate as that applied to existing sources and no
greater than their proposed NSPS. A State may also choose to distribute
allowances from this set-aside through an auction, which could be open
to anyone or limited (e.g., only new sources could participate). We ask
for comment on these various proposals, and for any other alternatives
commenters may wish to raise.
In today's proposed example allocation methodology, new units would
begin receiving allowances from the set-aside for the control period
immediately following the control period in which the new unit
commenced commercial operation, based on the unit's actual utilization
rates for the preceding control period. States would allocate
allowances from the set-aside to all new units in any given year as a
group. If there were more allowances requested than in the set-aside,
allowances would be distributed on a pro rata basis. Allowance
allocations in following years would continue to be based on the prior
year's utilization until the new unit is considered an existing unit
and is allocated allowances through the State's updating process. This
would enable new units to have a good sense of the amount of allowances
they would likely receive--in proportion to their generation. This
methodology would not provide allowances to a unit in its first year of
operation; however this methodology is straightforward and predictable.
As an alternative, States could distribute a new source set-aside
for a control period based on full utilization rates. Then, at the end
of the year, the actual allowance allocation would be adjusted to
account for actual unit utilization/output, and excess allowances would
be returned and redistributed, first taking into account new unit
requests that were not able to be addressed. This was the example
methodology used in the NOX SIP Call model rule. In
implementing the NOX SIP Call, EPA found this approach to be
complicated for both the States and the Agency in implementing the
procedure, as well as to the sources as this approach introduces a
higher level of uncertainty in the allocation process than may be
necessary.
[[Page 32713]]
With either approach, any unused set-aside allowances could be
redistributed to existing units based on their existing allocations.
The EPA is soliciting comment on the timing and method of allocating
allowances from the set aside in the example methodology.
While EPA recognizes States' flexibility in choosing their
NOX allocations method and is proposing that States be
allowed to determine their own method for allocating allowances to
sources in their State, EPA is also asking for comment on all aspects
of this example allocation proposal and whether the proposed regulatory
language, which codifies the above example as proposed in today's SNPR,
could reflect a different approach.
The EPA is also soliciting comment on alternate allocation methods.
b. Individual unit opt-in. In today's SNPR, EPA is soliciting
comment on whether opt-in provisions (i.e., provisions that allow units
that otherwise would not be subject to the proposed CAIR to
individually elect, or ``opt,'' to participate in the proposed CAIR
cap-and-trade programs) should be included in the final CAIR rule.
Further, EPA provides and solicits comment on an example opt-in
approach that could be included in the final CAIR model rules. If opt-
in provisions are included in final model rules, States would not be
required to include them, and both States with and without opt-in
provisions could participate in the EPA-managed cap-and-trade programs.
States that chose to include opt-ins would be required to adopt EPA's
methodology for including opt-ins as is.
Description of Potential Opt-In Approach
Opt-ins would be restricted to boilers and turbines that (1)
exhaust to a stack or duct, and (2) meet the same monitoring and
reporting requirements as CAIR-affected units. These requirements
ensure the consistent, rigorous monitoring and reporting required to
maintain the integrity of the emissions cap and trading market. To
establish baseline emissions and operating information, opt-in units
would be required to monitor and report in accordance with part 75 for
a minimum of one full calendar year prior to the unit entering the CAIR
trading program. If 3 or more consecutive calendar years of part 75
quality assured emissions and heat input data are available, then an
average of the most recent 3 calendar years would be used to establish
the baselines.
If a unit chooses to opt-in, the unit is required to opt into both
the SO2 and NOX cap-and-trade programs. By
requiring units to opt-in for both SO2 and NOX,
opt-in units are encouraged to develop integrated control strategies.
In addition, the burden of including opt-in units in the cap-and-trade
programs could be somewhat offset by the benefit of both SO2
and NOX emission reductions.
Opt-in units would be allocated SO2 and NOX
allowances on a year-by-year basis. The annual updating of allocations
based upon utilization reduces concerns that individual opt-in units
may shift utilization and, therefore, emissions, to other, unaffected
units. Opt-in allocations would be based upon (1) an emission rate, and
(2) the lesser of the baseline heat-input or the actual heat input
measured at the unit for the prior year. For example, the potential
SO2 allocation for an opt-in unit could be calculated by
taking (i) the lesser of the unit's actual heat-input for the prior
year or the unit's annual average baseline heat input for the most
recent 3 years for which part 75 quality-assured data are available
(or, if 3 years of such data are not available, the one year prior to
opting into the CAIR programs) and multiplying it by (ii) the lesser of
the unit's baseline SO2 emissions rate, the most stringent
State or Federal SO2 emissions limitation that applies to
the unit during the calender year prior to the year in which the unit
is being allocated allowances, or the emission rate representing 50
percent of the unit's baseline SO2 emission rate (in lb/
mmBtu)for the years 2010 through 2014 and 35 percent of the units's
baseline SO2 emission rate (in lb/mmBtu) for 2015 and
beyond. The EPA takes comment on this approach and specifically
solicits comment on allocating to opt-in units at a range of 20 to 65
percent below their baseline SO2 emission rates--the
equivalent of multiplying the baseline emission rate in the above
equation by 80 to 35 percent of their baseline emissions, respectively.
The NOX allocation for an opt-in unit could be calculated by
taking (i) the lesser of the unit's actual heat-input for the prior
year or the unit's annual average baseline heat input for the most
recent 3 years for which part 75 quality assured data is available or,
if 3 years of such data are not available, the one year prior to opting
into the CAIR program and multiplying it by (ii) the lesser of the
unit's baseline NOX emission rate, the most stringent State
or Federal NOX emissions limitation that applies to the opt-
in unit at any time during the calendar year prior to opting into the
CAIR program, or 0.15 lb/mmBtu for the years 2010 through 2014, and
0.11 lb/mmBtu for the years 2015 and beyond (these rates are based on
the average emission rates at which EPA projects EGUs will be
emitting). The EPA is taking comment on this approach and specifically
solicits comment on allocating to opt-in units at a range of levels
that are 20 to 65 percent below their baseline NOX
emissions, where an emissions rate of 0.11 lb NOX/mmBtu is
roughly equivalent to a 65 percent reduction.
States would need to notify EPA after the end of the calendar year
in order to allocate SO2 and NOX allowances to an
opt-in unit for the next calendar year. Because opt-in allocations
would be based upon data developed for the previous year, the
allocations would be distributed a few months after the beginning of
the next year (e.g., by April 1 of the next year, which would be of the
year for which the allowances are needed for compliance).
Non-EGU boilers and turbines under the NOX SIP Call that
choose to opt-in to the CAIR cap-and-trade programs would still be
required to meet the NOX SIP Call seasonal NOX
limitations. (The EPA does not have modeling, similar to that for EGUs,
that projects that if non-EGUs meet the annual NOX emission
limits, they will also meet the ozone season NOX emission
limit as well.) This requirement would ensure that the NOX
SIP Call States continue to meet their summertime NOX
emission limits and make progress toward attaining the ozone NAAQS.
Opt-in units must remain in the CAIR program for at least 5 years.
This would improve the cost effectiveness of implementing the program
and would avoid potential incentives for opting in and out of the
program. An opt-in unit could withdraw from the CAIR program any time
with the request being effective on December 31 following the
submission of the request or a subsequent December 31. The EPA believes
that the administrative burden for a permitting authority in processing
a withdrawal effective during a calendar year--particularly in
ascertaining the disposition of SO2 and NOX
allowances and in determining compliance for a partial calendar year--
would be sufficient to warrant the prohibition of an effective date of
withdrawal during a calendar year. Further, EPA believes that an opt-in
unit should not be allowed to withdraw retroactively, whether during a
calendar year or at the end of a prior calendar year. The ability to
withdraw retroactively could reduce the incentive to comply since an
opt-in unit could simply withdraw once it projects that it will not
hold enough SO2
[[Page 32714]]
and/or NOX allowances to account for its SO2 and/
or NOX emissions for that calendar year. At best, under such
a scenario, there would be no benefit from allowing the opt-in of the
unit. Under an alternate scenario, allowing the unit to ``opt out'' of
the program during a calendar year could result in higher overall
SO2 and/or NOX emissions, since an opt-in unit
could reduce its emissions during part of the year, sell some of its
allowances, and increase its emissions after withdrawing from the
program. Such increased emissions would not be accounted for with the
requisite surrender of SO2 and/or NOX allowances
required under the CAIR cap-and-trade programs and could occur outside
of a State's annual budget for SO2 and/or NOX.
The opt-in unit could, in effect, shift utilization from the part of
the year for which it must surrender allowances for emissions to the
part of the year for which emissions do not require an allowance
surrender.
Opt-in permits would be terminated for any unit that becomes a
CAIR-affected unit. This change in regulatory status for an opt-in unit
could occur as a result of a modification or reconstruction that may
take place at the unit. An opt-in unit that becomes a CAIR-affected
unit would be required to notify the permitting authority within 30
days of the change in regulatory status. The permitting authority
should revise the opt-in permit to reflect the CAIR permit content
requirements of subparts CC and CCC (for NOX and
SO2, respectively), effective as of the date of the change
in status. The SO2 and NOX allowances would be
deducted or allocated as necessary to ensure that the appropriate
number of allowances are allocated to the unit consistent with the
proposed CAIR trading rules for each calendar year after the effective
date of the change in status.
4. Structure of Proposed CAIR Model Trading Rules
In order to make the proposed CAIR NOX and
SO2 model trading rules as simple and consistent as
possible, EPA designed them to parallel the model trading rules of the
NOX SIP Call (part 96) and the Federal NOX Budget
Trading Program (part 97). Because EPA is proposing new CAIR
NOX and SO2 model rules--separate from the
existing model rule in part 96--States can continue to reference part
96 as they implement the NOX SIP Call through 2009. The new
CAIR NOX and SO2 model rules use the same basic
structure as part 96 and will allow for an easier transition to the
CAIR rules as States and sources will already be familiar with the rule
layout. Specifically, the model rules will be codified as follows:
NOX SIP Call model cap-and-trade rule will
remain in part 96 subparts A through J;
CAIR NOX model cap-and-trade rule will be
created in part 96 subparts AA through HH;
CAIR SO2 model cap-and-trade rule will be
created in part 96 subparts AAA through HHH; In addition, today's SNPR
will add and reserve subparts between those proposed in today's action
(i.e., subparts K through Z, subparts II through ZZ, and subparts III
through ZZZ). Both the CAIR NOX and SO2 model
rules will rely upon the detailed unit-level emissions monitoring and
reporting procedures of part 75. (Note that proposed regulations
establishing SIP requirements under the CAIR, i.e., part 51, are
discussed in section III of today's action.) Additionally, section III
of today's SNPR proposes revisions to part 72 through 77 in order to,
among other things, harmonize the title IV Acid Rain Program's
SO2 cap-and-trade provisions with those of the proposed
CAIR.
B. Elements of the Proposed NOX and SO2 Model
Trading Rules, Subparts AA Through HH and AAA Through HHH
This section of today's SNPR describes the purpose of each subpart
of the proposed NOX and SO2 model trading rules
in parallel. The descriptions highlight any improvements relative to
corresponding sections in the existing part 96 (NOX SIP
Call) and part 97 (Federal NOX Budget Trading Program) model
rules. In addition, each subsection notes provisions that have been
specifically adapted for either the CAIR SO2 or
NOX trading program.
1. Subparts AA and AAA, CAIR NOX and SO2 Trading
Program Applicability and General Provisions
a. 96.101 and 96.201 purpose. This section states the reason for
the regulation.
b. 96.102 and 202 Definitions and 96.103 and 96.203 measurements,
abbreviations, and acronyms. Many of the definitions, measurements,
abbreviations, and acronyms remain unchanged from those used in 40 CFR
parts 96 and 97, in order to maintain consistency among programs.
However, certain terms that are specific to the CAIR SO2 and
NOX model cap-and-trade rule have been added and certain
other terms have been modified.
In today's supplemental proposal of the model SO2 cap-
and-trade rule, EPA has defined CAIR SO2 allowances to
reflect the SO2 retirement ratios described in section
VIII.B.2.f (69 FR 6932) of the January 2004 proposal. Specifically, the
definition established the number of title IV or CAIR SO2
allowances, by vintage, that must be retired to offset one ton of
SO2 emissions. Specifically, one SO2 allowance of
vintage years 2009 and earlier authorizes the emission of one ton of
SO2. Two SO2 allowances of vintage years 2010-
2014 authorize one ton of SO2 emission. Three SO2
allowances of vintage years 2015 and beyond authorizes the emission of
one ton of SO2.
In today's SNPR, EPA is clarifying the definition of cogeneration
unit included in the January 2004 proposal. (This clarification also
corrects an error in the January 2004 proposal, where it was
erroneously stated that the definition of a cogeneration facility under
the title IV Acid Rain Program and the NOX SIP Call was
based on the Federal Energy Regulatory Commission's qualifying
cogeneration facility definition.) The EPA proposes to use a definition
of cogeneration unit that is based on the Acid Rain Program definition
of ``cogeneration unit'' and the Federal Energy Regulatory Commission's
(FERC) definitions of ``cogeneration unit'' and ``qualifying
cogeneration facility.'' The proposed ``cogeneration unit'' has two
elements. First, in order to be a ``cogeneration unit,'' a unit must
produce electric energy and useful thermal energy for industrial,
commercial, heating or cooling purposes, through the sequential use of
original fuel energy. See 40 CFR 72.2 and 18 CFR 292.202(c)
(``cogeneration'' definition). Second, the unit must meet the operating
and efficiency standards under 18 CFR 292.205, but applied to all
cogeneration units, instead of applying the efficiency standards only
to oil- and gas-fired units as under 18 CFR 292.205. The EPA believes
that applying the operating and efficiency standards to all units would
be more consistent with its fuel-neutral approach throughout this
proposed rule. In addition, not applying the efficiency standards to
coal-fired units would be counter-productive to EPA's efforts to reduce
SO2 and NOX emissions under this proposed rule
because of the relatively high SO2 and NOX
emissions from coal-fired units. Thus, under the second element of
today's proposed ``cogeneration unit'' definition, a topping-cycle
cogeneration unit must meet the following requirements.
The useful thermal energy output of the unit must be no less than 5
percent of the total energy output during the 12-month period beginning
with the date the unit first produces electric energy
[[Page 32715]]
and any subsequent calendar year. The useful power output of the unit
plus one-half the useful thermal energy output, during the 12-month
period beginning with the date the unit first produces electric energy,
and any calendar year after the year in which the unit first produces
electric energy, must be: (i) No less than 42.5 percent of the total
energy input to the unit; or (ii) if the useful thermal energy output
is less than 15 percent of the total energy output of the unit, no less
than 45 percent of the total energy input to the unit.
For bottoming-cycle cogeneration units, the useful power output of
the unit during the 12-month period beginning with the date the unit
first produces electric energy, and any subsequent calendar, must be no
less than 45 percent of the energy input.
c. 96.104 and 204 Applicability. Today's SNPR proposes to affect
fossil fuel-fired boilers and turbines serving an electrical generator
with a nameplate capacity exceeding 25MW and producing power for sale.
Cogeneration units would be affected if they meet the definition in b.
above.
d. 96.105 and 205 Retired unit exemption. This section of today's
SNPR provides an exemption from the CAIR NOX and
SO2 trading program requirements for retired units so that
retired CAIR units will be free from unnecessary requirements (e.g.,
emissions monitoring and reporting). The EPA proposes an exemption
beginning on the day the unit permanently retires, requiring no notice
and comment period regarding the retirement. This provision proposes
that the CAIR Designated Representative (CAIR DR) (i.e., the person
authorized by the owners and operators to make submissions and handle
other matters) submit notification to the permitting authority of the
CAIR unit's retirement within 30 days of the cessation of activity.
(Note that the CAIR DR designation is similar to the title IV Acid Rain
Program's Designated Representative, or ``Acid Rain DR,'' and the
NOX SIP Call's Authorized Account Representative, or
``AAR.'') In response, the permitting authority would amend the
operating permit in accordance with the exemption and notify EPA of the
unit's status as exempt. This provision imposes conditions that all
program requirements prior to the exemption are fulfilled and records
are kept on site to verify the non-emitting status of the retired unit.
A retired unit could continue to hold NOX and SO2
allowances previously allocated or be allocated NOX and
SO2 allowances in the future depending on the allocation
provisions adopted by the State where the retired unit is located. The
number of future year NOX and SO2 allowances that
a retired unit would be allocated would be dependent on the given
State's allocation system. The NOX and SO2
allowance allocations are discussed in sections IV.A.3.a and IV.B.5 of
this SNPR.
In order to resume operation without violating program requirements
(i.e., an exemption requires that the unit's permit language be changed
to reflect that it would not emit any NOX and SO2
emissions), the CAIR DR must submit a permit application to the
permitting authority no less than 18 months (or less, if so specified
by the applicable State permitting regulations) prior to the date on
which the unit is to resume operation, to allow the permitting
authority time to review and approve the application for the unit's re-
entry into the program. If a retired unit resumes operation, EPA
proposes to automatically terminate the exemption under this part.
e. 96.106 and 96.206 Standard requirements. Today's SNPR delineates
the standard requirements that CAIR units and their owners, operators,
and CAIR DRs must meet under the CAIR NOX and SO2
cap-and-trade program. This provision sets forth references to other
portions of the cap-and-trade rule for the full range of program
requirements: Permits, monitoring, NOX and SO2
emissions limitations, excess emissions, recordkeeping and reporting,
liability, and effect on other authorities. For example, the
permitting, monitoring, and emissions limit requirements are discussed
in general and the relevant sections of the cap-and-trade rule are
cited. The liability provisions state that the requirements of the
trading program must be met, and any knowing violations or false
statements are subject to enforcement under the applicable State or
Federal law. Violations and the associated liability are established on
a facility-wide basis. The provision addressing the effect on other
authorities establishes that no provision of the trading program can be
construed to exempt the owners or operators of a CAIR source from
compliance with any other provision of the applicable SIP, any
federally enforceable permit, or the CAA. This provision ensures, for
example, that a State may set a binding source-specific NOX
and SO2 limitation and, regardless of how many allowances a
CAIR source holds under the trading program, the emissions limit
established in the SIP cannot be violated.
Automatic penalties for non-compliance have been key to the success
of the title IV and the NOX SIP Call's cap-and-trade
programs and are an important feature of the proposed CAIR model rules
as well. Simple, transparent, automatic penalties avoid litigation,
which can be costly for both the air authorities and the sources, for
most non-compliance instances. For severe non-compliance, the air
authorities retain the right to pursue civil actions.
f. 96.107 and 207 Computation of time. This section clarifies how
to determine the deadlines referenced in the proposal. For example,
deadlines falling on a weekend or holiday are extended to the next
business day. These are the same computation-of-time provisions as are
in the regulation for the title IV and the NOX SIP Call
emissions trading programs.
2. Subparts BB and BBB, CAIR Designated Representative for CAIR Sources
Sections 96.108 and 96.208 of today's SNPR establish procedures for
appealing the decisions of the Administrator regarding the model cap-
and-trade rules in part 78. Part 78 also includes administrative appeal
procedures for the Acid Rain Program and the Federal NOX
Budget Trading Program. Today's SNPR revises part 78 to make these
procedures applicable to the CAIR NOX and SO2
trading programs as well.
Sections 96.110 through 96.114 and 96.210 and 96.214 of today's
proposed CAIR NOX and SO2 cap-and-trade programs
rule establish the process for certifying the CAIR DR and describe his
or her duties. Patterned after the roles and responsibilities of the
title IV Acid Rain Program's DR, a CAIR DR is the individual authorized
to represent the owners and operators of each CAIR NOX and
SO2 unit at a CAIR source (i.e., a facility that includes at
least one CAIR affected unit) in matters pertaining to the CAIR cap-
and-trade programs. Because the CAIR DR represents the owners and
operators of all the CAIR NOX and SO2 units at a
CAIR source, the CAIR DR must certify that he or she was selected by an
agreement binding on all such owners and operators and is authorized to
act on their behalf. The CAIR DR's responsibilities include: The
submission of permit applications to the permitting authority,
submission of monitoring plans and certification applications, holding
and transferring CAIR allowances, and submission of emissions data. The
rule proposes that each CAIR source have one DR that is responsible for
both the NOX and SO2 cap-and-trade program
requirements. Additionally, the rule proposes to
[[Page 32716]]
require that the CAIR DR be the same individual as the title IV Acid
Rain Program's Designated Representative (Acid Rain DR) at each source.
These requirements will ensure that one individual is responsible for
all matters pertaining to the CAIR as well as significantly reduce the
burden on the data systems used in the administration of the cap-and-
trade programs.
The EPA recognizes that the CAIR DR cannot always be available to
perform his or her duties. Therefore, the rule proposes to allow for
the appointment of one alternate CAIR DR for a CAIR source. The
alternate CAIR DR would have the same authority and responsibilities as
the CAIR DR. Therefore, unless expressly provided to the contrary,
whenever the term ``CAIR Designated Representative'' is used in the
rule, it should be read to apply to the alternate CAIR DR as well.
While the alternate CAIR DR would have full authority to act on behalf
of the CAIR DR, all correspondence from EPA, including reports, would
be sent only to the CAIR DR. It should be noted that additional
flexibility is provided within the electronic data systems that EPA
uses to administer the program. Within these systems the CAIR DR may
assign ``agents'' to perform specific tasks on his or her behalf, such
as submission of allowance transfers and electronic data reports.
Today's SNPR requires the completion and submission of the
Certificate of Representation in order to certify a CAIR DR for a CAIR
source and all CAIR NOX and SO2 units at the
source. There would be one standard form (the Certificate of
Representation [DR form]) which would be submitted by sources to EPA.
The DR form would include identifying information for the source, the
CAIR DR and the alternate CAIR DR, if applicable; the name of every
owner and operator of the source and each CAIR unit at the source; and
certification language and signature of the CAIR DR and alternate, if
applicable. The EPA would design this form to also include the Acid
Rain DR certifications, and the CAIR DR would indicate which units at
the source are included in which programs. This form can also be
completed and submitted electronically. Upon receipt of a complete DR
form, EPA would establish a compliance account for each source in the
systems used to track SO2 and NOX allowances.
In order to change the CAIR DR, alternate CAIR DR, or list of
owners and operators, EPA is proposing that a new complete account
certificate of representation be submitted. The EPA believes the CAIR
DR requirements afford the regulated community with flexibility, while
ensuring source accountability and simplifying the administration of
the cap-and-trade program.
3. Subparts CC and CCC, CAIR Permits
a. 96.120 and 96.220 General CAIR NOX and SO2
trading program permit requirements. The EPA has attempted to minimize
the number of new procedural requirements for CAIR permitting and to
defer, whenever possible, to the permitting programs already
established by the permitting authority. The proposed CAIR trading
program regulations assume that the CAIR permit would be a portion of a
federally enforceable permit issued to the CAIR source and administered
through permitting vehicles such as operating permits programs
established under title V of the CAA and 40 CFR part 70. Generally, the
permits regulations promulgated by the permitting authority cover:
Permit application, permit application shield, permit duration, permit
shield, permit issuance, permit revision and reopening, public
participation, and State and EPA review. The proposed CAIR trading
program permit regulations generally require use of the procedures
under these other regulations and add some requirements such as CAIR
permit application submission and renewal deadlines, CAIR permit
application information requirements and permit content, and the term
``CAIR permit''. The term ``CAIR permit'' throughout this preamble and
the CAIR trading program regulations therefore refers to the CAIR
trading program portion of the permit issued by the permitting
authority to a CAIR source.
b. 96.121 and 96.221 Submission requirements for CAIR
NOX and SO2 permit applications. The proposed
rule sets the initial CAIR permit application deadlines for units in
operation before January 1, 2007 so that the permits will be issued by
January 1, 2010. January 1, 2010 is the beginning of the first control
period for the CAIR cap-and-trade program, and therefore also the date
by which initial CAIR permits for existing units should be effective.
Application submission deadlines are based on the permitting
authority's title V permitting regulations. For instance, if a
permitting authority's permitting regulations allowed 12 months for
final action by the permitting authority on a permit application, the
application deadline would be the later of January 1, 2009 (12 months
prior to January 1, 2010) or 12 months before the unit commences
operation. The same principle applies to CAIR units commencing
operation on or after January 1, 2007, except that the application
submission deadline is the later of the date the CAIR unit commences
operation or January 1, 2010. The CAIR permit renewal application
deadlines are the same as those that apply to permit renewal
applications in general for sources under Title V. For instance, if a
permitting authority requires submission of a Title V permit renewal
application by a date which is 12 months in advance of a title V
permit's expiration, the same date would also apply to the CAIR permit
application.
c. Sections 96.122 and 96.222, Information requirements for CAIR
permit applications and Sec. Sec. 96.123 and 96.223 CAIR permit
contents and term. The CAIR cap-and-trade program requires that a CAIR
permit application properly identify the source and include the
standard requirements under proposed sections Sec. Sec. 96.121 and
96.221. The CAIR cap-and-trade program permit application should
include all elements of the program (including the standard
requirements). Such an approach allows the permitting authority to
incorporate virtually all of the applicable CAIR cap-and-trade program
requirements into a CAIR permit by including as part of such permit the
CAIR permit application submitted by the source. Directly incorporating
the CAIR permit application into the CAIR permit and, thus, into the
source's operating permit or the overarching permit minimizes the
administrative burden on the permitting authority of including the CAIR
cap-and-trade program applicable requirements. The permitting authority
may revise the term of the CAIR permit as necessary to facilitate
coordination of the renewal with the issuance, revision, or renewal of
the sources title V permit.
d. Sections 96.124 and 96.224, CAIR permit revisions. For revisions
to the CAIR permit, the CAIR trading program again defers to the
regulations addressing permits revisions promulgated by the permitting
authority under title V and 40 CFR part 70 or 71. The proposal also
provides that the allocation, transfer, or deduction of allowances is
automatically incorporated in the CAIR permit, and does not require a
permit revision or reopening by the permitting authority. The CAIR
permit must, however, expressly state that each source must hold enough
allowances to account for emissions by the allowance transfer deadline
for each control period. The EPA believes that requiring the permitting
authority to revise or reopen a CAIR permit each time a CAIR allowance
allocation, transfer, or deduction is made would be burdensome and
unnecessary.
[[Page 32717]]
4. Subpart DD and DDD, CAIR Compliance Certification
Sections 96.130 through 96.131 and 96.230 through 96.231 are
reserved. The NOX and SO2 cap-and-trade programs
in today's SNPR do not include the requirement for the source to submit
a compliance certification report. The requirements are unnecessary
because these sources already certify compliance with the emissions
monitoring and reporting requirements when they submit their quarterly
emissions data. In addition, these sources will submit compliance
certifications under title V for all CAA requirements, including the
CAIR, NOX SIP Call, and Acid Rain trading programs.
5. Subpart EE and EEE, CAIR NOX and SO2 Allowance
Allocations
Sections 96.140 through 96.142 of today's SNPR propose both
required provisions (i.e., State-by-State NOX emissions
budgets and the timing for States to report unit-by-unit NOX
allocations) as well as the example allocation approach, provided as an
illustration. Specifically, sections 96.140 and 96.240 propose the
State-by-State NOX emission budgets that may be allocated by
the State. Section 96.141 proposes elements of the NOX
allocation systems that States are required to include (i.e., a 3 year
minimum for advanced notification by the State of allocations and the
annual timing of submitting to EPA the updated, unit-by-unit
allocations) in order to ensure consistency for sources across all
States participating in the EPA-managed cap-and-trade program. Section
96.142 proposes provisions that would implement the example approach
for the NOX cap-and-trade program--discussed in detail in
above, including procedures for creating a new unit set-aside and
incorporating new units into a permanent allocation.
Sections 96.240 through 242, pertaining to the CAIR SO2
cap-and-trade program, are reserved. The title IV SO2
allowance allocation provisions of the CAA remain in effect. Should the
final CAIR program make CAIR SO2 allowances available to the
States, EPA would include requirements for a 3 year minimum for
advanced notification for unit-by-unit allocations that would be
similar to those proposed for NOX allocations in today's
action.
6. Subpart FF and FFF, CAIR NOX and SO2 Allowance
Tracking Systems.
a. Overview of tracking system. Sections 96.150 through 96.157 and
96.250 through 96.257 of today's proposed model rule cover the system
to track CAIR NOX and SO2 allowances. The
proposed rule is intended to make use of the allowance tracking systems
developed for the NOX SIP Call and Acid Rain Program, with
some modifications. Such an approach would help to allow the
integration of the CAIR NOX and SO2 cap-and-trade
programs with the existing cap-and-trade programs under the
NOX SIP Call and Acid Rain Program. It would also save
industry and government the time and resources necessary to develop new
tracking systems.
The current automated systems will be used to track CAIR
NOX and SO2 allowances held by CAIR sources under
the CAIR NOX and SO2 cap-and-trade programs, as
well as those allowances held by other organizations or individuals.
Specifically, the systems would track the allocation of all CAIR
NOX and SO2 allowances, holdings of CAIR
NOX and SO2 allowances in accounts, deduction of
CAIR NOX and SO2 allowances for compliance
purposes, and transfers between accounts. The primary role of the
tracking system is to provide an efficient, transparent, and automated
means of monitoring compliance with the CAIR NOX and
SO2 cap-and-trade programs. It would also provide the
allowance market with a record of ownership of allowances, dates of
allowance transfers, buyer and seller information, and the serial
numbers of allowances transferred.
The EPA is proposing that the tracking system contain two primary
types of accounts: Compliance accounts and general accounts. The EPA is
proposing that compliance accounts for NOX and
SO2 be created for each CAIR source with one or more CAIR
units, upon receipt of the Certificate of Representation form. General
accounts are created for any organization or individual upon receipt of
a General Account Information form.
b. Establishment of accounts.
i. Compliance accounts. The EPA is proposing to require source-
level accounts for compliance with the CAIR NOX and
SO2 cap-and-trade programs. The EPA's experience in
conducting compliance determinations (reconciliation) for the Acid Rain
cap-and-trade program at strictly the unit level indicates that there
is the potential for affected facilities to be subject to monetary
penalties simply for having too few allowances in one unit account at a
source when there are plenty of available allowances at another unit
account at the same source. This amounts to a monetary penalty,
potentially large, for an accounting error that has no significant
environmental effect. In developing the compliance procedures for the
NOX SIP Call cap-and-trade programs, this was taken into
consideration and overdraft accounts were introduced to provide some
flexibility in managing allowances at a source. However, both EPA and
the regulated community find that, in practice, overdraft accounts and
their use can be quite complicated and do not significantly reduce the
burden of unit-level accounting. Therefore, EPA is proposing compliance
accounts be established at the source level. This will significantly
reduce the accounting burden for both EPA and the regulated community
without causing any environmental consequences. The source-level
accounts would be identified by a account number incorporating the
source's Office of Regulatory Information System's (ORIS) code or
facility identification number.
Today's SNPR also modifies the Acid Rain Program regulations to
provide for source-level compliance. This will facilitate the
interaction of the Acid Rain Program and the CAIR cap-and-trade
programs.
ii. General accounts. Today's proposed model rules allow any person
or group to open a general account. These accounts would be identified
by the ``9999'' that would compose the first four digits of the account
number. Unlike compliance accounts, general accounts cannot be used for
compliance but can be used for holding or trading NOX or
SO2 allowances (e.g., by allowance brokers or owners of
multiple CAIR NOX or SO2 units or sources).
General accounts are currently used for both SO2 allowances
in the Acid Rain Program and NOX allowances in the
NOX SIP Call cap-and-trade program.
To open a general account, a person or group must complete the
standard General Account Information form, which is similar to the
Certificate of Representation that precedes the opening of a compliance
account. The form must include the name of a natural person who would
serve as the NOX or SO2 Authorized Account
Representative (AAR). The form would include identifying information
for the AAR and alternate AAR (if applicable); the organization name
and type, if applicable; the names of all parties with an ownership
interest with the respect to the NOX or SO2
allowances in the account; and certification language and signatures of
the NOX or SO2 AAR and alternate, if applicable.
Revisions to information regarding an existing general account are
made by submitting a new General Account Information form which would
be sent to EPA in all cases, whether the form is
[[Page 32718]]
used to open a new account, or revise information on an existing one.
The EPA would notify the NOX or SO2 AAR cited on
the application of the establishment of his or her general account or
of the registration of requested changes.
c. Recordation of allowance allocations. The NOX
allocations for existing units for the first 5 years (2010-2014), as
prescribed by each State, would be recorded into the CAIR
NOX (source-level) compliance accounts prior to the first
control period in 2010. Prior to the second control period, in 2011,
and each year thereafter, NOX allocations for the new fifth
sixth year, as prescribed by each State, would be recorded in each
compliance account (e.g., in 2011, year 2016 NOX allowances
would be allocated).
Title IV SO2 allowances are allocated and recorded under
the Acid Rain Program so this section of the CAIR SO2 model
cap-and-trade rules is reserved. Should the final CAIR rule make CAIR
SO2 allowances available to States, requirements for the
recordation of CAIR SO2 allowances would be similar to those
proposed for NOX allocations in today's action.
d. Compliance. Once a control period has ended (i.e., December 31)
CAIR NOX and SO2 sources would have a window of
opportunity (i.e., until the allowance transfer deadline of midnight on
March 1 following the control period) to evaluate their reported
emissions and obtain any additional NOX or SO2
allowances they may need to cover the emissions during the year.
NOX: The compliance requirement would be to hold one NOx
allowance for each ton of NOX emissions at each CAIR unit at
the source. For each ton of NOX emissions for which the
source does not hold an allowance, the excess emissions offset would be
a deduction of 3 NOX allowances allocated for the year after
the year in which the excess emissions occur.
SO2: The compliance requirement would depend upon the
vintage of the SO2 allowance being submitted for compliance.
For allowances with vintage years of 2009 and earlier, one
SO2 allowance must be held for each ton of SO2
emissions. For allowances for vintage years 2010-2014, a source must
hold 2 allowances of these vintages for each ton of SO2
emissions. A source must hold 3 SO2 allowances of vintage
years 2015 and beyond for each ton of SO2 emissions at the
source. For each ton of SO2 emissions for which the source
does not hold the requisite number of SO2 allowances, the
excess emissions offset would deduct three times the number of
SO2 allowances required for the sources emissions for the
vintage year immediately following the year in which the excess
emissions occurred. This would result in six 2010-2014 vintage year
allowances and nine 2015 and beyond year allowances, since two 2010-
2014 allowances or three 2015 and beyond allowances authorize one ton
of SO2 emissions.
The EPA believes that it is important to include this automatic
offset deduction because it ensures that non-compliance with the
NOX and SO2 emission limitations of this part is
a more expensive option than controlling emissions. The EPA required an
automatic deduction of 3-for-1 in the NOX SIP Call, and is
taking comment on the ratios used in the proposed model rules. The
automatic offset provisions do not limit the ability of the permitting
authority or EPA to take enforcement action under State law or the CAA.
In the Acid Rain Program, one SO2 allowance must be held
for each ton of SO2 emissions. As discussed above, one, two,
or three SO2 allowances must be held for each ton of
emissions, depending on the year for which the allowances were
allocated. Consequently, non-compliance with the allowance-holding
requirement in the CAIR SO2 cap-and-trade program would not
necessarily mean non-compliance with the allowance-holding requirement
in the Acid Rain Program. Therefore, it is necessary to ensure that
compliance with the Acid Rain Program allowance-holding requirements is
assessed independently from the CAIR requirements. The EPA is proposing
a detailed allowance deduction order for each CAIR unit at each CAIR
source where one allowance for each ton of emissions is deducted first
(satisfying the Acid Rain requirement) and then the additional
allowances are deducted to complete the CAIR SO2
requirement.
e. Banking. Banking is the retention of unused allowances from one
control period for use in a later control period. Banking allows
sources to create reductions beyond required levels and ``bank'' the
unused allowances for use later. The EPA is proposing that banking of
allowances after the start of the CAIR NOX and
SO2 cap-and-trade programs be allowed with no restriction.
Banking after a program starts and the budget is imposed allows sources
to retain any allowances not surrendered for compliance at the end of
each control period. Once the CAIR cap-and-trade program budgets are in
place, sources may over-control for one or more years and withdraw from
the bank in one or more later years. This type of banking provides the
following advantages: Encourages early reductions, stimulates the
market, and provides flexibility to sources, while also potentially
causing NOX or SO2 emissions in some control
periods to be greater than the allowances allocated for those years.
Allowing unrestricted banking is consistent with the current Acid
Rain Program for SO2. The NOX SIP Call cap-and-
trade program, however, has some restrictions on the use of banked
allowances, a procedure called flow control. Flow control was first
used in the OTC NOX cap-and-trade program and was carried
over into the NOX SIP Call cap-and-trade program. The flow
control provisions were designed to discourage extensive use of banked
allowances in a particular ozone season. Flow control establishes a 2-
to-1 discount ratio on the use of banked allowances above a certain
level. The discount ratio applies after the total number of banked
allowances from all sources exceeds 10 percent of the regionwide
NOX emissions budget. Flow control is a very complicated
procedure to explain, understand, and implement. The experience in the
OTC cap-and-trade program illustrated that flow control can cause
allowance market complexity and confusion for the regulated community
by stratifying the allowance market by vintages (i.e., the year for
which the allowances are allocated), making banked allowances less
valuable, and potentially increasing the cost of compliance. In
addition to these negative effects, it remains difficult to ascertain
an environmental benefit. The EPA is proposing to not use flow control
in order to keep compliance with the CAIR cap-and-trade programs as
simple and easy as possible.
7. Subparts GG and GGG, CAIR NOX and SO2
Allowance Transfers
The EPA is proposing that once a NOX or SO2
DR or AAR is appointed and an account is established, NOX or
SO2 allowances can be transferred to or from the accounts
with the submission of allowance transfer information, either on-line
or through the use of an Allowance Transfer form. Transfers can occur
between any accounts at any time of year with one exception: Transfers
of current and past year allowances into and out of compliance accounts
are prohibited after the allowance transfer deadline (March 1 following
each control period) until EPA completes the annual reconciliation
process by deducting the necessary allowances.
For those electing not to transfer allowances on-line, there would
be one standard NOX and one standard SO2
Allowance Transfer form. This form would be submitted to the EPA in all
[[Page 32719]]
cases. The form would generally include: the transferor and transferee
allowance account numbers; the transferor's printed name, phone number,
signature, and date of signature; and a list of allowances to be
transferred, by serial number.
8. Subparts HH and HHH, CAIR NOX and SO2
Monitoring and Reporting
Clear, rigorous, and transparent monitoring and reporting of all
emissions are the basis for holding sources accountable for their
emissions and are essential to the success of any cap-and-trade
program. Consistent and accurate measurement of emissions ensures that
each allowance actually represents one ton of emissions and that one
ton of reported emissions from one source is equivalent to one ton of
reported emissions from another source. Similarly, such measurement of
emissions ensures that each single allowance (or group of
SO2 allowances, depending upon the SO2 allowance
vintage) represents one ton of emissions, regardless of the source for
which it is 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. Given the variability in the type, operation, and
fuel mix of sources in the proposed CAIR NOX and
SO2 cap-and-trade programs, EPA believes that emissions must
be monitored continuously in order to ensure the precision,
reliability, accuracy, and timeliness of emissions data that support a
cap-and-trade program. As proposed, part 96 subpart HH for
NOX and subpart HHH for SO2 establish monitoring
and reporting requirements for CAIR sources. These subparts reference
the relevant sections of part 75 where the specific procedures and
requirements for measuring and reporting NOX and
SO2 mass emissions are found. These subparts are modeled
after subpart H of part 96.
Part 75 was originally developed for the Acid Rain Program. The
Acid Rain Program, as established by Congress in the 1990 Amendments to
the Act, requires the use of continuous emissions 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. The EPA believes that the use of CEMS is a
critical part of ensuring the effectiveness of regional cap-and-trade
programs. In implementing the Acid Rain Program, as well as the
NOX SIP Call Trading Program, EPA has allowed alternatives
to CEMS only where the total of the emissions contributed by specified
categories of affected sources is de minimis in comparison to the
emissions cap for the program, or where an alternative monitoring
system has been demonstrated, according to specified criteria, to meet
the standard Congress set. Provisions for monitoring and reporting
NOX mass emissions were added to Acid Rain Program
methodologies for both the OTC NOX Budget Program and for
the NOX SIP Call. As a result, several alternative
monitoring methodologies exist for qualifying sources to use. For
example, there is a SO2 emissions data protocol that allows
gas- or oil-fired units to use fuel sampling techniques along with fuel
flow metering to quantify emissions. (See part 75, appendix D.) There
is also a NOX estimation methodology for certain
infrequently used gas- or oil-fired units that can be found in part 75,
appendix E. There are also optional emissions calculation procedures
for gas-or oil-fired sources emitting no more than 25 tons of
SO2 annually or less than 100 tons of NOX
annually which allow the use of conservative emission factors to
estimate emissions. (See Sec. 75.19.) All of the existing part 75
monitoring methodologies will be available to CAIR sources as
applicable.
Sources subject to the CAIR must monitor and report NOX
and SO2 mass emissions year round. The majority of CAIR
sources are measuring and reporting SO2 mass emissions year
round under the Acid Rain Program. Therefore, these sources will have
little or no changes to make to their monitoring and reporting efforts
under the CAIR. Most CAIR sources are also reporting NOX
mass emissions year round under the NOX SIP Call. The CAIR-
affected Acid Rain sources that are located in States that are not
affected by the NOX SIP Call currently measure and report
NOX emission rates year round, but do not currently report
NOX mass emissions. These sources will need to modify only
their reporting practices in order to comply with the proposed CAIR
monitoring and reporting requirements. Today's SNPR is designed to be
as consistent as possible with existing requirements in order to
minimize the impact on CAIR sources of the monitoring and reporting
requirements, while maintaining the integrity of the cap-and-trade
programs.
The requirement to monitor and the associated monitoring deadlines
are found in Sec. 96.170 for NOX and Sec. 96.270 for
SO2 for the CAIR trading programs and require continuous
measurement of SO2 and NOX emissions by all
existing affected sources by January 1, 2009 using part 75 certified
monitoring methodologies. New sources have separate deadlines based
upon the date of commencement of operation, consistent with the Acid
Rain Program.
The quality assurance (QA) requirements for the Acid Rain Program
that were mandated by Congress under the CAA have been 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 affected source and provide prompt feedback if the
monitoring system is not operating properly. In addition, when the CEMS
is not operating 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
sources with consistent accounting for every ton of emissions and also
provides an incentive to keep the monitoring system properly up to date
with QA requirements. The NOX SIP Call trading program also
requires part 75 QA procedures. The EPA proposes to require the same QA
procedures (as applied to an entire year, not just the ozone season)
for the CAIR program. Initial certification or recertification is
required as specified in Sec. Sec. 96.171 and 96.271. Recognizing that
many of the CAIR units are already monitoring NOX or
SO2 (sometimes both) under part 75 through existing
programs, subparts HH and HHH allow continued use of previously
certified CEMS when appropriate rather than automatically requiring
recertification. Requirements for reporting data when the monitors do
not meet QA specifications are found in Sec. Sec. 96.172 and 96.272.
Sections 96.174 and 96.274 specify reporting requirements, which
include general requirements, monitoring plan reporting, certification
applications, quarterly emissions and operations reports, and
compliance certifications. The EPA proposes to require year-round
reporting of emissions and monitoring data from each affected unit. As
required for the Acid Rain Program and the NOX SIP Call
trading programs, quarterly emissions reports must be submitted to EPA
electronically on a quarterly basis and in a format specified by the
Agency using EPA-provided software. Many affected sources are
[[Page 32720]]
already reporting some or all of this data to EPA under either the Acid
Rain Program or the NOX SIP Call trading program and can
continue to report that data along with any additional data that may be
required by this program. The EPA has found centralized reporting to be
necessary to ensure consistent review, checking, and posting of the
emissions and monitoring data for all affected sources, which
contributes to the integrity, efficiency, and transparency of the
trading program. Another important feature is that sources regulated
under the Acid Rain Program, NOX SIP Call, or the CAIR
NOX and SO2 cap-and-trade programs must use the
same reporting format and submit only one report with all of the
information required for all of the applicable programs. Thus, if the
same data is needed for multiple programs, the source needs to report
it only once in the form of one comprehensive report.
Consistent with the current monitoring and reporting requirements
in part 75 for the Acid Rain and the NOX SIP Call programs,
the proposed rule would allow sources, Sec. 96.175 of subpart HH of
part 96 and under Sec. 96.275 of subpart HHH of part 96, to petition
for an alternative to any of the specified monitoring requirements in
the rule. These provisions provide sources with the flexibility to
petition to use an alternative monitoring system under subpart E of
part 75 or variations of the standard monitoring requirements as long
as the requirements of existing Sec. 75.66 are met.
Sections 96.176 and 96.276 require heat input data to be measured
and reported regardless of the type of monitoring system.
V. Clarifications to January 30, 2004 Proposal
This section provides clarifications to the January 2004 proposal
where the preamble language provided in the published proposal was
unclear, incomplete, inadvertently omitted, or inadvertently incorrect.
Unless otherwise indicated, all references to the Federal Register--69
FR 4566-4650--are to the proposed Interstate Air Quality Rule.
A. Scope of the Proposed Action
On 69 FR 4633 column 1, EPA discussed the NOX cap-and-
trade program. Under the heading ``States Outside the Proposed Region
with Existing Regional NOX Cap-and-trade Programs'', EPA
mistakenly identified Massachusetts in the list of States that
participate in existing NOX trading markets that would not
be affected by the proposed rules. Massachusetts should be deleted from
that list because it would be affected by the proposed rules.
In the January 2004 proposal, we discussed regional control
requirements and budgets based on a showing of ``significant
contribution'' by upwind States to nonattainment in other States. (69
FR 4611-4613). CAA section 110(a)(2)(D), which provides the authority
for the proposal, states among other things that SIPs must contain
adequate provisions prohibiting, consistent with the CAA, sources or
other types of emissions activity within a State from emitting
pollutants in amounts that will ``contribute significantly to
nonattainment in, or interfere with maintenance by, any other State
with respect to'' the NAAQS.
Thus, CAA section 110(a)(2)(D) requires that States prohibit
emissions that contribute significantly to downwind nonattainment. In
the January 2004 proposal, we discussed both the air quality component
and the cost-effectiveness component of the ``contribute
significantly'' determination. The EPA has interpreted CAA section
110(a)(2)(D) to require that States reduce emissions by specified
amounts, and has based those amounts on the availability of highly
cost-effective controls for certain source categories. Following this
interpretation, EPA based the January 2004 proposal on the availability
of highly cost-effective reductions of SO2 and
NOX from EGUs in States that meet EPA's proposed inclusion
criteria.
We noted in the January 2004 proposal, with respect to the cost-
effectiveness component, that one factor we consider in determining
cost effectiveness is the identification of source categories which
emit relatively large amounts of the relevant emissions. We noted that
this element is particularly important in a case such as the proposed
CAIR where the Federal government is proposing a multi-State regional
approach to reducing transported pollution. (69 FR 4611).
One approach cited in the January 2004 proposal for ensuring that
both the air quality component and the cost effectiveness component of
the section 110 ``contribute significantly'' determination is met, is
to consider a source category's contribution to ambient concentrations
above the attainment level in all nonattainment areas in affected
downwind States. Some have recommended a further refinement of this
concept, suggesting that a source category should be included only if
the proposed level of additional control of that category would meet a
specified threshold. Under this suggested approach, EPA could
determine, for example, that inclusion of a source category in a broad
multi-State SIP call would be appropriate only if it would result in at
least 0.5 percent of U.S. counties and/or parishes in the lower 48
States coming into attainment with a NAAQS. Given the number of
counties and parishes in the United States, this requirement would be
met if at least 16 counties in the lower 48 States were brought into
attainment with a NAAQS as a result of the proposed level of control on
a particular source category. Choice of a factor as low as 0.5 percent
of U.S. counties and/or parishes reflects the fact, according to this
approach, that, for every NAAQS, the vast majority of counties are
already in attainment. Nevertheless, for most criteria pollutants, this
figure represents a significant portion of the remaining nonattainment
problem.
The EPA seeks comment on whether this test should be incorporated
as a part of the ``highly cost-effective'' component of the
``contribute significantly'' requirement of CAA section 110(a)(2)(D)
when a multi-State call for SIP revisions to address interstate
transport of air pollution is at issue. The EPA has conducted air
quality modeling of the January 2004 proposal which indicates that the
proposed emissions reductions will bring 34 additional areas (from a
base of 73 down to 39) into attainment with either the PM2.5 or 8-hour
ozone NAAQS by 2015. Since there are over 3,000 counties and parishes
in the lower 48 States, basing the highly cost-effective control levels
in the proposed CAIR on EGUs would meet this 0.5 percent criterion.
States retain authority to decide which sources to control to
achieve the required amounts of reductions, but EPA considers the costs
of controls for more sources in determining what is a significant
contribution. Other CAA mechanisms, such as SIP disapproval authority
and State petitions under CAA section 126, are available to address
more isolated instances of the interstate transport of pollutants.
B. Summary of Control Costs
The control cost summary provided on 69 FR 4632 column 2 indicates
a marginal cost per ton of SO2 emissions of $805 in the
first phase, and $989 in the second phase, of the proposed control
program. These amounts were based on modeling performed to evaluate the
implications of using retirement ratios to implement the emission
reduction requirements of the
[[Page 32721]]
rule. This modeling is different from the modeling used to evaluate
highly cost-effective controls. The latter modeling is summarized in
Table VI-1 on 69 FR 4613, and shows marginal costs of $700 per ton in
the first phase, and $1000 per ton in the second phase.
C. Source of Cost Information
On 69 FR 4614, Table VI-4, EPA failed to include an additional
footnote referencing the source of the cost information for the last
entry in the table, ``Revision of NSPS for New EGUs.'' The footnote
should have indicated that the cost information is derived from
``Proposed Revision of Standards of Performance for Nitrogen Oxide
Emissions from New Fossil-Fuel Fired Steam Generating Units: Proposed
Revisions to Reporting Requirements for Standards of Performance for
New Fossil-Fuel Fired Steam Generating Units,'' 62 FR 36951. The
control costs for SCR shown in the table are for coal-fired utility
steam generating units and coal-fired industrial steam generating
units. The proposed NSPS revision included ranges of costs; EPA
presented the mid-point from those ranges in the table.
D. Judicial Review Under Clean Air Act Section 307
The EPA did not discuss in the January 2004 proposal the applicable
provisions for judicial review of CAA section 307. Section 307(b)(1)
indicates in which Federal Courts of Appeal petitions of review of
final actions by EPA must be filed. This section provides, in part,
that petitions for review must be filed in the Court of Appeals for the
District of Columbia Circuit if (i) the agency action consists of
``nationally applicable regulations promulgated, or final action taken,
by the Administrator,'' or (ii) the agency action is locally or
regionally applicable, but ``such action is based on a determination of
nationwide scope or effect and * * * in taking such action the
Administrator finds and publishes that such action is based on such a
determination.''
Any final action related to the CAIR is ``nationally applicable''
within the meaning of section 307(b)(1). As an initial matter, through
this rule, EPA interprets section 110(a)(2)(D)(i) of the CAA in a way
that could affect future actions regulating the transport of
pollutants. In addition the January 2004 proposal would require 29
States and the District of Columbia to decrease emissions of either
SO2 or NOX, or both. The Interstate Air Quality
Rule is based on a common core of factual findings and analyses
concerning the transport of ozone, PM2.5 and their precursors between
the different States subject to the Interstate Air Quality Rule.
Finally, EPA has established uniform approvability criteria that would
be applied to all States subject to the Interstate Air Quality Rule.
For these reasons, the Administrator also is determining that any final
action regarding the Interstate Air Quality Rule is of nationwide scope
and effect for purposes of section 307(b)(1). Thus, any petitions for
review of final actions regarding the Interstate Air Quality Rule must
be filed in the Court of Appeals for the District of Columbia Circuit
within 60 days from the date final action is published in the Federal
Register.
VI. Statutory and Executive Order Reviews
This section of the SNPR discusses reviews conducted to meet the
requirements of applicable statutes and executive orders. In the
January 2004 proposal (69 FR 4566, January 30, 2004), EPA addressed the
regulatory requirements that trigger statutory and executive order
reviews. This supplemental proposal does not add substantive regulatory
requirements. Rather, in general, it proposes a legal determination
that implementation of the model rule will meet the better-than-BART
requirements, clarifies aspects of the January 2004 proposal, and adds
regulatory text for the proposals in the January 2004 proposal.
Therefore, this supplemental proposal does not alter the findings of
the January 2004 proposal.
The EPA provides additional information below relating to the
National Technology Transfer and Advancement Act. In addition, the EPA
plans to conduct additional analyses as discussed in the January 2004
proposal relating to the Paperwork Reduction Act (PRA), the Regulatory
Flexibility Act (5 U.S.C. 601 et seq.) (RFA), as amended by the Small
Business Regulatory Enforcement Fairness Act (Pub. L. 104-121)
(SBREFA), and the Unfunded Mandates Reform Act of 1995 (Pub. L. 104-4)
(UMRA) in the Notice of Final Rulemaking for this action. The EPA
believes the analyses relating to the RFA and UMRA are not required for
this rule by statute, but these analyses will be conducted for
informational purposes. While it doesn't alter EPA's findings, EPA has
performed additional analysis of the impact that the proposed CAIR may
have on States not affected by the proposed CAIR. This analysis is
available in the docket.
National Technology Transfer Advancement Act. Section 12(d) of the
National Technology Transfer and Advancement Act (NTTAA) of 1995 (Pub.
L. 104-113; 15 U.S.C. 272 note) directs EPA to use voluntary consensus
standards in their regulatory and procurement 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, business practices)
developed or adopted by one or more voluntary consensus bodies. The
NTTAA directs EPA to provide Congress, through annual reports to OMB,
with explanations when an agency does not use available and applicable
voluntary consensus standards.
This SNPR would require all sources that participate in the trading
program under proposed part 96 to meet the applicable monitoring
requirements of 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 proposing 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
Sec. 75.66 before they are used under part 75. We welcome comments on
this aspect of the proposed rulemaking and, specifically, invite the
public to identify potentially applicable voluntary consensus standards
and to explain why EPA should use such standards in this regulation.
VII. Proposed Rule Text
This SNPR includes the proposed rule text for the CFR for the basic
elements of the CAIR proposal. This rule text includes the requirements
for the affected jurisdictions to submit transport SIPs under the
PM2.5 standard, the 8-hour ozone standard, or both; as well
as for implementation of the
[[Page 32722]]
applicable SO2 and NOX emissions budgets. It also
includes model rule language that States may adopt for interstate
trading rules. The rule language is located at the end of the preamble.
Specifically, EPA is today proposing to amend or revise the
following rule text:
(i) Part 51 subpart A, Sec. Sec. 51.1 through 51.45;
(ii) Part 51 subpart G, Sec. Sec. 51.122 through 51.125;
(iii) Part 51, Sec. 51.308;
(iv) Part 72, Sec. 72.2;
(v) Part 73, various Sec. Sec. 73.1 through 73.70;
(vi) Part 74, various Sec. Sec. 74.18 through 74.50;
(vii) Part 77, various Sec. Sec. 77.3 through 77.6;
(viii) Part 78, Sec. Sec. 78.1, 78.3, 78.4 and 78.12;
(ix) Part 96, Sec. Sec. 96.101 through 96.186 (NOX trading)
and Sec. Sec. 96.201 through 96.286 (SO2 trading).
List of Subjects
40 CFR Part 51
Environmental Protection, Administrative practice and procedure,
Air pollution control, Intergovernmental relations, Nitrogen dioxide,
Ozone, Particulate matter, Reporting and recordkeeping requirements,
Sulfur oxides.
40 CFR Parts 72, 73, 74, 77 and 78
Environmental Protection, Acid rain, Administrative practice and
procedure, Air pollution control, Electric utilities, Intergovernmental
relations, Nitrogen oxides, Reporting and recordkeeping requirements,
Sulfur oxides.
40 CFR Part 96
Environmental Protection, Administrative practice and procedure,
Air pollution control, Nitrogen oxides, Reporting and recordkeeping
requirements.
Dated: May 18, 2004.
Michael O. Leavitt,
Administrator.
Title 40, chapter I, of the Code of Federal Regulations is 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.
2. Part 51 subpart A is revised to read as follows:
Subpart A--Emission Inventory Reporting Requirements
General Information for Inventory Preparers
Sec.
51.1 Who is responsible for actions described in this subpart?
51.5 What tools are available to help prepare and report emissions
data?
51.10 How does my State report emissions that are required by the
NOX SIP Call and the Clean Air Interstate Rule?
Specific Reporting Requirements
51.15 What data does my State need to report to EPA?
51.20 What are the emission thresholds that separate point and non-
point sources?
51.25 What geographic area must my State's inventory cover?
51.30 When does my State report which emissions data to EPA?
51.35 How can my State equalize the emissions inventory effort from
year-to-year?
51.40 In what form and format should my State report the data to
EPA?
51.45 Where should my State report the data?
Appendix A to Subpart A of Part 51--Tables and Definitions
Appendix B to Subpart A of Part 51--[Reserved]
Subpart A--Emission Inventory Reporting Requirements
General Information for Inventory Preparers
Sec. 51.1 Who is responsible for actions described in this subpart?
States must inventory emission sources located on non-tribal lands
and report this information to EPA.
Sec. 51.5 What tools are available to help prepare and report
emissions data?
We urge your State to use estimation procedures described in
documents from the Emission Inventory Improvement Program (EIIP). These
procedures are standardized and ranked according to relative
uncertainty for each emission estimating technique. Using this guidance
will enable others to use your State's data and evaluate its quality
and consistency with other data.
Sec. 51.10 How does my State report emissions that are required by
the NOX SIP Call and the Clean Air Interstate Rule ?
The District of Columbia and States that are subject to the
NOX SIP Call (Sec. 51.121) are subject to the emission
reporting provisions of Sec. 51.122. The District of Columbia and
States that are subject to the Clean Air Interstate Rule are subject to
the emission reporting provisions of Sec. 51.125. This subpart A
incorporates the pollutants, source, time periods, and required data
elements for both of these reporting requirements.
Specific Reporting Requirements
Sec. 51.15 What data does my State need to report to EPA?
(a) Pollutants. Report actual emissions of the following (see
Definitions in appendix A to this subpart for precise definitions as
required):
(1) Required pollutants for triennial reports of annual (12-month)
emissions for all sources and every-year reports of annual emissions
from Type A sources:
(i) Sulfur dioxide (SO2).
(ii) Volatile organic compounds (VOC).
(iii) Nitrogen oxides (NOX).
(iv) Carbon monoxide (CO).
(v) Lead and lead compounds.
(vi) Primary PM2.5. Emissions of filterable,
condensible, and total PM2.5. should be reported, if all are
applicable to the source type.
(vii) Primary PM10. Emissions of filterable,
condensible, and total PM10 should be reported, if all are
applicable to the source type.
(viii) Ammonia (NH3).
(2) Required pollutants for every-year reporting of annual (12-
month) emissions for sources controlled to meet the requirements of
Sec. 51.123: NOX.
(3) Required pollutants for every-year reporting of annual (12-
month) emissions of sources controlled to meet the requirements of
51.124: SO2.
(4) Required pollutants for all reports of ozone season (5 months)
emissions: NOX.
(5) Required pollutants for triennial reports of summer daily
emissions:
(i) NOX.
(ii) VOC.
(6) Required pollutants for every-year reports of summer daily
emissions: NOX.
(7) A State may at its option include in its emissions inventory
reports estimates of emissions for additional pollutants such as other
pollutants listed in paragraph (a)(1) or hazardous air pollutants.
(b) Sources. Emissions should be reported from the following
sources in all parts of the State, excluding sources located on tribal
lands:
(1) Point.
(2) Non-point.
(3) Onroad mobile.
(4) Nonroad mobile.
(c) Supporting information. You must report the data elements in
Tables 2a through 2d of appendix A to this subpart. You must also
report information on the method of determination for data elements EPA
may designate for such reporting in each reporting period. Additional
information not listed in Tables 2a through 2d may be required, for
[[Page 32723]]
example information identifying the State contact person for the
submittal. We may ask you for other data on a voluntary basis to meet
special purposes.
(d) Confidential data. We do not consider the data in Tables 2a
through 2d of appendix A to this subpart confidential, but some States
limit release of this type of data. Any data that you submit to EPA
under this rule will be considered in the public domain and cannot be
treated as confidential. If Federal and State requirements are
inconsistent, consult your EPA Regional Office for a final
reconciliation.
(e) Option to Submit Inputs to Emission Inventory Estimation Models
in Lieu of Emission Estimates. For a given reporting year, EPA may
allow States to submit comprehensive input values for models capable of
estimating emissions from a certain source type on a national scale, in
lieu of submitting the emission estimates otherwise required by this
subpart.
Sec. 51.20 What are the emission thresholds that separate point and
non-point sources?
(a) All anthropogenic stationary sources must be included in your
inventory as either point or non-point sources, except that biogenic
emissions are not required to be reported.
(b) Sources which are major sources under section 302 or part D of
title I of the Clean Air Act, considering emissions only of the
pollutants listed in Sec. 51.15(a), must be reported as point sources,
starting with the 2008 inventory year. Provisions of part 70 affecting
the definition of a major source apply to this subpart also. All
pollutants specified in Sec. 51.15(a) must be reported for point
sources, not just the pollutant(s) which qualify the source as a point
source. Prior to the 2008 inventory year, States may omit from point
source treatment any source that would not be major if its actual
emissions were considered rather than its potential to emit.
(c) If your State has lower emission reporting thresholds for point
sources than paragraph (b) of this section, then you may use these in
reporting your emissions to EPA.
(d) All stationary sources that are not subject to reporting as
point sources must be reported as non-point sources. This includes wild
fires and prescribed fires. Episodic wind-generated particulate matter
emissions from sources that are not major sources may be excluded, for
example dust lifted by high winds from natural or tilled soil.
Emissions of non-point sources may be aggregated to the county level,
but must be separated and identified by source classification code
(SCC). Non-point source categories or emission events reasonably
estimated by the State to represent a de minimis percentage of total
county and State emissions of a given pollutant may be omitted.
Sec. 51.25 What geographic area must my State's inventory cover?
Because of the regional nature of these pollutants, your State's
inventory must be statewide, regardless of any area's attainment
status.
Sec. 51.30 When does my State report which emissions data to EPA?
All States are required to report two basic types of emission
inventories to EPA: Every-year Cycle Inventory; and Three-year Cycle
Inventory. The sources and pollutant to be reported vary among States.
(a) Every-year cycle. See Tables 2a, 2b, and 2c of appendix A to
this subpart for the specific data elements to report every year.
(1) All States are required to report every year the annual (12-
month) emissions of all pollutants listed in Sec. 51.15(a)(1) from
Type A (large) point sources, as defined in Table 1. The first every-
year cycle inventory will be for the year 2003 and must be submitted to
EPA within 17 months, i.e., by June 1, 2005. Subsequent every-year
cycle inventories will be due 17 months following the end of the
reporting year.
(2) States subject to Sec. Sec. 51.123 and 51.125 of this subpart
are required to report every year the annual (12-month) emissions of
NOX from any point, non-point, onroad mobile, or nonroad
mobile source for which the State specified control measures in its SIP
submission under Sec. 51.123 of this subpart. This requirement begins
with the 2009 inventory year. This requirement does not apply to any
State subject to Sec. 51.123 solely because of its contribution to
ozone nonattainment in another State.
(3) States subject to Sec. Sec. 51.124 and 51.125 of this subpart
are required to report every year the annual (12-month) emissions of
SO2 from any point, non-point, onroad mobile, or nonroad
mobile source for which the State specified control measures in its SIP
submission under Sec. 51.124 of this subpart. This requirement begins
with the 2009 inventory year.
(4) States subject to Sec. Sec. 51.123 and 51.125 are required to
report every year the ozone season emissions of NOX and
summer daily emissions of NOX from any point, non-point,
onroad mobile, or nonroad mobile source for which the State specified
control measures in its SIP submission under Sec. 51.123 of this
subpart. This requirement begins with the 2009 inventory year. This
requirement does not apply to any State subject to Sec. 51.123 solely
because of its contribution to PM2.5 nonattainment in
another State.
(5) States subject to the emission reporting requirements of Sec.
51.122 are required to report every year the ozone season emissions of
NOX and summer daily emissions of NOX from any
point, non-point, onroad mobile, or nonroad mobile source for which the
State specified control measures in its SIP submission under Sec.
51.121(g) of this subpart. This requirement begins with the inventory
year prior to the year in which compliance with the NOX SIP
Call requirements is first required.
(6) If sources report SO2 and NOX emissions
data to EPA in a given year pursuant to a trading program approved
under Sec. 51.123(o) or Sec. 51.124(o) of this part or pursuant to
the monitoring and reporting requirements of subpart H of 40 CFR 75,
then the State need not provide annual reporting of the pollutants to
EPA for such sources. If SO2 and NOX are the only
pollutants required to be reported for the source for the given
calendar year and emissions period (annual, ozone season, or summer
day), all data elements for the source may be omitted from the State's
emissions report for that period. We will make both the raw data
submitted by sources to the trading programs and summary data available
to any State that chooses this option.
(7) In years which are reporting years under the 3-year cycle, the
reporting required by the 3-year cycle satisfies the requirements of
this paragraph.
(b) Three-year cycle. See Tables 2a, 2b and 2c of appendix A to
this subpart for the specific data elements that must be reported
triennially.
(1) All States are required to report for every third year the
annual (12-month) emissions of all pollutants listed in Sec.
51.15(a)(1) from all point sources, non-point sources, onroad mobile
sources, and nonroad mobile sources. The first 3-year cycle inventory
will be for the year 2005 and must be submitted to us within 17 months,
i.e., by June 1, 2007. Subsequent 3-year cycle inventories will be due
17 months following the end of the reporting year.
(2) States subject to Sec. 51.122 must report ozone season
emissions and summer daily emissions of NOX from all point
sources, non-point sources, onroad mobile sources, and nonroad mobile
sources. The first 3-year cycle inventory will be for the year 2005 and
must be submitted to us within 17 months, i.e., by June 1, 2007. For
States with a NOX SIP Call compliance date of
[[Page 32724]]
2007, the first 3-year cycle inventory will be for 2008. Subsequent 3-
year cycle inventories will be due 17 months following the end of the
reporting year.
(3) States subject to Sec. Sec. 51.123 and 51.125 must report
ozone season emissions of NOX and summer daily emissions of
VOC and NOX from all point sources, non-point sources,
onroad mobile sources, and nonroad mobile sources. The first 3-year
cycle inventory will be for the year 2008 and must be submitted to us
within 17 months, i.e., by June 1, 2010. Subsequent 3-year cycle
inventories will be due 17 months following the end of the reporting
year. This requirement does not apply to any State subject to Sec.
51.123 solely because of its contribution to PM2.5
nonattainment in another State.
(4) Any State with an area for which EPA has made an 8-hour ozone
nonattainment designation finding (regardless of whether that finding
has reached its effective date) must report summer daily emissions of
VOC and NOX from all point sources, non-point sources,
onroad mobile sources, and nonroad mobile sources. The first 3-year
cycle inventory will be for the year 2005 and must be submitted to us
within 17 months, i.e., by June 1, 2007. Subsequent 3-year cycle
inventories will be due 17 months following the end of the reporting
year.
Sec. 51.35 How can my State equalize the emissions inventory effort
from year to year?
(a) Compiling a 3-year cycle inventory means much more effort every
3 years. As an option, your State may ease this workload spike by using
the following approach:
(1) Each year, collect and report data for all Type A (large) point
sources (This is required for all Type A point sources).
(2) Each year, collect data for one-third of your smaller point
sources. Collect data for a different third of these sources each year
so that data has been collected for all of the smaller point sources by
the end of each 3-year cycle. You must save 3 years of data and then
report all of the smaller point sources on the 3-year cycle due date.
(3) Each year, collect data for one-third of the area, nonroad
mobile, and onroad mobile sources. You must save 3 years of data and
then report all of these data on the 3-year cycle due date.
(b) For the sources described in paragraph (a) of this section,
your State will therefore have data from 3 successive years at any
given time, rather than from the single year in which it is compiled.
(c) If your State chooses the method of inventorying one-third of
your smaller point sources and 3-year cycle area, nonroad mobile,
onroad mobile sources each year, your State must compile each year of
the 3-year period identically. For example, if a process hasn't changed
for a source category or individual plant, your State must use the same
emission factors to calculate emissions for each year of the 3-year
period. If your State has revised emission factors during the 3 years
for a process that hasn't changed, resubmit previous year's data using
the revised factor. If your State uses models to estimate emissions,
you must make sure that the model is the same for all three years.
(d) If your State needs a new reference year emission inventory for
a selected pollutant, your State can not use these optional reporting
frequencies for the new reference year.
(e) If your State is a NOX SIP Call State, you can not
use these optional reporting frequencies for NOX SIP Call
reporting.
Sec. 51.40 In what form and format should my State report the data to
EPA?
You must report your emission inventory data to us in electronic
form. We support specific electronic data reporting formats and you are
required to report your data in a format consistent with these. The
term format encompasses the definition of one or more specific data
fields for each of the data elements listed in Tables 2a, 2b, and 2c;
allowed code values for categorical data fields; transmittal
information; and data table relational structure. Because electronic
reporting technology continually changes, contact the Emission Factor
and Inventory Group (EFIG) for the latest specific formats. You can
find information on the current formats at the following Internet
address: http://www.epa.gov /ttn/chief/nif/ index.html. You may also
call the air emissions contact in your EPA Regional Office or our Info
CHIEF help desk at (919) 541-1000 or e-mail to info.chief@epa.gov.
Sec. 51.45 Where should my State report the data?
(a) Your State submits or reports data by providing it directly to
EPA.
(b) The latest information on data reporting procedures is
available at the following Internet address: http://www.epa.gov/ ttn/
chief. You may also call our Info CHIEF help desk at (919) 541-1000 or
e-mail to info.chief@epa.gov.
Appendix A to Subpart A of Part 51--Tables and Definitions
Table 1.--Emission Thresholds by Pollutant (tpy1) for Treatment of Point
Sources as Type A Under Sec. 51.30
------------------------------------------------------------------------
Emissions threshold for type
Pollutant A treatment
------------------------------------------------------------------------
1. SO2.................................... >=2500
2. VOC.................................... >=250
3. NOX.................................... >=2500
4. CO..................................... >=2500
5. Pb..................................... Does not determine Type A
status
6. PM10................................... >=250
7. PM2.5.................................. >=250
8. NH3\2\................................. >=250
------------------------------------------------------------------------
\1\ tpy = tons per year of actual emissions.
\2\ Ammonia threshold applies only in areas where ammonia emissions are
a factor in determining whether a source is a major source, i.e.,
where ammonia is considered a significant precursor of PM2.5.
Table 2a.--Data Elements for Reporting on Emissions From Point Sources,
Where Required by Sec. 51.30
------------------------------------------------------------------------
Every-year Three-year
Data elements reporting reporting
------------------------------------------------------------------------
1. Inventory year........................... [check] [check]
2. Inventory start date..................... [check] [check]
3. Inventory end date....................... [check] [check]
4. Inventory type........................... [check] [check]
5. FIPS code................................ [check] [check]
6. Facility ID codes........................ [check] [check]
7. Unit ID code............................. [check] [check]
8. Process ID code.......................... [check] [check]
9. Stack ID code............................ [check] [check]
10. Site name............................... [check] [check]
11. Physical address........................ [check] [check]
[[Page 32725]]
12. SCC or PCC.............................. [check] [check]
13. Heat content (fuel) (annual average).... [check] [check]
14. Heat content (fuel) (ozone season, if [check] [check]
applicable)................................
15. Ash content (fuel)(annual average)...... [check] [check]
16. Sulfur content (fuel)(annual average)... [check] [check]
17. Pollutant code.......................... [check] [check]
18. Activity/throughput (for each period [check] [check]
reported)..................................
19. Summer daily emissions (if applicable).. [check] [check]
20. Ozone season emissions (if applicable).. [check] [check]
21. Annual emissions........................ [check] [check]
22. Emission factor......................... [check] [check]
23. Winter throughput (percent)............. [check] [check]
24. Spring throughput (percent)............. [check] [check]
25. Summer throughput (percent)............. [check] [check]
26. Fall throughput (percent)............... [check] [check]
27. Hr/day in operation..................... [check] [check]
28. Start time (hour)....................... [check] [check]
29. Day/wk in operation..................... [check] [check]
30. Wk/yr in operation...................... [check] [check]
31. X stack coordinate (longitude) with [check]
method accuracy descriptions...............
32. Y stack coordinate (latitude) with [check]
method accuracy descriptions...............
33. Stack height............................ [check]
34. Stack diameter.......................... [check]
35. Exit gas temperature.................... [check]
36. Exit gas velocity....................... [check]
37. Exit gas flow rate...................... [check]
38. SIC/NAICS and at the facility and unit [check]
levels.....................................
39. Design capacity (including boiler [check]
capacity if applicable)....................
40. Maximum generator nameplate capacity.... [check]
41. Primary capture and control efficiencies [check]
(percent)..................................
42. Total capture and control efficiency [check]
(percent)..................................
43. Control device type..................... [check]
44. Rule effectiveness (percent)............ [check]
------------------------------------------------------------------------
Table 2b.--Data Elements for Reporting on Emissions From Non-Point
Sources and Nonroad Mobile Sources, Where Required by Sec. 51.30
------------------------------------------------------------------------
Every-year Three-year
Data elements reporting reporting
------------------------------------------------------------------------
1. Inventory year........................... [check] [check]
2. Inventory start date..................... [check] [check]
3. Inventory end date....................... [check] [check]
4. Inventory type........................... [check] [check]
5. FIPS code................................ [check] [check]
6. SCC or PCC............................... [check] [check]
7. Emission factor.......................... [check] [check]
8. Activity/throughput level (for each [check] [check]
period reported)...........................
9. Total capture/control efficiency [check] [check]
(percent)..................................
10. Rule effectiveness (percent)............ [check] [check]
11. Rule penetration (percent).............. [check] [check]
12. Pollutant code.......................... [check] [check]
13. Ozone season emissions (if applicable).. [check] [check]
14. Summer daily emissions (if applicable).. [check] [check]
15. Annual emissions........................ [check] [check]
16. Winter throughput (percent)............. [check] [check]
17. Spring throughput (percent)............. [check] [check]
18. Summer throughput (percent)............. [check] [check]
19. Fall throughput (percent)............... [check] [check]
20. Hrs/day in operation.................... [check] [check]
21. Days/wk in operation.................... [check] [check]
22. Wks/yr in operation..................... [check] [check]
------------------------------------------------------------------------
[[Page 32726]]
Table 2c.--Data Elements for Reporting on Emissions From Onroad Mobile
Sources, Where Required by Sec. 51.30
------------------------------------------------------------------------
Every-year Three-year
Data elements reporting reporting
------------------------------------------------------------------------
1. Inventory year........................... [check] [check]
2. Inventory start date..................... [check] [check]
3. Inventory end date....................... [check] [check]
4. Inventory type........................... [check] [check]
5. FIPS code................................ [check] [check]
6. SCC or PCC............................... [check] [check]
7. Emission factor.......................... [check] [check]
8. Activity (VMT by SCC).................... [check] [check]
9. Pollutant code........................... [check] [check]
10. Ozone season emissions (if applicable).. [check] [check]
11. Summer daily emissions (if applicable).. [check] [check]
12. Annual emissions........................ [check] [check]
13. Winter throughput (percent)............. [check] [check]
14. Spring throughput (percent)............. [check] [check]
15. Summer throughput (percent)............. [check] [check]
16. Fall throughput (percent)............... [check] [check]
------------------------------------------------------------------------
Definitions
Activity throughput--A measurable factor or parameter that relates
directly or indirectly to the emissions of an air pollution source
during the period for which emissions are reported. Depending on the
type of source category, activity information may refer to the amount
of fuel combusted, raw material processed, product manufactured, or
material handled or processed. It may also refer to population,
employment, or number of units. Activity information is typically the
value that is multiplied against an emission factor to generate an
emissions estimate.
Annual emissions--Actual emissions for a plant, point, or process--
measured or calculated that represent a calendar year.
Ash content--Inert residual portion of a fuel.
Biogenic sources--Biogenic emissions are all pollutants emitted
from non-anthropogenic sources. Example sources include trees and
vegetation, oil and gas seeps, and microbial activity.
Control device type--The name of the type of control device (e.g.,
wet scrubber, flaring, or process change).
Day/wk in operations--Days per week that the emitting process
operates--average over the inventory period.
Design capacity--A measure of the size of a point source, based on
the reported maximum continuous throughput or output capacity of the
unit. For a boiler, design capacity is based on the reported maximum
continuous steam flow, usually in units of million BTU per hour.
Emission factor--Ratio relating emissions of a specific pollutant
to an activity or material throughput level.
Exit gas flow rate--Numeric value of stack gas's flow rate.
Exit gas temperature--Numeric value of an exit gas stream's
temperature.
Exit gas velocity--Numeric value of an exit gas stream's velocity.
Facility ID codes--Unique codes for a plant or facility treated as
a point source, containing one or more pollutant-emitting units. The
EPA's reporting format for a given reporting year may require several
facility ID codes to ensure proper matching between data bases, e.g.,
the State's own current and most recent facility ID codes, the EPA-
assigned facility ID codes, and the ORIS (Department of Energy) ID code
if applicable.
Fall throughput (percent)--Part of the throughput for the three
Fall months (September, October, November). This expresses part of the
annual activity information based on four seasons--typically spring,
summer, fall, and winter. It can be a percentage of the annual activity
(e.g., production in summer is 40 percent of the year's production) or
units of the activity (e.g., out of 600 units produced, spring = 150
units, summer = 250 units, fall = 150 units, and winter = 50 units).
FIPS Code--Federal Information Placement System (FIPS)is the system
of unique numeric codes the government developed to identify States,
counties and parishes for the entire United States, Puerto Rico, and
Guam.
Heat content--The amount of thermal heat energy in a solid, liquid,
or gaseous fuel, averaged over the period for which emissions are
reported. Fuel heat content is typically expressed in units of Btu/lb
of fuel, Btu/gal of fuel, joules/kg of fuel, etc.
Hr/day in operations--Hours per day that the emitting process
operates--average over the inventory period.
Inventory end date--Last day of the inventory period.
Inventory start date--First day of the inventory period.
Inventory type--A code indicating whether the inventory submission
includes emissions of hazardous air pollutants.
Inventory year--The calendar year for which you calculated
emissions estimates.
Lead (Pb)--As defined in 40 CFR 50.12, lead should be reported as
elemental lead and its compounds.
Maximum nameplate capacity--A measure of the size of a generator
which is put on the unit's nameplate by the manufacturer. The data
element is reported in megawatts or kilowatts.
Mobile source--A motor vehicle, nonroad engine or nonroad vehicle,
where:
A ``motor vehicle'' is any self-propelled vehicle used to carry
people or property on a street or highway.
A ``nonroad engine'' is an internal combustion engine (including
fuel system) that is not used in a motor vehicle or vehicle only used
for competition, or that is not affected by Sec. Sec. 111 or 202 of
the CAA.
A ``nonroad vehicle'' is a vehicle that is run by a nonroad engine
and that is not a motor vehicle or a vehicle only used for competition.
Nitrogen oxides (NOX)--The EPA has defined nitrogen
oxides (NOX) in 40 CFR part 60.2 as all oxides of nitrogen
except N2O. Nitrogen Oxides should be reported on an
equivalent molecular weight basis as nitrogen dioxide (NO2).
Non-point sources--Non-point sources collectively represent
[[Page 32727]]
individual sources that have not been inventoried as specific point,
mobile, or biogenic sources. These individual sources treated
collectively as non-point sources are typically too small, numerous, or
difficult to inventory using the methods for the other classes of
sources.
Ozone Season--The period May 1 through September 30 of a year.
PM (Particulate Matter)--Particulate matter is a criteria air
pollutant. For the purpose of this subpart, the following definitions
apply:
(1) Filterable PM2.5 or Filterable PM10:
Particles that are directly emitted by a source as a solid or liquid at
stack or release conditions and captured on the filter of a stack test
train. Filterable PM2.5 is particulate matter with an
aerodynamic diameter equal to or less than 2.5 micrometers. Filterable
PM10 is particulate matter with an aerodynamic diameter
equal to or less than 10 micrometers.
(2) Condensible PM: Material that is vapor phase at stack
conditions, but which condenses and/or reacts upon cooling and dilution
in the ambient air to form solid or liquid PM immediately after
discharge from the stack. Note that all condensible PM, if present from
a source, is typically in the PM2.5 size fraction, and
therefore all of it is a component of both primary PM2.5 and
primary PM10.
(3) Primary PM2.5: The sum of filterable
PM2.5 and condensible PM.
(4) Primary PM10: The sum of filterable PM10
and condensible PM.
(5) Secondary PM: Particles that form or grow in mass through
chemical reactions in the ambient air well after dilution and
condensation have occurred. Secondary PM is usually formed at some
distance downwind from the source. Secondary PM should not be reported
in the emission inventory and is not covered by this subpart.
PCC--Process classification code. A process-level code that
describes the equipment or operation which is emitting pollutants. This
code is being considered as a replacement for the SCC.
Physical address--Street address of a facility. This is the address
of the location where the emissions occur; not, for example, the
corporate headquarters.
Point source--Point sources are large, stationary (non-mobile),
identifiable sources of emissions that release pollutants into the
atmosphere. As used in this rule, a point source is defined as a
facility that is a major source under Sec. 302 or part D of title I of
the Clean Air Act. Emissions of hazardous air pollutants are not
considered in determining whether a source is a point source under this
subpart.
Pollutant code--A unique code for each reported pollutant assigned
by the reporting format specified by EPA for each reporting year.
Primary capture and control efficiencies (percent)--Two values
indicating the emissions capture efficiency and the emission reduction
efficiency of a primary control device. Capture and control
efficiencies are usually expressed as a percentage or in tenths.
Process ID code--Unique code for the process generating the
emissions, typically a description of a process.
Roadway class--A classification system developed by the Federal
Highway Administration that defines all public roadways as to type
based on land use and physical characteristics of the roadway.
Rule effectiveness (RE)--How well a regulatory program achieves all
possible emission reductions. This rating reflects the assumption that
controls typically are not 100 percent effective because of equipment
downtime, upsets, decreases in control efficiencies, and other
deficiencies in emission estimates. RE adjusts the control efficiency.
Rule penetration--The percentage of a non-point source category
covered by an applicable regulation.
SCC--Source classification code. A process-level code that
describes the equipment and/or operation which is emitting pollutants.
SIC/NAICS--Standard Industrial Classification code. NAICS (North
American Industry Classification System) codes will replace SIC codes.
U.S. Department of Commerce's code for businesses by products or
services.
Site name--The name of the facility.
Spring throughput (percent)--Part of throughput or activity for the
three spring months (March, April, May). See the definition of Fall
Throughput.
Stack diameter--A stack's inner physical diameter.
Stack height--A stack's physical height above the surrounding
terrain.
Stack ID code--Unique code for the point where emissions from one
or more processes release into the atmosphere.
Start time (hour)--Start time (if available) that was applicable
and used for calculations of emissions estimates.
Sulfur content--Sulfur content of a fuel, usually expressed as
percent by weight.
Summer daily emissions--Average day's emissions for a typical
summer day with conditions critical to ozone attainment planning. The
State will select the particular month(s) in summer and the day(s) in
the week to be represented. The selection of conditions should be
coordinated with the conditions assumed in the development of
reasonable further progress plans, rate of progress plans and
demonstrations, and/or emissions budgets for transportation conformity,
to allow comparability of daily emission estimates.
Summer throughput (percent)--Part of throughput or activity for the
three summer months (June, July, August). See the definition of Fall
Throughput.
Total capture and control efficiency (percent)--The net emission
reduction efficiency of all emissions collection and devices.
Type A source--Large point sources with actual annual emissions
greater than or equal to any of the emission thresholds listed in Table
1 for Type A sources.
Unit ID code--Unique code for the unit of generation of emissions,
typically a physical piece or closely related set of equipment. The
EPA's reporting format for a given reporting year may require multiple
unit ID codes to ensure proper matching between data bases, e.g., the
State's own current and most recent unit ID codes, the EPA-assigned
unit ID codes if any, and the ORIS (Department of Energy) ID code if
applicable.
VMT by SCC--Vehicle miles traveled (VMT) disaggregated to the SCC
level, i.e., reflecting combinations of vehicle type and roadway class.
VMT expresses vehicle activity and is used with emission factors. The
emission factors are usually expressed in terms of grams per mile of
travel. Because VMT does not correlate directly to emissions that occur
while the vehicle isn't moving, these nonmoving emissions are
incorporated into the emission factors in EPA's MOBILE Model.
VOC--Volatile Organic Compounds. The EPA's regulatory definition of
VOC is in 40 CFR 51.100.
Winter throughput (percent)--Part of throughput or activity for the
three winter months (December, January, February, all from the same
year, e.g., Winter 2000 = January 2000 + February, 2000 + December
2000). See the definition of Fall Throughput.
Wk/yr in operation--Weeks per year that the emitting process
operates.
X stack coordinate (longitude)--An object's east-west geographical
coordinate.
Y stack coordinate (latitude)--An object's north-south geographical
coordinate.
[[Page 32728]]
Appendix B to Subpart A of Part 51--[Reserved]
3. Part 51 is amended by revising Sec. 51.122 of subpart G to read
as follows:
Sec. 51.122 Emissions reporting requirements for SIP revisions
relating to budgets for NOX emissions.
(a) For its transport SIP revision under Sec. 51.121 of this part,
each State must submit to EPA NOX emissions data as
described in this section.
(b) Each revision must provide for periodic reporting by the State
of NOX emissions data to demonstrate whether the State's
emissions are consistent with the projections contained in its approved
SIP submission.
(1) Every-year reporting cycle. Each revision must provide for
reporting of NOX emissions data every year as follows:
(i) The State must report to EPA emissions data from all
NOX sources within the State for which the State specified
control measures in its SIP submission under Sec. 51.121(g) of this
part. This would include all sources for which the State has adopted
measures that differ from the measures incorporated into the baseline
inventory for the year 2007 that the State developed in accordance with
Sec. 51.121(g) of this part.
(ii) If sources report NOX emissions data to EPA for a
given year pursuant to a trading program approved under Sec. 51.121(p)
of this part or pursuant to the monitoring and reporting requirements
of subpart H of 40 CFR part 75, then the State need not provide an
every-year cycle report to EPA for such sources.
(2) Three-year cycle reporting. Each plan must provide for
triennial (i.e., every third year) reporting of NOX
emissions data from all sources within the State.
(3) The data availability requirements in Sec. 51.116 of this part
must be followed for all data submitted to meet the requirements of
paragraphs (b)(1) and (2) of this section.
(c) The data reported in paragraph (b) of this section must meet
the requirements of subpart A of this part.
(d) Approval of ozone season calculation by EPA. Each State must
submit for EPA approval an example of the calculation procedure used to
calculate ozone season emissions along with sufficient information to
verify the calculated value of ozone season emissions.
(e) Reporting schedules.
(1) Data collection is to begin during the ozone season one year
prior to the State's NOX SIP Call compliance date.
(2) Reports are to be submitted according to paragraph (b) of this
section and the schedule in Table 1. After 2008, triennial reports are
to be submitted every third year and annual reports are to be submitted
each year that a triennial report is not required.
Table 1.--Schedule for Submitting Reports
------------------------------------------------------------------------
Data collection year Type of report required
------------------------------------------------------------------------
2002...................................... Triennial.
2003...................................... Annual.
2004...................................... Annual.
2005...................................... Triennial.
2006...................................... Annual.
2007...................................... Annual.
2008...................................... Triennial.
------------------------------------------------------------------------
(3) States must submit data for a required year no later than 17
months after the end of the calendar year for which the data are
collected.
(f) Data reporting procedures are given in subpart A. When
submitting a formal NOX Budget Emissions Report and
associated data, States shall notify the appropriate EPA Regional
Office.
(g) Definitions. As used in this section, words and terms shall
have the meanings set forth in appendix A of subpart A of this part.
4. Part 51 is amended by adding Sec. 51.123 to Subpart G 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.
(a) Under section 110(a)(1) of the CAA, 42 U.S.C. 7410(a)(1), the
Administrator determines that each State identified in paragraph (c) of
this section must submit a SIP revision to comply with the requirements
of section 110(a)(2)(D)(i)(I) of the CAA, 42 U.S.C.
7410(a)(2)(D)(i)(I), through the adoption of adequate provisions
prohibiting sources and other activities from emitting NOX
in amounts that will contribute significantly to nonattainment in, or
interfere with maintenance by, one or more other States with respect to
the fine particles (PM2.5) and/or the 8-hour ozone NAAQS.
(b) For each State identified in paragraph (c) of this section, the
SIP revision required under paragraph (a) will contain adequate
provisions, for purposes of complying with Sec. 110(a)(2)(D)(i)(I) of
the CAA, 42 U.S.C. 7410(a)(2)(D)(i)(I), only if the SIP revision
contains measures that assure compliance with the applicable
requirements of this section.
(c) The following States are subject to the requirements of this
section: Alabama, Arkansas, Connecticut, Delaware, Florida, Georgia,
Illinois, Indiana, Iowa, Kansas, Kentucky, Louisiana, Maryland,
Massachusetts, Michigan, Minnesota, Mississippi, Missouri, New Jersey,
New York, North Carolina, Ohio, Pennsylvania, South Carolina,
Tennessee, Texas, Virginia, West Virginia, Wisconsin, and the District
of Columbia, provided that Connecticut shall be subject to a seasonal
NOX reduction requirement, unless it adopts an annual
NOX reduction requirement, as described in paragraph (q) of
this section.
(d)(1) The SIP submissions required under paragraph (a) of this
section must be submitted to EPA by no later than 18 months from the
date of promulgation of the final Clean Air Interstate Rule.
(2) The requirements of appendix V shall apply to the SIP
submissions required under paragraph (a) of this section.
(3) The State shall deliver 5 copies of the SIP revision to the
appropriate Regional Office, with a letter giving notice of such
action.
(e)(1)(i) The Annual EGU NOX budget for a State is
defined as the total amount of NOX emissions from all EGUs
in that State for a year if the State meets the requirements of
paragraph (a) of this section by imposing control measures, at least in
part, on EGUs. If a State imposes control measures under this section
on only EGUs, the Annual EGU NOX budget amounts for a State
shall not exceed the amounts, during the indicated periods, specified
in paragraph (e)(2) of this section.
(ii) The Non-EGU Reduction Requirement is defined as the amount of
NOX emission reductions the State demonstrates, in
accordance with paragraph (g) of this section, it will achieve from
non-EGUs during the appropriate period. If a State meets the
requirements of paragraph (a) of this section by imposing control
measures on only non-EGUs, the State's Non-EGU Reduction Requirement
shall equal or exceed the amount specified in paragraph (e)(3) of this
section.
(iii) If a State meets the requirements of paragraph (a) of this
section by imposing control measures on both EGUs and non-EGUs, the
amount of the Non-EGU Reduction Requirement shall equal or exceed the
difference between the amount of the State's Annual EGU NOX
budget specified in paragraph (e)(2) of this section and the amount of
the State's Annual EGU NOX budget specified in the SIP for
the appropriate period.
[[Page 32729]]
(2) For a State that complies with the requirements of paragraph
(a) of this section by imposing control measures only on EGUs, the
amount of the Annual EGU NOX budget, in tons per year, shall
be as follows, for the indicated State, for the indicated period:
------------------------------------------------------------------------
Annual EGU NOX Annual EGU NOX
State budget, 2010 budget, 2015
through 2014 and beyond
------------------------------------------------------------------------
Alabama................................. 67,422 56,185
Arkansas................................ 24,919 20,765
Delaware................................ 5,089 4,241
District of Columbia.................... 215 179
Florida................................. 115,503 96,253
Georgia................................. 63,575 52,979
Illinois................................ 73,622 61,352
Indiana................................. 102,295 85,246
Iowa.................................... 30,458 25,381
Kansas.................................. 32,436 27,030
Kentucky................................ 77,938 64,948
Louisiana............................... 47,339 39,449
Maryland................................ 26,607 22,173
Massachusetts........................... 19,630 16,358
Michigan................................ 60,212 50,177
Minnesota............................... 29,303 24,420
Mississippi............................. 21,932 18,277
Missouri................................ 56,571 47,143
New Jersey.............................. 9,895 8,246
New York................................ 52,503 43,753
North Carolina.......................... 55,763 46,469
Ohio.................................... 101,704 84,753
Pennsylvania............................ 84,552 70,460
South Carolina.......................... 30,895 25,746
Tennessee............................... 47,739 39,783
Texas................................... 224,314 186,928
Virginia................................ 31,087 25,906
West Virginia........................... 68,235 56,863
Wisconsin............................... 39,044 32,537
-----------------
Total............................... 1,600,799 1,333,999
------------------------------------------------------------------------
(3) For a State that complies with the requirements of paragraph
(a) of this section by imposing control measures on only non-EGUs, the
amount of the Non-EGU Reduction Requirement, in tons per year, shall be
as follows, for the indicated State, for the indicated period:
------------------------------------------------------------------------
Non-EGU Non-EGU
reduction reduction
State requirement, requirement,
2010 through 2015 and
2014 \1\ beyond \2\
------------------------------------------------------------------------
Alabama................................. 66,678 72,415
Arkansas................................ 27,581 32,035
Delaware................................ 5,211 6,559
District of Columbia.................... 0 0
Florida................................. 46,097 74,247
Georgia................................. 87,025 100,321
Illinois................................ 96,778 117,148
Indiana................................. 133,705 156,754
Iowa.................................... 51,642 61,219
Kansas.................................. 68,464 74,870
Kentucky................................ 115,962 133,752
Louisiana............................... 2,361 10,651
Maryland................................ 33,793 39,727
Massachusetts........................... 0 0
Michigan................................ 60,688 76,323
Minnesota............................... 71,697 80,280
Mississippi............................. 21,168 26,623
Missouri................................ 76,229 93,657
New Jersey.............................. 19,105 22,154
New York................................ 11,497 21,747
North Carolina.......................... 5,237 15,931
Ohio.................................... 159,696 171,147
Pennsylvania............................ 123,148 142,440
[[Page 32730]]
South Carolina.......................... 33,805 40,454
Tennessee............................... 55,061 62,917
Texas................................... 0 13,572
Virginia................................ 23,813 31,394
West Virginia........................... 86,965 91,337
Wisconsin............................... 66,456 64,863
------------------------------------------------------------------------
\1\ This period refers to each year during the 2010-2014 period.
\2\ This period refers to each year during 2015 and subsequently.
(f) Each SIP revision must set forth control measures to meet the
amounts specified in paragraph (e) of this section, as applicable,
including the following:
(1) A description of enforcement methods including, but not limited
to:
(i) Procedures for monitoring compliance with each of the selected
control measures;
(ii) Procedures for handling violations; and
(iii) A designation of agency responsibility for enforcement of
implementation.
(2)(i) Should a State elect to impose control measures on EGUs,
then those measures must impose a NOX mass emissions cap on
all such sources in the State.
(ii) Should a State elect to impose control measures on fossil
fuel-fired non-EGUs that are boilers or combustion turbines with a
maximum design heat input greater than 250 mmBtu/hr, then those
measures must impose a NOX mass emissions cap on all such
sources in the State.
(iii) Should a State elect to impose control measures on fossil
fuel-fired non-EGUs other than those described in paragraph (f)(2)(ii)
of this section, then those measures must impose a NOX mass
emissions cap on all such sources in the State, or the State must
demonstrate why such emissions cap is not practicable, and adopt
alternative requirements that ensure to the maximum practicable degree
that the State will comply with its requirements under paragraph (e) of
this section, as applicable, in 2010 and subsequent years. (g)(1) Each
SIP revision which includes control measures covering non-EGUs as part
or all of a State's obligation in meeting its requirement under
paragraph (a) of this section must demonstrate that such control
measures are adequate to provide for the timely compliance with the
State's Non-EGU Reduction Requirement under paragraph (e) of this
section, and are not otherwise required under the Clean Air Act.
(2) The demonstration under paragraph (g)(1) of this section must
include the following, with respect to each source category of non-EGUs
for which the SIP requires controls:
(i) A detailed historical baseline inventory of NOX mass
emissions from the source category in a representative year consisting,
at the State's election, of 2002, 2003, 2004, or 2005, or an average of
2 or more of those years, absent the control measures specified in the
SIP submission.
(A) This inventory must represent estimates of actual emissions
based on part 75 monitoring data, if the source category is subject to
part 75 monitoring requirements.
(B) In the absence of part 75 monitoring data, actual emissions
must be estimated using assumptions that ensure a source or source
category's actual emissions are not overestimated, and must include
source-specific or category-specific data. If a State uses factors to
estimate emissions, production or utilization, or effectiveness of
controls or rules for a source category, such factors must be chosen to
ensure that emissions are not overestimated, or the State must justify
the use of another value with additional information showing with
reasonable confidence that the substitute value is more appropriate for
estimating actual emissions.
(C) For measures to reduce emissions from motor vehicles, emission
estimates must be based on an emissions model that has been approved by
EPA for use in SIP development, and must be consistent with the
planning assumptions regarding vehicle miles traveled and other factors
current at the time of the SIP development.
(D) For measures to reduce emissions from nonroad engines or
vehicles, emission estimates must be based on the emission
methodologies recommended in EPA guidance current at the time of the
SIP development or the SIP must document that another method is
superior due to local factors.
(ii) A detailed baseline inventory of NOX mass emissions
from the source category in the years 2010 and 2015, absent the control
measures specified in the SIP submission, and reflecting changes in
these emissions from the historical baseline year to the years 2010 and
2015, based on projected changes in the production input and/or output,
population, vehicle miles traveled, economic activity or other factors
as applicable to this source category.
(A) These inventories must account for implementation of any rules
or regulations that will affect NOX emissions from this
source category, excluding any control measures specified in the SIP
submission to meet the NOX emissions reduction requirements
of this section.
(B) Economic and population forecasts must be as specific as
possible to the applicable industry, State, and county of the source or
source category, and must be consistent with both national projections
and relevant official planning assumptions including estimates of
population and vehicle miles traveled developed through consultation
between State and local transportation and air quality agencies.
However, if these official planning assumptions are themselves
inconsistent with official U.S. Census projections of population and
energy consumption projections contained in the Annual Energy Outlook
published by the U.S. Department of Energy, adjustments must be made to
correct the inconsistency, or the SIP must demonstrate how the official
planning assumptions are more accurate.
(C) These inventories must account for any changes in production
method, materials, fuels, or efficiency that are expected to occur
between the historical baseline year and 2010 or 2015, as appropriate.
(iii) A projection of NOX mass emissions in 2010 and
2015 from the source category identified in paragraph (g)(2)(i) of this
section resulting from implementation of each of the control
[[Page 32731]]
measures specified in the SIP submission.
(A) These inventories must address the possibility that the State's
new control measures may cause production and emissions to shift to
non-regulated or less stringently regulated sources in the source
category in the same or another State, and must include in the
projected emissions inventory any such amounts of emissions that may
shift to other sources.
(B) The State must provide EPA with a summary of the computations,
assumptions, and judgments used to determine the degree of reduction in
projected 2010 and 2015 NOX emissions that will be achieved
from the implementation of the new control measures compared to the
relevant baseline emissions inventory.
(iv) The result of subtracting the amounts in paragraph (g)(2)(iii)
for 2010 and 2015, respectively, from the lower of the amounts in
paragraph (g)(2)(i) or (g)(2)(ii) of this section for 2010 and 2015,
respectively, may be credited towards the State's Non-EGU Reduction
Requirement in paragraph (e)(3) of this section for the appropriate
period.
(v) Each revision must identify the sources of the data used in the
estimate and projection of emissions.
(h) Each revision must comply with Sec. 51.116 (regarding data
availability).
(i) Each revision must provide for monitoring the status of
compliance with any control measures adopted to meet the State's
requirements under paragraph (e) of this section. Specifically, the
revision must meet the following requirements:
(1) The revision must provide for legally enforceable procedures
for requiring owners or operators of stationary sources to maintain
records of, and periodically report to the State:
(i) Information on the amount of NOX emissions from the
stationary sources; and
(ii) Other information as may be necessary to enable the State to
determine whether the sources are in compliance with applicable
portions of the control measures;
(2) The revision must comply with Sec. 51.212 (regarding testing,
inspection, enforcement, and complaints);
(3) If the revision contains any transportation control measures,
then the revision must comply with Sec. 51.213 (regarding
transportation control measures);
(4)(i) If the revision contains measures to control EGUs, then the
revision must require such sources to comply with the monitoring and
reporting provisions of subpart H of part 75.
(ii) If the revision contains measures to control fossil fuel-fired
non-EGUs that are boilers or combustion turbines with a maximum design
heat input greater than 250 mmBtu/hr, then the revision must require
such sources to comply with the monitoring and reporting provisions of
subpart H of part 75.
(iii) If the revision contains measures to control any other non-
EGUs that are not described in paragraph (i)(4)(ii) of this section,
the revision must require such sources to comply with the monitoring
and reporting provisions of subpart H of part 75, or the State must
demonstrate why such requirements are not practicable, and adopt
alternative requirements that ensure to the maximum practicable degree
that the required emissions reductions will be achieved.
(j) Each revision must show that the State has legal authority to
carry out the revision, including authority to:
(1) Adopt emissions standards and limitations and any other
measures necessary for attainment and maintenance of the State's
relevant Annual EGU NOX budget or the Non-EGU Reduction
Requirement, as applicable, under paragraph (e);
(2) Enforce applicable laws, regulations, and standards, and seek
injunctive relief;
(3) Obtain information necessary to determine whether air pollution
sources are in compliance with applicable laws, regulations, and
standards, including authority to require recordkeeping and to make
inspections and conduct tests of air pollution sources; and
(4)(i) Require owners or operators of stationary sources to
install, maintain, and use emissions monitoring devices and to make
periodic reports to the State on the nature and amounts of emissions
from such stationary sources; and
(ii) Make the data described in paragraph (j)(4)(i) of this section
available to the public as reported and as correlated with any
applicable emissions standards or limitations.
(k)(1) The provisions of law or regulation which the State
determines provide the authorities required under this section must be
specifically identified, and copies of such laws or regulations must be
submitted with the SIP revision.
(2) Legal authority adequate to fulfill the requirements of
paragraphs (j)(3) and (4) of this section may be delegated to the State
under Sec. 114 of the CAA.
(l)(1) A revision may assign legal authority to local agencies in
accordance with Sec. 51.232.
(2) Each revision must comply with Sec. 51.240 (regarding general
plan requirements).
(m) Each revision must comply with Sec. 51.280 (regarding
resources).
(n) Each revision must provide for State compliance with the
reporting requirements set forth in Sec. 51.125.
(o)(1) Notwithstanding any other provision of this section, if a
State adopts regulations substantively identical to subparts AA through
HH of part 96 of this chapter, (the model CAIR NOX trading
program), incorporates such part by reference into its regulations, or
adopts regulations that differ substantively from such part only as set
forth in paragraph (o)(2) of this section, then that portion of the
State's SIP revision is automatically approved as meeting the
requirement of paragraph (e)(1)(i) of this section, provided that the
State has the legal authority to take such action and to implement its
responsibilities under such regulations.
(2)(i) If a State adopts an emissions trading program that differs
substantively from subparts AA through HH of part 96 of this chapter
only as described in paragraph (o)(2)(ii) of this section, then the
emissions trading program is approved as set forth in paragraph (o)(1)
of this section.
(ii) The State may decline to adopt the allocation provisions set
forth in subpart EE of part 96 of this chapter and may instead adopt
any methodology for allocating NOX allowances to individual
sources, provided that:
(A) The State's methodology does not allow the State to allocate
NOX allowances in excess of the total amount of
NOX emissions which the State has assigned to its trading
program; and
(B) The State's methodology conforms with the timing requirements
for submission of allocations to the Administrator set forth in Sec.
96.141 of this chapter.
(3) If a State adopts an emissions trading program that differs
substantively from subparts AA through HH of part 96 of this chapter,
other than as set forth in paragraph (o)(2)(ii) of this section, then
such portion of the trading program is not automatically approved as
set forth in paragraph (o)(1) of this section, but will be reviewed by
the Administrator for approvability in accordance with the other
provisions of this section.
(p)(1) The State may revise its applicable implementation plan to
provide that, for each year during which a State imposes controls on
EGUs under paragraph (o) of this section, such EGUs shall not be
subject to the requirements of the State's applicable implementation
plan that meet the requirements of
[[Page 32732]]
Sec. 51.121. The owners and operators of such EGUs shall surrender for
deduction by the Administrator any NOX SIP Call allowances
allocated to such units for any such year.
(2) Notwithstanding a revision by the State authorized under
paragraph (p)(1) of this section, a State's applicable implementation
plan that, without such revision, imposes controls on EGUs under Sec.
51.121 determined by the Administrator to meet the requirements of
Sec. 51.121 shall be deemed to continue to meet the requirements of
Sec. 51.121.(q)(1)(i) The SIP revision required under paragraph (a) of
this section for the State of Connecticut must require emissions
reductions during the ozone season, which begins May 1 and ends
September 30 of any year, commencing with 2010.
(ii) Except as provided under paragraph (q)(2) of this section, the
Administrator shall not approve SIP provisions that adopt the model
CAIR NOX trading program, under subparts AA through HH of
part 96 of this chapter.
(iii) For purposes of determining the applicability of paragraph
(e) of this section to the State of Connecticut's SIP revision required
under paragraph (a) of this section--
(A) The term ``Seasonal EGU NOX budget'' shall replace
the term ``Annual EGU NOX budget;'' and
(B) The Seasonal EGU NOX budget, in tons per season, for
the State of Connecticut shall be 4,360 for the years 2010 through
2014, and 3,633 for the years 2015 and beyond; and
(C) The amount of the Non-EGU Reduction Requirement, in tons per
season, for the State of Connecticut shall be zero, for the years 2010
through 2014, and zero, for the years 2015 and beyond.
(3) In lieu of the SIP provisions required under paragraph (q)(1)
of this section, the Administrator may approve a SIP revision adopted
by the State of Connecticut that requires annual NOX
emissions reductions and that meets the requirements of this section,
as revised by this paragraph.
(i) For purposes of paragraph (e)(2) of this section, the Annual
EGU NOX budget, in tons per year, for Connecticut shall be
9,283 for the years 2010 through 2014, and 7,735 for the years 2015 and
beyond; and
(ii) For purposes of paragraph (e)(3) of this section, the amount
of the Non-EGU Reduction Requirement, in tons per year, for Connecticut
shall be zero for the years 2010 through 2014, and zero for the years
2015 and beyond.
(4) The Administrator may approve a SIP revision from the State of
Connecticut adopted under paragraph (q)(2) of this section that adopts
the model CAIR NOX trading program, under subparts AA
through HH of part 96 of this chapter.
(r) The terms used in this section shall have the following
meanings:
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 cogeneration unit means a cogeneration unit in
which the energy input to the unit is first used to produce useful
thermal energy and at least some of the reject heat from the useful
thermal energy application or process is then used for power
production.
CAIR NOX Trading Program means a multi-State nitrogen
oxides air pollution control and emission reduction program established
by the Administrator in accordance with subparts AA through HH of part
96 of this chapter and this section, as a means of mitigating
interstate transport of fine particulates, ozone, and nitrogen oxides.
Cogeneration unit means a unit:
(1) Having equipment used to produce electricity and useful thermal
energy for industrial, commercial, heating, or cooling purposes through
the sequential use of energy; and
(2) Producing during the 12-month period starting on the date the
unit first produces electricity and during any calendar year after
which the unit first produces electricity--
(i) For a topping-cycle cogeneration unit,
(A) Useful thermal energy not less than 5 percent of total energy
output; and
(B) Useful power that, when added to one-half of useful thermal
energy produced, is not less than 42.5 percent of total energy input
or, if useful thermal energy produced is less than 15 percent of total
energy output, not less than 45 percent of total energy input.
(ii) For a bottoming-cycle cogeneration unit, useful power not less
than 45 percent of total energy input.
Combustion turbine means an enclosed device comprising 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. A combustion turbine that is
combined cycle also includes any associated heat recovery steam
generator and steam turbine.
Electric generating unit or EGU means:
(1) Except for a unit under paragraph (2) of this definition, a
fossil fuel-fired boiler or combustion turbine serving at any time a
generator with nameplate capacity of more than 25 MWe producing
electricity for sale; or
(2) A fossil fuel-fired cogeneration unit serving at any time a
generator with nameplate capacity of more than 25 MWe and in any year
supplying 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.
Fossil fuel means natural gas, petroleum, coal, or any form of
solid, liquid, or gaseous fuel derived from such material.
Fossil-fuel-fired means, with regard to a unit, any boiler or
turbine combusting any amount of fossil fuel.
Generator means a device that produces electricity.
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 specified by the manufacturer of the unit as of the initial
installation of the unit.
NAAQS means National Ambient Air Quality Standard.
Nameplate capacity means the maximum electrical generating output
(in MWe) that a generator can sustain over a specified period of time
when not restricted by seasonal or other deratings, as specified by the
manufacturer of the generator as of the initial installation of the
generator or, if the generator is subsequently modified or
reconstructed resulting in an increase in such maximum electrical
generating output, as specified by the person conducting the
modification or reconstruction.
Non-EGU means a source of NOX emissions that is not an
EGU.
NOX means oxides of nitrogen.
NOX Budget Trading Program means a multi-State nitrogen
oxide air pollution control and emission reduction program established
by air pollution control and emission reduction program established by
the Administrator in accordance with subparts A through I of part 96 of
this chapter and Sec. 51.121, as a means of mitigating interstate
transport of ozone and nitrogen oxides.
NOX SIP Call allowance means a limited authorization
issued by the Administrator under the NOX Budget Trading
Program to emit up to one ton of nitrogen oxides during the ozone
season of the specified year or any year thereafter.
Sequential use of energy means:
(1) For a topping-cycle cogeneration unit, the use of reject heat
from power production in a useful thermal energy application or
process; or
[[Page 32733]]
(2) For a bottoming-cycle cogeneration unit, the use of reject heat
from useful thermal energy application or process in power production.
Topping-cycle cogeneration unit means a cogeneration unit in which
the energy input to the unit is first used to produce useful power and
at least some of the reject heat from the power production is then used
to provide useful thermal energy.
Total energy input means, with regard to a cogeneration unit, total
energy of all forms supplied to the cogeneration unit, excluding energy
produced by the cogeneration unit itself.
Total energy output means, with regard to a cogeneration unit, the
sum of useful power and useful thermal energy produced by the
cogeneration unit.
Useful power means, with regard to a cogeneration unit, electricity
or mechanical energy made 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, with regard to a cogeneration unit,
thermal energy that is:
(1) Made available to an industrial or commercial process,
excluding any heat contained in condensate return or makeup water;
(2) Used in a heat application (e.g., space heating or domestic hot
water heating); or
(3) Used in a space cooling application (i.e., thermal energy used
by an absorption chiller).
Utility power distribution system means the portion of an
electricity grid owned or operated by a distribution utility and
dedicated to delivering electricity to customers.
5. Part 51 is amended by adding Sec. 51.124 to Subpart G 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.
(a) Under Sec. 110(a)(1) of the CAA, 42 U.S.C. 7410(a)(1), the
Administrator determines that each State identified in paragraph (c) of
this section must submit a SIP revision to comply with the requirements
of Sec. 110(a)(2)(D)(i)(I) of the CAA, 42 U.S.C. 7410(a)(2)(D)(i)(I),
through the adoption of adequate provisions prohibiting sources and
other activities from emitting SO2 in amounts that will
contribute significantly to nonattainment in, or interfere with
maintenance by, one or more other States with respect to the fine
particles (PM2.5) NAAQS.
(b) For each State identified in paragraph (c) of this section, the
SIP revision required under paragraph (a) will contain adequate
provisions, for purposes of complying with Sec. 110(a)(2)(D)(i)(I) of
the CAA, 42 U.S.C. 7410(a)(2)(D)(i)(I), only if the SIP revision
contains measures that assure compliance with the applicable
requirements of this section.
(c) The following States are subject to the requirements of this
section: Alabama, Arkansas, Delaware, Florida, Georgia, Illinois,
Indiana, Iowa, Kansas, Kentucky, Louisiana, Maryland, Massachusetts,
Michigan, Minnesota, Mississippi, Missouri, New Jersey, New York, North
Carolina, Ohio, Pennsylvania, South Carolina, Tennessee, Texas,
Virginia, West Virginia, Wisconsin, and the District of Columbia.
(d)(1) The SIP submissions required under paragraph (a) of this
section must be submitted to EPA by no later than 18 months from the
date of promulgation of the final Clean Air Interstate Rule.
(2) The requirements of appendix V shall apply to the SIP
submissions required under paragraph (a) of this section.
(3) The State shall deliver 5 copies of the SIP revision to the
appropriate Regional Office, with a letter giving notice of such
action.
(e)(1)(i) The Annual EGU SO2 budget for a State is
defined as the total amount of SO2 emissions from all EGUs
in that State for a year if the State meets the requirements of
paragraph (a) of this section by imposing control measures, at least in
part, on EGUs. If a State imposes control measures under this section
on only EGUs, the Annual EGU SO2 budget amounts for a State
shall not exceed the amounts, during the indicated periods, specified
in paragraph (e)(2) of this section.
(ii) The Non-EGU Reduction Requirement is defined as the amount of
SO2 emission reductions the State demonstrates, in
accordance with paragraph (g) of this section, it will achieve from
non-EGUs during the appropriate period. If a State meets the
requirements of paragraph (a) of this section by imposing control
measures on only non-EGUs, the State's Non-EGU Reduction Requirement
shall equal or exceed the amount specified in paragraph (e)(3) of this
section.
(iii) If a State meets the requirements of paragraph (a) of this
section by imposing control measures on both EGUs and non-EGUs, the
amount of the Non-EGU Reduction Requirement shall equal or exceed the
difference between the amount of the State's Annual EGU SO2
budget specified in paragraph (e)(2) of this section and the amount of
the State's Annual EGU SO2 budget specified in the SIP for
the appropriate period.
(2) For a State that complies with the requirements of paragraph
(a) of this section by imposing control measures only on EGUs, the
amount of the Annual EGU SO2 budget, in tons per year, shall
be as follows, for the indicated State, for the indicated period:
------------------------------------------------------------------------
Annual EGU SO2
budget, 2010 Annual EGU SO2
State through 2014 budget, 2015
\1\ and beyond \2\
------------------------------------------------------------------------
Alabama................................. 157,582 110,307
Arkansas................................ 48,702 34,091
Delaware................................ 22,411 15,687
District of Columbia.................... 708 495
Florida................................. 253,450 177,415
Georgia................................. 213,057 149,140
Illinois................................ 192,671 134,869
Indiana................................. 254,599 178,219
Iowa.................................... 64,095 44,866
Kansas.................................. 58,304 40,812
Kentucky................................ 188,773 132,141
Louisiana............................... 59,948 41,963
Maryland................................ 70,697 49,488
Massachusetts........................... 82,561 57,792
[[Page 32734]]
Michigan................................ 178,605 125,024
Minnesota............................... 49,987 34,991
Mississippi............................. 33,763 23,634
Missouri................................ 137,214 96,050
New Jersey.............................. 32,392 22,674
New York................................ 135,139 94,597
North Carolina.......................... 137,342 96,139
Ohio.................................... 333,520 233,464
Pennsylvania............................ 275,990 193,193
South Carolina.......................... 57,271 40,089
Tennessee............................... 137,216 96,051
Texas................................... 320,946 224,662
Virginia................................ 63,478 44,435
West Virginia........................... 215,881 151,117
Wisconsin............................... 87,264 61,085
-----------------
Total............................... 3,863,566 2,704,490
------------------------------------------------------------------------
\1\ This period refers to each year during the 2010-2014 period.
\2\ This period refers to each year during 2015 and subsequently.
(3) For a State that complies with the requirements of paragraph
(a) of this section by imposing control measures on only non-EGUs, the
amount of the Non-EGU Reduction Requirement, in tons per year, shall be
as follows, for the indicated State, for the indicated period:
------------------------------------------------------------------------
Non-EGU Non-EGU
reduction reduction
State requirement, requirement,
2010 through 2015 and
2014 \1\ beyond \2\
------------------------------------------------------------------------
Alabama................................. 157,582 204,857
Arkansas................................ 48,702 63,312
Delaware................................ 22,411 29,134
District of Columbia.................... 708 920
Florida................................. 253,450 329,485
Georgia................................. 213,057 276,974
Illinois................................ 192,671 250,472
Indiana................................. 254,599 330,978
Iowa.................................... 64,095 83,323
Kansas.................................. 58,304 75,795
Kentucky................................ 188,773 245,405
Louisiana............................... 59,948 77,932
Maryland................................ 70,697 91,906
Massachusetts........................... 82,561 107,329
Michigan................................ 178,605 232,187
Minnesota............................... 49,987 64,983
Mississippi............................. 33,763 43,892
Missouri................................ 137,214 178,378
New Jersey.............................. 32,392 42,109
New York................................ 135,139 175,681
North Carolina.......................... 137,342 178,545
Ohio.................................... 333,520 433,576
Pennsylvania............................ 275,990 358,787
South Carolina.......................... 57,271 74,452
Tennessee............................... 137,216 178,380
Texas................................... 320,946 417,230
Virginia................................ 63,478 82,521
West Virginia........................... 215,881 280,645
Wisconsin............................... 87,264 113,443
------------------------------------------------------------------------
\1\ This period refers to each year during the 2010-2014 period.
\2\ This period refers to each year during 2015 and subsequently.
(f) Each SIP revision must set forth control measures to meet the
amounts specified in paragraph (e) of this section, as applicable,
including the following:
(1) A description of enforcement methods including, but not limited
to:
(i) Procedures for monitoring compliance with each of the selected
control measures;
(ii) Procedures for handling violations; and
(iii) A designation of agency responsibility for enforcement of
implementation.
[[Page 32735]]
(2)(i) Should a State elect to impose control measures on EGUs,
then those measures must impose a SO2 mass emissions cap on
all such sources in the State.
(ii) Should a State elect to impose control measures on fossil
fuel-fired non-EGUs that are boilers or combustion turbines with a
maximum design heat input greater than 250 mmBtu/hr, then those
measures must impose a SO2 mass emissions cap on all such
sources in the State.
(iii) Should a State elect to impose control measures on fossil
fuel-fired non-EGUs other than those described in paragraph (f)(2)(ii)
of this section, then those measures must impose a SO2 mass
emissions cap on all such sources in the State, or the State must
demonstrate why such emissions cap is not practicable, and adopt
alternative requirements that ensure to the maximum practicable degree
that the State will comply with its requirements under paragraph (e) of
this section, as applicable, in 2010 and subsequent years.
(g)(1) Each SIP revision which includes control measures covering
non-EGUs as part or all of a State's obligation in meeting its
requirement under paragraph (a) of this section must demonstrate that
such control measures are adequate to provide for the timely compliance
with the State's Non-EGU Reduction Requirement under paragraph (e) of
this section, and are not otherwise required under the Clean Air Act.
(2) The demonstration under paragraph (g)(1) of this section must
include the following, with respect to each source category of non-EGUs
for which the SIP requires controls:
(i) A detailed historical baseline inventory of SO2 mass
emissions from the source category in a representative year consisting,
at the State's election, of 2002, 2003, 2004, or 2005, or an average of
2 or more of those years, absent the control measures specified in the
SIP submission.
(A) This inventory must represent estimates of actual emissions
based on part 75 monitoring data, if the source category is subject to
part 75 monitoring requirements.
(B) In the absence of part 75 monitoring data, actual emissions
must be estimated using assumptions that ensure a source or source
category's actual emissions are not overestimated, and must include
source-specific or category-specific data. If a State uses factors to
estimate emissions, production or utilization, or effectiveness of
controls or rules for a source category, such factors must be chosen to
ensure that emissions are not overestimated, or the State must justify
the use of another value with additional information showing with
reasonable confidence that the substitute value is more appropriate for
estimating actual emissions.
(C) For measures to reduce emissions from motor vehicles, emission
estimates must be based on an emissions model that has been approved by
EPA for use in SIP development, and must be consistent with the
planning assumptions regarding vehicle miles traveled and other factors
current at the time of the SIP development.
(D) For measures to reduce emissions from nonroad engines or
vehicles, emission estimates must be based on the emission
methodologies recommended in EPA guidance current at the time of the
SIP development or the SIP must document that another method is
superior due to local factors.
(ii) A detailed baseline inventory of SO2 mass emissions
from the source category in the years 2010 and 2015, absent the control
measures specified in the SIP submission, and reflecting changes in
these emissions from the historical baseline year to the years 2010 and
2015, based on projected changes in the production input and/or output,
population, vehicle miles traveled, economic activity or other factors
as applicable to this source category.
(A) These inventories must account for implementation of any rules
or regulations that will affect SO2 emissions from this
source category, excluding any control measures specified in the SIP
submission to meet the SO2 emissions reduction requirements
of this section.
(B) Economic and population forecasts must be as specific as
possible to the applicable industry, State, and county of the source or
source category, and must be consistent with both national projections
and relevant official planning assumptions including estimates of
population and vehicle miles traveled developed through consultation
between State and local transportation and air quality agencies.
However, if these official planning assumptions are themselves
inconsistent with official U.S. Census projections of population and
energy consumption projections contained in the Annual Energy Outlook
published by the U.S. Department of Energy, adjustments must be made to
correct the inconsistency, or the SIP must demonstrate how the official
planning assumptions are more accurate.
(C) These inventories must account for any changes in production
method, materials, fuels, or efficiency that are expected to occur
between the historical baseline year and 2010 or 2015, as appropriate.
(iii) A projection of SO2 mass emissions in 2010 and
2015 from the source category identified in paragraph (g)(2)(i) of this
section resulting from implementation of each of the control measures
specified in the SIP submission.
(A) These inventories must address the possibility that the State's
new control measures may cause production and emissions to shift to
non-regulated or less stringently regulated sources in the source
category in the same or another State, and must include in the
projected emissions inventory any such amounts of emissions that may
shift to other sources.
(B) The State must provide EPA with a summary of the computations,
assumptions, and judgments used to determine the degree of reduction in
projected 2010 and 2015 SO2 emissions that will be achieved
from the implementation of the new control measures compared to the
relevant baseline emissions inventory.
(iv) The result of subtracting the amounts in paragraph (g)(2)(iii)
for 2010 and 2015, respectively, from the lower of the amounts in
paragraph (g)(2)(i) or (g)(2)(ii) of this section for 2010 and 2015,
respectively, may be credited towards the State's Non-EGU Reduction
Requirement in paragraph (e)(3) of this section for the appropriate
period.
(v) Each revision must identify the sources of the data used in the
estimate and projection of emissions.
(h) Each revision must comply with Sec. 51.116 (regarding data
availability).
(i) Each revision must provide for monitoring the status of
compliance with any control measures adopted to meet the State's
requirements under paragraph (e) of this section. Specifically, the
revision must meet the following requirements:
(1) The revision must provide for legally enforceable procedures
for requiring owners or operators of stationary sources to maintain
records of, and periodically report to the State:
(i) Information on the amount of SO2 emissions from the
stationary sources; and
(ii) Other information as may be necessary to enable the State to
determine whether the sources are in compliance with applicable
portions of the control measures;
(2) The revision must comply with Sec. 51.212 (regarding testing,
inspection, enforcement, and complaints);
(3) If the revision contains any transportation control measures,
then the revision must comply with Sec. 51.213
[[Page 32736]]
(regarding transportation control measures);
(4)(i) If the revision contains measures to control EGUs, then the
revision must require such sources to comply with the monitoring and
reporting provisions of part 75.
(ii) If the revision contains measures to control fossil fuel-fired
non-EGUs that are boilers or combustion turbines with a maximum design
heat input greater than 250 mmBtu/hr, then the revision must require
such sources to comply with the monitoring and reporting provisions of
part 75.
(iii) If the revision contains measures to control any other non-
EGUs that are not described in paragraph (i)(4)(ii) of this section,
the revision must require such sources to comply with the monitoring
and reporting provisions of part 75, or the State must demonstrate why
such requirements are not practicable, and adopt alternative
requirements that ensure to the maximum practicable degree that the
required emissions reductions will be achieved.
(j) Each revision must show that the State has legal authority to
carry out the revision, including authority to:
(1) Adopt emissions standards and limitations and any other
measures necessary for attainment and maintenance of the State's
relevant Annual EGU SO2 budget or the Non-EGU Reduction
Requirement, as applicable, under paragraph (e);
(2) Enforce applicable laws, regulations, and standards, and seek
injunctive relief;
(3) Obtain information necessary to determine whether air pollution
sources are in compliance with applicable laws, regulations, and
standards, including authority to require recordkeeping and to make
inspections and conduct tests of air pollution sources; and
(4)(i) Require owners or operators of stationary sources to
install, maintain, and use emissions monitoring devices and to make
periodic reports to the State on the nature and amounts of emissions
from such stationary sources; and
(ii) Make the data described in paragraph (j)(4)(i) of this section
available to the public as reported and as correlated with any
applicable emissions standards or limitations.
(k)(1) The provisions of law or regulation which the State
determines provide the authorities required under this section must be
specifically identified, and copies of such laws or regulations must be
submitted with the SIP revision.
(2) Legal authority adequate to fulfill the requirements of
paragraphs (j)(3) and (4) of this section may be delegated to the State
under Sec. 114 of the CAA. (l)(1) A revision may assign legal
authority to local agencies in accordance with Sec. 51.232.
(2) Each revision must comply with Sec. 51.240 (regarding general
plan requirements).
(m) Each revision must comply with Sec. 51.280 (regarding
resources).
(n) Each revision must provide for State compliance with the
reporting requirements set forth in Sec. 51.125.
(o) Notwithstanding any other provision of this section, if a State
adopts regulations substantively identical to subparts AAA through HHH
of part 96 of this chapter (CAIR SO2 Emissions Trading
Program), or incorporates such part by reference into its regulations,
then that portion of the State's SIP revision is automatically approved
as meeting the requirements of paragraph (e)(1)(i) of this section,
provided that the State has the legal authority to take such action and
to implement its responsibilities under such regulations.
(p) For a State that does not adopt regulations in accordance with
paragraph (o) of this section:
(1) The sources subject to the Acid Rain Program , in addition to
complying with the requirements of Sec. 72.9(c)(1)(i) of this chapter,
shall hold the following amounts of Acid Rain allowances, as of the
allowance transfer deadline in the source's compliance account--
(i) For each Acid Rain allowance allocated for a year during 2010
through 2014 that is held in order to meet the requirements of Sec.
72.9(c)(1)(i) of this chapter, one additional Acid Rain allowance
allocated for a year during 2010 through 2014; and
(ii) For each Acid Rain allowance allocated for a year during 2015
or thereafter held in accordance with Sec. 72.9(c)(1)(i) of this
chapter, two additional Acid Rain allowances allocated for a year
during 2015 or thereafter.
(2) When the Administrator deducts Acid Rain allowances under Sec.
73.35(b) and (c) of this chapter, the Administrator will also deduct
from the source's compliance account the amount of Acid Rain allowances
required to be held under paragraph (p)(1) of this section. If the
owner and operator of the source fails to hold the Acid Rain allowances
required under paragraph (p)(1) of this section, then, for each Acid
Rain allowance required but not held, the Administrator will deduct
from such compliance account three Acid Rain allowances allocated for
the year after the year of the allowance transfer deadline by which the
Acid Rain allowances were required to be held.
(q) The terms used in this section shall have the following
meanings:
Acid Rain Program means a multi-State sulfur dioxide and nitrogen
oxides air pollution control and emissions reduction program
established by the Administrator under title IV of the CAA and parts 72
through 78 of this chapter.
Acid Rain allowance means a limited authorization issued by the
Administrator under the Acid Rain Program to emit up to one ton of
sulfur dioxide during the specified year or any year thereafter.
Allowance transfer deadline means the allowance transfer deadline
under the Acid Rain Program, as defined in Sec. 72.2 of this chapter.
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 cogeneration unit means a cogeneration unit in
which the energy input to the unit is first used to produce useful
thermal energy and at least some of the reject heat from the useful
thermal energy application or process is then used for power
production.
CAIR SO2 Emissions Trading Program means a multi-State
sulfur dioxide air pollution control and emission reduction program
established by the Administrator in accordance with subparts AAA
through HHH of part 96 of this chapter and this section, as a means of
mitigating interstate transport of fine particulates.
Cogeneration unit means a unit:
(1) Having equipment used to produce electricity and useful thermal
energy for industrial, commercial, heating, or cooling purposes through
the sequential use of energy; and
(2) Producing during the 12-month period starting on the date the
unit first produces electricity and during any calendar year after
which the unit first produces electricity--
(i) For a topping-cycle cogeneration 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
or, if useful thermal energy produced is less than 15 percent of total
energy output, not less than 45 percent of total energy input.
(ii) For a bottoming-cycle cogeneration unit, useful power not less
than 45 percent of total energy input.
[[Page 32737]]
Combustion turbine means an enclosed device comprising 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. A combustion turbine that is
combined cycle also includes any associated heat recovery steam
generator and steam turbine.
Compliance account means a compliance account under the Acid Rain
Program, as defined in Sec. 72.2 of this chapter.
Electric generating unit or EGU means:
(1) Except for a unit under paragraph (2) of this definition, a
fossil fuel-fired boiler or combustion turbine serving at any time a
generator with nameplate capacity of more than 25 MWe producing
electricity for sale; or
(2) A fossil fuel-fired cogeneration unit serving at any time a
generator with nameplate capacity of more than 25 MWe and in any year
supplying 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.
Fossil fuel means natural gas, petroleum, coal, or any form of
solid, liquid, or gaseous fuel derived from such material.
Fossil-fuel-fired means, with regard to a unit, any boiler or
turbine combusting any amount of fossil fuel.
Generator means a device that produces electricity.
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 specified by the manufacturer of the unit as of the initial
installation of the unit.
NAAQS means National Ambient Air Quality Standard.
Nameplate capacity means the maximum electrical generating output
(in MWe) that a generator can sustain over a specified period of time
when not restricted by seasonal or other deratings, as specified by the
manufacturer of the generator as of the initial installation of the
generator or, if the generator is subsequently modified or
reconstructed resulting in an increase in such maximum electrical
generating output, as specified by the person conducting the
modification or reconstruction.
Non-EGU means a source of SO2 emissions that is not an
EGU.
SO2 means sulfur dioxide.
Sequential use of energy means:
(1) For a topping-cycle cogeneration unit, the use of reject heat
from power production in a useful thermal energy application or
process; or
(2) For a bottoming-cycle cogeneration unit, the use of reject heat
from useful thermal energy application or process in power production.
Topping-cycle cogeneration unit means a cogeneration unit in which
the energy input to the unit is first used to produce useful power and
at least some of the reject heat from the power production is then used
to provide useful thermal energy.
Total energy input means, with regard to a cogeneration unit, total
energy of all forms supplied to the cogeneration unit, excluding energy
produced by the cogeneration unit itself.
Total energy output means, with regard to a cogeneration unit, the
sum of useful power and useful thermal energy produced by the
cogeneration unit.
Useful power means, with regard to a cogeneration unit, electricity
or mechanical energy made 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, with regard to a cogeneration unit,
thermal energy that is:
(1) Made available to an industrial or commercial process,
excluding any heat contained in condensate return or makeup water;
(2) Used in a heat application (e.g., space heating or domestic hot
water heating); or
(3) Used in a space cooling application (i.e., thermal energy used
by an absorption chiller).
Utility power distribution system means the portion of an
electricity grid owned or operated by a distribution utility and
dedicated to delivering electricity to customers.
6. Part 51 is amended by adding Sec. 51.125 to Subpart G to read
as follows:
Sec. 51.125 Emissions reporting requirements for SIP revisions
relating to budgets for SO[bdi2] and NOX emissions.
(a) For its transport SIP revision under Sec. 51.123 and/or 51.124
of this part, each State must submit to EPA SO2 and/or
NOX emissions data as described in this section.
(1) The District of Columbia and following States must report
annual (12 months) emissions of SO2 and NOX:
Alabama, Arkansas, Delaware, Florida, Georgia, Illinois, Indiana, Iowa,
Kansas, Kentucky, Louisiana, Maryland, Massachusetts, Michigan,
Minnesota, Mississippi, Missouri, New Jersey, New York, North Carolina,
Ohio, Pennsylvania, South Carolina, Tennessee, Texas, Virginia, West
Virginia, and Wisconsin.
(2) The District of Columbia and the following States must report
ozone season (May 1 through September 30) emissions of NOX:
Alabama, Arkansas, Connecticut, Delaware, Georgia, Illinois, Indiana,
Iowa, Kentucky, Louisiana, Maryland, Massachusetts, Michigan,
Mississippi, Missouri, New Jersey, New York, North Carolina, Ohio,
Pennsylvania, South Carolina, Tennessee, Virginia, West Virginia, and
Wisconsin.
(b) Each revision must provide for periodic reporting by the State
of SO2 and/or NOX emissions data as specified in
paragraph (a) of this section to demonstrate whether the State's
emissions are consistent with the projections contained in its approved
SIP submission.
(1) Every-year reporting cycle. As applicable, each revision must
provide for reporting of SO2 and NOX emissions
data every year as follows:
(i) The States identified in paragraph (a)(1) of this section must
report to EPA annual emissions data every year from all SO2
and NOX sources within the State for which the State
specified control measures in its SIP submission under Sec. Sec.
51.123 and/or 51.124 of this part.
(ii) The States identified in paragraph (a)(2) of this section must
report to EPA ozone season and summer daily emissions data every year
from all NOX sources within the State for which the State
specified control measures in its SIP submission under Sec. 51.123 of
this part.
(iii) If sources report SO2 and NOX emissions
data to EPA in a given year pursuant to a trading program approved
under Sec. 51.123(o) or Sec. 51.124(o) of this part or pursuant to
the monitoring and reporting requirements of subpart H of 40 CFR part
75, then the State need not provide annual reporting of these
pollutants to EPA for such sources.
(2) Three-year reporting cycle. As applicable, each plan must
provide for triennial (i.e., every third year) reporting of
SO2 and NOX emissions data from all sources
within the State.
(i) The States identified in paragraph (a)(1) of this section must
report to EPA annual emissions data every third year from all
SO2 and NOX sources within the State.
(ii) The States identified in paragraph (a)(2) of this section must
report to EPA ozone season and ozone daily emissions data every third
year from all NOX sources within the State.
[[Page 32738]]
(3) The data availability requirements in Sec. 51.116 of this part
must be followed for all data submitted to meet the requirements of
paragraphs (b)(1)and(2) of this section.
(c) The data reported in paragraph (b) of this section must meet
the requirements of subpart A of this part.
(d) Approval of annual and ozone season calculation by EPA. Each
State must submit for EPA approval an example of the calculation
procedure used to calculate annual and ozone season emissions along
with sufficient information for EPA to verify the calculated value of
annual and ozone season emissions.
(e) Reporting schedules.
(1) Reports are to begin with data for emissions occurring in the
year 2008, which is the first year of the 3-year cycle.
(2) After 2008, 3-year cycle reports are to be submitted every
third year and every-year cycle reports are to be submitted each year
that a triennial report is not required.
(3) States must submit data for a required year no later than 17
months after the end of the calendar year for which the data are
collected.
(f) Data reporting procedures are given in subpart A. When
submitting a formal NOX budget emissions report and
associated data, States shall notify the appropriate EPA Regional
Office.
(g) Definitions. As used in this section, words and terms shall
have the meanings set forth in appendix A of subpart A of this part.
7. Sec. 51.308 is amended by revising the introductory text of
paragraph (e)(2), paragraphs (e)(3) and (e)(4), and by adding paragraph
(e)(5) as follows:
Sec. 51.308 Regional haze program requirements
* * * * *
(e) * * *
(2) A State may opt to implement an emissions trading program or
other alternative measure rather than to require sources subject to
BART to install, operate and maintain BART. Except as provided in
paragraph (e)(3) of this section, to do so, the State must demonstrate
that this emissions trading program or other alternative measure will
achieve greater reasonable progress than would be achieved through the
installation and operation of BART. To make this demonstration, the
State must submit an implementation plan containing the following plan
elements and include documentation for all required analyses:
* * * * *
(3) A State that opts to participate in the Clean Air Interstate
Rule cap-and-trade program under part 96 AAA-EEE need not require
affected BART-eligible EGU's to install, operate, and maintain BART. A
State that chooses this option may also include provisions for a
geographic enhancement to the program to address the requirement under
Sec. 51.302(c) related to BART for reasonably attributable impairment
from the pollutants covered by the CAIR cap-and-trade program.
(4) After a State has met the requirements for BART or implemented
emissions trading program or other alternative measure that achieves
more reasonable progress than the installation and operation of BART,
BART-eligible sources will be subject to the requirements of Sec.
51.308(d) in the same manner as other sources.
(5) Any BART-eligible facility subject to the requirement under
Sec. 51.308(e) to install, operate, and maintain BART may apply to the
Administrator for an exemption from that requirement. An application
for an exemption will be subject to the requirements of Sec.
51.303(a)(2)-(h).
PART 72--PERMITS REGULATION
1. The authority citation for part 72 continues to read as follows:
Authority: 42 U.S.C. 7601 and 7651, et seq.
Sec. 72.2 [Amended]
2. Section 72.2 is amended as follows:
a. Amend the definition of ``Acid rain emissions limitation'' by
replacing, in paragraph (1)(i), the words ``an affected unit'' by the
words ``the affected units at a source'' and replacing, in paragraph
(1)(ii)(C), the words ``compliance subaccount for that unit'' by the
words ``compliance account for that source'';
b. Amend the definition of ``Allocate or allocation'' by replacing
the words ``unit account'' by the words ``compliance account'';
c. Amend the definition of ``Allowance deduction, or deduct'' by
replacing the words ``compliance subaccount, or future year
subaccount,'' by the words ``compliance account'' and replacing the
words ``from an affected unit'' by the words ``from the affected units
at an affected source'';
d. Amend the definition of ``Allowance transfer deadline'' by
replacing the words ``affected unit's compliance subaccount'' by the
words ``an affected source's compliance account'' and replacing the
words ``the unit's'' by the words ``the source's'';
e. Amend the definition of ``Authorized account representative'' by
replacing the words ``unit account'' by the words ``compliance
account'' and replacing the words ``affected unit'' by the words
``affected source and the affected units at the source'';
f. Amend the definition of ``Compliance use date'' by replacing the
word ``unit's'' by the word ``source's'';
g. Amend the definition of ``excess emissions'' by, in paragraph
(1), replacing the words ``an affected unit'' by the words ``the
affected units at an affected source'' and replacing the words ``for
the unit'' by the words ``for the source'';
h. Amend the definition of ``Recordation, record, or recorded'' by
removing the words ``or subaccount''; and
i. Revise the definition of ``Cogeneration unit'', adding a new
definition of ``Compliance account'', and removing the definitions of
``Compliance subaccount'', ``Current year subaccount'', ``Future year
subaccount'', and ``Unit account'' to read as follows:
Sec. 72.2 Definitions.
* * * * *
Cogeneration unit means a unit that has equipment used to produce
electric energy and forms of useful thermal energy (such as heat or
steam) for industrial, commercial, heating, or cooling purposes,
through sequential use of energy.
* * * * *
Compliance account means an Allowance Tracking System account,
established by the Administrator for an affected source and for each
affected unit at the source pursuant to Sec. 73.31(a) or (b) of this
chapter.
* * * * *
Sec. 72.7 [Amended]
3. Section 72.7 is amended in paragraph (c)(1)(ii), in the first
sentence, remove the word ``unit's'' and add after the words
``Allowance Tracking System account'' the words ``of the source that
includes the unit'' and remove the third sentence.
Sec. 72.9 [Amended]
4. Section 72.9 is amended by:
a. In paragraph (c)(1)(i), replace the words ``unit's compliance
subaccount'' with the words ``source's compliance account'' and replace
the words ``from the unit'' by the words ``from the affected units at
the source'';
b. In paragraphs (e)(1) and (e)(2) introductory text, replace the
words ``an affected unit'' by the words ``an affected source''; and
c. In paragraph (g)(6), remove the second sentence.
[[Page 32739]]
Sec. 72.21 [Amended]
5. Section 72.21 is amended by removing from paragraph (b)(1) the
word ``affected'' wherever it appears.
Sec. 72.24 [Amended]
6. Section 72.24 is amended by removing and reserving paragraphs
(a)(5), (a)(7), and (a)(10).
Sec. 72.40 [Amended]
7. Section 72.40 is amended, in paragraph (a)(1), replace the words
``unit's compliance subaccount'' with the words ``compliance account of
the source where the unit is located '', remove the words ``, or in the
compliance subaccount of another affected unit at the source to the
extent provided in Sec. 73.35(b)(3),'', and replace the words ``from
the unit'' by the words ``from the affected units at the source''.
Sec. 72.73 [Amended]
8. Section 72.73 is amended, in paragraph (b)(2), replace the words
``the first Acid Rain permit'' by the words ``an Acid Rain permit''.
Sec. 72.90 [Amended]
9. Section 72.90 is amended, in paragraph (a), add, after the words
``each calendar year'', the words ``during 1995 through 2004''.
Sec. 72.95 [Amended]
10. Section 72.95 is amended by:
a. In the introductory text, replace the words ``an affected unit's
compliance subaccount'' with the words ``an affected source's
compliance account''; and
b. In paragraph (a), replace the words ``by the unit'' by the words
``by the affected units at the source''.
PART 73--SULFUR DIOXIDE ALLOWANCE SYSTEM
1. The authority citation continues to read as follows:
Authority: 42 U.S.C. 7601 and 7651, et seq.
Sec. 73.10 [Amended]
2. Section 73.10 is amended by:
a. In paragraph (a), remove the words ``in each future year
subaccount'';
b. In paragraph (b)(1), replace the words ``in the future year
subaccounts representing calendar years'' with the words ``for the
years''; and
c. In paragraph (b)(2), replace the words ``in the future year
subaccounts representing calendar years'' with the words ``for the
year''.
Sec. 73.30 [Amended]
3. Section 73.30 is amended by:
a. In paragraph (a), replace the words ``affected units'' by the
words ``affected sources''; and
b. In paragraph (b), replace the word ``unit'' by the word
``source''.
Sec. 73.31 [Amended]
4. Section 73.31 is amended by:
a. In paragraph (a), replace the words ``each unit'' with the words
``each source that includes a unit'';
b. In paragraph (b), replace the words ``the unit.'' by the words
``the source that includes the unit, unless the source already has a
compliance account.''; and
c. In paragraph (c)(1)(v), remove the words `` I shall abide by any
fiduciary responsibilities assigned pursuant to the binding
agreement.''.
Sec. 73.32 [Removed and Reserved]
5. Sec. 73.32 is removed and reserved.
Sec. 73.33 [Amended]
6. Removing and reserving paragraph (c).
Sec. 73.34 [Amended]
7. Section 73.34 is amended as follows:
a. Revise paragraph (a) to read as set forth below;
b. Remove and reserve paragraph (b); and
c. In paragraph (c) heading, replace the words ``in subaccounts''
with the words ``in compliance accounts'' and in the introductory text,
replace the words ``compliance, current year, and future year'' with
the words ``compliance account''.
Sec. 73.34 Recordation in accounts.
(a) Recordation in compliance accounts. When a compliance account
is established under Sec. 73.31(a), the Administrator will record in
the account any allowances allocated to the affected units at the
source under Sec. 73.10 or part 74 for 30 years starting with the
later of 1995 or the year in which the account is established. At the
beginning of 1995 and, in the case of each year thereafter, after the
Administrator has made all deductions from the compliance account
pursuant to Sec. 73.35(b), the Administrator will record in the
compliance account the allowances allocated to such units under Sec.
73.10 or part 74 for the new 30th year.
* * * * *
Sec. 73.35 [Amended]
8. Section 73.35 is amended as follows:
a. In paragraph (a) introductory text and paragraph (a)(1), replace
the words ``unit's'' by the word ``source's'';
b. In paragraph (a)(2)(i), replace the words ``the unit's
compliance subaccount'' with the words ``the compliance account of the
source that includes the unit'';
c. In paragraph (a)(2)(ii), replace the words ``the unit's
compliance subaccount'' with the words ``the compliance account of the
source that includes the unit'' wherever they appear and remove the
words ``for the unit'', and replace the words ``; or'' with a period.
d. Remove paragraph (a)(2)(iii).
e. In paragraph (b)(1), add after the words ``deduct allowances''
the words ``available for deduction under paragraph (a) of this
section'' and replace the words ``each affected unit's compliance
subaccount'' with the words ``each affected source's compliance
account'';
f. In paragraph (b)(2), replace the words ``allowances remain in
the compliance subaccount'' with the words ``allowances available for
deduction under paragraph (a) of this section remain in the compliance
account'';
g. Remove paragraph (b)(3);
h. Revise paragraph (c)(1) to read as set forth below;
i. In paragraph (c)(2), replace the words ``for the unit'' with the
words ``for the units at the source'', replace the words ``in its
compliance subaccount.'' by the words ``in the source's compliance
account.'', replace the words ``from the compliance subaccount'' by the
words ``from the compliance account'', and replace the words ``unit's
compliance subaccount'' by the words ``source's compliance account'';
j. In paragraph (d), replace the words ``for each unit'' by the
words ``for each source'' and replace the word ``unit's'' by the word
``source's''; and
k. Remove paragraph (e).
Sec. 73.35 Compliance.
* * * * *
(c)(1) Identification of allowances by serial number. The
authorized account representative for a source's compliance account may
request that specific allowances, identified by serial number, in the
compliance account be deducted for a calendar year in accordance with
paragraph (b) or (d) of this section. Such request shall be submitted
to the Administrator by the allowance transfer deadline for the year
and include, in a format prescribed by the Administrator, the
identification of the source and the appropriate serial numbers.
* * * * *
Sec. 73.36 [Amended]
9. Section 73.36 is amended by:
a. In paragraph (a), replace the words ``Unit accounts.'' with the
words ``Compliance accounts.'' and replace with words ``compliance
subaccount''
[[Page 32740]]
with the words ``compliance account'' whenever they appear; and
b. In paragraph (b), replace the words ``current year subaccount''
with the words ``general account'' whenever they appear.
10. Section 73.37 is revised to read as follows:
Sec. 73.37 Account error.
The Administrator may, at his or her sole discretion and on his or
her own motion, correct any error in any Allowance Tracking System
account. Within 10 business days of making such correction, the
Administrator will notify the authorized account representative for the
account.
Sec. 73.38 [Amended]
11. Section 73.38 is amended as follows:
a. In paragraph (a), replace the words ``delete the general account
from the Allowance Tracking System.'' by the words ``close the general
account.''; and
b. In paragraph (b), remove the words ``and eliminated from the
Allowance Tracking System'' and the last sentence.
Sec. 73.50 [Amended]
12. Section 73.50 is amended as follows:
a. In paragraph (a), remove the words ``, including, but not
limited to, transfers of an allowance to and from contemporaneous
future year subaccounts, and transfers of an allowance to and from
compliance subaccounts and current year subaccounts, and transfers of
all allowances allocated for a unit for each calendar year in
perpetuity'';
b. In paragraph (b)(1)(ii), remove the words ``, or correct
indication on the allowance transfer where a request involves the
transfer of the unit's allowance in perpetuity'';
c. In paragraph (b)(2)(ii), remove the words ``Allowance Tracking
System'' and ``under 40 CFR part 73, or any other remedies'' and remove
the comma after the words ``under State or Federal law''; and
d. Remove paragraph (b)(3).
Sec. 73.51 [Removed and Reserved]
13. Section 73.51 is removed and reserved.
14. Section 73.52 is amended as follows revising paragraphs (a)(1),
(a)(2) and (a)(3) and by removing paragraph (a)(4), and revising
paragraph (b) and adding a new paragraph (c) to read as follows:
Sec. 73.52 EPA recordation.
(a) * * *
(1) The transfer is corrected submitted under Sec. 73.50;
(2) The transferor account includes each allowance identified by
serial number in the transfer;
(3) If the allowances identified by serial number specified
pursuant to Sec. 73.50(b)(1)(ii) are subject to the limitation on
transfer imposed pursuant to Sec. 72.44(h)(1)(i) of this chapter,
Sec. 74.42 of this chapter, or Sec. 74.47(c) of this chapter, the
transfer is in accordance with such limitation.
(b) To the extent an allowance transfer submitted for recordation
after the allowance transfer deadline includes allowances allocated for
any year before the year of the allowance transfer deadline, the
transfer of such allowance will not be recorded until after completion
of the deductions pursuant to Sec. 73.35(b) for year before the year
of the allowance transfer deadline.
(c) Where an allowance transfer submitted for recordation fails to
meet the requirements of paragraph (a) of this section, the
Administrator will not record such transfer.
Sec. 73.70 [Amended]
15. Section 73.70 is amended as follows:
a. In paragraph (f), replace the words ``the subaccount'' by the
words ``the Allowance Tracking System account''; and
b. In paragraph (i)(1), add, after the words ``Allowance Tracking
System account'', the words ``of the source that includes''.
PART 74--SULFUR DIOXIDE OPTS-INS
1. The authority citation for part 74 continues to read as follows:
Authority: 42 U.S.C. 7601 and 7651, et seq.
Sec. 74.18 [Amended]
2. Section 74.18 is amended, in paragraph (d), remove the last
sentence.
Sec. 74.40 [Amended]
3. Section 74.40 is amended, in paragraph (a), add, after the words
``an account'', the words ``(unless the source that includes the opt-in
unit already has a compliance account)'' and remove the last sentence.
4. Section 74.42 is revised to read as follows:
Sec. 74.42 Limitation on transfers.
(a) With regard to a transfer request submitted for recordation
during the period starting January 1 and ending with the allowance
transfer deadline in the same year, the Administrator will not record a
transfer of an opt-in allowance that is allocated to an opt-in source
for the year in which the transfer request is submitted or a subsequent
year.
(b) With regard to a transfer request during the period starting
with an allowance transfer deadline and ending December 31 in the same
year, the Administrator will not record a transfer of an opt-in
allowance that is allocated to an opt-in source for a year after the
year in which the transfer request is submitted.
Sec. 74.43 [Amended]
5. Section 74.43 is amended as follows:
a. In paragraph (a), remove the words ``in lieu of any annual
compliance certification report required under subpart I of part 72 of
this chapter'';
b. In paragraph (b)(7), replace the word ``At'' by the words, ``In
an annual compliance certification report for a year during 1995
through 2004, at''; and
c. In paragraph (b)(8), replace the word ``The'' by the words, ``In
an annual compliance certification report for a year during 1995
through 2004, the''.
Sec. 74.44 [Amended]
6. Section 74.44 is amended as follows:
a. In paragraphs (c)(2)(iii)(C), (c)(2)(iii)(D), (c)(2)(iii)(E)
introductory text, and (c)(2)(iii)(E)(3), replace the words ``opt-in
source's compliance subaccount'' by the words ``compliance account of
the source that includes the opt-in source'' whenever they occur; and
b. In paragraph (c)(2)(iii)(F), replace the words ``opt-in source's
compliance subaccount'' by the words ``compliance account of the source
that includes the opt-in source'' and replace the words ``source's
compliance subaccount'' by the words ``compliance account of the source
that includes the opt-in source''.
Sec. 74.46 [Amended]
7. Section 74.6 is amended by removing and reserving paragraph
(b)(2).
Sec. 74.47 [Amended]
8. Section 74.47 is amended as follows:
a. In paragraph (c), replace the words ``unit account'' by the
words ``compliance account of the source that includes the replacement
unit''; and
b. In paragraph (d)(2), add, after the words ``Allowance Tracking
System accounts'', the words ``of the source that include the opt-in
source and each replacement unit'' and remove the words ``for the opt-
in source and for each replacement unit''.
Sec. 74.49 [Amended]
9. Section 74.49 is amended, in paragraph (a), replace the words
``an opt-in source's compliance subaccount''
[[Page 32741]]
by the words ``the compliance account of a source that include an opt-
in source''.
Sec. 74.50 [Amended]
10. Section 74.50 is amended as follows:
a. In paragraph (a)(2) introductory text, add, after the words
``the account of the'' the words ``source that includes'';
b. In paragraph (a)(2)(i), replace the words ``opt-in source's
compliance subaccount'' by the words ``the compliance account of the
source that includes the opt-in source''; and
c. In paragraph (b), replace the words ``the opt-in source's unit
account'' by the words ``the compliance account of the source that
includes the opt-in source''; and
d. In paragraph (d), replace the words ``an opt-in source does not
hold'' by the words ``the source that include the opt-in source does
not hold''.
PART 77--EXCESS EMISSIONS
1. The authority citation for part 77 continues to read as follows:
Authority: 42 U.S.C. 7601 and 7651, et seq.
Sec. 77.3 [Amended]
2. Section 77.3 is amended as follows:
a. In paragraph (a), replace the words ``affected unit'' by the
words ``affected source'' and replace the word ``unit's'' by the word
``source's'';
b. In paragraphs (b) and (c), replace the word ``unit'' by the word
``source'' wherever it appears; and
c. In paragraph (d) introductory text and paragraphs (d)(1),
(d)(2), (d)(3), and (d)(5), replace the word ``unit'' by the word
``source'' wherever it appears, replace the word ``unit's'' by the word
``source's'' wherever it appears, and replace the words ``compliance
subaccount'' by the words ``compliance account''.
Sec. 77.4 [Amended]
3. Section 77.4 is amended, in paragraphs (c)(1)(ii)(A), (d)(1),
(d)(2), (d)(3), (g)(2)(ii), (g)(3)(ii), and (g)(3)(iii), by replacing
the word ``unit'' by the word ``source''.
Sec. 77.5 [Amended]
4. Section 77.5 is amended by:
a. In paragraph (b), replace the words ``compliance subaccount''
with the words ``compliance account'';
b. In paragraph (c), replace the words ``, from the unit's
compliance subaccount'' with the words ``allocated for the year after
the year in which the source has excess emissions, from the source's
compliance account'' and replace the word ``unit's'' by the word
``source's''; and
c. Remove paragraph (d).
Sec. 77.6 [Amended]
5. Section 77.6 is amended by, in paragraph (a)(1), add, after the
words ``sulfur dioxide'', the words occur at the affected source'' and
add, after the words ``owners and operators of'', the words ``the
affected source or''.
PART 78--APPEAL PROCEDURES FOR ACID RAIN PROGRAM
1. The authority citation for part 78 continues to read as follows:
Authority: 42 U.S.C. 7401, 7403, 7410, 7426, 7601, and 7651, et
seq.
Sec. 78.1 [Amended]
2. Section 78.1 is amended, in paragraph (a)(1), replace the words
``parts 72, 73, 74, 75, 76, or 77 of this chapter or part 97 of this
chapter'' by the words ``part 72, 73, 74, 75, 76, or 77 of this
chapter, subparts AA through GG and subparts AAA and GGG of part 96 of
this chapter, or part 97 of this chapter'' and add new paragraphs
(b)(7) and (b)(8) to read as follows:
Sec. 78.1 Purpose and scope.
(b) * * *
(7) Under subparts AA through GG of part 96 of this chapter,
(i) The decision on the deduction of CAIR NOX
allowances, and the adjustment of the information in a submission and
the deduction or transfer of CAIR NOX allowances based on
the information, as adjusted, under Sec. 96.154;
(ii) The correction of an error in a CAIR NOX Allowance
Tracking System account under Sec. 97.156;
(iii) The decision on the transfer of CAIR NOX
allowances under Sec. 96.161;
(iv) The finalization of control period emissions data, including
retroactive adjustment based on audit;
(v) The approval or disapproval of a petition under Sec. 96.175.
(8) Under subparts AAA through GGG of part 96 of this chapter,
(i) The decision on the deduction of CAIR SO2
allowances, and the adjustment of the information in a submission and
the deduction or transfer of CAIR SO2 allowances based on
the information, as adjusted, under Sec. 96.254;
(ii) The correction of an error in a CAIR SO2 Allowance
Tracking System account under Sec. 97.256;
(iii) The decision on the transfer of CAIR SO2
allowances under Sec. 96.261;
(iv) The finalization of control period emissions data, including
retroactive adjustment based on audit;
(v) The approval or disapproval of a petition under Sec. 96.275.
Sec. 78.3 [Amended]
3. Section 78.3 is amended by:
a. Amend paragraph (b)(3)(i) by adding, after the words ``(unless
the NOX authorized account representative is the
petitioner)'', the words ``or the CAIR designated representative or
CAIR authorized account representative under paragraph (a)(5) or (a)(6)
of this section (unless the CAIR designated representative or CAIR
authorized account representative is the petitioner)'';
b. In paragraph (c)(7) replace the words ``or part 97 of this
chapter, as appropriate'' by the words ``, subparts AA through GG of
part 96 of this chapter, subparts AAA through GGG of part 96 of this
chapter, or part 97 of this chapter, as appropriate'';
c. In paragraph (d)(2) add, after the words ``under the
NOX Budget Trading Program'', the words ``or on an account
certificate of representation submitted by a CAIR designated
representative or an application for a general account submitted by a
CAIR authorized account representative under subparts AA through GG of
part 96 of this chapter or subparts AAA through GGG of part 96 of this
chapter,'';
d. Add new paragraphs (a)(5), (a)(6), and (d)(5) and (d)(6).
The additions and revisions read as follows:
Sec. 78.3 Petition for administrative review and request for
evidentiary hearing.
(a) * * *
(5) The following persons may petition for administrative review of
a decision of the Administrator that is made under subparts AA through
GG of part 96 and that is appealable under Sec. 78.1(a) of this part:
(i) The CAIR designated representative for a source or the CAIR
authorized account representative for any CAIR NOX Allowance
Tracking System account covered by the decision; or
(ii) Any interested person.
(6) The following persons may petition for administrative review of
a decision of the Administrator that is made under subparts AAA through
GGG of part 96 and that is appealable under Sec. 78.1(a) of this part:
(i) The CAIR designated representative for a source or the CAIR
authorized account representative for any CAIR SO2 Allowance
Tracking System account covered by the decision; or
(ii) Any interested person.
* * * * *
[[Page 32742]]
(d) * * *
(5) Any provision or requirement of subparts AA through GG of part
96, including the standard requirements under Sec. 96.106 of this
chapter and any emission monitoring or reporting requirements.
(6) Any provision or requirement of subparts AAA through GGG of
part 96, including the standard requirements under Sec. 96.206 of this
chapter and any emission monitoring or reporting requirements.
* * * * *
Sec. 78.4 [Amended]
4. Section 78.4 is amended by adding two new sentences after the
fifth sentence in paragraph (a) to read as follows:
Sec. 78.4 Filings.
(a) * * * Any filings on behalf of owners and operators of a CAIR
unit or source shall be signed by the CAIR designated representative.
Any filings on behalf of persons with an interest in CAIR
NOX or SO2 allowances in a general account shall
be signed by the CAIR authorized account representative. * * *
* * * * *
Sec. 78.12 [Amended]
5. Section 78.12 is amended, in paragraph (a)(2), by adding, after
the words ``a NOX Budget permit'', the words '', CAIR
permit,''.
PART 96--[AMENDED]
1. Authority citation for Part 96 continues to read as follows:
Authority: 42 U.S.C. 7401, 7403, 7410, 7601.
2. Part 96 is amended by adding subparts AA through CC, adding and
reserving subpart DD and adding subparts EE through HH to read as
follows:
Subpart AA--CAIR NOX Trading Program General Provisions
Sec.
96.101 Purpose.
96.102 Definitions.
96.103 Measurements, abbreviations, and acronyms.
96.104 Applicability.
96.105 Retired unit exemption.
96.106 Standard requirements.
96.107 Computation of time.
96.108 Appeal Procedures.
Subpart BB--CAIR Designated Representative for CAIR Sources
96.110 Authorization and responsibilities of CAIR designated
representative.
96.111 Alternate CAIR designated representative.
96.112 Changing CAIR designated representative and alternate CAIR
designated representative; changes in owners and operators.
96.113 Certificate of representation.
96.114 Objections concerning CAIR designated representative.
Subpart CC--Permits
96.120 General CAIR NOX Trading Program permit
requirements.
96.121 Submission of CAIR permit applications.
96.122 Information requirements for CAIR permit applications.
96.123 CAIR permit contents and term.
96.124 CAIR permit revisions.
Subpart DD--[Reserved]
Subpart EE--CAIR NOX Allowance Allocations
96.140 State trading budgets.
96.141 Timing requirements for CAIR NOX allowance
allocations.
96.142 CAIR NOX allowance allocations.
Subpart FF--CAIR NOX Allowance Tracking System
96.150 CAIR NOX Allowance Tracking System accounts.
96.151 Establishment of accounts.
96.152 Responsibilities of CAIR NOX authorized account
representative.
96.153 Recordation of CAIR NOX allowance allocations.
96.154 Compliance with CAIR NOX emissions limitation.
96.155 Banking.
96.156 Account error.
96.157 Closing of general accounts.
Subpart GG--CAIR NOX Allowance Transfers
96.160 Submission of CAIR NOX allowance transfers.
96.161 EPA recordation.
96.162 Notification.
Subpart HH--Monitoring and Reporting
96.170 General requirements.
96.171 Initial certification and recertification procedures.
96.172 Out of control periods.
96.173 Notifications.
96.174 Recordkeeping and reporting.
96.175 Petitions.
96.176 Additional requirements to provide heat input data.
Subpart AA--CAIR NOX Trading Program General Provisions
Sec. 96.101 Purpose.
This subpart establishes the model rule comprising general
provisions and the applicability, permitting, allowance, excess
emissions, and monitoring for the state Clean Air Interstate Rule
(CAIR) NOX Trading Program, under section 110 of the Clean
Air Act (CAA) and Sec. 51.123 of this chapter, as a means of reducing
national NOX emissions.
Sec. 96.102 Definitions.
The terms used in this subpart shall have the meanings set forth in
this section as follows:
Account number means the identification number given by the
Administrator to each CAIR NOX Allowance Tracking System
account.
Acid Rain emissions limitation means a limitation on emissions of
sulfur dioxide or nitrogen oxides under the Acid Rain Program.
Acid Rain Program means a multi-state sulfur dioxide and nitrogen
oxides air pollution control and emission reduction program established
by the Administrator under title IV of the CAA and parts 72 through 78
of this chapter.
Administrator means the Administrator of the United States
Environmental Protection Agency or the Administrator's duly authorized
representative.
Allocate or allocation means, with regard to CAIR NOX
allowances, the determination by the Administrator of the amount of
CAIR NOX allowances to be initially credited to a CAIR unit
or a new unit set-aside.
Alternate CAIR designated representative means, for a CAIR source
and each CAIR unit at the source, the natural person who is authorized
by the owners and operators of the source and all CAIR units at the
source in accordance with subpart BB of this part, to act on behalf of
the CAIR designated representative in matters pertaining to the CAIR
SO2 Trading Program and the CAIR NOX Trading
Program. This natural person shall be the same person as the alternate
designated representative under the Acid Rain Program under Sec. 72.22
of this chapter.
Automated data acquisition and handling system or DAHS means that
component of the CEMS, or other emissions monitoring system approved
for use under subpart HH of this part, designed to interpret and
convert individual output signals from pollutant concentration
monitors, flow monitors, diluent gas monitors, and other component
parts of the monitoring system to produce a continuous record of the
measured parameters in the measurement units required by subpart HH of
this part.
Boiler means an enclosed fossil- or other-fuel-fired combustion
device used to produce heat and to transfer heat to recirculating
water, steam, or other medium.
Bottoming-cycle cogeneration unit means a cogeneration unit in
which the energy input to the unit is first used to produce useful
thermal energy and at least some of the reject heat from the useful
thermal energy application or
[[Page 32743]]
process is then used for power production.
CAIR designated representative means, for a CAIR source and each
CAIR unit at the source, the natural person who is authorized by the
owners and operators of the source and all CAIR units at the source, in
accordance with subpart BB of this part, to represent and legally bind
each owner and operator in matters pertaining to the CAIR
SO2 Trading Program and to the CAIR NOX Trading
Program. This natural person shall be the same person who is the
authorized account representative under the Acid Rain Program under
Sec. 72.20 of this chapter.
CAIR NOX allowance means a limited authorization issued
by the Administrator to emit up to one ton of nitrogen oxide during the
control period of the specified year or of any year thereafter under
the CAIR NOX Program or, except for purposes of subpart EE
of this part, any NOX SIP Call allowance, allocated for the
2009, or any earlier, ozone season that is not used to meet an
NOX emissions limitation under the NOX Budget
Trading Program.
CAIR NOX allowance deduction or deduct CAIR
NOX allowances means the permanent withdrawal of CAIR
NOX allowances by the Administrator from a compliance
account in order to account for a specified number of tons of nitrogen
oxide emissions from all CAIR units at a CAIR source for a control
period, determined in accordance with subparts FF and HH of this part,
or to account for excess emissions.
CAIR NOX Allowance Tracking System (INATS) means the
system by which the Administrator records allocations, deductions, and
transfers of CAIR NOX allowances under the CAIR
NOX Trading Program.
CAIR NOX Allowance Tracking System account means an
account in the CAIR NOX Allowance Tracking System
established by the Administrator for purposes of recording the
allocation, holding, transferring, or deducting of CAIR NOX
allowances.
CAIR NOX allowance transfer deadline means midnight of
March 1 or, if March 1 is not a business day, midnight of the first
business day thereafter and is the deadline by which a CAIR
NOX allowance transfer must be submitted for recordation in
a CAIR source's compliance account in order to meet the source's CAIR
NOX emissions limitation for the control period immediately
preceding such deadline.
CAIR NOX allowances held or hold CAIR NOX
allowances means the CAIR NOX allowances recorded by the
Administrator, or submitted to the Administrator for recordation, in
accordance with subparts FF and GG of this part, in a CAIR
NOX Allowance Tracking System account.
CAIR NOX authorized account representative means a
responsible natural person who is authorized, in accordance with
subpart BB of this part, to transfer and otherwise dispose of CAIR
NOX allowances held in a CAIR NOX Allowance
Tracking System general account; or, in the case of a compliance
account, the CAIR designated representative of the source.
CAIR NOX emissions limitation means, for a CAIR source,
the tonnage equivalent of the CAIR NOX allowances available
for compliance deduction for the source under Sec. Sec. 96.154(a) and
(b) in a control period.
CAIR NOX Trading Program means a multi-state nitrogen
oxides air pollution control and emission reduction program established
by the Administrator in accordance with subparts AA through HH of this
part and Sec. 51.123 of this chapter, as a means of mitigating
interstate transport of fine particulates, ozone, and nitrogen oxides.
CAIR permit means the legally binding and federally enforceable
written document, or portion of such document, issued by the permitting
authority under subpart CC of this part, including any permit
revisions, specifying the CAIR SO2 and NOX
Trading Program requirements applicable to a CAIR source, to each CAIR
unit at the CAIR source, and to the owners and operators and the CAIR
designated representative of the CAIR source and each CAIR unit.
CAIR SO2 Trading Program means a multi-state sulfur
dioxide air pollution control and emission reduction program
established by the Administrator in accordance with subparts AAA
through HHH of this part and Sec. 51.124 of this chapter, as a means
of mitigating interstate transport of fine particulates.
CAIR source means a source that includes one or more CAIR units.
CAIR unit means a unit that is subject to the CAIR NOX
Trading Program under Sec. 96.104.
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, with regard to a unit, combusting coal or any
coal-derived fuel alone or in combination with any amount of any other
fuel in any year.
Cogeneration unit means a unit:
(1) Having equipment used to produce electricity and useful thermal
energy for industrial, commercial, heating, or cooling purposes through
the sequential use of energy; and
(2) Producing during the 12-month period starting on the date the
unit first produces electricity and during any calendar year after
which the unit first produces electricity--
(i) For a topping-cycle cogeneration 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
or, if useful thermal energy produced is less than 15 percent of total
energy output, not less than 45 percent of total energy input.
(ii) For a bottoming-cycle cogeneration unit, useful power not less
than 45 percent of total energy input.
Combustion turbine means an enclosed device comprising 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. A combustion turbine that is
combined cycle also includes any associated heat recovery steam
generator and steam turbine.
Commence commercial operation means, with regard to a unit that
serves a generator, to have begun to produce steam, gas, or other
heated medium used to generate electricity for sale or use, including
test generation. Except as provided in Sec. 96.105, for a unit that is
a CAIR unit under Sec. 96.104 on the date the unit commences
commercial operation, such date shall remain the unit's date of
commencement of commercial operation even if the unit is subsequently
modified or reconstructed. Except as provided in Sec. 96.105, for a
unit that is not a CAIR unit under Sec. 96.104 on the date the unit
commences commercial operation, the date the unit becomes a CAIR unit
under Sec. 96.104 shall be the unit's date of commencement of
commercial operation.
Commence operation means to have begun any mechanical, chemical, or
electronic process, including, with regard to a unit, start-up of a
unit's combustion chamber. Except as provided in Sec. 96.105, for a
unit that is a CAIR unit under Sec. 96.104 on the date of commencement
of operation, such date shall remain the unit's date of commencement of
operation even if the unit is subsequently modified or reconstructed.
Except as provided in Sec. 96.105, for a unit that is not a CAIR
[[Page 32744]]
unit under Sec. 96.104 on the date of commencement of operation, the
date the unit becomes a CAIR unit under Sec. 96.104 shall be the
unit's date of commencement of operation.
Common stack means a single flue through which emissions from two
or more units are exhausted.
Compliance account means a CAIR NOX Allowance Tracking
System account, established by the Administrator for a CAIR source
under subpart FF of this part, in which the CAIR NOX
allowance allocations for the CAIR units at the source are initially
recorded and in which are held CAIR NOX allowances available
for use for a control period in order to meet the source's CAIR
NOX emissions limitation.
Continuous emission monitoring system or CEMS means the equipment
required under subpart HH of this part to sample, analyze, measure, and
provide, by means of readings recorded at least once every 15 minutes
(using an automated data acquisition and handling system (DAHS)), a
permanent record of nitrogen oxide (NOX) emissions, stack
gas volumetric flow rate or stack gas moisture content (as applicable),
in a manner consistent with part 75 of this chapter. The following
systems are the principal types of continuous emission monitoring
systems required under subpart HH of this part:
(1) A flow monitoring system, consisting of a stack flow rate
monitor and an automated DAHS. A flow monitoring system provides a
permanent, continuous record of stack gas volumetric flow rate, in
standard cubic feet per hour (scfh);
(2) A nitrogen oxides (NOX) concentration monitoring
system, consisting of a NOX pollutant concentration monitor
and an automated DAHS. A NOX concentration monitoring system
provides a permanent, continuous record of NOX emissions, in
parts per million (ppm);
(3) A nitrogen oxides emission rate (or NOX-diluent)
monitoring system, consisting of a NOX pollutant
concentration monitor, a diluent gas (CO2 or O2)
monitor, and an automated DAHS. A NOX-diluent monitoring
system provides a permanent, continuous record of: NOX
concentration, in parts per million (ppm); diluent gas concentration,
in percent CO2 or O2 (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. A moisture monitoring system provides a permanent,
continuous record of the stack gas moisture content, in percent
H2O (percent H2O);
(5) A carbon dioxide (CO2) monitoring system, consisting
of a CO2 pollutant concentration monitor (or an oxygen
monitor plus suitable mathematical equations from which the
CO2 concentration is derived) and the automated DAHS. A
carbon dioxide monitoring system provides a permanent, continuous
record of CO2 emissions, in percent CO2 (percent
CO2); and
(6) An oxygen (O2) monitoring system, consisting of an
O2 concentration monitor and an automated DAHS. An
O2 monitoring system provides a permanent, continuous record
of O2 in percent O2 (percent O2).
Control period means the period beginning January 1 of a year and
ending on December 31 of the same year, inclusive.
Emissions means air pollutants exhausted from a unit or source into
the atmosphere, as measured, recorded, and reported to the
Administrator by the CAIR designated representative and as determined
by the Administrator in accordance with subpart HH of this part.
Energy Information Administration means the Energy Information
Administration of the United States Department of Energy.
Excess emissions means any ton of nitrogen oxide emitted by the
CAIR units at a CAIR source during a control period that exceeds the
CAIR NOX emissions limitation for the source.
Fossil fuel means natural gas, petroleum, coal, or any form of
solid, liquid, or gaseous fuel derived from such material.
Fossil-fuel-fired means, with regard to a unit, any boiler or
turbine combusting any amount of fossil fuel.
General account means a CAIR NOX Allowance Tracking
System account, established under subpart FF of this part, that is not
a compliance account.
Generator means a device that produces electricity.
Gross thermal energy means, with regard to a cogeneration unit,
useful thermal energy output plus, where such output is made available
for an industrial or commercial process, any heat contained in
condensate return or makeup water.
Heat input means, with regard to a specified period to time, the
product (in mmBtu/time) of the gross calorific value of the fuel (in
Btu/lb) divided by 1,000,000 Btu/mmBtu and 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 CAIR designated
representative and as determined by the Administrator in accordance
with subpart HH of this part. Heat input does not include the heat
derived from preheated combustion air, recirculated flue gases, or
exhaust from other sources.
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 customer reserves, or
is entitled to receive, a specified amount or percentage of nameplate
capacity and associated energy from any specified unit and pays its
proportional amount of such unit's total costs, pursuant to a contract:
(1) For the life of the unit;
(2) For a cumulative term of no less than 30 years, including
contracts that permit an election for early termination; or
(3) For a period 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 specified by the manufacturer of the unit as of the initial
installation of the unit.
Monitoring system means any monitoring system that meets the
requirements of subpart HH of this part, including a continuous
emissions monitoring system or an alternative monitoring system.
Nameplate capacity means the maximum electrical generating output
(in MWe) that a generator can sustain over a specified period of time
when not restricted by seasonal or other deratings as specified by the
manufacturer of the generator as of the initial installation of the
generator or, if the generator is subsequently modified or
reconstructed resulting in an increase in such maximum electrical
generating output, as specified by the person conducting the
modification or reconstruction.
NOX Budget Trading Program means a multi-state nitrogen
oxide air pollution control and emission reduction program established
by air pollution control and emission
[[Page 32745]]
reduction program established by the Administrator in accordance with
subparts A through I of this part and Sec. 51.121 of this chapter, as
a means of mitigating interstate transport of ozone and nitrogen
oxides.
NOX SIP Call allowance means a limited authorization
issued by the Administrator under the NOX Budget Trading
Program to emit up to one ton of nitrogen oxides during the ozone
season of the specified year or any year thereafter under the
NOX Budget Trading Program or during the control period in
2010 or any year thereafter under the CAIR NOX Trading
Program, provided that Sec. 96.54(f) of this chapter shall not apply
to the use of such allowance under Sec. 96.154.
Operator means any person who operates, controls, or supervises a
CAIR unit or a CAIR 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 any of the following persons:
(1) Any holder of any portion of the legal or equitable title in a
CAIR unit; or
(2) Any holder of a leasehold interest in a CAIR unit; or
(3) Any purchaser of power from a CAIR unit under a life-of-the-
unit, firm power contractual arrangement; 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 the CAIR unit;
or
(4) With regard to any general account, any person who has an
ownership interest with respect to the CAIR NOX allowances
held in the general account and who is subject to the binding agreement
for the CAIR authorized account representative to represent that
person's ownership interest with respect to CAIR NOX
allowances.
Permitting authority means the State air pollution control agency,
local agency, other State agency, or other agency authorized by the
Administrator to issue or revise permits to meet the requirements of
the CAIR NOX Trading Program in accordance with subpart CC
of this part.
Potential electrical output capacity means 33 percent of a unit's
maximum design heat input, divided by 3,413 mmBtu/kWh, divided by 1,000
kWh/MWh, and multiplied by 8,760 hr/yr.
Receive or receipt of means, when referring to the permitting
authority or the Administrator, to come into possession of a document,
information, or correspondence (whether sent in hard copy or by
authorized electronic transmission), as indicated in an official
correspondence log, or by a notation made on the document, information,
or correspondence, by the permitting authority or the Administrator in
the regular course of business.
Recordation, record, or recorded means, with regard to CAIR
NOX allowances, the movement of CAIR NOX
allowances by the Administrator into or between CAIR NOX
Allowance Tracking 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.
Serial number means for a CAIR NOX allowance, the unique
identification number assigned to each CAIR NOX allowance by
the Administrator, under Sec. 96.153(f).
Sequential use of energy means:
(1) For a topping-cycle cogeneration unit, the use of reject heat
from power production in a useful thermal energy application or
process; or
(2) For a bottoming-cycle cogeneration unit, the use of reject heat
from useful thermal energy application or process in power production.
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. For purposes of section 502(c) of the Clean
Air Act, a ``source,'' including a ``source'' with multiple units,
shall be considered a single ``facility.''
State means one of the 50 States or the District of Columbia that
adopts the CAIR NOX Trading Program pursuant to Sec. 51.123
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.
Compliance with any ``submission,'' ``service,'' or ``mailing''
deadline shall be determined by the date of dispatch, transmission, or
mailing and not the date of receipt.
Title V operating permit means a permit issued under title V of the
Clean Air Act and part 70 or part 71 of this chapter.
Title V operating permit regulations means the regulations that the
Administrator has approved or issued as meeting the requirements of
title V of the Clean Air Act and part 70 or 71 of this chapter.
Ton means 2,000 pounds. For the purpose of determining compliance
with the CAIR NOX emissions limitation, total tons of
nitrogen oxides emissions for a control period shall be calculated as
the sum of all recorded hourly emissions (or the mass equivalent of the
recorded hourly emission rates) in accordance with subpart HH of this
part, with any remaining fraction of a ton equal to or greater than
0.50 tons deemed to equal one ton and any remaining fraction of a ton
less than 0.50 tons deemed to equal zero tons.
Topping-cycle cogeneration unit means a cogeneration unit in which
the energy input to the unit is first used to produce useful power and
at least some of the reject heat from the power production is then used
to provide useful thermal energy.
Total energy input means, with regard to a cogeneration unit, total
energy of all forms supplied to the cogeneration unit, excluding energy
produced by the cogeneration unit itself.
Total energy output means, with regard to a cogeneration unit, the
sum of useful power and useful thermal energy produced by the
cogeneration unit.
Unit means a stationary boiler or combustion turbine.
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, with regard to a
cogeneration unit, electricity or mechanical energy made 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, with regard to a cogeneration unit,
thermal energy that is:
(1) Made available to an industrial or commercial process,
excluding any heat contained in condensate return or makeup water;
(2) Used in a heat application (e.g., space heating or domestic hot
water heating); or
(3) Used in a space cooling application (i.e., thermal energy used
by an absorption chiller).
Utility power distribution system means the portion of an
electricity grid owned or operated by a distribution utility and
dedicated to delivering electricity to customers.
[[Page 32746]]
Sec. 96.103 Measurements, abbreviations, and acronyms.
Measurements, abbreviations, and acronyms used in this part are
defined as follows:
Btu--British thermal unit.
CO2--carbon dioxide.
NOX--nitrogen oxide.
hr--hour.
kW--kilowatt electrical.
kWh--kilowatt hour.
mmBtu--million Btu.
MWe--megawatt electrical.
MWh--megawatt hour.
O2--oxygen.
SO2--sulfur dioxide.
yr--year.
Sec. 96.104 Applicability.
The following units in a State shall be CAIR units, and any source
that includes one or more such units shall be a CAIR source, subject to
the requirements of this subpart and subparts BB through HH of this
part:
(a) Except a unit under paragraph (b) of this section, a fossil
fuel-fired boiler or combustion turbine serving at any time a generator
with nameplate capacity of more than 25 MWe producing electricity for
sale.
(b) A fossil fuel-fired cogeneration unit serving at any time a
generator with nameplate capacity of more than 25 MWe and in any year
supplying 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.
Sec. 96.105 Retired unit exemption.
(a) This section applies to any CAIR unit that is permanently
retired.
(b)(1) Any CAIR unit that is permanently retired shall be exempt
from the CAIR NOX Trading Program, except for the provisions
of this section, Sec. 96.102, Sec. 96.103, Sec. 96.104, Sec.
96.106(c)(5) through (8), Sec. 96.107, and subparts EE through GG of
this part.
(2) The exemption under paragraph (b)(1) of this section shall
become effective the day on which the unit is permanently retired.
Within 30 days of permanent retirement, the CAIR designated
representative shall submit a statement to the permitting authority
otherwise responsible for administering any CAIR permit for the unit.
The CAIR designated representative shall submit a copy of the statement
to the Administrator. The statement shall state, in a format prescribed
by the permitting authority, that the unit was permanently retired on a
specific date, and will comply with the requirements of paragraph (c)
of this section.
(3) After receipt of the notice under paragraph (b)(2) of this
section, the permitting authority will amend any permit under subpart
CC of this part covering the source at which the unit is located to add
the provisions and requirements of the exemption under paragraphs
(b)(1) and (c) of this section.
(c) Special provisions.
(1) A unit exempt under this section shall not emit any nitrogen
oxides, starting on the date that the exemption takes effect.
(2) The permitting authority will allocate CAIR NOX
allowances under subpart EE of this part to a unit exempt under this
section.
(3) For a period of 5 years from the date the records are created,
the owners and operators of a unit exempt under this section shall
retain at the source that includes the unit, records demonstrating that
the unit is permanently retired. The 5-year period for keeping records
may be extended for cause, at any time prior to the end of the period,
in writing by the permitting authority or the Administrator. The owners
and operators bear the burden of proof that the unit is permanently
retired.
(4) The owners and operators and, to the extent applicable, the
CAIR designated representative of a unit exempt under this section
shall comply with the requirements of the CAIR NOX 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.
(5) A unit exempt under this section and located at a source that
is required, or but for this exemption would be required, to have a
title V operating permit shall not resume operation unless the CAIR
designated representative of the source submits a complete CAIR permit
application under Sec. 96.122 for the unit not less than 18 months (or
such lesser time provided by the permitting authority) before the later
of January 1, 2010 or the date on which the unit resumes operation.
(6) On the earlier of the following dates, a unit exempt under
paragraph (b) of this section shall lose its exemption:
(i) The date on which the CAIR designated representative submits a
CAIR permit application for the unit under paragraph (c)(5) of this
section;
(ii) The date on which the CAIR designated representative is
required under paragraph (c)(5) of this section to submit a CAIR permit
application for the unit; or
(iii) The date on which the unit resumes operation, if the CAIR
designated representative is not required to submit a CAIR permit
application for the unit.
(7) For the purpose of applying monitoring requirements under
subpart HH of this part, a unit that loses its exemption under this
section shall be treated as a unit that commences operation and
commercial operation on the first date on which the unit resumes
operation.
Sec. 96.106 Standard requirements.
(a) Permit Requirements.
(1) The CAIR designated representative of each CAIR source required
to have a title V operating permit and each CAIR unit required to have
a title V operating permit at the source shall:
(i) Submit to the permitting authority a complete CAIR permit
application under Sec. 96.122 in accordance with the deadlines
specified in Sec. 96.121(b) and (c); and
(ii) Submit in a timely manner any supplemental information that
the permitting authority determines is necessary in order to review a
CAIR permit application and issue or deny a CAIR permit.
(2) The owners and operators of each CAIR source required to have a
title V operating permit and each CAIR unit required to have a title V
operating permit at the source shall have a CAIR permit issued by the
permitting authority and operate the unit in compliance with such CAIR
permit.
(3) The owners and operators of a CAIR source that is not otherwise
required to have a title V operating permit are not required to submit
a CAIR permit application, and to have a CAIR permit, under subpart CC
of this part for such CAIR source.
(b) Monitoring requirements.
(1) The owners and operators and, to the extent applicable, the
CAIR designated representative of each CAIR source and each CAIR unit
at the source shall comply with the monitoring requirements of subpart
HH of this part.
(2) The emissions measurements recorded and reported in accordance
with subpart HH of this part shall be used to determine compliance by
the unit with the CAIR NOX emissions limitation under
paragraph (c) of this section.
(c) Nitrogen oxide emission requirements.
(1) As of the CAIR NOX allowance transfer deadline for a
control period, the owners and operators of each CAIR source and each
CAIR unit at the source shall hold, in the source's compliance account,
CAIR NOX allowances available for compliance deductions for
the control period under Sec. 96.154(a) in an amount not less than the
total nitrogen oxides emissions for the
[[Page 32747]]
control period from all CAIR units at the source, as determined in
accordance with subpart HH of this part.
(2) Each ton of nitrogen oxide emitted in excess of the CAIR
NOX emissions limitation shall constitute a separate
violation of this subpart, the Clean Air Act, and applicable State law.
(3) A CAIR unit shall be subject to the requirements under
paragraph (c)(1) of this section starting on the later of January 1,
2010 or the deadline for meeting the unit's monitor certification
requirements under Sec. 96.170(b)(1) or (b)(2).
(4) A CAIR NOX allowance shall not be deducted, in order
to comply with the requirements under paragraph (c)(1) of this section,
for a control period in a year prior to the year for which the CAIR
NOX allowance was allocated.
(5) CAIR NOX allowances shall be held in, deducted from,
or transferred into or among CAIR NOX Allowance Tracking
System accounts in accordance with subpart EE of this part.
(6) A CAIR NOX allowance is a limited authorization to
emit one ton of nitrogen oxide in accordance with the CAIR
NOX Trading Program. No provision of the CAIR NOX
Trading Program, the CAIR permit application, the CAIR permit, or
exemption under Sec. 96.105 and no provision of law shall be construed
to limit the authority of the State or the United States to terminate
or limit such authorization.
(7) A CAIR NOX allowance does not constitute a property
right.
(8) Upon recordation by the Administrator under subparts FF and GG
of this part, every allocation, transfer, or deduction of a CAIR
NOX allowance to or from a CAIR unit's compliance account is
incorporated automatically in any CAIR permit of the CAIR unit.
(d) Excess emissions requirements.
(1) The owners and operators of a CAIR unit that has excess
emissions in any control period shall:
(i) Surrender the CAIR NOX allowances required for
deduction under Sec. 96.154(d)(1); and
(ii) Pay any fine, penalty, or assessment or comply with any other
remedy imposed under Sec. 96.154(d)(2).
(e) Recordkeeping and Reporting Requirements.
(1) Unless otherwise provided, the owners and operators of the CAIR
source and each CAIR unit at the source shall keep on site at the
source each of the following documents for a period of 5 years from the
date the document is created. This period may be extended for cause, at
any time prior to the end of 5 years, in writing by the permitting
authority or the Administrator.
(i) The certificate of representation under Sec. 96.113 for the
CAIR designated representative for the source and each CAIR 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. 96.113 changing the
CAIR designated representative.
(ii) All emissions monitoring information, in accordance with
subpart HH of this part; provided that to the extent that subpart HH of
this part provides for a 3-year period for recordkeeping, the 3-year
period shall apply.
(iii) Copies of all reports, compliance certifications, and other
submissions and all records made or required under the CAIR
NOX Trading Program.
(iv) Copies of all documents used to complete a CAIR permit
application and any other submission under the CAIR NOX
Trading Program or to demonstrate compliance with the requirements of
the CAIR NOX Trading Program.
(2) The CAIR designated representative of a CAIR source and each
CAIR unit at the source shall submit the reports required under the
CAIR NOX Trading Program, including those under subpart HH
of this part.
(f) Liability.
(1) Any person who knowingly violates any requirement or
prohibition of the CAIR NOX Trading Program, a CAIR permit,
or an exemption under Sec. 96.105 shall be subject to enforcement
pursuant to applicable State or Federal law.
(2) Any person who knowingly makes a false material statement in
any record, submission, or report under the CAIR NOX Trading
Program shall be subject to criminal enforcement pursuant to the
applicable State or Federal law.
(3) No permit revision shall excuse any violation of the
requirements of the CAIR NOX Trading Program that occurs
prior to the date that the revision takes effect.
(4) Each CAIR source and each CAIR unit shall meet the requirements
of the CAIR NOX Trading Program.
(5) Any provision of the CAIR NOX Trading Program that
applies to a CAIR source or the CAIR designated representative of a
CAIR source shall also apply to the owners and operators of such source
and of the CAIR units at the source.
(6) Any provision of the CAIR NOX Trading Program that
applies to a CAIR unit or the CAIR designated representative of a CAIR
unit shall also apply to the owners and operators of such unit.
(g) Effect on Other Authorities. No provision of the CAIR
NOX Trading Program, a CAIR permit application, a CAIR
permit, or an exemption under Sec. 96.105 shall be construed as
exempting or excluding the owners and operators and, to the extent
applicable, the CAIR designated representative of a CAIR source or CAIR
unit from compliance with any other provision of the applicable,
approved State implementation plan, a federally enforceable permit, or
the Clean Air Act.
Sec. 96.107 Computation of time.
(a) Unless otherwise stated, any time period scheduled, under the
CAIR NOX 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
CAIR NOX 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 CAIR NOX Trading Program, falls on a weekend or a
State or Federal holiday, the time period shall be extended to the next
business day.
Sec. 96.108 Appeal Procedures.
The appeal procedures for decisions of the Administrator under the
CAIR NOX Trading Program are set forth in part 78 of this
chapter.
Subpart BB--CAIR Designated Representative for CAIR Sources
Sec. 96.110 Authorization and responsibilities of CAIR designated
representative.
(a) Except as provided under Sec. 96.111, each CAIR source,
including all CAIR units at the source, shall have one and only one
CAIR designated representative, with regard to all matters under the
CAIR NOX Trading Program concerning the source or any CAIR
unit at the source.
(b) The CAIR designated representative of the CAIR source shall be
selected by an agreement binding on the owners and operators of the
source and all CAIR units at the source and shall act in accordance
with the certification statement in Sec. 96.113(a)(5)(iv).
(c) Upon receipt by the Administrator of a complete certificate of
representation under Sec. 96.113, the CAIR designated representative
of the source shall represent and, by his or her representations,
actions, inactions, or submissions, legally bind each owner
[[Page 32748]]
and operator of the CAIR source represented and each CAIR unit at the
source in all matters pertaining to the CAIR NOX Trading
Program, notwithstanding any agreement between the CAIR designated
representative and such owners and operators. The owners and operators
shall be bound by any decision or order issued to the CAIR designated
representative by the permitting authority, the Administrator, or a
court regarding the source or unit.
(d) No CAIR permit will be issued, no emissions data reports will
be accepted, and no CAIR NOX Allowance Tracking System
account will be established for a CAIR unit at a source, until the
Administrator has received a complete certificate of representation
under Sec. 96.113 for a CAIR designated representative of the source
and the CAIR units at the source.
(e)(1) Each submission under the CAIR NOX Trading
Program shall be submitted, signed, and certified by the CAIR
designated representative for each CAIR source on behalf of which the
submission is made. Each such submission shall include the following
certification statement by the CAIR 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.''
(2) The permitting authority and the Administrator will accept or
act on a submission made on behalf of owner or operators of a CAIR
source or a CAIR unit only if the submission has been made, signed, and
certified in accordance with paragraph (e)(1) of this section.
Sec. 96.111 Alternate CAIR designated representative.
(a) A certificate of representation may designate one and only one
alternate CAIR designated representative, who may act on behalf of the
CAIR designated representative. The agreement by which the alternate
CAIR designated representative is selected shall include a procedure
for authorizing the alternate CAIR designated representative to act in
lieu of the CAIR designated representative.
(b) Upon receipt by the Administrator of a complete certificate of
representation under Sec. 96.113, any representation, action,
inaction, or submission by the alternate CAIR designated representative
shall be deemed to be a representation, action, inaction, or submission
by the CAIR designated representative.
(c) Except in this section and Sec. Sec. 96.102, 96.110(a),
96.112, 96.113, and 96.151, whenever the term ``CAIR designated
representative'' is used in this subpart, the term shall be construed
to include the alternate CAIR designated representative.
Sec. 96.112 Changing CAIR designated representative and alternate
CAIR designated representative; changes in owners and operators.
(a) Changing CAIR designated representative. The CAIR designated
representative may be changed at any time upon receipt by the
Administrator of a superseding complete certificate of representation
under Sec. 96.113. Notwithstanding any such change, all
representations, actions, inactions, and submissions by the previous
CAIR designated representative prior to the time and date when the
Administrator receives the superseding certificate of representation
shall be binding on the new CAIR designated representative and the
owners and operators of the CAIR source and the CAIR units at the
source.
(b) Changing alternate CAIR designated representative. The
alternate CAIR designated representative may be changed at any time
upon receipt by the Administrator of a superseding complete certificate
of representation under Sec. 96.113. Notwithstanding any such change,
all representations, actions, inactions, and submissions by the
previous alternate CAIR designated representative prior to the time and
date when the Administrator receives the superseding certificate of
representation shall be binding on the new alternate CAIR designated
representative and the owners and operators of the CAIR source and the
CAIR units at the source.
(c) Changes in owners and operators.
(1) In the event a new owner or operator of a CAIR source or a CAIR
unit is not included in the list of owners and operators submitted in
the certificate of representation under Sec. 96.113, such new 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 CAIR designated representative and any alternate
CAIR designated representative of the source or unit, and the
decisions, orders, actions, and inactions of the permitting authority
or the Administrator, as if the new owner or operator were included in
such list.
(2) Within 30 days following any change in the owners and operators
of a CAIR source or a CAIR unit, including the addition of a new owner
or operator, the CAIR designated representative or alternate CAIR
designated representative shall submit a revision to the certificate of
representation under Sec. 96.113 amending the list of owners and
operators to include the change.
Sec. 96.113 Certificate of representation.
(a) A complete certificate of representation for a CAIR designated
representative or an alternate CAIR designated representative shall
include the following elements in a format prescribed by the
Administrator:
(1) Identification of the CAIR source and each CAIR unit at the
source for which the certificate of representation is submitted.
(2) For each CAIR unit at the source, the dates on which the unit
commenced operation and commenced commercial operation.
(3) The name, address, e-mail address (if any), telephone number,
and facsimile transmission number (if any) of the CAIR designated
representative and any alternate CAIR designated representative.
(4) A list of the owners and operators of the CAIR source and of
each CAIR unit at the source.
(5) The following certification statements by the CAIR designated
representative and any alternate CAIR designated representative--
(i) ``I certify that I was selected as the CAIR designated
representative or alternate CAIR designated representative, as
applicable, by an agreement binding on the owners and operators of the
source and each unit at the source.''
(ii) ``I certify that I have all the necessary authority to carry
out my duties and responsibilities under the CAIR SO2 and
NOX Trading Programs on behalf of the owners and operators
of the source and of each unit at the source and that each such owner
and operator shall be fully bound by my representations, actions,
inactions, or submissions.''
(iii) ``I certify that the owners and operators of the source and
of each unit at the source shall be bound by any order issued to me by
the Administrator, the permitting authority, or a court regarding the
source or unit.''
[[Page 32749]]
(iv) ``Where there are multiple holders of a legal or equitable
title to, or a leasehold interest in, a unit, or where a customer
purchases power from a unit under life-of-the-unit, firm power
contractual arrangements, I certify that: I have given a written notice
of my selection as the ``designated representative'' or `alternated
designated representative', as applicable, and of the agreement by
which I was selected to each owner and operator of the source and of
each unit at the source; and allowances and proceeds of transactions
involving allowances will be deemed to be held or distributed in
proportion to each holder's legal, equitable, leasehold, or contractual
reservation or entitlement or, if such multiple holders have expressly
provided for a different distribution of allowances by contract, that
allowances and the proceeds of transactions involving allowances will
be deemed to be held or distributed in accordance with the contract.''
(6) The signature of the CAIR designated representative and any
alternate CAIR designated representative and the dates signed.
(b) Unless otherwise required by the permitting authority or the
Administrator, documents of agreement referred to in the certificate of
representation shall not be submitted to the permitting authority or
the Administrator. Neither the permitting authority nor the
Administrator shall be under any obligation to review or evaluate the
sufficiency of such documents, if submitted.
Sec. 96.114 Objections concerning CAIR designated representative.
(a) Once a complete certificate of representation under Sec.
96.113 has been submitted and received, the permitting authority and
the Administrator will rely on the certificate of representation unless
and until a superseding complete certificate of representation under
Sec. 96.113 is received by the Administrator.
(b) Except as provided in Sec. 96.112(a) or (b), no objection or
other communication submitted to the permitting authority or the
Administrator concerning the authorization, or any representation,
action, inaction, or submission of the CAIR designated representative
shall affect any representation, action, inaction, or submission of the
CAIR designated representative or the finality of any decision or order
by the permitting authority or the Administrator under the CAIR
NOX Trading Program.
(c) Neither the permitting authority nor the Administrator will
adjudicate any private legal dispute concerning the authorization or
any representation, action, inaction, or submission of any CAIR
designated representative, including private legal disputes concerning
the proceeds of CAIR NOX allowance transfers.
Subpart CC--Permits
Sec. 96.120 General CAIR Trading Program permit requirements.
(a) For each CAIR source required to have a title V operating
permit, such permit shall include a CAIR permit administered by the
permitting authority for the title V operating permit. The CAIR portion
of the title V permit shall be administered in accordance with the
permitting authority's title V operating permits regulations
promulgated under part 70 or 71 of this chapter, except as provided
otherwise by this subpart.
(b) Each CAIR permit shall contain all applicable CAIR
SO2 and NOX Trading Program requirements and
shall be a complete and separable portion of the title V operating
permit under paragraph (a) of this section.
Sec. 96.121 Submission of CAIR permit applications.
(a) Duty to apply. The CAIR designated representative of any CAIR
source required to have a title V operating permit shall submit to the
permitting authority a complete CAIR permit application under Sec.
96.122 by the applicable deadline in paragraph (b) of this section.
(b) Application deadline. For any source with any CAIR unit, the
CAIR designated representative shall submit a complete CAIR permit
application under Sec. 96.122 covering such CAIR unit to the
permitting authority at least 18 months (or such lesser time provided
by the permitting authority) before the later of January 1, 2010 or the
date on which the CAIR unit commences operation.
(c) Duty to Reapply. For a CAIR source required to have a title V
operating permit, the CAIR designated representative shall submit a
complete CAIR permit application under Sec. 96.122 for the CAIR source
covering the CAIR units at the source in accordance with the permitting
authority's title V operating permits regulations addressing operating
permit renewal.
Sec. 96.122 Information requirements for CAIR permit applications.
A complete CAIR permit application shall include the following
elements concerning the CAIR source for which the application is
submitted, in a format prescribed by the permitting authority:
(a) Identification of the CAIR source, including plant name and the
ORIS (Office of Regulatory Information Systems) or facility code
assigned to the source by the Energy Information Administration, if
applicable;
(b) Identification of each CAIR unit at the CAIR source; and
(c) The standard requirements under Sec. Sec. 96.106 and 96.206.
Sec. 96.123 CAIR permit contents and term.
(a) Each CAIR permit will contain, in a format prescribed by the
permitting authority, all elements required for a complete CAIR permit
application under Sec. 96.122.
(b) Each CAIR permit is deemed to incorporate automatically the
definitions of terms under Sec. 96.102 and, upon recordation by the
Administrator under subparts FF and GG of this part, every allocation,
transfer, or deduction of a CAIR NOX allowance to or from
the compliance account of the CAIR source covered by the permit.
(c) The term of the CAIR permit will be set by the permitting
authority, as necessary to facilitate coordination of the renewal of
the CAIR permit with issuance, revision, or renewal of the CAIR
source's title V permit.
Sec. 96.124 CAIR permit revisions.
Except as provided in Sec. 96.123(b), the permitting authority
will revise the CAIR permit, as necessary, in accordance with the
permitting authority's title V operating permits regulations addressing
permit revisions.
Subpart DD--[Reserved]
Subpart EE--CAIR NOX Allowance Allocations
Sec. 96.140 State trading budgets.
The State trading program budgets for annual allocations of CAIR
NOX allowances for 2010 through 2014 and for 2015 and
thereafter are respectively as follows:
------------------------------------------------------------------------
State NOX State NOX
State budget 2010 budget 2015
(tons) (tons)
------------------------------------------------------------------------
Alabama................................. 67,422 56,185
[[Page 32750]]
Arkansas................................ 24,919 20,765
Delaware................................ 5,089 4,241
District of Columbia.................... 215 179
Florida................................. 115,503 96,253
Georgia................................. 63,575 52,979
Illinois................................ 73,622 61,352
Indiana................................. 102,295 85,246
Iowa.................................... 30,458 25,381
Kansas.................................. 32,436 27,030
Kentucky................................ 77,938 64,948
Louisiana............................... 47,339 39,449
Maryland................................ 26,607 22,173
Massachusetts........................... 19,630 16,358
Michigan................................ 60,212 50,177
Minnesota............................... 29,303 24,420
Mississippi............................. 21,932 18,277
Missouri................................ 56,571 47,143
New Jersey.............................. 9,895 8,246
New York................................ 52,503 43,753
North Carolina.......................... 55,763 46,469
Ohio.................................... 101,704 84,753
Pennsylvania............................ 84,552 70,460
South Carolina.......................... 30,895 25,746
Tennessee............................... 47,739 39,783
Texas................................... 224,314 186,928
Virginia................................ 31,087 25,906
West Virginia........................... 68,235 56,863
Wisconsin............................... 39,044 32,537
-----------------
Total Regional Budget............... 1,600,799 1,333,999
------------------------------------------------------------------------
Sec. 96.141 Timing requirements for CAIR NOX allowance allocations.
(a)(1) By October 31, 2006, the permitting authority will submit to
the Administrator the CAIR NOX allowance allocations, in a
format prescribed by the Administrator and in accordance with Sec.
96.142(a) and (b), for the control periods in 2010, 2011, 2012, 2013,
and 2014.
(2) If the permitting authority fails to submit to the
Administrator the CAIR NOX allowance allocations in
accordance with paragraph (a)(1) of this section, the Administrator
will allocate CAIR NOX allowances for the applicable control
periods, in accordance with Sec. 96.142(a) and (b).
(b)(1) By October 31, 2009 and October 31 of each year thereafter,
the permitting authority will submit to the Administrator the CAIR
NOX allowance allocations, in a format prescribed by the
Administrator and in accordance with Sec. 96.142(a) and (b), for the
control period in the year that is 6 years after the year of the
applicable deadline for submission under this paragraph.
(2) If the permitting authority fails to submit to the
Administrator the CAIR NOX allowance allocations in
accordance with paragraph (b)(1), the Administrator will allocate CAIR
NOX allowances for the applicable control period, in
accordance with Sec. 96.142(a) and (b).
Sec. 96.142 CAIR NOX allowance allocations.
(a)(1) The baseline heat input (in mmBtu) used with respect to CAIR
NOX allowance allocations under paragraph (b) of this
section for each CAIR unit will be:
(i) For units commencing operation before January 1, 1998 the
average of the three highest amounts of the unit's annual heat input
for 1998 through 2002.
(ii) For units commencing operation on or after January 1, 1998 and
operating each year during a period of 5 or more consecutive years, the
average of the three highest amounts of the unit's total converted
annual heat input over the first such 5 years.
(2)(i) A unit's annual heat input for a year under paragraphs
(a)(1)(i), (a)(2)(ii)(A), and (c)(3)(ii) of this section will be
determined in accordance with part 75 of this chapter, if the CAIR unit
was otherwise subject to the requirements of part 75 of this chapter
for the year, or will be based on the best available data reported to
the permitting authority for the unit, if the unit was not otherwise
subject to the requirements of part 75 of this chapter for the year.
(ii) A unit's converted annual heat input for a year specified
under paragraph (a)(1)(ii) of this section equals--
(A) The annual gross electrical output of the generator or
generators served by the unit multiplied by 8,000 Btu/kWh, provided
that if the generator is served by two or more units, then the gross
electrical output of the generator will be attributed to each unit in
proportion to the unit's share of total heat input of such units for
the year; plus
(B) For a cogeneration unit, one-half of the unit's annual gross
thermal energy multiplied by 8,000 Btu/kWh.
(b)(1) For each control period under Sec. 96.141, the permitting
authority will allocate to all CAIR units in the State that have a
baseline heat input (as determined under paragraph (a) of this section)
a total amount of CAIR NOX allowances equal to 98 percent of
the tons of CAIR NOX emissions in the State trading program
budget under Sec. 96.140 (except as provided in Sec. 96.142(d)).
(2) The permitting authority will allocate CAIR NOX
allowances to each CAIR unit under paragraph (b)(1) of this section in
an amount determined by multiplying the total amount of allowances
allocated under paragraph (b)(1) of this section by the ratio of the
baseline heat input of such unit to the total amount of baseline heat
input of all CAIR units in the State and rounding to
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the nearest whole allowance as appropriate.
(c) For each control period under Sec. 96.141, the permitting
authority will allocate CAIR NOX allowances to CAIR units in
the State that commenced operation on or after January 1, 1998 and do
not yet have a baseline heat input (as determined under paragraph (a)
of this section), in accordance with the following procedures:
(1) The permitting authority will establish a separate new unit
set-aside for each control period. Each new unit set-aside will be
allocated CAIR NOX allowances equal to 2 percent of the
amount of tons of CAIR NOX emissions in the State trading
program budget under Sec. 96.140.
(2) The CAIR designated representative of such a CAIR unit may
submit to the permitting authority a request, in a format specified by
the permitting authority, to be allocated CAIR NOX
allowances, starting with the first control period after the control
period in which the CAIR unit commences commercial operation and until
the first control period for which the unit is allocated CAIR
NOX allowances under paragraph (b) of this section. The CAIR
NOX allowance allocation request must be submitted before
January 1 of the first control period for which the CAIR NOX
allowances are requested and after the date on which the CAIR unit
commences commercial operation.
(3) In a CAIR NOX allowance allocation request under
paragraph (c)(2) of this section, the CAIR designated representative
may request for a control period CAIR NOX allowances in an
amount not exceeding--
(i) 1.00 lb/MWh for boilers, coal-fired combustion turbines, and
integrated gasification combined cycle plants, 0.56 lb/MWh for gas-
fired combustion turbines, or 1.01 lb/MWh for all other combustion
turbines;
(ii) multiplied by the CAIR unit's heat input for the control
period immediately preceding the control period for which the
allowances are requested; and
(iii) rounded to the nearest whole allowance as appropriate.
(4) The permitting authority will review each CAIR NOX
allowance allocation request under paragraph (c)(2) of this section and
will allocate CAIR NOX allowances for each control period
pursuant to such request as follows:
(i) Upon receipt of an allowance allocation request, the permitting
authority will determine whether, and will make any necessary
adjustments to the request to ensure that the request is consistent
with the requirements of paragraphs (c)(2) and (3) of this section.
(ii) On or after January 1 of the control period, the permitting
authority will determine the sum of the CAIR NOX allowances
requested (as adjusted under paragraph (c)(4)(i) of this section) in
all CAIR NOX allowance allocation requests under paragraph
(c)(2) of this section for the control period.
(iii) If the amount of CAIR NOX allowances in the new
unit set-aside for the control period is greater than or equal to the
sum under paragraph (c)(4)(ii) of this section, the permitting
authority will allocate the amount of CAIR NOX allowances
requested (as adjusted under paragraph (c)(4)(i) of this section) to
each CAIR unit covered by an allocation request under paragraph (c)(2)
of this section.
(iv) If the amount of CAIR NOX allowances in the new
unit set-aside for the control period is less than the sum under
paragraph (c)(4)(ii) of this section, the permitting authority will
allocate to each CAIR unit covered by an allocation request under
paragraph (c)(2) of this section the amount of the CAIR NOX
allowances requested (as adjusted under paragraph (c)(4)(i) of this
section), multiplied by the number of CAIR NOX allowances in
the new unit set-aside for the control period, divided by the sum
determined under paragraph (c)(4)(ii) of this section, and rounded to
the nearest whole allowance as appropriate.
(v) The permitting authority will notify each CAIR designated
representative that submitted an allowance allocation request, and the
Administrator (in a format prescribed by the Administrator), of the
amount of CAIR NOX allowances (if any) allocated for the
control period to the CAIR unit covered by the allowance allocation
request.
(d) If, after completion of the procedures under paragraph (c)(4)
of this section, any unallocated CAIR NOX allowances remain
in the new unit set-aside for a control period, the permitting
authority will reallocate to each CAIR unit that was allocated CAIR
NOX allowances under paragraph (b) an amount of CAIR
NOX allowances equal to the total amount of such remaining
unallocated CAIR NOX allowances, multiplied by the unit's
allocation under paragraph (b) of this section, divided by 98 percent
of the amount of tons of CAIR NOX emissions in the State
trading program budget, and rounded to the nearest whole allowance as
appropriate. The permitting authority will notify the Administrator (in
a format prescribed by the Administrator) of the amounts of CAIR
NOX allowances (if any) allocated for the control period to
such CAIR units under this paragraph.
Subpart FF--CAIR NOX Allowance Tracking System
Sec. 96.150 CAIR NOX Allowance Tracking System Accounts.
(a) Nature and function of compliance accounts. Consistent with
Sec. 96.151(a), the Administrator will establish one compliance
account for each CAIR source with one or more CAIR units. Allocations
of CAIR NOX allowances to CAIR units pursuant to subpart EE
of this part, and deductions or transfers of CAIR NOX
allowances pursuant Sec. 96.154, Sec. 96.156, or subpart GG of this
part will be recorded in compliance accounts in accordance with this
subpart.
(b) Nature and function of general accounts. Consistent with Sec.
96.151(b), the Administrator will establish, upon request, a general
account for any person. Transfers of CAIR NOX allowances
pursuant to subpart GG of this part will be recorded in general
accounts in accordance with this subpart.
Sec. 96.151 Establishment of accounts.
(a) Compliance accounts. Upon receipt of a complete certificate of
representation under Sec. 96.113, the Administrator will establish a
compliance account for the CAIR source for which the certificate of
representation was submitted.
(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 CAIR NOX allowances. An
application for a general account may designate one and only one CAIR
NOX authorized account representative and one and only one
alternate CAIR NOX authorized account representative who may
act on behalf of the CAIR NOX authorized account
representative. The agreement by which the alternate CAIR
NOX authorized account representative is selected shall
include a procedure for authorizing the alternate CAIR NOX
authorized account representative to act in lieu of the CAIR
NOX authorized account representative.
(ii) A complete application for a general account shall be
submitted to the Administrator and shall include the following elements
in a format prescribed by the Administrator:
(A) Name, mailing address, e-mail address (if any), telephone
number, and facsimile transmission number (if any) of the CAIR
NOX authorized account representative and any alternate CAIR
NOX authorized account representative;
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(B) Organization name and type of organization;
(C) A list of all persons subject to a binding agreement for the
CAIR NOX authorized account representative and any alternate
CAIR NOX authorized account representative to represent
their ownership interest with respect to the allowances held in the
general account;
(D) The following certification statement by the CAIR
NOX authorized account representative and any alternate CAIR
NOX authorized account representative: ``I certify that I
was selected as the CAIR NOX authorized account
representative or the CAIR NOX alternate authorized account
representative, as applicable, by an agreement that is binding on all
persons who have an ownership interest with respect to allowances held
in the general account. I certify that I have all the necessary
authority to carry out my duties and responsibilities under the CAIR
NOX Trading Program on behalf of such persons and that each
such person shall be fully bound by my representations, actions,
inactions, or submissions and by any order or decision issued to me by
the Administrator or a court regarding the general account.''
(E) The signature of the CAIR NOX authorized account
representative and any alternate CAIR NOX authorized account
representative and the dates signed.
(iii) Unless otherwise required by the permitting authority or the
Administrator, documents of agreement referred to in the application
for a general account shall not be submitted to the permitting
authority or the Administrator. Neither the permitting authority nor
the Administrator shall be under any obligation to review or evaluate
the sufficiency of such documents, if submitted.
(2) Authorization of CAIR NOX authorized account
representative. Upon receipt by the Administrator of a complete
application for a general account under paragraph (b)(1) of this
section:
(i) The Administrator will establish a general account for the
person or persons for whom the application is submitted.
(ii) The CAIR NOX authorized account representative and
any alternate CAIR NOX authorized account representative for
the general account shall represent and, by his or her representations,
actions, inactions, or submissions, legally bind each person who has an
ownership interest with respect to CAIR NOX allowances held
in the general account in all matters pertaining to the CAIR
NOX Trading Program, notwithstanding any agreement between
the CAIR NOX authorized account representative or any
alternate CAIR NOX authorized account representative and
such person. Any such person shall be bound by any order or decision
issued to the CAIR NOX authorized account representative or
any alternate CAIR NOX authorized account representative by
the Administrator or a court regarding the general account.
(iii) Any representation, action, inaction, or submission by any
alternate CAIR NOX authorized account representative shall
be deemed to be a representation, action, inaction, or submission by
the CAIR NOX authorized account representative.
(iv) Each submission concerning the general account shall be
submitted, signed, and certified by the CAIR NOX authorized
account representative or any alternate CAIR NOX authorized
account representative for the persons having an ownership interest
with respect to CAIR NOX allowances held in the general
account. Each such submission shall include the following certification
statement by the CAIR NOX authorized account representative
or any alternate CAIR NOX authorizing account
representative: ``I am authorized to make this submission on behalf of
the persons having an ownership interest with respect to the CAIR
NOX allowances held in the general account. I certify under
penalty of law that I have personally examined, and am familiar with,
the statements and information submitted in this document and all its
attachments. Based on my inquiry of those individuals with primary
responsibility for obtaining the information, I certify that the
statements and information are to the best of my knowledge and belief
true, accurate, and complete. I am aware that there are significant
penalties for submitting false statements and information or omitting
required statements and information, including the possibility of fine
or imprisonment.''
(v) The Administrator will accept or act on a submission concerning
the general account only if the submission has been made, signed, and
cert