ILLINOIS POLLUTION CONTROL BOARD
April 19, 2007
IN THE MATTER OF:
PROPOSED NEW CLEAN AIR
INTERSTATE RULES (CAIR) SO
2
, NO
x
ANNUAL AND NO
x
OZONE SEASON
TRADING PROGRAMS, 35 ILL. ADM.
CODE 225, SUBPARTS A, C, D, E, and F
)
)
)
)
)
)
)
R06-26
(Rulemaking – Air)
Proposed Rule. First Notice.
OPINION AND ORDER OF THE BOARD (by T.E. Johnson):
Today the Board proceeds to first notice under the Illinois Administrative Procedure Act
(5 ILCS 100/1-1
et seq.
(2004)) with a rulemaking proposed by the Illinois Environmental
Protection Agency (Agency) on May 30, 2006. The Agency states that the purpose of the Clean
Air Interstate Rule (CAIR) is to reduce intra- and interstate transport of sulfur dioxide (SO
2
) and
nitrogen oxide (NO
x
) emissions from fossil fuel-fired electric generating units (affected units)
through the adoption of trading programs. The Board accepted this matter for hearing on
June 15, 2006. The Board has held five days of hearings, and received numerous public
comments. For the reasons more fully outlined below, the Board finds that the proposal is
technically feasible and economically reasonable. After proceeding to first notice, the Board will
accept additional comments on the proposal.
In today’s order, the Board first provides background and procedural background on the
proposal. Next, the Board summarizes the proposal and the Agency’s proposed amendments.
The Board then addresses preliminary matters such as the outstanding motion to dismiss and the
motions to amend. The public comments are summarized before the Board considers and
addresses the major issues raised at hearing and in public comment. Finally, the Board provides
discussion of why it finds the proposal technically feasible and economically reasonable.
BACKGROUND
The Agency states the proposal satisfies Illinois’ obligations under the United States
Environmental Protection Agency’s (USEPA) Rule to Reduce Interstate Transport of Fine
Particulate Matter and Ozone; Revisions to Acid Rain Program; Revisions to the NO
x
SIP Call
1
(Federal CAIR), 70 Fed. Reg. 25162 (May 12, 2005). Stat. at 1.
2
The Agency also states the
rule satisfies the Agency’s obligation to meet Clean Air Act (CAA) requirements for the control
1
SIP is the short form of state implementation plan.
2
The Agency’s Statement of Reasons included in the rulemaking proposal will be cited as “Stat.
at _.”
2
of fine particulate matter (PM
2.5
) and ozone in the Chicago and Metro East/St. Louis
nonattainment areas. Stat. at 2.
In the Federal CAIR, the USEPA states it “has assessed the role of transported emissions
from upwind States in contributing to unhealthy levels of PM
2.5
and 8-hour ozone in downwind
States.” Rule to Reduce Interstate Transport of Fine Particulate Matter and Ozone, 69 Fed. Reg.
4566 (Jan. 30, 2004). The USEPA proposed the Federal CAIR emission reductions for SO
2
and
NO
x
that apply to upwind states based on that assessment.
Id
. The USEPA gave three primary
reasons for addressing interstate pollution transport in a timely manner. First, the USEPA stated
that emissions from upwind States can, either alone or combined with local emissions, cause
NAAQS exceedences and jeopardize public health in downwind communities.
Id
. Second,
states the USEPA, the interstate transport of pollution must be addressed on a regional scale
because the significant contributions of pollution from upwind states force downwind areas to
incur extra clean-up costs in order to achieve greater local emissions reductions.
Id
. Third, a
regional approach to controls should result in achieving air quality standards more economically.
Id
.
The Federal CAIR requires 28 eastern states that were identified as significantly
contributing or interfering with the maintenance of one or more National Ambient Air Quality
Standards (NAAQS) in downwind areas to revise their SIPs to include control measures on SO
2
and NO
x
. The Federal CAIR also requires that 25 states must reduce: (1) annual SO
2
and NO
x
emissions for the purposes of PM
2.5
NAAQS; and (2) reduce seasonal NO
x
emissions for
purposes of eight-hour ozone NAAQS.
In the Federal CAIR, the USEPA found that Illinois significantly contributes both PM
2.5
and ozone, and is impacted by pollution from other states. USEPA gave Illinois the option of
complying with emission budgets set by the USEPA or adopting a federal cap-and-trade program
covering its electric generating units (EGUs). The Agency’s proposed rule chose the latter
option.
The CAA establishes a comprehensive program for controlling and improving the
nation’s air quality through both state and federal regulation. Stat. at 4. Under Sections 108 and
109 of the CAA, USEPA is charged with identifying air pollutants that endanger the public
health and welfare, and with formulating the NAAQS that specify the maximum permissible
concentrations of those pollutants in the ambient air. 42 U.S.C. §§ 7408-7409. USEPA has
promulgated NAAQS for various pollutants, including 8-hour ozone and PM
2.5
. 40 C.F.R. § 50.
Pursuant to Section 107(a) of the CAA, states are given primary responsibility for ensuring that
the ambient air quality meets the NAAQS for the identified pollutants. 42 U.S.C. § 7407(a)
(2000).
Part D, Subpart I of the CAA, requires adoption of control strategies necessary to
demonstrate attainment of the fine particulate matter (PM
2.5
) and eight-hour ozone NAAQS in
the greater Chicago moderate nonattainment area and the Metro East/St. Louis moderate
nonattainment area. Part D, Subpart 2 of the CAA, requires adoption of control strategies
necessary to demonstrate attainment of 8-hour ozone NAAQS for those two nonattainment areas.
3
Sections 169(A) and 110(a)(2)(D) of the CAA require the adoption of an implementation plan
addressing visibility, and a SIP addressing interstate transport of air pollution. Stat. at 2.
The USEPA believes that notwithstanding the CAA requirements for achieving the
NAAQS as described above, the majority of eastern states will not be able to meet the 8-hour
ozone and PM
2.5
NAAQS by the statutory deadlines for attainment.
See
69 Fed. Reg
.
4566, 4579
(Jan. 30, 2004). The USEPA believes that a major reason for this failure is that states are not
able to address interstate transport of pollution from upwind areas. Interstate transport is the
process by which air pollutants move from upwind areas to downwind areas. Stat. at 8.
The source category that USEPA determined to be most cost-effective to control is
EGUs, although states have the flexibility to choose the measures to adopt to achieve the
specified emissions reductions. Under CAIR, USEPA is requiring that states found to be
contributing to PM
2.5
transport be subject to an annual NO
x
limitation and SO
2
limitation under
CAIR and that states found to be contributing to ozone transport be subject to an ozone season
limitation. Since Illinois is a significant contributor for both PM
2.5
and ozone, USEPA has
established three emissions budgets for Illinois: the first would cap emissions of NO
x
on an
annual basis; the second would cap emissions of NO
x
during the ozone season; and the third
would cap the emissions of SO
2
on an annual basis. These caps are based on emission reductions
from EGUs. The required emissions reduction will be implemented in two phases. Phase I for
NO
x
reductions will start in 2009 (covering 2009-2014) and SO
2
reductions will start in 2010
(covering 2010-2014). Phase II for both NO
x
and SO
2
reductions will start in 2015 (covering
2015 and thereafter).
In lieu of complying with emissions budgets, states have the option of adopting the
Federal cap-and-trade programs covering its EGUs: CAIR NO
x
Annual trading program; CAIR
NO
x
Ozone Season trading program; and CAIR SO
2
trading program. 40 C.F.R. §§ 51.123(o)(1)
and (aa) and 40 C.F.R. § 51.124(o)(1), respectively. With respect to the CAIR NO
x
trading
programs, each state is given a pool of allowances equal to their NO
x
budgets to distribute as
they choose. With respect to the CAIR SO
2
trading program, USEPA allocates the allowances to
affected EGUs based on the allocations that the unit receives under the federal Acid Rain
program. The trading programs do not require EGUs to install specific control technology or
meet a particular emission limit. Instead, each affected unit is required at the end of each control
period to hold allowances sufficient to cover the tons of NO
x
and SO
2
emitted. These allowances
can be obtained either through a direct allocation from a state (NO
x
allowances) or USEPA (SO
2
allowances) or through trading. It is anticipated that affected units that can install the least costly
controls will do so, and will over control, and thereby have extra allowances to sell to other
EGUs that cannot as cost-effectively reduce emissions.
The Agency’s proposal amends Subpart A and proposes new Subparts C, D, E, and F of
Part 225. The Agency proposes adopting the CAIR SO
2
, CAIR NO
x
Annual, and CAIR NO
x
Ozone Season trading programs to reduce intrastate and interstate transport of sulfur dioxide
(SO
2
) and nitrogen oxides (NO
x
) emissions. Stat. at 1.
The proposal is intended to cover the entire State of Illinois. The proposed regulations
are expected to affect existing and new EGUs. Stat. at 24. Approximately 229 existing EGUs
4
will be subject to the CAIR NO
x
Annual, CAIR SO
2
, and CAIR NO
x
Ozone Season trading
programs. Stat. at 24-25. For the CAIR NO
x
Annual, and SO
2
trading programs, existing units
are those that commenced operation before January 1, 2006; and for the CAIR NO
x
Ozone
Season trading program, existing units are those that commenced operation before May 1, 2006.
Stat. at 25.
Of these units, 170 are gas and oil-fired boilers, 59 are coal-fired boilers, and the
remainder are gas and oil-fired combustion turbines. Stat. at 25. Some coal-fired boilers have
the capability to burn natural gas, fuel oil or both. Of the 59 coal-fired boilers, 34 are
tangentially-fired, five are wall-fired, 18 are cyclone-fired boilers and one is a circulating
fluidized bed boiler.
Id
.
The proposed regulations are expected to affect existing EGUs, and any new EGUs that
serve a generator greater than 25 megawatts, or any unit with a maximum design heat input that
is greater than 250 thousand British thermal units per hour (mmBtu/hr) and that has the potential
to use more than 50% of the “potential electrical output capacity” and that sell electricity to the
grid. Stat. at 25. While gas-fired turbines typically have low emissions of SO
2
, they still must
comply with the requirements of the CAIR SO
2
trading program.
Id
. In Illinois, emissions from
oil and gas boilers and turbines are approximately 2,000 tons per year (TPY) of SO
2
as compared
to 361,000 TPY of SO
2
from coal-fired boilers.
Id
.
PROCEDURAL BACKGROUND
The Agency filed this proposal for rulemaking on May 30, 2006. The Agency filed
motions for expedited review, to hold the required hearings in Springfield and Collinsville, and
for waiver of certain filing requirements concurrently with the petition.
As noted, the Board accepted this case for hearing on June 15, 2006. In that June 15,
2006 order, the Board also reserved ruling on the three pending Agency motions. On June 28,
2006, the Board sent a letter to Jack Lavin, Director of the Department of Commerce and
Economic Opportunity (DCEO) requesting an Economic Impact Study. DCEO did not respond,
and the Board received no testimony or comments regarding the DCEO’s decision not to perform
an economic impact study on this rulemaking.
On June 30, 2006, Dynegy Midwest Generation, Inc. (Dynegy) and Midwest Generation,
LLC (Midwest Generation) filed a motion for leave to file responses to the Agency’s motion for
expedited hearings and to hold required hearings in Springfield and Collinsville, accompanied by
the respective responses.
On July 20, 2006, the Board granted, in part, the Agency’s motion to expedite.
Specifically, the Board declined to send this matter to first notice without commenting on
the merits of the proposal, but did grant expedited review to the extent feasible given the Board’s
available resources and decision deadlines.
See
R06-26, (July 20, 2006). The Board also denied
the motion to hold the hearings in Springfield and Collinsville, and granted the motion to waive
certain filing requirements.
5
Hearings in this matter were held before hearing officer John Knittle. The first hearing
began on October 10, 2006 and continued through October 12, 2006, in Springfield. The second
hearing began on November 28, 2006 and continued through November 29, 2006, in Chicago.
Over the course of the two hearings, Rachel Doctors and John Kim appeared and
participated on behalf of the Agency. Kathleen Bassi, Stephen Bonebrake, and Shelden Zabel
appeared and participated on behalf of Dynegy and Southern Illinois Power Cooperative
(SIPCO). David Rieser appeared and participated on behalf of Ameren Energy Generating
Company, Ameren Energy Resources Generating Company, and Electric Energy, Inc.
(collectively, Ameren). Steven J. Murawski appeared and participated on behalf of Zion Energy,
LLP (Zion). Faith E. Bugel appeared and participated on behalf of the Environmental Law and
Policy Center (ELPC). Bruce E. Nilles appeared and participated on behalf of the Sierra Club.
James Russell appeared and participated on behalf of the Christian County Generation, LLC.
Bill Forcade appeared and participated on behalf of Kincaid Generation, LLC (Kincaid). Finally,
Keith Harley appeared and participated on behalf of Environment Illinois.
At the first hearing, the hearing officer entered pre-filed testimony, submitted on behalf
of the Agency, of the following witnesses into the record as Agency exhibits: Gary E. Beckstead
(Ag. Exh. 6), David E. Bloomberg (Ag. Exh. 10), Roston Cooper (Ag. Exh. 12), Rory Davis (Ag.
Exh. 9), Robert Kaleel (Ag. Exh. 4), Yoginder Mahajan (Ag. Exh. 7), James R. Ross (Ag. Exh.
2), and Jacquelyn Sims (Ag. Exh. 8). A total of 20 exhibits were offered and accepted at the first
hearing.
On October 11, 2006, the Agency filed a motion to amend the rulemaking proposal. On
October 19, 2006, the Agency moved to withdraw the motion. On October 27, 2006, the Agency
filed post-hearing comments to the first set of hearings. On November 16, 2006, the Board
granted the Agency’s motion to withdraw the motion to amend the rulemaking proposal.
At the second hearing, the hearing officer entered pre-filed testimony of the following
witnesses into the record as exhibits: Jason M. Goodwin on behalf of Zion (Zion Exh. 1),
Gregory Kunkel on behalf of Christian County Generation (Christian County Exh. 1), C.J.
Saladino on behalf of Kincaid (Kincaid Exh. 1), Steven C. Whitworth on behalf of Ameren
(Ameren Exh. 1), and Charles Kubert on behalf of the ELPC (Kubert Exh. 1). Robert B.
Asplund testified on behalf of Kincaid. Seven exhibits were offered and accepted at the second
hearing.
On November 27, 2006, the Agency filed a second motion to amend the rulemaking
proposal. Dynegy, Midwest Generation, and SIPCO responded to the second motion to amend
on December 7, 2006.
At the close of the second hearing, the hearing officer set the public comment period to
expire on December 22, 2006. The hearing officer granted the Agency leave to file a reply to
any response to the motion to amend the rulemaking within seven days after any response was
filed.
6
On November 30, 2006, Dynegy, Midwest Generation, and SIPCO moved to dismiss the
rulemaking proposal. SIPCO affirmed the motion to dismiss on December 15, 2006. On
December 13, 2006, Environment Illinois and the ELPC (collectively, Environmental
Advocates), responded to the motion to dismiss. On December 18, 2006, the Agency filed three
motions for extension of time: (1) a motion for extension of time to respond to the motion to
dismiss; (2) a motion for extension of time in which to file a reply to the response to the second
motion to amend the rulemaking proposal; and (3) a motion for extension of time to file its
written comments.
On December 20, 2006, the Board hearing officer, John Knittle, granted the motions for
extension, giving the Agency until December 22, 2006, to respond to the motion to dismiss, and
reply to the response to the motion to amend rulemaking. Simultaneously, the hearing officer
extended the written comment deadline for all parties to January 5, 2007.
On December 22, 2006, the Agency responded to the motion to dismiss and replied to the
response to the motion to amend the rulemaking proposal. On January 5, 2007, SIPCO and
Midwest Generation moved to withdraw as parties to the motion to dismiss.
Eleven public comments have been filed to date. The Agency filed post-hearing
comments to the first set of hearings on October 27, 2006 (PC1). On December 15, 2006,
Kincaid Generation, L.L.C. filed a Dominion NO
x
Compliance Strategy and the resumé of Mr.
Andy Yaros (PC2). On December 21, 2006, the Board received the post-hearing comments to
the second set of hearings from of Jason M. Goodwin (PC3). On January 5, 2007, post-hearing
comments were received from Ameren (PC4); the Agency (PC5); Dynegy and SIPCO (PC6); the
ELPC, the American Lung Association of Metropolitan Chicago, Environment Illinois, and the
Sierra Club (PC7); Midwest Generation (PC8); Midwest Generation and the Agency (PC9); and
Kincaid (PC10). On January 10, 2007, the Agency filed a motion for leave to file
instanter
a
revised joint comment, and the revised joint comment (PC11) of the Agency and Midwest
Generation. Finally, on February 5, 2007, the Sierra Club submitted 85 clean air questionnaires
from Harold Washington College (PC12).
PRELIMINARY MATTERS
The Board must address a number of outstanding preliminary matters before
consideration of the proposal itself. Specifically, the Agency’s November 27, 2006 motion to
amend the proposal; the November 30, 2006 motion to dismiss the proposal filed by Dynegy,
Midwest Generation, and SIPCO (and its associated pleadings); and various motions to amend
the proposal included in motions as well as comments.
The Board first considers the motion to dismiss. The motion to dismiss is based on the
premise that the Board lacks statutory authority to adopt proposed Subparts C, D, and E of Part
225.
See
Mot. to Dis. at 3, 7, 11. Subsequent to the filing of the motion to dismiss, SIPCO and
Midwest Generation have asked to withdraw from the motion to dismiss. The Board grants each
request to withdraw, thereby leaving Dynegy as the sole remaining movant of the motion to
dismiss.
7
On March 13, 2007, the Agency and Dynegy filed a joint motion to amend Section
225.465(b)(4)(B) of the proposed rule to address Dynegy’s concerns regarding the manner in
which the clean air set-aside (CASA) provisions penalized sources with consent decrees relative
to their baghouse projects (Joint Mot.). Joint Mot. at 1, 3. Dynegy requests that the Board stay
action on the motion to dismiss. Joint Mot. at 4. Dynegy and the Agency have agreed that if the
Board grants the joint motion to amend and includes the language therein in the Board’s first
notice of the rule, Dynegy will withdraw its motion to dismiss. Joint Mot. at 4.
No response to the request for stay of the motion to dismiss has been received. The
Board grants the request, and will stay the motion to dismiss pending a further pleading on the
issue by Dynegy. Thus, the Board will not, at this time, address the substance of the motion to
dismiss nor any of the responsive pleadings.
As stated, a number of pleadings seeking to amend the proposal have been filed with the
Board. Rather than addressing the substance of each motion here, the Board will address the
proposed amendments in the discussion portion of the order. The Board grants all outstanding
motions for leave to file and considers each one below.
MOTIONS TO AMEND
The Board received three motions to amend the rule. Motions to amend were submitted
by the Agency on November 27, 2006 (Ag. Mot. to Amend), by Midwest Generation and the
Agency, jointly, on February 16, 2007 (Midwest Mot. to Amend), and by Dynegy and the
Agency, jointly, on March 13, 2007 (Dynegy Mot. to Amend). The Board grants the following
three motions to amend as described in the Board Discussion below.
Agency’s November 27, 2006 Motion to Amend
The Agency’s motion to amend addresses changes and clarifications as a result of
communications with USEPA, the first hearing in Springfield, stylistic conventions used in the
Board’s second notice for R06-25, and typographical errors. Ag. Mot. to Amend at 2.
The Agency proposed changes that were recommended by USEPA such as several
changes to definitions in Section 225.130. The definitions were revised to provide clarity and/or
be consistent with wording in the April 28, 2006 Federal Register. Ag. Mot. to Amend at 2-3.
The Agency also proposed revisions to the following sections to conform to federal
requirements. For example, Section 225.140 reflects latest the updates in the Incorporations by
Reference. In Sections 225.300, 225.400, and 225.500, the Agency proposes using applicability
language verbatim from the April 28, 2006
Federal Register
.
The Agency would replace the term “CAIR designated representative” with “owner or
operator” and add a more detailed description of the allowance transfer deadline in Sections
225.310(d), 225.410(d), and 225.510(d). The Agency also recommends that in Section
225.310(d)(1), the term “ton” be replaced with “tonnage” to clarify that an allowance has a
different value depending on the year it is allocated.
8
In Sections 225.310(e)(1)(D) and (f)(4), 225.410(e)(1)(D) and (f)(4), and
225.510(e)(1)(D) and (f)(4), the Agency suggests changes to conform to federal requirements for
the owner or operator to submit documents to demonstrate compliance. The Agency also
amends Sections 225.320(a)(1), (2) and (c), 225.410(a)(1), (2) and (c), and 225.510(a)(1), (2)
and (c) to require the owner or operator to submit supplemental information requested by the
Agency, reference the Agency’s authority to issue permits and specify that allocations, transfers
or deductions of allowances automatically amend the permit.
In Section 225.325, the Agency again replaces the term “ton” with “tonnage” to clarify
that an allowance has a different value depending on the year it is allocated, and it retains that
value no matter when it is used for compliance or traded. The term also reflects that while the
Agency does not, other states may have the authority to issue SO
2
allowances.
Sections 225.430 and 225.530are amended by the Agency to conform to 40 C.F.R. §
51.123(p) and (aa) and reflect timing required by the federal CAIR rule for NO
x
allowance
allocations, such that the Agency will make initial allocations for control periods 2009 through
2011 no later than July 31, 2007, and will submit subsequent allocations 4 years in advance of
the control period. Allowances from the New Unit Set-Aside (NUSA) would be reported to
USEPA by July 31 of the applicable control period, and new units would not receive allowances
for the first year of commercial operation.
The Agency recommends amending Sections 225.435 and 225.535 to reflect the change
in dates that allocations must be made and allows the owner/operator to use heat input data in
lieu of gross electrical output data from years 2006 through 2008. Sections 225.440 and 225.540
limit allocations of allowances on a
pro rata
basis and Sections 225.445 and 225.545 reflect
requirements of 40 C.F.R. § 51.123 for submittal dates, while Sections 225.455 and 225.555
require aggregated allowances under the CASA to equal at least one. Ag. Mot. to Amend at 3-6.
The Agency also proposed amendments as a result of comments made at the hearing
October 10-12, 2006 in Springfield. The Agency added a definition for “commence
construction” and amended the definition for “project sponsor” to lessen the possibility that more
than one organization or person could submit applications for the same project. Ag. Mot. to
Amend at 6.
In response to comments made at the first hearing, the Agency amended Sections
225.430 and 225.530 to clarify allowances from the CASA would be allocated in the year they
are to be used based on reductions made in the previous year. Ag. Mot. to Amend at 6. Further,
the Agency amended Sections 225.435 and 225.535 clarify that either gross electrical output or
heat input may be used to calculate converted gross output for the control periods 2009 through
2013.
Id
.
The Agency next states it amended Sections 225.450 and 225.550 to allow other
measurement systems for gross electrical output, but that such a system must be in place by
January 1, 2008 and that data for the initial allocations for control periods 2009-2011, be
submitted to the Agency by June 1, 2007. In addition, the Agency amended Sections 225.455
9
and 225.555 to reflect the new definition of “project sponsor” and that units found to be out of
compliance must restore their allowances to the Agency. Ag. Mot. to Amend at 6-7.
The Agency amended Sections 225.460 and 225.560 to clarify which projects are not
eligible to receive allowances from the CASA, such as combined heat and power projects that
are also CAIR NO
x
units or CAIR NO
x
Ozone Season units, projects pursuant to a consent
decree or court order, and Supplemental Environmental Projects. Ag. Mot. to Amend at 7.
In Sections 225.465 and 225.565, the Agency amended language to reflect changes in
Sections 225.460 and 225.560, clarifying that combined heat and power projects are eligible at a
different rate for CASA allowances than other projects listed as supply-side projects. Ag. Mot.
to Amend at 7. Clarifications were made for projects pursuant to consent decrees and court
orders. Amendments to these sections also specify that clean technology projects and highly
efficient power generation projects use the same formula to calculate allowances.
Id
.
Finally, the Agency amended Sections 225.470 and 225.570 to reflect the new definition
and certification requirements of a “project sponsor,” and Sections 225.475 and 225.575 to
reflect new dates and the tipping scheme for excess allowances. Ag. Mot. to Amend at 7.
Midwest Generation and the Agency’s Joint Motion to Amend (2-16-2007)
The joint motion to amend from Midwest Generation and the Agency would correct two
typographical errors. At Section 225.615(g)(3)(D), “for” would replace “or” in the phrase “. . .
applicable requirements for or particulate matter or opacity.” Midwest Mot. to Amend at 1.
Section 225.625(a)(3) would be amended to reflect a Control Technology deadline of
December 31, 2015 rather than the year 2013. The motion states the 2015 deadline was agreed
to by the Agency and Midwest Generation and is embodied in a December 10, 2006
Memorandum of Understanding. Midwest Mot. to Amend at 1-2.
Dynegy and the Agency’s Joint Motion to Amend (3-13-2007)
The joint motion to amend from Dynegy and the Agency would address Dynegy’s
concerns with CASA provisions that penalize sources with consent decrees for baghouse
projects. Dynegy Mot. to Amend at 3.
See
PC 6. The motion explains that the Agency initially
determined CASA allowances for baghouses installed pursuant to a consent order or decree
based on two principles: (1) baghouses required by a consent order or decree should not be
eligible for as many allowances as baghouses installed for other reasons, and (2) the number of
eligible allowances should be consistent with allowances available for SO
2
and NO
x
controls
since CAIR is intended to reduce particulate matter, the primary pollutant removed by a
baghouse. Dynegy Mot. at Amend at 3-4.
The motion reflects the Agency’s agreement to revise the number of allowances for
baghouses installed pursuant to a consent order or decree. The amendments are intended to
provide an incentive for such baghouses to provide greater control of particulate matter than
required by the consent order or decree. Dynegy Mot. to Amend at 4. Specifically, the proposed
10
amendments redefine and introduce new parameters as well as a second formula for calculating
the number of allowances for a particular baghouse project at Section 225.465(b)(4)(B). Dynegy
Mot. to Amend at 2-3.
SUMMARY OF PUBLIC COMMENTS
Public Comment 2: Kincaid
On December 15, 2006, Kincaid filed the Dominion NO
x
Compliance Strategy and
resumé of Mr. Andy Yaros, docketed as public comment 2. Mr. Yaros works as Manager of
Environmental Systems (Fossil & Hydro) at Dominion Resource Services of Richmond, Virginia
(Dominion) developing compliance plans under CAIR, in addition to various other
environmental regulations. Tr. 11/29/06 at 27.
Dominion predicates its NO
x
compliance strategy on making the most economical
decisions on a Dominion System basis, under the NO
x
SIP Call Cap & Trade Regulations. PC 2
at 1. Dominion asserts that the most economic means to affect this strategy is to install high
capital cost selective catalytic reduction (SCR) equipment on their largest units with the highest
NO
x
rates.
Id
. Mr. Yaros asserts in PC 2 that while SCR represents a huge capital investment
and large annual operating costs, it is generally more cost-effective in terms of cost per NO
x
ton
removed, and is also capable of removing 90% of NO
x
.
Id
.
Mr. Yaros states that in executing this strategy, Dominion has put SCRs on 12 of their
largest coal units. PC 2 at 1. With SCRs removing 90% or more on their large units, Dominion
is able to put less costly controls on smaller units that do not remove nearly as high a percentage
of NO
x
.
Id.
With SCRs on the large Dominion units, and other lower-cost equipment (selective
non-catalytic NO
x
reduction (SNCR) equipment or advanced over-fired air (OFA)) on most of
the smaller, older units, Dominion is able to comply company-wide, with the SIP Call, and with
CAIR in the future.
Id.
However, if Dominion loses substantial allowances from large units
with SCRs, Mr. Yaros states in PC 2 that then the economics of the strategy do not work and
Dominion would be forced to invest in more controls which tend to have a much higher cost per
NO
x
ton removed, or to rely on buying allowances in the marketplace.
Id.
Public Comment 3: Jason M. Goodwin
Mr. Goodwin states he has filed written comments and testified in this rulemaking on
behalf of Zion. PC 3 at 1. In PC 3, Mr. Goodwin seeks to provide additional facts and thoughts
to supplement Zion’s primary position on the issues that could bridge a gap between the
seemingly divergent views expressed throughout the public comment period regarding fuel-
weighting/fuel-neutrality and the proposed CASA.
Id.
Fuel-Weighting/Fuel-Neutrality
Mr. Anand Rao, of the Board’s technical unit, asked Mr. Goodwin whether there is an
alternative weighting factor that Zion would be willing to support. PC 3 at 2. Goodwin
emphasizes that Zion prefers a fuel-neutral allocation mechanism, but is willing to consider a
11
compromise alternative fuel-weighting factor that closes the gap between the fuel-neutral option
and the Agency’s current proposal.
Id.
Mr. Goodwin states that Zion suggests a compromise factor of 0.7 for both gas-fired and
oil-fired units. PC 3 at 2. This number represents the mid-point between 1.0 for coal-fired units
and 0.4 for gas-fired units and is a minimal increase from the 0.6 factor for oil-fired
units/operating modes.
Id.
A revised oil-fired factor that is consistent with the proposed gas-
fired factor is necessary to streamline the process for determining the quantity of allowance
allocations.
Id.
A compromise factor also provides additional consideration for reliability
(through enhanced allocation treatment) for units operating in gas-curtailed situations when: (a)
natural gas is unavailable; (b) power demand is potentially very high; or (c) reliability of the
electric power supply is critical.
Id.
Mr
.
Goodwin believes that Zion’s recommended position on fuel-weighting is entirely
consistent with the majority of fuel-weighting concepts being used in states where Calpine
Operating Services Company, Inc. (COSCI) has been involved: Alabama, Arkansas and
Wisconsin are all fuel-neutral; Florida, Louisiana and Minnesota all follow a standard of 0.4
gas/0.6 oil/ 1.0 coal (consistent with federal model); and South Carolina follows a standard of 0.6
gas/0.6 oil/1.0 coal (state-based custom approach). PC 3 at 3.
CASA
In response to comments about the Agency’s proposed CASA size, Mr. Goodwin states
that the Agency’s proposed 25% CASA is far out of line with the proposed set-aside pools in
many other CAIR states. Mr. Goodwin compared the proposed set-aside pools in a number of
other CAIR states and concluded that the CASA, as set forth in the proposal, should be revised
based on two factors. PC 3 at 3.
First, a smaller proportion of the total allowance budget should be made available for
non-emitting sources. Mr. Goodwin suggests a CASA set-aside percentage in the 5-10% range,
rather than the proposed 25%, because setting aside such a large portion of the allowance pool
unjustifiably increases the compliance burden on facilities that already face significant emission
reduction obligations through an artificial reduction in allowances available for allocations. PC 3
at 4. Second, Mr. Goodwin suggests that CASA applicants be restricted to electric-generating
sources and that non-generating sources be eliminated from consideration in the proposed rule.
Id.
Public Comment 4: Ameren Corporation
In general, Ameren states that it supports the proposal filed by the Agency, as amended
by the amended proposal filed on November 11, 2006, with one exception. PC 4 at 1. Ameren
requests that the Board allow the use of CASA allowances to support advanced OFA NO
x
reduction strategies and to adopt the amendment proposed by Ameren in Attachment A to the
pre-filed testimony of Mr. Michael Menne.
Id
.
12
Ameren supports the Agency in establishing an innovative approach to promote
important energy and environmental goals. PC 4 at 2. Ameren agrees that CASA is a useful
balancing of technology, economic, energy and environmental considerations in achieving those
goals, and specifically requests the Board to adopt those portions of the amended proposal that
allow Ameren and other companies seeking to use the multi-pollutant strategy to achieve CASA
allowances.
Id
.
Regarding Ameren’s requested amendment, Ameren contends that the Agency’s basis for
not including this proposal in its amended proposal is based almost entirely on policy rather than
technical grounds.
Id
. According to Ameren, the Agency excluded OFA because it was not
expected to reduce NO
x
as effectively, nor be as capital intensive as the listed technologies.
Id
.
at 3-4. Ameren contends that from a policy standpoint, the only issue should be whether NO
x
reductions can be achieved, and that substantial cost effective NO
x
reductions benefit the entire
process.
Id
. at 4. Ameren argues that when equal technologies to achieve NO
x
goals exist,
companies should not be given incentives to choose the higher-cost technology simply because
allowance credits may be available.
Id
.
Ameren proposes language, included as Attachment B to Ameren Exhibit 1, designed to
create a narrow and limited eligibility for OFA projects. PC 4 at 5. Ameren states that such
projects can only be eligible if they achieve 30% reductions. Ameren states this percentage
reduction represents the level at which advanced OFA becomes directly comparable to SNCR (a
CAIR-listed technology) and distinct from the first generation OFA used at some Illinois
facilities. Alternatively, projects must be installed as part of a phased NO
x
control program
which includes an advanced computerized combustion control system or a NO
x
control reduction
strategy already identified as eligible under Sections 225.460(c) and 225.560(c).
Id
.
Public Comment 5: The Agency
The Agency asserts that although the testimony elicited and evidence submitted to date in
this proceeding reflects agreement of all parties on many of the issues involved, some of the
regulated sources do not agree with the Agency’s approach for allocations based on gross
electrical output or the amount of the set-asides. PC 5 at 2. The Agency notes that
representatives of the power plants do not necessarily agree as to whether allowances should be
allocated on heat input or gross electrical output or the amount of the set-asides.
Id
. The Agency
further notes that although the participating environmental interest groups are generally
supportive of the proposed rulemaking, they do not favor including the fluidized bed boilers in
the CASA.
Id
.
The Agency states that an additional public comment filed jointly with Midwest
Generation that describes and proposes the combined pollutant standards (CPS). According to
the Agency, the CPS provides compliance flexibility for the mercury emissions reduction
requirements in R06-25 (35 Ill. Adm. Code 225, Subpart B) in exchange for significant
reductions in NO
x
and SO
2
emissions. PC 5 at 3. The Agency contends that the CPS, like the
multi-pollutant standard (MPS) included in R06-25, are voluntary provisions that allow for
additional compliance flexibility.
Id
.
13
Fuel-Weighting
The Agency maintains that fuel-weighting as proposed is appropriate. PC 5 at 4.
According to the Agency, the predominant sources of both NO
x
and SO
2
emissions in Illinois are
the coal-fired power plants.
Id
. The Agency concludes that since these sources emit higher rates
of both pollutants, reductions at these sources will provide the greatest benefits, and the greater
the feasibility, the more likely they are to be controlled.
Id
. In addition, the Agency contends
that its economic analysis that found the NO
x
policy to be economically reasonable based upon
the proposed fuel-weighting allocation methodology. Deviation from this allocation
methodology, states the Agency, would impact the economic analysis performed and relied upon
for the proposed rule.
Id
.
CASA
The Agency rejects a proposal on behalf of Christian County Generation to eliminate
pro
rata
reduction of CASA allocations for early adopters. The Agency states it has explored a
number of allocation schemes. PC 5 at 6. The Agency found that
pro rata
allocation was
ultimately felt to best serve those purposes by proportionately sharing among all eligible, and
that fixed portion schemes would be particularly problematic for the Agency to implement
because Illinois’ CASA allocation scheme is specifically based on the number of electricity
hours generated or conserved, which will change from year to year.
Id
. The Agency concluded
that the rule could not, therefore, simply offer a fixed number of allowances.
Id
. The Agency
views the current scheme as a compromise that allows a portion of the CASA to all those
eligible, while simultaneously being implementable given the Agency’s limited resources.
Id
. at
6-7.
After considering the view by participants that the 30% set-aside is too great, the Agency
maintains its support for the 30% CASA as currently drafted. The Agency contends that the
USEPA left the authority to the individual States to distribute their allocations as necessary to
meet their own State’s individual goals. PC 5 at 7. The Agency states that it has chosen to carve
a set-aside away from the main pool to provide incentive to various other areas to promote
Illinois’ interests (
e.g
., pollution control upgrades for cleaner air, integrated gasification
combined cycle (IGCC) for cleaner generation, energy efficiency/renewable energy (EE/RE)
efforts for zero emission generation, and a small pool to undertake these projects early on) whose
individual contributions benefit the environment.
Id
. Further, the Agency argues that each of
those project categories assists Illinois EPA in their duty to attain NAAQS.
Id
.
The Agency hired outside consultants to perform a financial analysis of the impact, under
the worst-case scenario that the 30% set-aside was effectively retired. The Agency states the
results showed that relying solely on a 70% main pool, the reliability of the grid was intact and
residential and commercial electric rates would not be greatly impacted. PC 5 at 7.
The Agency does not agree that it should increase the RE/EE set-asides from 12 to 15.4%
for the purpose of “being consistent with the policy goals and policy targets” set forth in the
Governor Blagojevich’s Sustainable Energy Plan. PC 5 at 9. While both the Governor’s plan
and the allocation methodology proposed in the Illinois CAIR encourage renewable energy and
energy efficiency, states the Agency, they are mutually exclusive programs.
Id
. Nonetheless,
14
states the Agency, the set-aside allowances and the Governor’s energy plan are complimentary
and further the same goal.
Id
.
The Agency declines to allow OFA projects to receive allowances from the CASA. PC 5
at 10. The Agency asserts that the primary purpose of the CASA, with respect to the pollution
control upgrade category, is to reduce the typically large capital costs with the goal of promoting
a few selected project types that are comparatively much more expensive than OFA and
advanced OFA.
Id
. The Agency contends that the more costly controls generally result in the
greatest reductions in emissions.
Id
.
The Agency agrees to allow the only remaining fluidized bed combustion (FBC) boiler in
Illinois to receive CASA allowances. The single existing FBC boiler is the SIPCO 123 boiler in
Marion, Williamson County. The Agency, however, will not allow any future FBC boilers to
receive CASA allowances. PC 5 at 11. When constructed in 2001, SIPCO’s FBC boiler was
considered a more current technology that the 58 other and older boilers in Illinois. The boiler
achieves lower NO
x
and SO
2
emission rates than any of the other boilers in Illinois, but the rates
could be lower if SIPCO decided to operate the NO
x
controls at a greater capacity or install
additional NO
x
and SO
2
controls.
Id
. at 12. The Agency concludes that providing SIPCO CASA
allowances will encourage these further reductions in emissions.
However, future FBC boilers will not receive CASA allowances because the Agency
seeks to ultimately encourage the most promising clean coal technology, such as integrated
gasification combined cycle (IGCC) facilities, that are capable of much lower emissions than
FBC boilers.
Id
. at 12-13.
The Agency agrees to revise the allocation method in the proposed in Sections
225.465(b)(5)(B) and 225.565(b)(5)(B) relating to allocating CASA allowances to clean coal
technology projects. PC 5 at 17. SIPCO directly measures its emission rate in pound per
megawatt (lb/MW) rather than converting from pound per million Btu (lb/mmBtu).
Id
. The
Agency had previously performed an estimate that does not report the direct measurement that
SIPCO performs and therefore was less accurate than the direct measurement.
Id
. at 17-18.
The proposed revision will result in the same CASA allowance distribution as compared
to the prior estimate. PC 5 at 18. The Agency asserts that the proposed revision will include
new subsections in Sections 225.465(b)(5)(B) and 225.565(b)(5)(B). The new subsections will
include a factor change from 1.0 to 1.4 in the same equation currently used.
Id
. The factor
change will compensate for SIPCO’s direct measurements and provide the same level of
incentive the Agency was previously attempting to achieve.
Id.
Air Quality Modeling
The Agency rejects a suggestion by Mr. Saladino, on behalf of Kincaid, that the Agency
conduct additional modeling to determine the amount of further reductions that may be necessary
to meet air quality standards following the implementation of CAIR reductions. PC 5 at 18-19.
15
The Agency asserts that the technical support document
3
submitted to the Board in this
rulemaking presented the results of two modeling studies that address the issues raised by Mr.
Saladino, and that the Agency has, therefore, already presented the type of modeling requested
by Mr. Saladino.
Id
. Further, the Agency states it cannot conclude that it would be
economically reasonable for the Chicago nonattainment area to meet air quality standards.
Id
. at
19.
Summary of Proposed Changes
The Agency made several additional changes to the rule language suggested by the
USEPA. PC 5 at 21. The Agency contends that the three most significant suggested
amendments were: (1) deleting Subsection (d)(5)(C) in Sections 225.445 and 225.545 that
required the Agency to reduce a unit’s allocation from the NUSA if it had been allocated excess
allowances for the prior control period; (2) deleting the definition for “CAIR Trading programs”
because it was not used in the proposal; and (3) clarifying the language concerning fractional
allowances to indicate that the Agency can only allocate whole allowances and allowances that
cannot be distributed on that basis will be retained and distributed
pro rata
for the next control
period.
Id
.
Public Comment 6: Dynegy and
SIPCO
In their post-hearing comment, Dynegy and SIPCO (for the purposes of this comment,
“the companies”) express frustration that the Agency has not changed in any substantive way to
reflect industry arguments concerning the size of the CASA and an allocation methodology
based upon only a two-year look-back and gross electrical output. PC 6 at 2. The only
concession, argue the companies, has been to allow the conversion of heat input to gross
electrical output for the first several years of the program.
Id
. The companies conclude the
public comment by suggesting improvements to the rule as proposed.
Dynegy and SIPCO contend they have also expressed deep concerns about the two-year
look-back and the demonstrated inability of the Agency to consistently and timely submit
allocations to the USEPA. With no “levelizing” of a two-year look-back, the Agency’s failure to
timely submit allocations could be devastating to the companies. In addition, the companies
generally prefer that allocations be based upon heat input rather than gross electrical output as
proposed by the Agency. Finally, the companies state they do not support any change to the
proposed reliance on fuel-weighting as included in the rule. PC 6 at 2.
CASA
Dynegy and SIPCP state they have consistently expressed their position that a set-aside
of 25% for the CASA is not justifiable. The companies argue that the Agency never explained
why it chose 25% of the total cap for the size of the CASA. Further, the companies state that
3
The proposal includes a technical support document (TSD) that provides information
supporting the rulemaking proposal.
16
other than the retirement of unused CASA allowances in the distant future, the Agency did not
demonstrate how the CASA will result in improvements to air quality in Illinois. The Agency
repeated throughout its oral testimony, state the companies, that the CASA would not reduce the
overall emissions cap. In fact, modeling by the Agency’s consultant, ICF, demonstrated that
NO
x
emissions in Illinois would not be reduced with a 25% CASA even if the entire 25% were
retired. Therefore, conclude the companies, the proposed CASA will merely displace the
location of the emissions. PC 6 at 3.
Use of Unused, Accrued CASA Allowances for CAA Demonstrations.
Dynegy and
SIPCO contend that the Agency has not presented a clear rationale for the 25% set-aside. PC 6
at 3. The Agency originally stated that the large set-aside was necessary for attainment and that
the Agency would retire unused, accrued allowances from the collective set-aside pools.
Id
. The
companies contend, however, that the Agency’s position shifted and the Agency later
acknowledged that it could not quantify the number of allowances that would be available for
retirement and that retirements could not be used to demonstrate attainment.
Id
. at 4.
Dynegy and SIPCP state that the same doubts concerning the unused, accrued set-aside
allowances for purposes of demonstrating attainment also apply to reliance on these allowances
in a maintenance plan: they cannot be quantified and their number is not permanent. PC 6 at 4.
The companies state that in the proposed rule, the language states the Agency
may
retire the
unused, accrued allowances. PC 6 at 4; citing proposed 35 Ill. Adm. Code 225.475(b)(5).
Accordingly, the companies assert that the Agency cannot say there are a permanent number of
allowances that would be retired in the future. The companies further contend that actual
emissions reductions are not quantifiable because the Agency cannot predict with certainty how
many allowances will be used from year to year and the rate at which unused allowances will
accrue and thereby be eligible for retirement. PC 6 at 4-5.
Next, Dynegy and SIPCO dispute the Agency’s “the-more-NO
x
-reduced-the-better”
principle. The companies argue that the Agency has not provided support for several aspects of
this approach. First, the companies state that while the Agency claims that various additional
reductions of NO
x
are necessary in order for the state to demonstrate attainment of the ozone and
PM
2.5
NAAQS, the Agency’s own witness, Mr. Robert Kaleel, indicated that the Chicago area
has attained the 8-hour ozone standard. PC 6 at 6. The companies note that attainment of the 8-
hour ozone standard in Chicago was achieved without the implementation of any part of CAIR
and conclude by questioning the need for a 25% CASA for air quality purposes relative to ozone.
PC 6 at 6.
Comprehensive Approach to CAA Requirements.
The companies seek a
comprehensive approach to federal requirements that they claim the Agency has failed to set
forth. The companies state that industry cannot support the “‛
ad hoc
, willy nilly approach’ – or
lack of comprehensive, organized approach – that the Agency has put forth so far.” Dynegy and
SIPCO contend that this approach has forced individual companies, including the operators of all
the EGUs subject to this proposed rule except City Water Light & Power, to enter into
negotiations with the Agency on an individual basis, resulting in the “inconsistent hodge podge”
of regulation that will become Part 225. PC 6 at 6-7.
17
The companies state that the Agency has failed to explain the role that the proposal will
play in the overall plan for the attainment demonstrations or provide information regarding the
amount of local NO
x
reduction necessary for attainment. The companies seek a demonstration
by the Agency of the air quality benefit derived from the 25% CASA, the air quality needs, and
how a 25% CASA satisfies those needs. PC 6 at 8.
Lack of Identified Projects.
Next, Dynegy and SIPCO state that the Agency has not
identified projects that justify the size of the set-aside. The companies state that even in light of
testimony by ELPC witness, Mr. Charles Kubert, regarding energy efficiency and renewable
energy (EE/RE) projects, the Agency’s identification of new coal-fired projects either permitted
or under review, and recognizing Ameren’s eligibility for early-adopter CASA allowances, the
evidence does not justify anything approaching a 25% CASA.
The companies state that through the “tipping” provisions of the CASA, a significant
portion of the CASA allowances could go to Ameren. It is extremely inequitable, state the
companies, that the five other power generation companies in the state should be expected to
subsidize Ameren through the CASA when the other companies had reduced SO
2
emissions for
many years prior to implementation of the MPS.
Effect of 25% Set-Aside on Economic Analysis of the Proposed Rule.
The companies
dispute the Agency’s economic analysis of the CASA as highly cost effective. The companies
contend that the 25% CASA is the equivalent to not allocating allowances to the Dynegy, City
Water Light & Power, and SIPCO systems, with 102 megawatts (MW) still not accounted for.
PC 6 at 10.
The companies question the Agency’s reasoning that Illinois’ cap is not affected by the
25% CASA. The Agency contends the CASA allowances remain in the regional pool to be
purchased by Illinois EGUs that are not allocated a number of allowances sufficient to cover
their emissions, and so the rule remains within the scope of USEPA’s determination of highly
cost effective. Dynegy and SIPCO argue, however, that if EGUs must purchase allowances that
USEPA intended be allocated to them without cost, then the Illinois rule is significantly different
from USEPA’s assumptions in its “highly cost effective” analysis. The companies argue that the
Illinois rule will be significantly more costly for Illinois EGUs than for EGUs in states with set-
asides the same as or closer to the 5% new unit set-aside (NUSA) provided in the model rule.
The companies note that the USEPA’s analysis did not assume a CASA of any size. PC 6 at 11.
The companies dispute the Agency’s contention that USEPA granted flexibility to states
with respect to inclusion of a set-aside for EE/RE projects. According to the companies, USEPA
does not suggest anywhere in the preamble to CAIR that there should be an additional set-aside
for early adopters, clean coal technology, and so forth. The companies assert that the Agency’s
set-aside proposal exhibits “pretzel-like flexibility, very bent but rigid.” PC 6 at 12.
Extremely Large Proposed CASA Neither Mandated Nor Supported.
The
companies contend that the Governor’s energy plans are no bases to justify the size of the EE/RE
portion of the CASA. The Agency, state the companies, relied upon the Governor’s Sustainable
Energy Plan to justify the size of the EE/RE portion of the CASA. However, the Governor’s
18
Sustainable Energy Plan states that the responsibility for ensuring that the requisite percentage of
power used in Illinois lies with the distributors of power, not the EGUs. PC 6 at 12-13.
The companies also agree that the Agency does not bear the responsibility for developing
CAIR to accommodate the Governor’s Energy Plan. The companies agree that there are no
regulations or other mandates with respect to that plan, and believe that it would be more
appropriate to eliminate the CASA for that very reason. PC 6 at 13.
Disparate Treatment of EGUs Subject to Consent Decrees.
The companies disagree
with the Agency’s rationale for excluding EGUs that entered into consent decrees prior to
May 30, 2006. The companies opine that the clear purpose of carving out reductions for these
EGUs was to exclude Dynegy from participation in the CASA for reductions it will achieve
pursuant to its consent decree with USEPA. PC 6 at 14.
Dynegy and SIPCO disagree with the Agency’s rationale that a consent decree is
somehow not voluntary. The companies emphasize that no source is compelled to enter into a
consent decree, and very often a consent decree contains no admission of liability or guilt.
Entering into a consent decree is often more economical than defending against an enforcement
action. The companies further state that entry into the consent decree is a business decision and
not involuntary. PC 6 at 14-15.
Review of CASA Allowance Allocations.
The companies seek clarification of proposed
Section 225.455(b) for appeals of CASA allocations. The companies note that while the
regulations do not provide for Board review of the Agency’s final decisions regarding CASA
allocations, the Environmental Protection Act (Act) provides for the review of permits issued by
the Agency. PC 6 at 15.
The companies state that while an upheld appeal of a CASA allocation would not likely
qualify as noncompliance with the Subpart, it could result in a readjustment of the distribution of
CASA allowances for the given time period. This scenario could involve the return of
allowances to the Agency for redistribution. The companies suggest that the language of the
proposed Section 225.455(b) should be amended to address this potentiality. PC 6 at 15-16.
Adding Overfire Air to the CASA.
The companies oppose Ameren’s proposal to add
“advanced” OFA to the CASA. The companies contend that, if the Board were to accept
Ameren’s proposal without certain qualifications, Ameren would again be rewarded merely for
coming to par with the other generators in the state. Steven Whitworth testified that only two of
Ameren’s Illinois units are currently fitted with OFA. PC 6 at 16-17.
The companies state that unless the regulated community as a whole would be given
credit for OFA systems that achieve a specified level of NO
x
removal (rather than distinguishing
between “advanced” and other OFA schemes), the Board should reject Ameren’s request. PC 6
at 17.
Annual Operation of SCRs.
The companies address Dominion’s suggested that annual
operation of SCRs installed since adoption of Part 217, Subpart W should be eligible for CASA
19
credit. The companies state that if the Agency and the Board consider inclusion of Dominion’s
suggestion, the resulting CASA language should include annual operation of previously installed
SNCRs, as well. PC 6 at 17.
Purpose of the CASA.
The companies assert that the CASA as it is structured, does not
further the Agency’s stated purpose of CASA. According to the companies, the Agency has
stated that the purpose of the CASA is to encourage early reductions, principally obtained
through construction and operation of new or upgraded pollution control devices, and encourage
projects that will benefit the environment. PC 6 at 17-18. The companies state that providing
carve-out “incentives” for those who reduce early, subsidizing the costs of more expensive
pollution control equipment, is inconsistent and skews how CASA allowances are allocated.
Id
.
at 18.
Dynegy and SIPCO state that a project does not have to be “big-ticket” to benefit the
environment. The companies state, for example, that low NO
x
burners and OFA are less “big-
ticket” than SNCR, yet they benefit the environment without exposing the environment to
ammonia slip or leaks. PC 6 at 18.
Finally, the companies argue that the CASA does not treat all EGUs equally. The
companies claim that CASA subsidizes the construction of pollution control equipment by some
companies at the expense of others. For example, Dominion has made improvements on the
Kincaid facility and SIPCO has installed a circulating fluidized bed (CFB) unit, baghouses, a
scrubber, and an SNCR, yet they are effectively penalized 25% of the allowances USEPA
anticipated they would receive. Although SIPCO may receive some allowances from the CASA,
that number of allowances does not come close to the 25% it will lose to the CASA. PC 6 at 19-
20.
CASA Allowances for MPS Reductions.
The companies state that despite the
Agency’s contentions, not all projects undertaken pursuant to the MPS will be excluded from
having to surrender allowances to the Agency. PC 6 at 20. According to the companies, it
appears that beginning in 2012 for NO
x
projects and 2013 for SO
2
projects, the project sponsors
may apply for allowances from the CASA, but under the language of Section 225.233(f)(1) of
the MPS, the project sponsors would have to surrender those allowances back to the Agency
because those allowances would have been generated “as a result of actions taken to comply with
the standards of subsection (e) of this Section [225.233].”
Id
. at 20-21; citing Proposed New 35
Ill. Adm. Code 225 Control of Emissions From Large Combustion Sources (Mercury), R06-25,
slip op. at 113 (Nov. 2, 2006).
Conclusion.
For all of the reasons provided above, the companies assert that industry is
very reluctant to agree that a 30% set-aside is justifiable or even beneficial to interests the state
purports to promote through creation of the set-aside. The companies state that the CASA is
either a misguided attempt to support so-called green projects, or is skewed to benefit one
company. Neither scenario is acceptable to the companies. The CASA represents 4,521
(megawatt electrical (Mwe). The companies state that at $2,500/allowance, this represents
$47,643,750 value lost to the existing power generators on an annual basis plus $9,528,750 in
allowance value for the NUSA. Moreover, state the companies, the Agency has specifically
20
omitted the CSP of 11,299 allowances, worth $28,274,500 at $2,500 per allowance. The
companies reason that since the Agency proposes to encourage early reductions, the cost of the
lost CSP is actually double that, or $56,495,000. PC 6 at 21-22.
Allocation Methodology
Heat Input v. Gross Electrical Output.
The companies oppose the Agency’s proposal
that allowance allocations be based upon gross electrical output rather than heat input. The
companies suggest that the rule language simply mirror the federal requirements. PC 6 at 24.
SIPCO adamantly opposes reliance on gross electrical output as the basis for allowance
allocations.
Id
. at 24. Dynegy prefers reliance on gross electrical output as the basis for
allocations, but would find heat input as a basis for allocations acceptable because of the amount
of historical data on heat input, and the well-established quality assurance procedures for
reporting.
Id
. Further, notes Dynegy, it was the basis USEPA used for establishing caps under
the federal CAIR, and the Agency has put forth no compelling reason to switch from heat input
as the basis for allocations.
Id
.
The companies state that the efficiency assumed in the Agency’s heat input to gross
electrical output formula is not representative of actual efficiencies at the plants. This formula
disadvantages the vast majority of the regulated entities to varying degrees and is particularly
disadvantageous to SIPCO.
The companies state that industry wants an appropriate conversion formula to be applied.
PC 6 at 25. The current conversion formula, for example, would put integrated
gasification/combined cycle (IGCC) plants at a disadvantage. Alternatively, state Dynegy and
SIPCO, if Illinois followed the federal example, as new sources, IGCC plants would be allocated
allowances based upon gross electrical output pursuant to USEPA’s formula.
Id
.
With respect to encouraging efficiency, the companies note that not all types of boilers
are considered environmentally beneficial and not all clean coal technology are exceedingly
efficient. CFBs, for example, are considered a clean coal technology and are eligible for
allowance allocations under the CASA. Operation of the CFB, however, is not as efficient as
other types of boilers in terms of gross electrical output. Compared to USEPA’s list of the top
25 most efficient boilers, SIPCO’s CFB, state the companies, is almost 40% less efficient. The
companies explain that this means the CFB requires 40% more Btu to generate a kilowatt-hour.
The environmental controls of a CFB occur inside the boiler resulting in a gross heat rate
penalty. In other types of boilers, controls are external to the boiler and appear more efficient
when comparing gross heat rates. As a result, SIPCO’s CFB is penalized by the use of gross
electrical output as the basis for allowance allocations. Nonetheless, SIPCO’s CFB has
inherently lower emissions and was specifically designed to burn recovered coal fines, which
provides an environmental benefit by reducing acid run-off. PC 6 at 25-26.
Acceptable Gross Electrical Output Data.
The companies understand, from the
Agency’s presentations at the Springfield hearing and in subsequent discussions, that the Agency
will accept as gross electrical output data any data that is acceptable to USEPA pursuant to 40
C.F.R. § 60 or 75. The companies note that the proposed language requires an actual
21
measurement device be installed on the generator. However, such a device is not required by
USEPA pursuant to 40 C.F.R. § 60 or 75. The companies urge the Board to ensure that the rule
language reflects the parties’ intent. PC 6 at 27.
Fuel-Weighting.
The companies support the Agency’s proposal regarding weights
assigned to fuel types and oppose the change suggested by Zion. PC 6 at 27. Zion requested that
the Board remove the fuel-weighting or, alternatively, assign a factor of 1.0 for coal and 0.6 for
all other fuels. The companies argue that the change would result in fewer allowances allocated
to the companies, and with a 25% CASA, the companies do not support any amendments that
would further reduce the number of allocated allowances.
Id
. at 27-28. The companies state that
use of fuel factors is appropriate for the reasons provided by the USEPA and the Agency.
Id
.
Look-Back Period and Annual Updating.
The companies oppose the Agency’s
approach to annual allowance allocations, and support use of the USEPA’s approach of using a
permanent baseline. PC 6 at 28-29. The companies state that the look-back period will, from
time to time, include periods when the EGUs experience outages of various lengths of time. The
companies contend that the rule is not clear on how companies that opt in to the MPS will be
able to bank their allowances to cover outage years.
Id
. at 29. The companies are also
concerned with the approach of annual updating because of the Agency’s past failures to timely
allocate allowances. Further, state the companies, a two-year look-back period would require
that the updating occur annually and timely. PC 6 at 28-29. Failure to timely allocate
allowances under this approach could also effect the EGUs’ emissions trading.
Id
. at 30-31.
USEPA suggested a permanent baseline for sources in the model rule, reasoning that it
“will eliminate the potential for a generation subsidy (and efficiency loss) as well as any
potential incentive for less efficient existing units to generate more.” PC 6 at 29; citing 70 Fed.
Reg. 25161, 25279 (May 12, 2005). The companies urge the Board to revise the updating
allocation methodology to take the average of the three highest years’ heat input during a five-
year look-back period (currently in place in Illinois under Part 217, Subpart W).
Id
. at 31. The
companies contend this approach would level the effects of outages.
Id
.
Suggested Improvements to the Rule as Proposed
CASA Size.
The companies propose reducing the CASA size to 5% of the state’s cap.
This 5%, state the companies, would cover the allowances necessary to address the projects that
Mr. Kubert stated were in development. PC 6 at 34.
CASA Categories.
The companies recommend that the CASA be limited to EE/RE
projects if the size of the CASA is reduced as urged above. If the existing companies are not
effectively penalized by the loss of an additional 20% of their allowances as anticipated by
USEPA in establishing the state’s cap, then the additional CASA categories are not necessary. If
the Board decides not reduce the size of the CASA, the companies urge the Board to accept the
changes to the CASA indicated in their Response to the Agency’s Motion to Amend
Rulemaking. PC 6 at 34.
22
The companies state that if the Board determines that it is appropriate to include OFA as
a CASA category, the rule should also make historical OFA systems that meet or exceed the
30% reduction threshold eligible regardless of whether upgrades to existing OFA systems are
necessary to achieve such a reduction level. PC 6 at 34-35.
Compliance Supplement Pool.
The companies favor including the CSP in the rule, as
opposed to its retirement. PC 6 at 35.
Allocation Methodology.
The companies strongly urge the Board to reject the Agency’s
proposed allocation methodology and replace it with one that reflects USEPA’s model rule. The
companies doubt the Agency will consistently manage the proposed annual updating
methodology for two trading programs plus the CASA in the timeframes set forth in the rule. PC
6 at 35.
Public Comment 7: Environmental Advocates
The ELPC, by itself and on behalf of American Lung Association of Metropolitan
Chicago; Environment Illinois; and the Sierra Club (collectively, “Environmental Advocates”)
urge the Board to amend the Agency’s proposed CAIR rule in three principle ways. PC 7 at 1.
First, the renewable energy and energy efficiency set-asides should be increased to better meet
the rule’s own renewable energy goals.
Id.
Second, the CASA proposed for circulating fluidized
bed (FBC) boilers should be eliminated, since FBC boilers are not a clean coal technology.
Id.
Third, the fuel-weighting factors should be eliminated, since they discourage the use of cleaner
fuels in energy production.
Id.
The Energy Efficiency and Renewable Energy Set Aside Should be Increased
Renewable energy production projects will benefit from assignment of allowances
corresponding to the amount of energy they produce. PC 7 at 2. The Agency has acknowledged
that while the Governor’s plan calls for 10% of Illinois energy to come from renewable sources
by 2015, the current CAIR proposal will only lead to an offset of 5-8% of future need.
Id.
The
RE/EE set asides included in CASA, currently set at 12%, should be raised to 15%, with an
annual increase of 1% to a maximum of 20%.
Id.
This will best allow the Illinois CAIR rule to
work toward both the Governor’s plan and its own goals.
Id.
In response to requests made at hearing, the Environmental Advocates attached several
studies concerning renewable energy to the comment. PC 7 at 2. One study that dealt with the
effects of wind turbines on radar concluded that with proper planning and site selection, any
conflict between radar technology and wind turbines may be mitigated.
Id.
Two further studies
compared wind power to coal power.
Id
. at 4. The first concluded that adding new wind power
can be more economically effective than adding new gas or coal power and that a higher
percentage of dollars spent on coal and gas will leave the state.
Id.
The second study showed
that developing wind power instead of coal power and natural gas power can have a net benefit
to a state’s economy.
Id.
Another attachment to the comment showed that generation costs of
RE/EE are competitive with coal.
Id.
23
The Rule Should Not Provide Incentives for FBC Boilers
The Environmental Advocates state that FBC boilers should not receive CASA credits
because: (1) controlled FBC boilers are not lower in NO
x
emissions than controlled pulverized
coal (PC) boilers; (2) FBC boilers do not achieve the low NO
x
emissions that IGCC plants do;
and (3) FBC boilers emit more greenhouse gases than PC boilers. PC 7 at 4. The Environmental
Advocates contend that Agency’s explanation for including FBC boilers in the CASA lacks
justification for FBC boilers receiving CASA credits. According to the Environmental
Advocates, the TSD contains no support for giving incentive credits to FBCs and the Agency
was merely responding to concerns of the coal-fired power plants in doing so.
Id
. at 5. The
Environmental Advocates contend that because the Agency puts forward no persuasive reason
for including FBC boilers in the CASA, and because FBC boilers emit more NO
x
and
greenhouse gases than controlled PC boilers and IGCC plants, FBC boilers should be removed
from the CASA.
Id.
FBC Boilers Do Not Lead to Reduced NO
x
Emissions Compared to PC Boilers
.
While FBC boilers may be lower emitting than PCs when looking at uncontrolled emissions,
FBC boilers are not lower emitting once controlled. PC 7 at 5. In this day and age, new coal-
fired power plants are all built with controls.
Id
. at 5. Therefore, it is emissions from controlled
FBC boilers compared to emissions from controlled PC boilers that should be considered
because that is demonstrative of what the actual emissions will be.
Id.
Therefore, PC boilers
generally achieve lower NO
x
emissions levels and have lower NO
x
permit levels than FBC
boilers because PC boilers, but not new FBC boilers, can install the most effective NO
x
controls
(SCR). New PC boilers, which generally use the most modern NO
x
controls, achieve
approximately 30% lower NO
x
emissions than FBC boilers, which generally are built without the
best performing NO
x
controls.
Id.
Consequently, there is no justification for offering incentives
for FBC boilers considering they do not achieve lower emission levels than PC boilers.
Id.
FBC Boilers Do Not Achieve Emissions Levels Comparable to IGCC
. The TSD
discusses the eligibility for other projects to receive credits under this section for the “Clean Coal
Technology” incentive and states that projects that use “technologies that achieve comparable
emission rates” to IGCC or CFB boilers may be eligible for the set-aside. PC 7 at 6; citing TSD
at 112. However, FBC boilers and IGCC projects themselves do not achieve comparable NO
x
emissions rates. PC 7 at 7
.
CFB boilers permit levels have generally ranged from 0.07 to
0.08lb/MMBtu.
Id.
Expected NO
x
emission levels for recently proposed IGCC plants average
0.039lb/MMBtu, resulting upwards of 45% lower NO
x
emissions.
Id.
Since CFB boilers do not
perform nearly as well as IGCC, they should not be included in the same category of incentives.
Id.
If the two projects listed in the clean coal technologies category are not similar in their
effects, it would be impossible to determine what emissions rates new projects ought to be
achieving in order to receive clean coal technology credits.
Id.
at 8;
see
proposed 35 Ill. Adm.
Code 225.460(e)
.
For these reasons, the Environmental Advocates assert that FBC boilers
should be removed from the CASA.
Id
.
CFB Boilers Emit 15% More Greenhouse Gases
. CFB boilers emit more N
2
O, a
potent greenhouse gas, than PC boilers. PC 7 at 7. Comparatively, CFB boilers emit
approximately 15% more global warming pollutants than PC boilers.
Id.
In fact, SNCR, the
24
NO
x
controls most commonly used on CFB boilers, increase the amount of N
2
O.
Id.
Creating an
incentive for a technology that emits 15% more global warming pollutants than the alternatives is
contrary to both state and the Agency goals.
Id.
Both the Governor and Agency Director Doug
Scott have publicly stated that reducing global warming pollutants is a state priority. PC 7 at 8.
By endorsing CFB boilers and providing incentives or them, the Environmental Advocates
contend that the Agency and the state are acting completely contrary to state policy on global
warming.
Id.
The Environmental Advocates conclude that it is incumbent upon the Board to
correct the course of this rule and remove “clean coal” incentives for CFB boilers.
Id.
Illinois Should Adopt a Fuel-Neutral Approach In Allocating NOx Allowances To Specific
Sources
The Environmental Advocates note that the federal CAIR proposal is fuel-neutral,
meaning it did not include an adjusted fuel-weighting calculation to determine NO
x
emission
credit allowances. PC 7 at 9; citing 69 Fed. Reg. 4610 (2004). According to the State and
Territorial Air Pollution Program Administrators (STAPPA) and the Association of Local Air
Pollution Control Officials (ALAPCO), a fuel-neutral allocation system that does not
differentiate between coal and non-coal units “even[s] the playing field by treating all units the
same. Among other things, this allows the trading program to do a more effective job of
determining the most cost effective compliance mix.” PC 7 at 10.
The Environmental Advocates state that the operators of coal-fired EGUs, or their trade
associations, submitted virtually all of the comments USEPA received in opposition to the fuel-
neutral approach to determine NO
x
emission credit allowances. PC 7 at 10. The Agency did not
object to the fuel-neutral approach in allocating NO
x
emission credit allowances in their
March 30, 2004 comments.
Id.
When CAIR was promulgated in final form, it was no longer fuel-neutral. PC 7 at 10.
As a result, Illinois, which had argued for deeper reductions, now found itself with more NO
x
allowances by virtue of the elimination of fuel-neutrality.
Id
. However, having given Illinois
additional NO
x
allowances, CAIR in its final form explicitly does not require Illinois or any other
state to use the fuel allocation factors in distributing allocations to individual sources.
Id.
The
USEPA allowed individual states to decide whether to use a fuel-neutral or fuel-weighted system
in making allocations to individual systems.
Id
. at 11. The Environmental Advocates ask that
the Board eliminate or modify the fuel-weighting component of the proposed Illinois rule.
Id.
The Environmental Advocates contend that in the fuel-weighted system that is now a part
of the proposed rule, coal-fired power plants are the clear beneficiaries by comparison to their
oil- and especially gas-fired counterparts. PC 7 at 12. According to the Environmental
Advocates, the immediate losers of this market inefficiency are the gas and oil fired boilers and
combustion turbines identified by the Agency.
Id.
The Environmental Advocates contend that
Agency’s reasoning for using a fuel-weighted system that benefits one sector at the expense of
others has been consistent throughout these proceedings, and it is twisted.
Id.
Oil- and gas-fired
EGUs are being punished for using an inherently cleaner fuel, which disadvantages EGUs that
generate an equivalent unit of energy with lower emissions compared to a coal-fired unit.
Id.
25
Many oil and gas fired EGUs are also being punished by virtue of operating more
modern, well-controlled facilities than their coal-fired counterparts. PC 7 at 12. The
Environmental Advocates point to testimony made by Jason Goodwin to clarify this point.
Id
. at
13. The Environmental Advocates add that “[p]utting modern, well-controlled and cleaner
facilities at such disadvantage is a far cry from the Agency’s stated objective.”
Id.
In the TSD,
the Agency states its objective is to provide more allowances to sources that operate more
efficiently, install air pollution control equipment, and upgrade equipment.
Id.
; citing TSD at 35.
In light of the success of fuel-neutral NO
x
seasonal trading program and the Agency’s stated
policy to provide more allowances to efficient, modern facilities, the Environmental Advocates
ask why the Agency proposed a fuel-weighted system? PC 7 at 14. Mr. Goodwin was succinct
in stating, “clearly, Illinois is strongly oriented to coal generation.”
Id.
The Environmental
Advocates state that on this issue, the Illinois CAIR rule is not reasonably related to the stated
purposes of encouraging cleaner energy generation.
Id.
For these reasons, the Environmental Advocates recommend that the Board amend the
CAIR rule to increase the renewable energy and energy efficiency set-asides, remove any
allowance incentives granted to fluidized boilers, and eliminate the included fuel-weighting
factors. PC 7 at 15-16.
Public Comment 8: Post-Hearing Comments of Midwest Generation
Midwest Generation supports a three-year averaging and five-year look-back period to
determine an EGU’s allowances, rather than the two-year period in the Agency’s proposed rule.
PC 8 at 1. Midwest Generation is concerned that the two-year look-back will encompass periods
when the EGUs experience outages of various lengths of time and EGUs will consequently
receive a “short” allocation.
Id
In addition, Midwest is concerned about the process of annual updating and the relevant
look-back period. PC 8 at 1. Where the look-back is so short with no “levelizing” allowed
through the averaging of a number of years’ operations chosen from a larger number of years,
such as the highest three years’ operation out of a specified five-year period, it becomes critical
that the updating occur annually and timely.
Id.
at 1-2.
USEPA has suggested a permanent baseline for sources in the model rule, which the
USEPA has stated is easier to implement administratively. PC 8 at 2; citing 70 Fed. Reg. 25161,
25279 (May 12, 2005). New sources roll into the existing source permanent baseline once they
have five years of operating data, causing an adjustment of all existing sources’ allocations.
Id.
USEPA reasoned that it chose not to utilize an updating system for allocating allowances, in
order to avoid the subsidization of increased fuel use and the associated market distortions.
Id.
;
citing 71 Fed. Reg. 25328, 25356 (Apr. 28, 2006). The USEPA further stated that if allocations
were based upon updated heat input data then increased fuel use would result in increased future
allocations and thus would in effect be subsidized.
Id.
Midwest believes that this is the best
approach for providing certainty to existing plants, integrating new plants into the allowance
system, and minimizing the resource burden on the Agency associated with annual updating.
Id.
Midwest also urges the Agency to consider using a five-year look-back (three highest years of
operational heat input over a five-year period).
Id.
This approach will help to levelize the
26
allowances for EGUs in Illinois and will avoid skewed distribution of allowances or penalties
associated with unexpected or extended outages.
Id.
Like Dynegy and SIPCO, Midwest Generation is concerned that future human error
could result in delayed allowance allocations by the Agency, and believes the rules should be
written to ensure against, or at least minimize, the negative outcomes of human error. PC 8 at 3.
According to Midwest Generation, as a safety net, the USEPA has provided in its NO
x
trading rules that when a state fails to allocate allowances in a timely manner, USEPA will rely
upon the previous allocation to cover the unallocated period. PC 8 at 3. If a timely allocation is
not made for the two NO
x
programs proposed by these rules, some EGUs will be frozen at an
allowance level that reflects extensive outages.
Id.
This cannot be avoided under the current
language of the rule, yet either of Midwest Generation’s proposed alternatives would avoid this
outcome.
Id.
Midwest Generation urges the Board to revise the rule to reflect the three-year averaging
concept and the five-year look-back period. PC 8 at 4. Finally, Midwest Generation requests
that the Board consider heat input as the basis for allocations, which is how Midwest Generation
has reported and certified for years.
Id
. at 5. Heat input data is more reliable than output data as
the manner of output data’s measurement and its quality assurance is not uniform.
Id.
Public Comment 9: Joint Comment of the Agency and Midwest Generation
Please refer to PC 11, a revised joint comment of Midwest Generation and the Agency,
discussed below.
Public Comment 10: Final Comments of Kincaid
Over the past eight years, Dominion’s Kincaid station has been installing pollution
controls, switching fuels and making other changes to ensure compliance with the increasingly
more stringent air quality emissions limitations. Kincaid supports the adoption of state
regulations that embrace the federal CAIR. PC 10 at 1-2.
Kincaid does not support Subparts D and E of the Agency’s proposal. Specifically,
Kincaid states it does not support the 25% CASA. Kincaid states the Agency has provided no
justification that the level of the proposed set-aside is necessary from an air quality perspective.
Kincaid further contends that these provisions will significantly increase compliance costs for
Illinois sources and competitively disadvantage the state relative to surrounding states.
According to Kincaid, this approach also could jeopardize USEPA approval of the Illinois CAIR
SIP, and even Illinois sources’ participation in the federal trading program. Kincaid asserts this
may also deny Illinois the economic advantages of the USEPA trading program that many other
surrounding states will realize through the adoption of the USEPA rule.
Kincaid also does not support the proposed withholding of allowances from the
compliance supplement pool (CSP). The early reduction incentives that Illinois included in its
rules implementing the NO
x
SIP Call not only provide companies added compliance flexibility
27
that eases the burden once the requirements take effect, but also benefit the environment by
providing real emission reductions sooner. PC 10 at 2-3.
Kincaid opposes any requirement that all Illinois sources subject to CAIR implement
“beyond CAIR” reductions. The Agency should evaluate only those local areas in Illinois that
fail to meet the air quality standards following implementation of the CAIR regional reductions.
PC 10 at 3. Taking this approach, asserts Kincaid, the Agency can determine the amount of
additional air quality improvement and emission reductions needed in the more localized
nonattainment area in order to achieve the needed air quality improvements in the most cost-
effective manner.
Id
. Kincaid urges the Board to reject the IEPA proposal and, instead, approve
full adoption of USEPA’s federal “model rule” on the same schedule established by USEPA. PC
10 at 3-4.
Kincaid further contends that “beyond CAIR” reductions are premature without more
data and more research demonstrating that EGU reductions of SO
2
and NO
x
impact PM
2.5
concentrations. PC 10 at 4. Until additional speciated monitoring data is available, argues
Kincaid, it is premature to require “beyond CAIR” SO
2
or NO
x
reductions from EGUs because
the absolute value of PM
2.5
concentrations measured in the field may not be driven by SO
2
or
NO
x
reductions.
Id
. Kincaid, therefore, supports the approach to implement CAIR essentially as
established by USEPA, in addition to working with sources in local nonattainment areas to
determine the appropriate mix of reductions needed to resolve the remaining local nonattainment
area issues. PC 10 at 4-5.
Kincaid states that source apportionment data provided by the Lake Michigan Air
Directors Consortium (LADCO) indicates that Illinois EGUs make up only a small part of the
ozone non-attainment problem in the Chicago area (Illinois EGU NO
x
emissions make up 4% of
the ozone contribution, behind “Illinois Non-road,” “Illinois Non-EGU,” and “Indiana On-road”
sources). PC 10 at 5.
Kincaid argues that adopting “beyond CAIR” NO
x
reductions will place Illinois at an
economic disadvantage compared to surrounding states. PC 10 at 6. Kincaid contends that the
25% CASA proposal will severely restrict NO
x
allocations for affected units. Essentially, asserts
Kincaid, the 25% set-aside becomes a 25% reduction beyond the NO
x
limits in the federal CAIR
rule. Imposition of “beyond CAIR” control strategies, such as the ones described in the white
paper prepared by LADCO on additional control scenarios for EGUs, could have a significant
negative impact on the economies of several Midwestern states.
Id
.
Kincaid states that recent studies on “beyond CAIR” requirements and corresponding
impacts of higher electric rates on the State of Illinois show increases in electric rates, an
decreased demand for coal mined in Illinois, Indiana and Ohio, a reduced annual economic
output in the five-state region (Illinois, Indiana, Ohio, Michigan, and Wisconsin), and reduced
employment in the five-state region. In addition, Kincaid can provide an estimated cost for the
five-state Midwest region for a scenario where LADCO controls are supplemented by
replacement power to compensate for early generating unit retirements at $865 million per year.
Kincaid contends Illinois would not have to bear its portion of these costs if it were to adopt the
federal CAIR program. PC 10 at 8-9.
28
Kincaid supports the Agency proposal to adopt the federal CAIR SO
2
trading program as
part of the Illinois CAIR rule. Modeling conducted by LADCO in the fall of 2005, suggests the
current PM
2.5
models are not yet sufficiently accurate on which to base regulatory decisions. PC
10 at 9.
Kincaid supports the five-year baseline proposed at Part 225, Subparts D and E, Sections
225.435(a) and 225.535(a) for the initial annual and ozone season allocation of NO
x
allowances
for the years 2009, 2010, and 2011. For the year 2012 and beyond, Kincaid urges IEPA to use a
five-year baseline, with an average of the three highest years, throughout the annual and seasonal
NO
x
trading rules with periodic revisions every five or six years. Kincaid asserts that a longer
baseline period will ensure that allocations will be fairly distributed among affected facilities,
taking into account market swings, prolonged maintenance breaks and lengthy outages to install
the extensive control equipment needed to comply with these rules as well as the recently
finalized mercury rules at Part 225, Subpart B. PC 10 at 10.
The Illinois Subpart W rules at Part 217.770 include an opportunity for affected sources
to obtain “early reduction credits” by reducing NO
x
emissions to specified levels before the rules
were fully effective in the ozone season of 2004. Kincaid states that its facility was equipped
with the most effective NO
x
controls available, emissions were reduced earlier than required and
the benefits to the environment were delivered. Nevertheless, the IEPA CAIR proposal
summarily withdraws this important incentive for early reductions with no other explanation than
“for public health and air quality improvements.” Kincaid urges the Board to restore the
allowances for the CSP in order to promote early compliance that will provide environmental
benefits to accrue and allow affected facilities to properly plan and implement compliance
strategies. Withdrawing these early reduction provisions removes the incentive for sources to
reduce NO
x
emissions in the non-ozone season in 2007 and 2008 (by operating SCRs year-
round). PC 10 at 11-12.
Withholding the additional 25% of the NO
x
allowance budget significantly impacts the
economics of the rule for EGUs. For Kincaid, the 30% set-aside (CASA plus NUSA) equates to
an annual allowance surrender of about $2.5 million per year. Under the IEPA proposal, if
Kincaid needed to purchase back these allowances (which under federal model rule would have
been directly allocated to Kincaid), the net financial impact would be $5 million per year. PC 10
at 12-13.
Kincaid urges the Board to reject the 30% NO
x
set-aside in favor of a set-aside consistent
with the federal model rule or some other more reasonable approach, and, regarding the EEC/RE
set-aside, to adopt provisions that would return any allowances not claimed by EEC/RE projects
to the EGUs. PC 10 at 13.
To effect this change, Kincaid suggests that the Board amend Section 225.475(b)(4) of
the proposed Subpart D: CAIR NO
x
Annual Trading Program as follows:
If allowances still remain undistributed after the allocations and distributions in the above
subsections are completed, the Agency may elect to retire any CAIR NO
x
allowances
,
29
with the exception of allowances assigned to the Energy Efficiency and
Conservation/Renewable Energy set-aside,
that have not been distributed to any CASA
category, to continue progress toward attainment or maintenance of the National Ambient
Air Quality Standards pursuant to the CAA.
Allowances from the Energy Efficiency and
Conservation/Renewable Energy set-aside that remain undistributed shall be distributed
to each CAIR NO
x
unit in accordance with section 225.440.
PC 10 at 14 (emphasis in
original).
Kincaid suggests that the Board make the following similar changes in section
225.575(b)(4) of the proposed Subpart E: CAIR NO
x
Ozone Season Trading Program:
If allowances still remain undistributed after the allocations and distributions in the above
subsections are completed, the Agency may elect to retire any CAIR NO
x
allowances
,
with the exception of allowances assigned to the Energy Efficiency and
Conservation/Renewable Energy set-aside,
that have not been distributed to any CASA
category, to continue progress toward attainment or maintenance of the National Ambient
Air Quality Standards pursuant to the CAA.
Allowances from the Energy Efficiency and
Conservation/Renewable Energy set-aside that remain undistributed shall be distributed
to each CAIR NO
x
Ozone Season unit in accordance with section 225.440.
PC 10 at 14
(emphasis in original).
According to Kincaid, because the eligibility to apply this “air pollution control
equipment upgrade” set-aside apparently hinges on installation of new controls on an existing
source, it appears the SCRs at Kincaid would not be eligible for these allowances. This is unfair.
Allowances were intended to help companies offset their economic burdens, and Kincaid does
not believe that Illinois should disproportionately burden its electric generators. PC 10 at 15.
Excluding existing air pollution control equipment that must be operated on a year-round
basis following adoption of the proposed rule from applying for allowances from the “air
pollution control equipment upgrade” set-aside is unfair and Kincaid urges the Board to change
the eligibility so that these existing controls are included. Kincaid suggests that the Board amend
the proposed rule at Section 225.460(c)(1) as follows:
Air pollution control equipment upgrades at existing coal-fired electric generating units,
as follows: installation of flue gas desulfurization (FGD) for control of SO
2
emissions;
installation of a baghouse for control of particulate matter emissions; and installation of
or extended operation of existing
selective catalytic reduction (SCR), selective non-
catalytic reduction (SNCR), or other add-on control devices for control of NO
x
emissions.
PC 10 at 15.
Kincaid states that the USEPA noted in its CAIR preamble that the “EPA’s CAIR and the
previously promulgated NO
x
SIP Call reflect EPA’s determination that the required SO
2
and
NO
x
reductions are sufficient to eliminate upwind States’ significant contribution to downwind
nonattainment. These programs are not designed to eliminate all contributions to transport, but
rather to balance the burden for achieving attainment between regional-scale and local-scale
control programs.” PC 10 at 16. Kincaid supports the USEPA’s position that CAIR does not
30
require states to prepare an attainment SIP to comply with CAIR and that the CAIR-related
emission reductions are not designed to result in attainment of the NAAQS.
Id
.
Finally, Kincaid contends that the Board has failed to evaluate the technical feasibility
and economic reasonableness of the combined impact of CAIR and CAMR. Both regulations
impose unique impacts on coal-fired EGUs. Kincaid states that it has provided information in
both regulatory proceedings that the economic impact of the individual and combined regulations
is unreasonable. Further, states Kincaid, the Board’s failure to evaluate the simultaneous impact
of both rules is inconsistent with Illinois law. PC 10 at 16; citing
Commonwealth Edison Co. v.
PCB, 25 Ill. App. 3d 271, 323 N.E.2d 84 (1st Dist. 1975) (
aff’d
62 Ill. 2d 494, 343 N.E.2d 4
(1976); Illinois State Chamber of Commerce v. PCB, 67 Ill. App. 3d 839, 384 N.E.2d 922 (1st
Dist. 1978).
Public Comment 11: Revised Joint Comment of the Agency and Midwest Generation
On January 10, 2007, five days after the close of the public comment period, the Agency
moved to file
instanter
a revised joint public comment (PC11), intended to supplement PC 9 that
the Agency and Midwest Generation filed jointly on January 5, 2007. The Agency attached the
revised public comment to the motion. The Board grants the motion, accepts PC 11, and
discusses the two comments below.
The Agency and Midwest Generation assert that on December 10, 2006, they entered into
a memorandum of understanding (MOU) under which the parties agreed to a timeline for
Midwest Generation to achieve “deep and sustained” reductions in emissions of mercury, SO
2,
and NO
x
from Midwest Generation’s coal-fired Illinois EGUs. PC 9 at 2. As a result, the
Agency and Midwest Generation ask the Board to include a new section, 35 Ill. Adm. Code
Section 225, titled Subpart F, Combined Pollutant Standards, 35 Ill. Adm. Code Section 225.600
et seq.
in the proposed CAIR rulemaking that reflects the parties’ agreement.
Id
.
The parties to the MOU assert that Subpart F will establish an alternative means of
compliance with the proposed emissions standards for mercury in Subpart B, Section 225.230(a)
and will establish specific emissions levels for NO
x
, PM, and SO
2.
PC 9 at 2. Under Subpart F,
the agreement provides that Midwest Generation will achieve reductions in mercury, NO
x
, PM,
and SO
2
emissions through a combination of permanent shut-downs of EGUs, installation of
activated halogenated carbon injection systems for reduction of mercury (ACI), and the
installation of pollution control equipment for NO
x
, PM, and SO
2
emissions that will also reduce
mercury emissions.
Id
. EGUs identified for compliance with the proposed Subpart F are
referred to as a combined pollutant standard group (CPS Group).
Id
.
The parties to the MOU assert that the owner or operator of the CPS Group must begin
installation of ACI equipment on certain EGUs twelve months earlier than the dates required for
installation and operation of ACI under the recently adopted mercury standards in Subpart B,
Section 225. The proposed Subpart F specifically provides that ACI must be installed and
operable by July 1, 2008 or July 1, 2009, depending on the EGU. PC 9 at 2. Further, by
January 1, 2015, EGUs in the CPS Group (other than Will County 3, which has a compliance
deadline of Jan. 1, 2016) must achieve mercury emissions standards of either: (a) 0.0080 lbs
31
mercury/GWh gross electrical output; or (b) a minimum 90% reduction of input mercury.
Id
. at
2-3.
The MOU mandates, first, that by 2012, all operable EGUs in the CPS Group must
achieve and maintain an overall average annual NO
x
emission rate of no more than 0.11
lbs/mmBtu. PC 9 at 3. Second, the MOU provides that by 2013, all operable EGUs in the CPS
Group must achieve an overall average SO
2
emissions rate of no more than 0.44 lbs/mmBtu, and
each subsequent year continue to reduce the overall average SO
2
emissions from all operable
EGUs to 0.11 lbs/mmBtu by 2019. Third, that the owner or operator of the CPS Group must
install and operate SNCR (or an equivalent technology) to reduce NO
x
emissions and flue gas
desulfurization (FGD) equipment to reduce SO
2
emissions at the EGUs specified in Section
225.625 of the proposed Subpart F, and according to the schedule established therein.
Id
. at 3.
The parties to the MOU anticipate that the new equipment required under Subpart F will
achieve reductions in SO
2
, NO
X
, and mercury beyond that required from existing regulations,
and will further reduce ambient levels of ozone and PM
2.5
.
Id
. According to the parties, these
reductions will improve air quality and result in significant benefits to public health and the
environment.
Id
.
The parties to the MOU agree that compliance with the proposed Subpart F is both
technically feasible and economically reasonable, and expect that the levels reductions required
in the proposed Subpart F will substantially contribute to the State’s efforts to achieve the CAA’s
NAAQS. The parties add that any further reductions needed beyond those proposed in Subpart F
would need to come from other sources. PC 9 at 4.
In the revised public comment, the Agency and Midwest Generation note that they were
not able to agree on specific deadlines and milestones related to shutting down or installing new
control equipment at certain facilities prior to the filing deadline for PC 9. PC 11 at 1. However,
since the January 5, 2007 filing deadline, the Agency and Midwest Generation have reached an
agreement on those issues. Accordingly, the Agency and Midwest Generation attached to PC 11
the revised language of the new Subpart F that includes the agreed upon milestones, options, and
deadlines applicable to the EGUs specifically referenced in the rule.
Id
.
BOARD DISCUSSION
The Board has held five days of hearings and received substantial testimony and
comments on this proposal. The comments and the additional language changes suggested by
both the Agency and the participants have been evaluated, and the first-notice proposal adopted
by the Board today reflects the Board’s consideration of all the comments and testimony the
Board has received. The Board will discuss below the issues raised by the participants at the
hearings and in the post-hearing comments along with the first-notice changes.
Section 27 of the Act requires that the Board must determine that a rule of general
applicability is economically reasonable and technically feasible before adopting the rule. The
majority of interested participating parties support the majority of the rule as amended during
this proceeding. However, a number of issues still remain.
32
The major contested issues are: (1) whether the size of the CASA is too large; (2)
whether over-fired air (OFA) projects should be excluded from receiving allowances from the
CASA 25% set aside; (3) whether a
pro rata
allocation of allowances from the CASA is
appropriate; (4) whether fluidized bed combustion (FBC) boilers should receive CASA
allowances in the clean coal technology category; (5) whether allocations should be based on
gross electrical output or heat input; (6) whether a two-year look-back provision updated on an
annual basis to determine an EGU’s allowances is appropriate; (7) whether the air quality
modeling submitted by the Agency in the TSD is appropriate and supportive of the emissions
standards in the proposal; (8) whether fuel-weighting as proposed is appropriate; and (9) whether
a new section titled Subpart F, Combined Pollutant Standards, should be included in the
proposal.
The Board will address each contested issue separately.
CASA
Size of the CASA
The CASA, and particularly the 30% set-aside, has been widely addressed during this
rulemaking proceeding. The Agency asserts that the USEPA left the authority to the individual
states to distribute their allocations as necessary to meet their own State’s individual goals. PC 5
at 7. The Agency contends that a financial analysis of the impact of the worst-case scenario that
the 30% set-aside (CASA plus NUSA) was effectively retired showed that relying solely on a
70% main pool, the reliability of the grid would be intact and residential and commercial electric
rates would not be greatly impacted.
Id
.
Kincaid provided testimony that the 30% set-aside is too great and that the proposal
penalizes facilities that have already installed the best available technology.
See
Kincaid Exh. 1
(Test. of Saladino) at 13. Kincaid argues that the Agency proposal to adopt “beyond CAIR” NO
x
reductions through a proposed set-aside program that far surpasses that of any surrounding states,
places Illinois electricity consumers at a severe economic disadvantage. PC 10 at 6. Kincaid
contends that there appears to be little chance that these allowances will ever be returned to the
EGUs since the proposal calls for any NO
x
allowances that remain unclaimed from the four
CASA allowance pools to be used to replenish each of the four CASA pools. PC 10 at 6.
Zion asserts that the Agency’s proposed 25% CASA is far out of line with the proposed
set-aside pools in many other CAIR states. PC 3 at 3. Zion believes that the CASA in the
proposed rule should be revised. Zion contends that a smaller proportion of the total allowance
budget should be made available for non-emitting sources. Zion suggests a CASA set-aside
percentage in the 5-10% range, rather than the proposed 25%, because setting aside such a large
portion of the allowance pool unjustifiably increases the compliance burden on facilities that
already face significant emission reduction obligations through an artificial reduction in
allowances available for allocations. PC 3 at 4. Second, Zion suggests that CASA applicants be
restricted to electric generating sources and that non-generating sources be eliminated from
consideration in the proposed rule.
Id.
33
Ameren believes that CASA represents a useful balancing of technology, economic,
energy and environmental considerations, and specifically requests the Board to adopt those
portions of the amended proposal that allow Ameren and other companies which seek to utilize
the Multi-Pollutant Strategy (MPS) to obtain CASA allowances. PC 4 at 3.
Dynegy and SIPCO contend that a set-aside of 25% for the CASA is not justifiable. PC 6
at 2. They argue that setting aside 25% of Illinois’ cap is the equivalent of providing no
allowances to approximately a 4,250 MW EGU, and that this is equivalent to not allocating
allowances to the entirety of Dynegy's system plus City Water Light & Power plus SIPCO - with
102 MW still not accounted for. PC 6 at 11.
Conversely, the ELPC provided testimony recommending that the RE/EE set-asides be
increased in order to be consistent with the policy goals and policy targets set forth in the
Governor Blagojevich’s Sustainable Energy Plan. Tr.2 at 138. The ELPC testified that
increasing the RE/EE set-aside from 12-15.4% would provide enough allowances to reach the
Governor’s Sustainable Energy Plan goal of having 10% of the electricity provided to Illinois
consumers come from renewable energy sources by 2015. PC 7 at 3.
The Board finds that the set-aside as proposed by the Agency is appropriate. Kincaid’s
assertion that it is penalized for previously installing technology is interesting but not persuasive.
The Agency has stated that its goal in drafting the set aside was to reasonably maximize the
impact for future emissions reductions, and not to reward entities that would already be utilizing
emission controls. The intention appears to have been to provide as large an incentive as
possible to attract new controls by subsidizing the large installation costs and not the already
existing, and smaller, operational costs. The Board agrees that providing incentives for controls
already installed would lessen the incentive for new controls.
Further, the record shows that a number of facilities are in a situation similar to Kincaid
regarding CASA allowances for already installed equipment. Fourteen units are controlled by
SCR/ SNCR, one unit controlled by baghouse, and five units controlled by FGD. Each of these
units is ineligible for CASA as proposed.
Kincaid acknowledged at hearing that the installation of the SCRs was a voluntary
decision made for business purposes.
See
Kincaid Exh. 1 (Test. of Saladino) at 7. Kincaid’s
installation of the SCRs was spurred at least in part by the incentives presented by the early
reduction credits available under Part 217.770 of the Subpart W rules. Thus CASA aside,
Kincaid has already received credit to assist in recovering installation costs for their SCRs.
Finally, the Board agrees with the Agency in that while entities that have previously installed
controls may not avail themselves to CASA allocations for those installations, such entities may
still earn allowances by participating in a different CASA category.
The Board finds that the ELPC’s position that the Agency increase the RE/EE set-asides
from 12-15.4% to be consistent with the policy of Governor Blagojevich’s Sustainable Energy
Plan is likewise without merit. The Governor’s Sustainable Energy Plan and the allocation
methodology proposed in the Illinois CAIR may both encourage renewable energy and energy
efficiency, but they are separate programs. The Agency has stated that it did not intend to set its
34
RE/EE allocations predicated on the policy goals of the Governor’s Sustainable Energy Plan.
Nonetheless, the Board notes that the possibility of under subscription in CASA categories other
than RE/EE may result in allocations eligible for approved RE/EE projects, thereby exceeding
the 12% initial design value.
Over-Fired Air
A question exists as to whether OFA projects should be excluded from receiving
allowances from the CASA. As proposed, Sections 225.460(c)(1) and 225.560(c) specifically
exclude OFA from the list of projects eligible for CASA clean technology allowances. The
Agency maintains that neither standard OFA nor advanced OFA should be an eligible project for
the CASA. The Agency argues that OFA is expected to be a common NO
x
control employed by
sources under the model CAIR trading program due to its low costs. PC 5 at 10. The Agency
contends that allowing OFA or advanced OFA to be considered for allowances from the CASA
could greatly reduce the available CASA allowances and, therefore, reduce the incentive for
sources to install the significantly more costly and typically more effective NO
x
controls such as
SNCR and SCR.
Id
. at 10-11.
Ameren requests that the Board allow the use of CASA allowances to support advanced
OFA NO
x
reduction strategies. PC 4 at 1. Ameren proposes that projects providing advanced
OFA to achieve at least a 30% reduction of the baseline NO
x
or OFA projects which are included
as part of a comprehensive NO
x
reduction strategy with other technologies listed in the section
allowed to receive CASA allowances. PC 4 at 3.
Dynegy and SIP argue that if the Board were to accept Ameren’s proposal without certain
qualifications, Ameren would again be rewarded merely for coming to par with the other
generators in the state. PC 6 at 16. Dynegy and SIP contend that unless the regulated
community as a whole would be given credit for OFA systems, regardless of the date of
installation, that achieve a specified level of NO
x
removal rather than by use of some type of
ambiguous "advanced" OFA scheme, they cannot support Ameren’s requested addition to the
CASA. PC 6 at 17.
In reviewing the record, the main reason cited by many companies for not installing
controls is the large capital costs, and to a lesser degree the generally smaller ongoing operating
and maintenance costs. The testimony shows that the costs of OFA and advanced OFA are
significantly less than the costs of other controls. The Agency’s primary stated purpose in
establishing the pollution control upgrade category of the CASA was to lower the capitol costs of
upgrading thereby promoting more expensive controls than OFA and advanced OFA. Further,
the Agency contends that the more costly controls generally result in the greatest reductions in
emissions. PC 5 at 10.
The Board agrees with the Agency in that no evidence exists that advanced OFA would
result in significantly higher costs than standard OFA. The Agency’s conclusion that it is likely
that many units would be installing OFA control technology even without CASA incentives is
soundly supported in the record.
See e.g.
, Prefiled Test. of Menne at 5. Further, any CASA
allowances allocated to OFA or advanced OFA could possibly offset more costly controls with
35
greater reductions in emissions and, therefore, increase the probability that such controls will not
be installed, whereas it does not appear that further incentive for the use of OFA and advanced
OFA is necessary.
Pro rata
Allocation of Allowances from the CASA
The Agency argues that
pro rata
allocation of CASA allowances (a proportionate sharing
among all eligible parties) is the best allocation method in that it provides equality for applicants
as well as ease of implementation for the Agency. The Agency specifically found that fixed
portion schemes would be difficult to implement because the CASA allocation scheme is based
on the number of electricity hours generated or conserved and will vary each year.
Christian County Generation provided testimony that would eliminate
pro rata
reduction
of CASA allocations for early adopters, primarily to reduce the uncertainty in allocations
introduced by a
pro rata
allotment. Christian County Exh. 1 (Test. of Kunkel), at 6. As an
alternate, Christian County Generation suggested a first-come first-serve basis. Tr.2 at 156.
The Board finds that a proportionate sharing of allowances among all eligible
applications is appropriate. The Board agrees with the Agency that a system using fixed portions
could lead to difficulties in execution since the CASA is based on the number of electricity hours
generated or conserved, which will vary on a yearly basis. A
pro rata
allocation system will
open up the CASA to all eligible facilities, and will also be workable from the Agency’s
perspective.
Fluidized Bed Combustion Boilers
In its in initial proposal, the Agency proposed that FBC boilers be allowed to receive
CASA allowances in the clean coal technology category. However, the Agency committed to
review its stance on this issue after the first hearing and now proposes that Illinois’ single
existing FBC boiler be allowed to receive CASA allowances, but that allowances to any future
FBC boilers will be denied. PC 5 at 11. The Board agrees with the Agency and adopts the
revisions proposed by the Agency to Sections 225.460 and 225.465 with some minor changes.
The ELPC argues that allowances should not be available as proposed for FBC boilers.
PC 7 at 2. The ELPC argues that FBC boilers should not receive CASA credits because: (1)
controlled FBCs are not lower in NO
x
emissions than controlled pulverized coal (PC) boilers; (2)
they do not achieve the low NO
x
emissions that IGCC plants do; and (3) they emit more
greenhouse gases than PC boilers. PC 7 at 4.
The ELPC argues that because new FBC boilers have not been required to install the
most effective NO
x
controls, PC boilers achieve lower NO
x
emissions levels and have lower NO
x
permit levels than FBC boilers. PC 7 at 6. PC boilers using the most modern NO
x
controls
achieve approximately 30% lower NO
x
emissions than FBCs, which are generally built without
the best-performing control technology.
Id
. Further, the ELPC argues that expected NO
x
emission levels for recently proposed IGCC plants result in more than 45% lower NO
x
emissions.
Id
. at 7.
36
Illinois currently has 59 coal-fired boilers that will be affected by the proposal. Only one
of these is an FBC boiler: the SIPCO FBC boiler in Marion. The other boilers are all pulverized
coal combustion (PCC) boilers and cyclone-fired boilers (which burn crushed coal). The SIPCO
FBC boiler was constructed in 2001 and began operation in 2003. PC 5 at 11.
The SIPCO FBC boiler is approximately 120 MW in size, fires predominantly Illinois
coal, and is a circulating FBC boiler with limestone injection and add-on controls consisting of
an SNCR and baghouse. From 2003 to 2005, the SIPCO FBC boiler had an average annual NO
x
emission rate of 0.10 lbs/mmbtu, which is lower than the system-wide NO
x
emission rates for
any of the other boilers in Illinois. It is believed that this NO
x
emission rate was achieved with
only part-time operation of the SNCR for NO
x
control. The NO
x
emission rate from SIPCO’s
FBC boiler has reached as low as 0.06 lbs/mmbtu during the 3rd quarter of 2005. For SO
2
, the
FBC boiler had an average annual NO
x
emission rate of 0.47 lbs/mmbtu, which likewise is lower
than the system-wide SO
2
emission rates for any of the other boilers in Illinois. These emission
rates could be lower should SIPCO decide to more fully utilize the NO
x
controls currently in
place or install additional controls for NO
x
and SO
2
on the FBC boiler.
Id.
at 12.
Regarding the existing SIPCO FBC boiler, the Board agrees with the Agency that it is
appropriate to recognize SIPCO’s prior initiative to invest in a cleaner technology and allow
SIPCO FBC to receive CASA allowances. The record indicates that the uncontrolled emission
rates of FBC boilers are lower than the emission rates of other boilers for both NO
x
and SO
2
.
Further, the SIPCO FBC boiler’s actual emissions between 2003 and 2005 averaged at 0.10
lbs/mmbtu for NO
x
and 0.47 lbs/mmbtu for SO
2
with part-time operation of SNCR for NO
x
control. As noted by the Agency, the FBC boiler emission rates could be lower should SIPCO
decide to more fully utilize the NO
x
controls currently in place or install additional controls for
NO
x
and SO
2
on the FBC boiler. Allowing the SIPCO FBC to receive CASA allowances
provides an incentive for SIPCO to further reduce NO
x
emissions because the number of CASA
allowances received is proportional to the amount of NO
x
emitted.
The Board also agrees with the Agency’s position to deny access to CASA allowances
for any new FBC boiler. At the time of construction, SIPCO’s FBC boiler was considered a
more current technology for utility boilers. PC 5 at 11. However, since the installation of
SIPCO’s FBC boiler, IGCC facilities have become commercially viable and the number of
applications for IGCC permits has increased nationwide. PC 5 at 13. The record is clear, and
the Agency acknowledges, that FBC boilers result in higher NO
x
emissions than IGCC plants.
Since IGCC have become commercially viable, the Board finds that CASA allowances for clean
coal technology must be available only for the most promising commercially available
technology,
i.e
., IGCC. The Board also finds persuasive the ELPC’s argument that it is
inappropriate to allow “other” technologies that achieve emission rates comparable to FBC
boilers to receive CASA allowance.
See
PC 7 at 6. To further the Agency’s intent and
implement the ELPC’s suggestion, the Board amends Section 225.460(e) to exclude FBC boilers
from the list of comparable technologies. The Board, therefore, amends Section 225.460(e) to
limit the comparison only to projects similar in effect as the projects listed in Section 225.460(a),
(b), (c)(1) and (c)(2)(A).
37
In light of the Agency’s amended proposal and the changes discussed above, the Board
does not need to consider the impact of FBC boilers on greenhouse gases (GHG). The Board
notes, however, that the matter is multifaceted and factors such as fuel choice may have as great
an impact on GHG as boiler type.
The Agency has revised the allocation method in the proposed in Sections
225.465(b)(5)(B) and 225.565(b)(5)(B) relating to allocating CASA allowances to clean coal
technology projects to account for the fact that SIPCO directly measures its emission rate in
pound per megawatt (lb/MW) rather than converting from pound per million Btu (lb/mmBtu).
PC 5 at . The Agency asserts that the proposed revision will not result in a significant change for
the CASA allowance distribution.
Id
. The proposed revision will include new subsections in
Sections 225.465(b)(5)(B) and 225.565(b)(5)(B). Subsection (b)(5)(B) will include an equation
similar in all respects to the prior method with the exception of a factor change from 1.0 to 1.4.
The factor change will compensate for SIPCO’s direct measurements and provide the same level
of incentive that the Agency was previously attempting to achieve.
Id
.
The Board agrees that the SIPCO FBC boiler represents a special circumstance as
compared to the other boilers in the state. The solution proposed by the Agency has merit in that
it recognizes the difference between the SIPCO FBC boiler and existing boilers, while also
recognizing that clean coal technology has improved since the SIPCO FBC boiler was
constructed. The Agency’s new proposal along with the changes made by the Board should also
alleviate the concerns raised by the ELPC in that future FBC boilers will not have access to
CASA clean coal technology allowances.
By focusing on the most promising technology (IGCC), the Agency’s proposal
accomplishes CASA intentions while not penalizing SIPCO for its recent installation of, what
until recently, was the best commercially viable technology. As is evidenced by the increasing
number of IGCC applications for permits nationwide, it is that only recently have IGCC facilities
been recognized and accepted as commercially viable. Thus, the Board finds that the Agency’s
amended proposal that Illinois’ existing FBC boiler be allowed to receive CASA allowances, but
that allowances to any future FBC boilers will be denied is appropriate.
Two-Year Look-Back
The Agency’s proposed rule for allowance trading includes a two-year look-back period,
updated on an annual basis, to determine an EGU’s allowances. Dynegy and SIPCO are very
deeply troubled by the Agency's approach to annual allowance allocations. The proposed rule
includes a two-year look-back period to determine an EGU’s allowances, to be updated annually.
The companies' concern with the two-year look-back is that the look-back period will, from time
to time, encompass periods when the EGUs experience outages of various lengths of time. PC 6
at 28. Dynegy and SIPCO are concerned that where the look-back is so short with no
“levelizing” allowed through the averaging of a number of years’ operations chosen from a
larger number of years, such as the highest three years’ operation out of a specified five-year
period. PC 6 at 28-29. The companies argue that in light of the Agency’s past failure to timely
allocate allowances, it becomes critical that the updating occur annually and timely. PC 6 at 29.
38
Dynegy and SIPCO argue that the USEPA suggested a permanent baseline for sources in
the model rule with new sources rolling into the existing source permanent baseline once they
have five years’ operating data, causing an adjustment of all existing sources’ allocations. PC 6
at 29, citing 70 Fed. Reg. 25161, 25279 (May 12, 2005). Dynegy and SIPCO argue that a
permanent baseline comprised of the three highest years' operational heat input or converted heat
input over a five-year period would provide the level of certainty of the allowance stream. PC 6
at 32.
Midwest Generation is also concerned about the impact of outages on what it opines is a
short, two-year, look-back period. PC 8 at 1. Midwest Generation asserts that under the current
language of the rule, these situations cannot be avoided.
Id.
Further, Midwest Generation notes
that the USEPA has provided in its NO
x
trading rules that when a State fails to timely allocate
allowances, USEPA will rely upon the previous allocation to cover the unallocated period. PC 8
at 3. Thus, argues Midwest Generation, if a timely allocation is not made for the two NO
x
programs proposed by these rules, some EGUs may be frozen at an allowance level that reflects
extensive outages.
Id.
Midwest supports revising the rule to reflect a three-year averaging
concept and five-year look-back period.
While the Board is cognizant of the issues concerning a two-year look-back, the benefits
of relative short look-back period outweigh any potential difficulties. The Agency asserts that a
two-year look-back period is provides an incentive for efficient operations, which will result in
fewer emissions per unit of power produced. Stat. at 35. The Board agrees with this general
principle.
In addition, the concerns raised by Midwest Generation, SIPCO and Dynegy were also
raised to the Agency prior to the proposal being filed with the Board. In response, the Agency
changed the initial look-back period for the 2009, 2010, and 2011 control periods from using
data only from 2004 and 2005, to allowing the use of data from the three highest control periods
of 2001 through 2005. Stat. at 48. The Agency reasoned that because companies did not have
an opportunity to plan for the first allocation when scheduling outages, such a change was
appropriate, and that with respect to future allocations, the allocations will balance out.
Id
.
Again, the Board finds the Agency’s logic persuasive. Also, the changes incorporated
into the proposal to allow the use of data from the three highest periods should alleviate the
concerns raised as noted above. Because allocations are made annually and with a shorter look-
back period, if a company has a planned outage in one control period, it will need and will
receive fewer allowances for that control period, and since the company should have received
allowances for that future outage year based on a higher rate of operation, it should have excess
banked allowances from the outage year that it can use for the allocation year that reflects the
prior outage. Thus, the short look-back period allows low and high usage years to be quickly
accounted for, and the Board will adopt the rule as proposed in this regard.
Heat Input vs. Gross Electrical Output
The Agency is proposing that allocations be based on gross electrical output for both new
and existing affected units. For sources that do not currently have the equipment installed to
39
measure gross electrical output, the initial allocations for control periods 2009 through 2011 will
be based on heat input. A conversion factor of 3.413 mmBtu/MWh and an efficiency factor of
33% will be used to convert the heat input of a unit to gross electrical output. Stat. at 35; TSD at
101.
Midwest requests that the Board consider heat input as the basis for allocations, which is
what Midwest has reported and certified for years. PC 8 at 5. Midwest argues that heat input
data is more reliable than output data as the manner of output data’s measurement and its quality
assurance is not uniform.
Id.
The joint comment filed by Dynegy and SIPCO asserts that the two companies generally
prefer that allocations be based upon heat input rather than gross electrical output as proposed by
the Agency. PC 6 at 2. However, that same public comment provides that Dynegy prefers
reliance on gross electrical output as the basis for allocations, but would find heat input as a basis
for allocations acceptable. PC 6 at 24. Nonetheless, Dynegy and SIPCO assert that the
efficiency assumed in the Agency’s formula at Section 225.435(a)(2) to convert heat input to
gross electrical output is not representative of actual efficiencies at the plants.
Id
.
Further, Dynegy and SIPCO assert that it is their understanding is that the Agency will
accept as gross electrical output data any data that is acceptable to USEPA pursuant to 40 C.F.R.
§ 60 or 75. PC 6 at 27. Dynegy and SIPCO are concerned about language currently in the rule
suggesting that there must be an actual measurement device installed on the generator,
effectively a wattmeter, when such is not required by USEPA pursuant to 40 C.F.R. § 60 or 75.
Dynegy and SIPCO ask the Board to ensure that the language included in the rule reflects the
parties’ intent.
Id
.
Christian County Generation provided testimony that its integrated gasification combined
cycle (IGCC) project would be greatly disadvantaged by an allocation methodology that relies
upon heat input. Tr.2 at 126-29.
The Board finds that the Agency’s proposal to use gross electrical output as a basis for
distributing allowances is reasonable. The Agency’s proposal allows owners and operators that
do not have gross electrical output data for the initial look-back period to use heat input data for
the allocations during the first three control periods. Additional flexibility was provided for in
the amendment to the proposal filed on November 27, 2006. As amended, the proposal clarifies
that either gross electrical output or heat input may be used to calculate converted gross output
for the control periods 2009 through 2013. The proposal also allows for other measurement
systems for gross electrical output provided that such a system is in place by January 1, 2008,
and that data for the initial allocations for control periods 2009-2011 be submitted to the Agency
by June 1, 2007.
The Board is aware that the June 1, 2007 date for submission of initial allocations is
rapidly approaching. The Board encourages any interested party to comment on this fact during
the first-notice period. The Board finds in this opinion and order that gross electrical output does
encourage efficiency, and that its application in this instance, as amended, is technical feasible
and economically reasonable.
40
Air Quality Modeling
Kincaid urges the Agency to conduct a thorough modeling demonstration to determine
the level of reductions that may be necessary to resolve any residual non-attainment problems
following implementation of the CAIR reductions. PC 10 at 3; Kincaid Exh. 1 (Test. of
Saladino) at 4-5. Kincaid asserts that recent air quality modeling by LADCO suggests additional
reductions from the EGU sector beyond the reductions expected from the federal CAIR program
will not solve the residual ozone and PM
2.5
non-attainment problem in the Chicago area. PC 10
at 4.
The Agency asserts that it presented the results of two modeling studies that address the
issues raised by Kincaid in the TSD, and has, therefore, already presented the type of modeling
suggested. PC 5 at 19.
In reviewing the record, the Board notes that in March 2005, the USEPA presented a
document entitled: “Technical Support Document for the Final Clean Air Interstate Rule – Air
Quality Modeling.” TSD at 35. The Agency summarized the USEPA’s modeling results in the
TSD showing that NO
x
and SO
2
reductions from power plants are effective in reducing ozone
and PM
2.5
concentrations in downwind nonattainment areas, but that CAIR would not provide
sufficient emission reductions, even in Phase II, to allow the Chicago nonattainment area to
attain either the ozone or PM
2.5
standards.
Id
.
The TSD also presented the results of modeling performed by LADCO.
See
Table 3-5 of
the TSD. The LADCO modeling indicates that in order to reach the emission reduction targets
needed for both ozone and PM
2.5
attainment, local VOC reductions of approximately 75% are
needed for Chicago to attain the ozone standard, assuming that no additional reductions are
achieved regionally beyond those provided by CAIR.
The Agency asserts that when regional reductions of NO
x
and SO
2
are made, the
modeling indicates that there is less emission reduction burden in the nonattainment area. The
USEPA’s modeling, therefore, clearly shows that Illinois must seek additional emission
reductions, either locally or regionally, to achieve attainment of the air quality standards. PC 5 at
19.
The Board finds that modeling submitted by the Agency in the TSD is appropriate and
supportive of the emissions standards in the proposal. The record indicates, notes the Board, that
lowering emissions of NO
x
and SO
2
from power plants is effective in reducing ozone and PM
2.5
concentrations in downwind nonattainment areas. Therefore, the Board finds that the record
supports adopting the proposal, and that no additional modeling is needed at this time.
Fuel-Weighting
The various participants are split on this issue, but the Agency maintains that fuel-
weighting as proposed is appropriate. Zion prefers a fuel-neutral allocation mechanism, but is
willing to consider a compromise alternative fuel-weighting factor that closes the gap between
41
the fuel-neutral option and the Agency’s current proposal, and suggests a compromise factor of
0.7 for both gas-fired and oil-fired units. PC 3 at 2.
The ELPC urges the elimination or modification of the fuel-weighting component of the
proposed Illinois rule, arguing that a fuel-neutral approach will achieve the deeper, faster
reductions the Agency seeks. PC 7 at 10.
Dynegy and SIPCO support the Agency’s proposal regarding weights assigned to fuel
types, noting that the USEPA retained the fuel factors. Dynegy and SIPCO encourage the Board
to retain them as proposed by the Agency. PC 6 at 27-28.
The fuel-weighting factors in the proposal are identical to the federal CAIR model rule
and reflect different burdens to control emissions. As testified to at hearing, coal-fired units bear
the greatest burden to achieve emission reductions under CAIR. Tr.1 at 127-29. This is also the
reason stated by the USEPA for not employing a fuel-neutral allocation methodology in the
CAIR model rule.
The Board agrees with the Agency that the predominant sources of both NO
x
and SO
2
emissions in Illinois are from coal-fired power plants, and that these sources likewise have
higher emission rates for both pollutants. Reductions at these sources, therefore, will provide the
greatest benefits. The more feasible controlling these emissions is under the proposed rule, the
more likely they are to be controlled. Accordingly, the Board the Board does not modify the
Agency’s approach to fuel-weighting as proposed.
Proposed Supbart F
As noted above, the Agency and Midwest Generation have proposed a new Subpart F be
added to the proposal as a result of a December 10, 2006 MOU between the parties. The new
subpart establishes an alternative means of compliance with the proposed emissions standards for
mercury in Subpart B, Section 225.230(a) and will establish specific emissions levels for NO
x
,
PM, and SO
2.
The proposed Subpart was included in joint public comments, PC 9 and PC 11, filed
before the Board on January 5 and 10, 2007. Because it was filed at the close of the public
comment period, interested parties other than the Agency and Midwest Generation have not had
the opportunity to comment on the proposed Subpart. The Board agrees that the proposal for
compliance set forth in Subpart F will achieve greater reductions in SO
2
, NO
x
, and mercury than
the proposed CAIR standards. The Board also finds the proposed Subpart F will further reduce
ambient levels of ozone and PM
2.5
, leading to benefits to public health and the environment. The
parties to the MOU assert that the proposed Subpart F is both technically feasible and
economically reasonable, and that the level of mercury, NO
x
, and SO
2
reductions required in the
proposed Subpart F is expected to substantially contribute to the State’s efforts to achieve the
CAA’s NAAQS. PC 9 at 4.
The Board finds that Subpart F is technically feasible and economically reasonable, and
includes the proposed Subpart in the proposal the Board adopts today. Nonetheless, the Board
invites comments on the Subpart during the post first-notice public-comment period.
42
Technical Feasibility and Economic Reasonableness
The Agency has demonstrated that technology is available to meet CAIR requirements.
The Board will first discuss the CAIR SO
2
and NO
x
issues before reaching a decision on
technical feasibility and economic reasonableness.
CAIR SO
2
Trading Program
In the federal CAIR and supporting documents, the USEPA has determined that the
control techniques required for EGUs to comply with the CAIR SO
2
trading program are highly
cost-effective, and are, thus, technically feasible and economically reasonable. Stat. at 40, citing
Exh. A, 70 Fed. Reg. 25165 (May 12, 2005).
Control techniques for reducing SO
2
emissions from new or existing fossil fuel-fired
EGUs include physical coal cleaning to remove pyrites (inorganic sulfur compounds); chemical
coal cleaning to remove pyrites and organic sulfur present in coal; switching to either natural gas
or to low sulfur western coal; blending coal and limestone before combustion; dry scrubbing
with limestone or lime slurry (also called spray dryer absorber); and FGD. Stat. at 41; TSD 5.1.
The record shows that coal cleaning can result in SO
2
emission reductions ranging from
10-40% for physical coal cleaning and can result in SO
2
emission reductions ranging from 50-
75% for chemical coal cleaning, while emissions reductions achieved through fuel substitution
depend on the type of fuel, ranging from 50-80% from switching to low-sulfur coal to 98-100%
from switching to natural gas. TSD 5.1. Emission reductions from dry SO
2
removal range from
60-85% for combustion of a limestone mixture to 90-98% when spray drying is used in
conjunction. Other than fuel switching to natural gas, the greatest emission reductions of SO
2
are achieved through the use of a FGD, ranging from 90-98% reduction, regardless of the type
used.
Id
.
The Agency contends that costs of coal cleaning processes vary from $10.10 (at 35-70%
pyretic sulfur removal) to $58.67 per ton of coal (at 99% pyretic sulfur and 24-72% organic
sulfur removal). Stat. at 42. Cost data for FGD systems, expressed as electrical output, range
from $7.89 to $14.36 mill/kWh for a lime FGD to $9.72 to $63.82 mill/kWh for magnesium
oxide FGDs. TSD 6.1.
The record shows that in Illinois, electric utility units are currently using coal washing,
blending low-sulfur western coal with higher sulfur eastern coal, and FGDs. Blending coal with
limestone is not currently used in Illinois, but companies have submitted applications to the
Agency to use the process at two boilers. TSD 5.1.
The Agency contends that cost effectiveness of SO
2
controls for Illinois’ EGUs will be
$500 to $800 (in 1999 dollars) per ton of SO
2
reduced in the years 2010 through 2014, and $700
to $1200 (in 1999 dollars) per ton of SO
2
reduced in the year 2015 and the years thereafter. Stat.
at 42, TSD Table 6-6. The Agency asserts that it relied upon the cost analyses performed by
USEPA and believes that the cost effectiveness of controls for Illinois EGUs will be similar.
43
Stat. at 42.
NO
x
NO
x
emissions from EGUs are regulated in Illinois under the federal Acid Rain Program
(Title IV of the CAA), the NO
x
SIP Call trading program as set forth in Subpart W of 35 Ill.
Adm. Code Part 217, and a state rate-based rule set forth in Subpart V of 35 Ill. Adm. Code Part
217. Under Phase I of the federal Acid Rain program, NO
x
emissions for affected units
lb/mmBtu are limited to 0.45 lb/mmBtu and 0.50 lb/mmBtu for certain existing tangential and
wall-fired boilers burning coal, respectively. Under Phase II, NO
x
emissions are limited to 0.40
and 0.46 for these boilers. The limit for cyclone-fired boilers greater than 155 MW is 0.86
lb/mmBtu.
See
Stat. at 42. However, in Illinois, any unit serving a generator that has a
nameplate capacity greater than 25 MWe and produces electricity for sale was required to meet a
NO
x
emissions limit during the ozone season of 0.25 lb/mmBtu, beginning with the 2003 control
period.
See
35 Ill. Adm. Code 217, Subpart V.
In 2000, Illinois adopted the federal NO
x
SIP Call trading program. An initial NO
x
emission budget for EGUs was established based on an emission rate of 0.15 lb/mmBtu. The
program commenced with the 2004 ozone season. Sources complied with this rule through
either installation of add-on controls, or trading of NO
x
allowances. Stat. at 43
The allowance allocation budget for the CAIR NO
x
Annual and Ozone Season programs
in 2009 is based on a NO
x
emission rate of 0.15 lb/mmBtu and for 2015, 0.125 lb/mmBtu. The
Agency anticipates that sources that installed SNCR with ammonia or urea injection or SCR with
ammonia to comply with the requirements of Subpart W (Federal NO
x
SIP Call trading program)
will be able to meet the requirements of the CAIR NO
x
Annual trading program by operating the
add-on controls year round. Stat. at 43. The Agency asserts that compliance with the CAIR NO
x
Ozone Season trading program during Phase I will not require additional control measures since
the NO
x
allocation budget for the years 2009 through 2014 is the same in Illinois, 30,701 tons for
allocation.
Id
.
However, the Agency states that for the annual program, sources that have not yet
installed add-on controls are anticipated to either need to install add-on control or purchase
additional allowances. Stat. at 43-44.
The control technologies available to reduce NO
x
emissions from EGUs have been
discussed at hearing, in public comments, and by the USEPA. A listing of the technologies can
be found in table 5-2 of the Agency’s TSD. These technologies include combustion tuning (CT),
burner-out-of-service (BOOS), OFA, Low NO
x
Burners (LNB), Fuel Switching (low nitrogen
coal or natural gas), lean flue gas reburn, SNCR, and SCR. The record indicates that operational
modifications such as BOOS, OFA, and LNB can achieve NO
x
reductions in a range of 10-25%
for coal-fired boilers and 30-50% for gas and oil-fired boilers, reburning can achieve NO
x
reductions in a range of 50-60% for coal-fired boilers and gas and oil-fired boilers, fuel
switching from coal to natural gas or low-nitrogen coal can achieve NO
x
reductions in a range of
40-75% for all types of boilers, while SNCR can achieve NO
x
emission reductions in a range of
30-60% for all types of boilers, and SCR can achieve NO
x
reductions in a range of 75-90% for
44
all types of boilers.
See
TSD Table 5-2.
Tables 6-3, 6-4, and 6-5 of the TSD summarize the range of cost effectiveness of the
various control options for each type and size of EGU. TSD Tables 6-3, 6-4, and 6-5.
According to the Agency, for the control periods 2009 through 2014, there will be no additional
cost associated with complying with the CAIR NO
x
Ozone Season trading program because the
Illinois’ CAIR NO
x
Ozone Season budget remains the same as the current NO
x
SIP Call budget.
Stat. at 44. This estimate assumes the cost effectiveness values for Illinois EGUs are the same as
that calculated by USEPA for the entire region impacted by CAIR.
Id
. For the CAIR NO
x
Annual trading program, there will be an additional cost of $500 per ton to operate these controls
in the non-ozone season in 2009 through 2014 (October 1 through March 31), and the cost
effectiveness of annual and seasonal NO
x
controls for Illinois EGUs will be $1,600 per ton of
NO
x
reduced in 2015 and thereafter. TSD 6.3.
The Agency used an integrated planning model (IPM) to evaluate the economic impact of
the CASA and NUSA provisions included in this proposal. According to the Agency, the IPM
modeling shows that the reduction of allowances only minimally increases the costs discussed
above. Stat. at 44. The Agency stresses that while the CASA is 25% of the allowances, existing
units are eligible to apply for these allowances for free if they install air pollution controls, build
clean units, or implement other energy conserving or renewable energy projects.
Id
. The
Agency contends that IPM modeling represents the worst-case scenario because it did not
address the potential use of any CASA allowances for the existing EGUs. The Agency notes,
however, that future projects will more likely be eligible for CASA use and thus further reduce
cost. Stat. at 45.
Discussion
After carefully reviewing the entirety of the record, the Board finds that the proposal as
amended is technically feasible and economically reasonable. In making this determination, the
Board considers the USEPA findings on CAIR NO
x
and SO
2
control technology costs and
applications, and NO
x
and SO
2
removal effectiveness. The Board is also persuaded by the IPM
modeling provided by the Agency. In addition to the IPM modeling discussed above, the
Agency conducted modeling to determine the cost impact of the 25% CASA and 5% NUSA on
Illinois electricity rates. That modeling projects that retail electricity rates will not change, and
there was a slight change in average production costs. TSD Table 7.6.
While retail electricity prices for the CAIR region are projected to increase minimally
with the implementation of CAIR, the Board agrees with the Agency that trading will provide
EGUs a cost-effective way to comply with CAIR that will minimize the costs passed on to
consumers. The Agency estimates that regional retail electricity prices will be 2-3% higher with
CAIR. In Illinois, the Agency predicts the retail electricity prices will increase 2.6% in 2010 and
4.3% in 2015 as a result of implementing CAIR. However, by 2020, the Agency expects rates to
decrease 2.6%, leaving a net increase of 1.7%. TSD 6.4.
The Board notes that the SO
2
trading program the Agency proposes is substantially
identical to the measurement requirements for the federal CAIR Rule developed by the USEPA.
45
Further, the issues concerning NO
x
are issues that relate to the underlying federal requirements.
The Board, therefore, finds the USEPA’s decision to adopt the requirements persuasive.
In addition, the Board notes that the interested parties in this rule making in large part do
not argue that the proposal is not technically feasible or economically reasonable. Kincaid
argues that no evidence exists in the record of either regulatory proceeding that it is technically
feasible and economically reasonable for the affected facilities to comply simultaneously with
both CAIR and CAMR regulations, and that it has provided information in both regulatory
proceedings that the economic impact of the individual and combined regulations is
unreasonable. PC 10 at 20. The Board disagrees. The Board has considered whether each
rulemaking is technically feasible and economically reasonable, and has decided affirmatively in
both rules.
The Board has made additional changes to the rule, including those necessary to comport
with the requirements of the APA. The Board will not summarize or delineate the entirety of the
rule or the changes made by the Board. The Board’s order reflects these changes.
Additional Amendments
The Board notes that a number of proposed amendments were made during the public
comment period and in other pleadings. Above the Board granted motions to amend filed by the
Agency, the Agency and Dynegy, jointly, and the Agency and Midwest Generation, jointly. The
Board incorporates the amendments proposed in those motions, as specified above, into the
proposal.
In addition, the Board amends the proposed language in Subpart F, Section
225.625(a)(1), (2), (3) and (c)(2) from “on before” to “on or before” the dates provided by which
the EGU must meet control technology requirements. The Board asks the Agency to comment if
these amendments in any way change the intent of the proposed rule language.
CONCLUSION
The Board finds that the proposal is technically feasible and economically reasonable.
The Board adopts the Agency’s proposal, as amended, for first-notice publication in the
Illinois
Register
. After first-notice publication, the Board will accept additional comments on the
proposal.
ORDER
The Board directs the Clerk to cause the filing of the following rule with the Joint
Committee on Administrative Rules for its first-notice review.
TITLE 35: ENVIRONMENTAL PROTECTION
SUBTITLE B: AIR POLLUTION
CHAPTER I: POLLUTION CONTROL BOARD
SUBCHAPTER c: EMISSION STANDARDS AND LIMITATIONS FOR STATIONARY
SOURCES
PART 225
CONTROL OF EMISSIONS FROM LARGE COMBUSTION SOURCES
SUBPART A: GENERAL PROVISIONS
Section
225.100
Severability
225.120
Abbreviations and Acronyms
225.130
Definitions
225.140
Incorporations by Reference
225.150
Commence Commercial Operation
SUBPART B: CONTROL OF MERCURY EMISSIONS FROM COAL-FIRED ELECTRIC
GENERATING UNITS
Section
225.200
Purpose
225.202
Measurement Methods
225.205
Applicability
225.210
Compliance Requirements
225.220
Clean Air Act Permit Program (CAAPP) Permit Requirements
225.230
Emission Standards for EGUs at Existing Sources
225.232
Averaging Demonstrations for Existing Sources
225.233
Multi-Pollutant Standard (MPS)
225.234
Temporary Technology-Based Standard for EGUs at Existing Sources
225.235
Units Scheduled for Permanent Shut Down
225.237
Emission Standards for New Sources with EGUs
225.238
Temporary Technology-Based Standard for New Sources with EGUs
225.240
General Monitoring and Reporting Requirements
225.250
Initial Certification and Recertification Procedures for Emissions Monitoring
225.260
Out of Control Periods for Emission Monitors
225.261
Additional Requirements to Provide Heat Input Data
225.263
Monitoring of Gross Electrical Output
225.265
Coal Analysis for Input Mercury Levels
225.270
Notifications
225.290
Recordkeeping and Reporting
225.295
Treatment of Mercury Allowances
47
SUBPART C: CLEAN AIR ACT INTERSTATE RULE (CAIR) SO
2
TRADING PROGRAM
Section
225.300
Purpose
225.305
Applicability
225.310
Compliance Requirements
225.315
Appeal Procedures
225.320
Permit Requirements
225.325
Trading Program
SUBPART D: CAIR NO
x
ANNUAL TRADING PROGRAM
Section
225.400
Purpose
225.405
Applicability
225.410
Compliance Requirements
225.415
Appeal Procedures
225.420
Permit Requirements
225.425
Annual Trading Budget
225.430
Timing for Annual Allocations
225.435
Methodology for Calculating Annual Allocations
225.440
Annual Allocations
225.445
New Unit Set-Aside (NUSA)
225.450
Monitoring, Recordkeeping and Reporting Requirements for Gross Electrical
Output and Useful Thermal Energy
225.455
Clean Air Set-Aside (CASA)
225.460
Energy Efficiency and Conservation, Renewable Energy, and Clean Technology
Projects
225.465
Clean Air Set-Aside (CASA) Allowances
225.470
Clean Air Set-Aside (CASA) Applications and Recordkeeping
225.475
Agency Action on Clean Air Set-Aside (CASA) Applications
225.480
Compliance Supplement Pool
SUBPART E: CAIR NO
x
OZONE SEASON TRADING PROGRAM
Section
225.500
Purpose
225.505
Applicability
225.510
Compliance Requirements
225.515
Appeal Procedures
225.520
Permit Requirements
225.525
Ozone Season Trading Budget
225.530
Timing for Ozone Season Allocations
225.535
Methodology for Calculating Ozone Season Allocations
225.540
Ozone Season Allocations
225.545
New Unit Set-Aside (NUSA)
48
225.550
Monitoring, Recordkeeping and Reporting for Gross Electrical Output and Useful
Thermal Energy
225.555
Clean Air Set-Aside (CASA)
225.560
Energy Efficiency, Renewable Energy, and Clean Technology Projects
225.565
Clean Air Set-Aside (CASA) Allowances
225.570
Clean Air Set-Aside (CASA) Applications and Recordkeeping
225.575
Agency Action on Clean Air Set-Aside (CASA) Applications
SUBPART F: COMBINED POLLUTANT STANDARDS
225.600
Purpose
225.605
Applicability
225.610
Notice of Intent
225.615
Control Technology Requirements and Emissions Standards for Mercury
225.620
Emissions Standards for NO
x
and SO
2
225.625
Control Technology Requirements for NO
x
, SO
2
, and PM Emissions
225.630
Permanent Shut-Downs
225.635
Requirements for CAIR SO
2
, CAIR NO
x
, and CAIR NO
x
Ozone Season
Allowances
225.640
Clean Air Act Requirements
225.Appendix A
Specified EGUs for Purposes of Subpart F (Midwest Generation’s Coal-
Fired Boilers as of July 1, 2006)
AUTHORITY: Implementing and authorized by Section 27 of the Environmental Protection Act
[415 ILCS 5/27].
SOURCE: Adopted in R06-25 at 31 Ill. Reg. 129, effective December 21, 2006; amended in
R06-26 at 31 Ill. Reg. ___________, effective _________________.
SUBPART A: GENERAL PROVISIONS
Section 225.130
Definitions
The following definitions apply for the purposes of this Part. Unless otherwise defined in this
Section or a different meaning for a term is clear from its context, the terms used in this Part
have the meanings specified in 35 Ill. Adm. Code 211.
“Agency” means the Illinois Environmental Protection Agency.
[415 ILCS 5/3.105]
“Averaging demonstration” means, with regard to Subpart B of this Part, a demonstration
of compliance that is based on the combined performance of EGUs at two or more
sources.
49
“Base Emission Rate” means, for a group of EGUs subject to emission standards for NOx
and SO
2
pursuant to Section 225.233, the average emission rate of NOx or SO
2
from the
EGUs, in pounds per million Btu heat input, for calendar years 2003 through 2005 (or,
for seasonal NO
x
, the 2003 through 2005 ozone seasons), as determined from the data
collected and quality assured by the USEPA, pursuant to the 40 CFR 72 and 96 federal
Acid Rain and NO
x
Budget Trading Programs, for the emissions and heat input of that
group of EGUs.
“Board” means the Illinois Pollution Control Board.
[415 ILCS 5/3.130]
“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
electricity production.
“CAIR authorized account representative” means, for the purpose of general accounts, a
responsible natural person who is authorized, in accordance with 40 CFR 96 subparts BB,
FF, BBB, FFF, BBBB, and FFFF to transfer and otherwise dispose of CAIR NO
x
, SO
2
,
and NO
x
Ozone Season allowances, as applicable, held in the CAIR NO
x
, SO
2
, and NO
x
Ozone Season general account, and for the purpose of a CAIR NO
x
compliance account,
a CAIR SO
2
Allowance System Tracking account, or a CAIR NO
x
Ozone Season
compliance account, the CAIR designated representative of the source.
“CAIR designated representative” means for a CAIR NO
x
source, a CAIR SO
2
source,
and a CAIR NO
x
Ozone Season source and each CAIR NO
x
unit, CAIR SO
2
unit and
CAIR NO
x
Ozone Season unit at the source, the natural person who is authorized by the
owners and operators of the source and all such units at the source, in accordance with 40
CFR 96 subparts BB, FF, BBB, FFF, BBBB, and FFFF as applicable, to represent and
legally bind each owner and operator in matters pertaining to the CAIR NO
x
Annual
Trading Program, CAIR SO
2
Trading Program, and the CAIR NO
x
Ozone Season
Trading Program, as applicable. For any unit that is subject to one or more of the
following programs: CAIR NO
x
Annual Trading Program, the CAIR SO
2
Trading
Program, the CAIR NO
x
Ozone Season Trading Program, or the federal Acid Rain
Program, the designated representative for the unit must be the same natural person for
all programs applicable to the unit.
“CAIR Trading Programs” means the requirements of this Part, and those provisions of
the federal CAIR NO
x
Annual Season, CAIR SO
2
, or CAIR NO
x
Ozone Season Trading
Programs set forth in 40 CFR 96, as incorporated by reference in Section 225.140.
“Coal” means any solid fuel classified as anthracite, bituminous, subbituminous, or
lignite by the American Society for Testing and Materials (ASTM) Standard
50
Specification for Classification of Coals by Rank D388-77, 90, 91, 95, 98a, or 99
(Reapproved 2004).
“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:
For purposes of Subparts B, D, and E combusting any amount of coal or coal-
derived fuel, alone or in combination with any amount of any other fuel, during a
specified year;
For purposes of Subpart C, combusting any amount of coal or coal-derived fuel,
alone or in combination with any amount of any other fuel.
“Cogeneration unit” means, for the purposes of Subparts C, D, and E, a stationary, fossil
fuel-fired boiler or a stationary, fossil fuel-fired combustion turbine of which both of the
following conditions are true:
It uses equipment to produce electricity and useful thermal energy for industrial,
commercial, heating, or cooling purposes through the sequential use of energy;
and
It produces either of the following during the 12-month period beginning on the
date the unit first produces electricity and during any subsequent calendar year
after that in which the unit first produces electricity:
For a topping-cycle cogeneration unit, both of the following:
Useful thermal energy not less than five percent of total energy
output; and
Useful power that, when added to one-half of useful thermal
energy produced, is not less than 42.5 percent of total energy input,
if useful thermal energy produced is 15 percent or more of total
energy output, or not less than 45 percent of total energy input if
useful thermal energy produced is less than 15 percent of total
energy output; or
For a bottoming-cycle cogeneration unit, useful power not less than 45
percent of total energy input.
“Combined cycle system” means a system comprised of one or more combustion
turbines, heat recovery steam generators, and steam turbines configured to improve
overall efficiency of electricity generation or steam production.
“Combustion turbine” means:
51
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; and
If the enclosed device pursuant to under the above paragraph of this definition is
combined cycle, any associated duct burner, heat recovery steam generator and
steam turbine.
“Commence commercial operation” means, for the purposes of Subpart B of this Part,
with regard to an EGU 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.
Such date must remain the unit's date of commencement of operation even if the EGU is
subsequently modified, reconstructed or repowered.
For the purposes of Subparts C, D
and E, “commence commercial operation is as defined in Section 225.150.
“Commence construction” means, for the purposes of Section 225.460(f), 225.470,
225.560(f), and 225.570, that the owner or owner’s designee has obtained all necessary
preconstruction approvals (e.g., zoning) or permits and either has:
Begun, or caused to begin, a continuous program of actual on-site construction of
the source, to be completed within a reasonable time; or
Entered into binding agreements or contractual obligations, which cannot be
cancelled or modified without substantial loss to the owner or operator, to
undertake a program of actual construction of the source to be completed within a
reasonable time.
For purposes of this definition:
“Construction” shall be determined as any physical change or change in
the method of operation, including but not limited to fabrication, erection,
installation, demolition, or modification of projects eligible for CASA
allowances, as set forth in Sections 225.460 and 225.560.
“A reasonable time” shall be determined considering but not limited to the
following factors: the nature and size of the project, the extent of design
engineering, the amount of off-site preparation, whether equipment can be
fabricated or can be purchased, when the project begins (considering both
the seasonal nature of the construction activity and the existence of other
projects competing for construction labor at the same time, the place of the
environmental permit in the sequence of corporate and overall
governmental approval), and the nature of the project sponsor (e.g.,
private, public, regulated).
“Commence operation,” for purposes of Subparts C, D and E, means:
52
To have begun any mechanical, chemical, or electronic process, including, for the
purpose of a unit, start-up of a unit’s combustion chamber, except as provided in
40 CFR 96.105, 96.205, or 96.305, as incorporated by reference in Section
225.140.
For a unit that undergoes a physical change (other than replacement of the unit by
a unit at the same source) after the date the unit commences operation as set forth
in the first paragraph of this definition, such date will remain the date of
commencement of operation of the unit, which will continue to be treated as the
same unit.
For a unit that is replaced by a unit at the same source (e.g., repowered), after the
date the unit commences operation as set forth in the first paragraph of this
definition, such date will remain the replaced unit’s date of commencement of
operation, and the replacement unit will be treated as a separate unit with a
separate date for commencement of operation as set forth in this definition as
appropriate.
“Common stack” means a single flue through which emissions from two or more units
are exhausted.
“Compliance account” means, for the purposes of Subparts D and E, a CAIR NO
x
Allowance Tracking System account, established by USEPA for a CAIR NO
x
source or
CAIR NO
x
Ozone Season source pursuant to 40 CFR 96 subparts FF and FFFF in which
any CAIR NO
x
allowance or CAIR NO
x
Ozone Season allowance allocations for the
CAIR NO
x
units or CAIR NO
x
Ozone Season units at the source are initially recorded
and in which are held any CAIR NO
x
or CAIR NO
x
Ozone Season allowances available
for use for a control period in order to meet the source’s CAIR NO
x
or CAIR NO
x
Ozone
Season emissions limitations in accordance with Sections 225.410 and 225.510, and 40
CFR 96.154 and 96.354, as incorporated by reference in Section 225.140. CAIR NO
x
allowances may not be used for compliance with the CAIR NO
x
Ozone Season Trading
program and CAIR NO
x
Ozone Season allowances may not be used for compliance with
the CAIR NO
x
Annual Trading program.
“Control period” means:
For the CAIR SO
2
and NO
x
Annual Trading programs in Subparts C and D, the
period beginning January 1 of a calendar year, except as provided in Sections
225.310(d)(3) and 225.410(d)(3), and ending on December 31 of the same year,
inclusive; or
For the CAIR NO
x
Ozone Season Trading Program in Subpart E, the period
beginning May 1 of a calendar year, except as provided in Section 225.510(d)(3),
and ending on September 30 of the same year, inclusive.
53
“Designated representative” means, for the purposes of Subpart B of this Part, the same
as defined in 40 CFR 60.4102.
“Electric generating unit (EGU)” means a fossil fuel-fired stationary boiler, combustion
turbine or combined cycle system that serves a generator that has a nameplate capacity
greater than 25 MWe and produces electricity for sale.
“Flue” means a conduit or duct through which gases or other matter is exhausted to the
atmosphere.
“Fossil fuel” means natural gas, petroleum, coal, or any form of solid, liquid, or gaseous
fuel derived from such material.
“Fossil fuel-fired” means the combusting any amount of fossil fuel, alone or in
combination with any other fuel in any calendar year.
“Generator” means a device that produces electricity.
“Gross electrical output” means the total electrical output from an EGU before making
any deductions for energy output used in any way related to the production of energy.
For an EGU generating only electricity, the gross electrical output is the output from the
turbine/generator set.
“Heat input” means, for the purposes of Subparts C, D, and E, a specified period of time,
the product (in mmBtu/hr) 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 USEPA by the CAIR designated
representative and determined by USEPA in accordance with 40 CFR 96, subpart HH,
HHH, or HHHH, if applicable, and excluding the heat derived from preheated
combustion air, recirculated flue gases, or exhaust from other sources.
“Higher heating value (HHV)” means the total heat liberated per mass of fuel burned
(Btu per pound), when fuel and dry air at standard conditions undergo complete
combustion and all resultant products are brought to their standard states at standard
conditions.
“Input mercury” means the mass of mercury that is contained in the coal combusted
within an EGU.
“Integrated gasification combined cycle (IGCC)” means a coal-fired electric utility steam
generating unit that burns a synthetic gas derived from coal in a combined-cycle gas
turbine. No coal is directly burned in the unit during operation.
“Nameplate capacity” means, starting from the initial installation of a generator, the
maximum electrical generating output (in MWe) that the generator is capable of
producing on a steady-state basis and during continuous operation (when not restricted by
54
seasonal or other deratings) as specified by the manufacturer of the generator or, starting
from the completion of any subsequent physical change in the generator resulting in an
increase in the maximum electrical generating output (in MWe) that the generator is
capable of producing on a steady-state basis and during continuous operation (when not
restricted by seasonal or other deratings), such increased maximum amount as specified
by the person conducting the physical change.
“Oil-fired unit” means a unit combusting fuel oil for more than 15.0 percent of the annual
heat input in a specified year and not qualifying as coal-fired.
“Output-based emission standard” means, for the purposes of Subpart B of this Part, a
maximum allowable rate of emissions of mercury per unit of gross electrical output from
an EGU.
“Potential electrical output capacity” means 33 percent of a unit’s maximum design heat
input, expressed in mmBtu/hr divided by 3.413 mmBtu/MWh, and multiplied by 8,760
hr/yr.
“Project sponsor” means a person or an entity, including but not limited to the owner or
operator of an EGU or a not-for-profit group, that provides the majority of funding for an
energy efficiency and conservation, renewable energy, or clean technology project as
listed in Sections 225.460 and 225.560, unless another person or entity is designated by a
written agreement as the project sponsor for the purpose of applying for NO
x
allowances
or NO
x
Ozone Season allowances from the CASA.
“Rated-energy efficiency” means the percentage of thermal energy input that is recovered
as useable energy in the form of gross electrical output, useful thermal energy, or both
that is used for heating, cooling, industrial processes, or other beneficial uses as follows:
For electric generators, rated energy efficiency is calculated as one kilowatt hour
(3,413 Btu) of electricity divided by the unit’s design heat rate using the higher
heating value of the fuel, and expressed as a percentage.
For combined heat and power projects, rated-energy efficiency is calculated using
the following formula:
REE =
((GO + UTE)/HI)
×
100
Where:
REE =
Rated-energy efficiency, expressed as percentage.
GO
=
Gross electrical output of the system expressed in Btu/hr.
UTE =
Useful thermal output from the system that is used for
heating, cooling, industrial processes or other beneficial uses, expressed in
Btu/hr.
55
HI
=
Heat input, based upon the higher heating value of fuel, in
Btu/hr.
“Repowered” means, for the purposes of an EGU, replacement of a coal-fired boiler with
one of the following coal-fired technologies at the same source as the coal-fired boiler:
Atmospheric or pressurized fluidized bed combustion;
Integrated gasification combined cycle;
Magnetohydrodynamics;
Direct and indirect coal-fired turbines;
Integrated gasification fuel cells; or
As determined by the USEPA in consultation with the United States Department
of Energy, a derivative of one or more of the technologies under this definition
and any other coal-fired technology capable of controlling multiple combustion
emissions simultaneously with improved boiler or generation efficiency and with
significantly greater waste reduction relative to the performance of technology in
widespread commercial use as of January 1, 2005.
“Rolling 12-month basis” means, for the purposes of Subpart B of this Part, a
determination made on a monthly basis from the relevant data for a particular calendar
month and the preceding 11 calendar months (total of 12 months of data), with two
exceptions. For determinations involving one EGU, calendar months in which the EGU
does not operate (zero EGU operating hours) must not be included in the determination,
and must be replaced by a preceding month or months in which the EGU does operate, so
that the determination is still based on 12 months of data. For determinations involving
two or more EGUs, calendar months in which none of the EGUs covered by the
determination operates (zero EGU operating hours) must not be included in the
determination, and must be replaced by preceding months in which at least one of the
EGUs covered by the determination does operate, so that the determination is still based
on 12 months of data.
“Total energy output” means, with respect to a cogeneration unit, the sum of useful
power and useful thermal energy produced by the cogeneration unit.
“Useful thermal energy” means, for the purpose of a cogeneration unit, the thermal
energy that is made available to an industrial or commercial process, excluding any heat
contained in condensate return or makeup water:
Used in a heating application (e.g., space heating or domestic hot water heating);
or
56
Used in a space cooling application (e.g., thermal energy used by an absorption
chiller).
(Source: Amended at 31 Ill. Reg. ____________, effective _______________)
Section 225.140
Incorporations by Reference
The following materials are incorporated by reference. These incorporations do not include any
later amendments or editions.
a)
40 CFR 60, 60.17, 60.45a, 60.49a(k)(1) and (p), 60.50a(h), and 60.4170 through
60.4176 (2005).
b)
40 CFR 75 (2005 2006).
c)
40 CFR 78 (2006).
d)
40 CFR 96, CAIR SO
2
Trading Program, subpart AAA (excluding 40 CFR 96.204
and 96.206), subpart BBB, subpart FFF, subpart GGG, and subpart HHH (2006).
e)
40 CFR 96, CAIR NO
x
Annual Trading Program, subpart AA (excluding 40 CFR
96.104, 96.105(b)(2), and 96.106), subpart BB, subpart FF, subpart GG, and
subpart HH (2006).
f)
40 CFR 96, CAIR NO
x
Ozone Season Trading Program, subpart AAAA
(excluding 40 CFR 96.304, 96.305(b)(2), and 96.306), subpart BBBB, subpart
FFFF, subpart GGGG, and subpart HHHH (2006).
gc)
ASTM. The following methods from the American Society for Testing and
Materials, 100 Barr Harbor Drive, P.O. Box C700, West Conshohocken PA 19428-2959, (610)
832-9585:
1)
ASTM D388-77 (approved February 25, 1977), D388-90 (approved
March 30, 1990), D388-91a (approved April 15, 1991), D388-95
(approved January 15, 1995), D388-98a (approved September 10, 1998),
or D388-99 (approved September 10, 1999, reapproved in 2004),
Classification of Coals by Rank.
2)
ASTM D3173-03, Standard Test Method for Moisture in the Analysis
Sample of Coal and Coke (Approved April 10, 2003).
3)
ASTM D3684-01, Standard Test Method for Total Mercury in Coal by the
Oxygen Bomb Combustion/Atomic Absorption Method (Approved
October 10, 2001).
57
4)
ASTM D5865-04, Standard Test Method for Gross Calorific Value of
Coal and Coke (Approved April 1, 2004).
5)
ASTM D6414-01, Standard Test Method for Total Mercury in Coal and
Coal Combustion Residues by Acid Extraction or Wet Oxidation/Cold
Vapor Atomic Absorption (Approved October 10, 2001).
6)
ASTM D6784-02, Standard Test Method for Elemental, Oxidized,
Particle-Bound and Total Mercury in Flue Gas Generated from Coal-Fired
Stationary Sources (Ontario Hydro Method) (Approved April 10, 2002).
h)
Federal Energy Management Program, M&V Measurement and Verification for
Federal Energy Projects, US Department of Energy, Office of Energy Efficiency
and Renewable Energy, Version 2.2, DOE/GO-102000-0960 (September 2000).
(Source: Amended at 31 Ill. Reg. ____________, effective _______________)
Section 225.150
Commence Commercial Operation
Commence commercial operation means, for the purposes of Subparts C, D and E, with regard to
a unit serving a generator:
a)
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 40 CFR 96.105, 96.205, or 96.305, as incorporated by
reference in Section 225.140.
1)
For a unit that is a CAIR SO
2
unit, CAIR NO
x
unit, or a CAIR NO
x
Ozone Season unit pursuant to 40 CFR 96.104, 96.204 or 96.304,
respectively, on the date the unit commences commercial operation
on the later of November 15, 1990 or the date the unit commences
commercial operation as defined in subsection (a) of this Section
and that subsequently undergoes a physical change (other than
replacement of the unit by a unit at the same source), such date will
remain the unit’s date of commencement of commercial operation,
which will continue to be treated as the same unit.
2)
For a unit that is a CAIR SO
2
unit, CAIR NO
x
unit, or a CAIR NO
x
Ozone Season unit pursuant to 40 CFR 96.104, 96.204 or 96.304,
respectively, on the later of November 15, 1990 or the date the unit
commences commercial operation as defined in subsection (a) of
this Section and that is subsequently replaced by a unit at the same
source (e.g., repowered), such date will remain the replaced unit’s
date of commencement of commercial operation, and the replaced
unit will be treated as a separate unit with a separate date for
58
commencement of commercial operation as defined in subsection
(a) or (b) of this Section as appropriate.
b)
Notwithstanding subsection (a) of this Section and except as provided in
40 CFR 96.105, 96.205, or 96.305 for a unit that is not a CAIR SO
2
unit,
CAIR NO
x
unit, or a CAIR NO
x
Ozone Season unit pursuant to Section
225.305, 225.405, or 225.405, respectively, on the later of November 15,
1990 or the date the unit commences commercial operation as defined in
subsection (a) of this Section, the unit’s date for commencement of
commercial operation will be the date on which the unit becomes an
affected unit pursuant to Section 225.305, 225.405, or 225.405,
respectively.
1)
For a unit with a date for commencement of commercial operation
as defined in subsection (b) of this Section and that subsequently
undergoes a physical change (other than replacement of the unit by
a unit at the same source), such date will remain the unit’s date of
commencement of commercial operation, which shall continue to
be treated as the same unit.
2)
For a unit with a date for commencement of commercial operation
as defined in subsection (b) of this Section and that is subsequently
replaced by a unit at the same source (e.g., repowered), such date
will remain the replaced unit’s date of commencement of
commercial operation, and the replaced unit will be treated as a
separate unit with a separate date for commencement of
commercial operation as defined in subsection (a) or (b) of this
Section as appropriate.
(Source: Added at 31 Ill. Reg. _________, effective _____________)
SUBPART C: CLEAN AIR ACT INTERSTATE RULE (CAIR) SO
2
TRADING PROGRAM
Section 225.300
Purpose
The purpose of this Subpart C is to control the emissions of sulfur dioxide (SO
2
) from EGUs
annually by implementing the CAIR SO
2
Trading Program pursuant to 40 CFR 96, as
incorporated by reference in Section 225.140.
(Source: Added at 31 Ill. Reg. ________________, effective ______________)
Section 225.305
Applicability
a)
Except as provided in subsections (b)(1), (b)(3), and (b)(4) of this Section:
59
1)
The following units are CAIR SO
2
units, and any source that includes one
or more such units is a CAIR SO
2
source subject to the requirements of
this Subpart C: any stationary, fossil-fuel-fired boiler or stationary, fossil-
fuel-fired combustion turbine serving at any time, since the later of
November 15, 1990 or the start-up the unit’s combustion chamber, a
generator with nameplate capacity of more than 25 MWe producing
electricity for sale.
2)
If a stationary boiler or stationary combustion turbine that, pursuant to
subsection (a)(1) of this Section, is not a CAIR SO
2
unit begins to combust
fossil fuel or to serve a generator with nameplate capacity of more than 25
MWe producing electricity for sale, the unit will become a CAIR SO
2
unit
as provided in subsection (a)(1) of this Section on the first date on which it
both combusts fossil fuel and serves such generator.
b)
The units that meet the requirements set forth in subsections (b)(1), (b)(3), and
(b)(4) of this Section will not be CAIR SO
2
units and units that meet the
requirements of subsections (b)(2) and (b)(5) of this Section are CAIR SO
2
units:
1)
Any unit that is a CAIR SO
2
unit pursuant to subsection (a)(1) or (a)(2) of
this Section and:
A)
Qualifies as a cogeneration unit during the 12-month period
starting on the date the unit first produces electricity and
continuing to qualify as a cogeneration unit; and
B)
Does not serve at any time, since the later of November 15, 1990
or the start-up of the unit’s combustion chamber, a generator with
nameplate capacity of more than 25 MWe supplying any calendar
year more than one-third of the of the unit’s potential electric
output capacity or 219,000 MWh, whichever is greater, to any
utility power distribution for sale.
2)
If a unit qualifies as a cogeneration unit during the 12-month period
starting on the date the unit first produces electricity and meets the
requirements of subsection (b)(1) of this Section for at least one calendar
year, but subsequently no longer meets all such requirements, the unit
shall become a CAIR SO
2
unit starting on the earlier of January 1 after the
first calendar year during which the unit no longer qualifies as a
cogeneration unit or January 1 after the first calendar year during which
the unit no longer meets the requirements of subsection (b)(1)(B) of this
Section.
3)
Any unit that is a CAIR SO
2
unit pursuant to subsection (a)(1) or (a)(2) of
this Section commencing operation before January 1, 1985 and:
60
A)
Qualifies as a solid waste incineration unit; and
B)
With an average annual fuel consumption of non-fossil fuel for
1985-1987 exceeding 80 percent (on a Btu basis) and an average
annual fuel consumption of non-fossil fuel for any three
consecutive calendar years after 1990 exceeding 80 percent (on a
Btu basis).
4)
Any unit that is a CAIR SO
2
unit under subsection (a)(1) or (a)(2) of this
Section commencing operation on or after January 1, 1985: and
A)
Qualifies as a solid waste incineration unit; and
B)
With an average annual fuel consumption of non-fossil fuel the
first three years of operation exceeding 80 percent (on a Btu basis)
and an average annual fuel consumption of non-fossil fuel for any
three consecutive calendar years after 1990 exceeding 80 percent
(on a Btu basis).
5)
If a unit qualifies as a solid waste incineration unit and meets the
requirements of subsection (b)(3) or (b)(4) of this Section for at least three
consecutive years, but subsequently no longer meets all such
requirements, the unit shall become a CAIR SO2 unit starting on the
earlier of January 1 after the first three consecutive calendar years after
1990 for which the unit has an average annual fuel consumption of fuel of
20 percent or more.
(Source: Added at 31 Ill. Reg. ________________, effective ______________)
Section 225.310
Compliance Requirements
a)
The owner or operator of a CAIR SO
2
unit must comply with the requirements of
the CAIR SO
2
Trading Program for Illinois as set forth in this Subpart C and 40
CFR 96, subpart AAA (CAIR SO
2
Trading Program General Provisions,
excluding 40 CFR 96.204, and 96.206); 40 CFR 96, subpart BBB (CAIR
Designated Representative for CAIR SO
2
Sources); 40 CFR 96, subpart FFF
(CAIR SO
2
Allowance Tracking System); 40 CFR 96, subpart GGG (CAIR SO
2
Allowance Transfers); and 40 CFR 96, subpart HHH (Monitoring and Reporting);
as incorporated by reference in Section 225.140 .
b)
Permit requirements:
61
1)
The owner or operator of each source with one or more CAIR SO
2
units at
the source must apply for a permit issued by the Agency with federally
enforceable conditions covering the CAIR SO
2
Trading Program (“CAIR
permit”) that complies with the requirements of Section 225.320 (Permit
Requirements).
2)
The owner or operator of each CAIR SO
2
source and each CAIR SO
2
unit
at the source must operate the CAIR SO
2
unit in compliance with its CAIR
permit.
c)
Monitoring requirements:
1)
The owner or operator of each CAIR SO
2
source and each CAIR SO
2
unit
at the source must comply with the monitoring requirements of 40 CFR
96, subpart HHH. The CAIR designated representative of each CAIR SO
2
source and each CAIR SO
2
unit at the CAIR SO
2
source must comply with
those sections of the monitoring, reporting and recordkeeping
requirements of 40 CFR 96, subpart HHH, applicable to the CAIR
designated representative.
2)
The compliance of each CAIR SO
2
source with the emissions limitation
pursuant to subsection (d) of this Section will be determined by the
emissions measurements recorded and reported in accordance with 40
CFR 96, subpart HHH and 40 CFR 75.
d)
Emission requirements:
1)
By the allowance transfer deadline, March 1, 2011, and by March 1 of
each subsequent year, the owner or operator of each CAIR SO
2
source and
each CAIR SO
2
unit at the source must hold a tonnage equivalent in CAIR
SO
2
allowances available for compliance deductions pursuant to 40 CFR
96.254(a) and (b) in the CAIR SO
2
source’s CAIR SO
2
Allowance System
Tracking account. The allowance transfer deadline means by midnight of
March 1 (if it is a business day) or midnight of the first business day
thereafter. The number of allowances held may not be less than the total
tons of SO
2
emissions for the control period from all CAIR SO
2
units at
the CAIR SO
2
source, as determined in accordance with 40 CFR 96,
subpart HHH.
2)
Each ton of SO
2
emitted by a CAIR SO
2
unit in excess of the tonnage
authorization of CAIR SO
2
allowances held by the owner or operator for
each CAIR SO
2
unit in its CAIR SO
2
Allowance System Tracking account
for each day of the applicable control period will constitute a separate
violation of this Subpart C, the Clean Air Act, and the Act.
62
3)
Each CAIR SO
2
unit will be subject to the monitoring requirements of
subsection (c)(1) of this Section starting on the later of January 1, 2009, or
the deadline for meeting the unit’s monitoring certification requirements
pursuant to 40 CFR 96.270(b)(1) or (2) and for each control period
thereafter.
4)
CAIR SO
2
allowances must be held in, deducted from, or transferred into
or among allowance accounts in accordance with this Subpart and 40 CFR
96, subparts FFF and GGG.
5)
In order to comply with the requirements of subsection (d)(1) of this
Section, a CAIR SO
2
allowance may not be deducted for compliance
according to subsection (d)(1) of this Section, for a control period in a
calendar year before the year for which the allowance is allocated.
6)
A CAIR SO
2
allowance is a limited authorization to emit SO
2
in
accordance with the CAIR SO
2
Trading Program. No provision of the
CAIR SO
2
Trading Program, the CAIR permit application, the CAIR
permit, or a retired unit exemption pursuant to 40 CFR 96.205, and no
provision of law, will be construed to limit the authority of the United
States or the State to terminate or limit this authorization.
7)
A CAIR SO
2
allowance allocated by USEPA pursuant to the CAIR SO
2
Trading Program does not constitute a property right.
8)
Upon recordation by USEPA pursuant to 40 CFR 96 subpart FFF or
subpart GGG, every allocation, transfer, or deduction of a CAIR SO
2
allowance to or from a CAIR SO
2
source’s compliance account, as defined
by 40 CFR 96.202, is deemed to amend automatically, and become a part
of, any CAIR permit of the CAIR SO
2
source. This automatic amendment
of the CAIR permit will be deemed an operation of law and will not
require any further review.
e)
Recordkeeping and reporting requirements:
1)
Unless otherwise provided, the owner or operator of the CAIR SO
2
source
and each CAIR SO
2
unit at the source must keep on site at the source each
of the documents listed in subsections (e)(1)(A) through (e)(1)(D) of this
Section for a period of five (5) years from the date the document is
created. This period may be extended for cause, at any time prior to the
end of five years, in writing by the Agency or USEPA.
A)
The certificate of representation for the CAIR designated
representative for the source and each CAIR SO
2
unit at the source,
all documents that demonstrate the truth of the statements in the
certificate of representation, provided that the certificate and
63
documents must be retained on site at the source beyond such five-
year period until the documents are superseded because of the
submission of a new certificate of representation pursuant to 40
CFR 96.213, changing the CAIR designated representative.
B)
All emissions monitoring information, in accordance with 40 CFR
96, subpart HHH.
C)
Copies of all reports, compliance certifications, and other
submissions and all records made or required pursuant to the CAIR
SO
2
Trading Program or documents necessary to demonstrate
compliance with the requirements of the CAIR SO
2
Trading
Program or with the requirements of this Subpart C.
D)
Copies of all documents used to complete a CAIR permit
application and any other submission or documents used to
demonstrate compliance pursuant to the CAIR SO
2
Trading
Program.
2)
The CAIR designated representative of a CAIR SO
2
source and each
CAIR SO
2
unit at the source must submit to the Agency and USEPA the
reports and compliance certifications required pursuant to the CAIR SO
2
Trading Program, including those pursuant to 40 CFR 96, subpart HHH.
f)
Liability:
1)
No revision of a permit for a CAIR SO
2
unit may excuse any violation of
the requirements of this Subpart C or the requirements of the CAIR SO
2
Trading Program.
2)
Each CAIR SO
2
source and each CAIR SO
2
unit must meet the
requirements of the CAIR SO
2
Trading Program.
3)
Any provision of the CAIR SO
2
Trading Program that applies to CAIR
SO
2
source (including any provision applicable to the CAIR designated
representative of a CAIR SO
2
source) will also apply to the owner and
operator of the CAIR SO
2
source and to the owner and operator of each
CAIR SO
2
unit at the source.
4)
Any provision of the CAIR SO
2
Trading Program that applies to a CAIR
SO
2
unit (including any provision applicable to the CAIR designated
representative of a CAIR SO
2
unit) will also apply to the owner and
operator of the CAIR SO
2
unit.
64
5)
The CAIR designated representative of a CAIR SO
2
unit that has excess
SO
2
emissions in any control period must surrender the allowances as
required for deduction pursuant to 40 CFR 96.254(d)(1).
6)
The owner or operator of a CAIR SO
2
unit that has excess SO
2
emissions
in any control period must pay any fine, penalty, or assessment or comply
with any other remedy imposed pursuant to the Act and 40 CFR
96.254(d)(2).
g)
Effect on other authorities. No provision of the CAIR SO
2
Trading Program, a
CAIR permit application, a CAIR permit, or a retired unit exemption pursuant to
40 CFR 96.205 will be construed as exempting or excluding the owner and
operator and, to the extent applicable, the CAIR designated representative of a
CAIR SO
2
source or a CAIR SO
2
unit, from compliance with any other regulation
promulgated pursuant to the CAA, the Act, any State regulation or permit, or a
federally enforceable permit.
(Source: Added at 31 Ill. Reg. ________________, effective ______________)
Section 225.315
Appeal Procedures
The appeal procedures for decisions of USEPA pursuant to the CAIR SO
2
Trading Program are
set forth in 40 CFR 78, as incorporated by reference in Section 225.140.
(Source: Added at 31 Ill. Reg. ________________, effective ______________)
Section 225.320
Permit Requirements
a)
Permit requirements:
1)
The owner or operator of each source with a CAIR SO
2
unit is required to
submit:
A)
A complete permit application addressing all applicable CAIR SO
2
Trading Program requirements for a permit meeting the
requirements of this Section 225.320, applicable to each CAIR SO
2
unit at the source. Each CAIR permit must contain elements
required for a complete CAIR permit application pursuant to
subsection (b)(2) of this Section.
B)
Any supplemental information that the Agency determines is
necessary in order to review a CAIR permit application and issue a
CAIR permit.
65
2)
Each CAIR permit will be issued pursuant to Section 39 or 39.5 of the
Act, must contain federally enforceable conditions addressing all
applicable CAIR SO
2
Trading Program and requirements, and will be a
complete and segregable portion of the source’s entire permit pursuant to
subsection (a)(1) of this Section.
3)
No CAIR permit may be issued and no CAIR SO
2
Allowance System
Tracking account may be established for the CAIR SO
2
source, until the
Agency and USEPA have received a complete certificate of representation
for a CAIR designated representative or alternate designated
representative pursuant to 40 CFR 96, subpart BBB, for a source and the
CAIR SO
2
unit at the source.
4)
For all CAIR SO
2
units that commenced operation before July 1, 2008, the
owner or operator of the unit must submit a CAIR permit application
meeting the requirements of this Section 225.320 on or before July 1,
2008.
5)
For CAIR SO
2
units that commence operation on or after July 1, 2008, and
that are and are not subject to Section 39.5 of the Act, the owner or
operator of such units must submit applications for construction and
operating permits pursuant to the requirements of Sections 39 and 39.5 of
the Act, as applicable, and 35 Ill. Adm. Code 201 and the applications
must specify that they are applying for CAIR permits, and must address
the CAIR permit application requirements of this Section 225.320.
b)
Permit applications:
1)
Duty to apply. The owner or operator of any source with one or more
CAIR SO
2
units must submit to the Agency a CAIR permit application for
the source covering each CAIR SO
2
unit pursuant to subsection (b)(2) of
this Section by the applicable deadline in subsection (a)(4) or (a)(5) of this
Section. The owner or operator of any source with one or more CAIR SO
2
units must reapply for a CAIR permit for the source as required by this
Subpart, 35 Ill. Adm. Code 201, and, as applicable, Sections 39 and 39.5
of the Act.
2)
Information requirements for CAIR permit applications. A complete
CAIR permit application must include the following elements concerning
the source for which the application is submitted:
A)
Identification of the source, including plant name. The ORIS
(Office of Regulatory Information Systems) or facility code
assigned to the source by the Energy Information Administration
must also be included, if applicable;
66
B)
Identification of each CAIR SO
2
unit at the source; and
C)
The compliance requirements applicable to each CAIR SO
2
unit as
set forth in Section 225.310.
3)
An application for a CAIR permit will be treated as a modification of the
CAIR SO
2
source’s existing federally enforceable permit, if such a permit
has been issued for that CAIR SO
2
source, and will be subject to the same
procedural requirements. When the Agency issues a CAIR permit
pursuant to the requirements of this Section 225.320, it will be
incorporated into and become part of that CAIR SO
2
source’s existing
federally enforceable permit.
c)
Permit content. Each CAIR permit is deemed to incorporate automatically the
definitions and terms pursuant to Section 225.120 and, upon recordation of
USEPA under 40 CFR 96, Subparts FFF and GGG as incorporated by reference in
Section 225.140, every allocation, transfer, or deduction of a CAIR SO
2
allowance to or from the compliance account of the CAIR SO
2
source covered by
the permit.
(Source: Added at 31 Ill. Reg. ________________, effective ______________)
Section 225.325
Trading Program
a)
The CAIR SO
2
Trading Program is administered by USEPA. CAIR SO
2
allowances are issued as described by the definition for allocate in 40 CFR
96.220, as incorporated by reference in Section 225.140. The amount of CAIR
SO
2
allowances to be credited to a CAIR SO
2
source’s CAIR SO
2
Allowance
Tracking System account for a CAIR SO
2
unit will be determined in accordance
with 40 CFR 96.253, as incorporated by reference in Section 225.140.
b)
A CAIR SO
2
allowance is a limited authorization to emit SO
2
during the calendar
year for which the allowance is allocated or any calendar year thereafter pursuant
to the CAIR SO
2
Trading Program as follows:
1)
For one CAIR SO
2
allowance allocated for a control period in a year
before 2010, one ton of SO
2
, except as provided for in the compliance
deductions pursuant to 40 CFR 96.254(b);
2)
For one CAIR SO
2
allowance allocated for a control period in 2010
through 2014, 0.5 ton of SO
2
, except as provided for in the compliance
deductions pursuant to 40 CFR 96.254(b); and
67
3)
For one CAIR SO
2
allowance allocated for a control period in 2015 or
later, 0.35 ton of SO
2
, except as provided for in the compliance deductions
pursuant to 40 CFR 96.254(b).
(Source: Added at 31 Ill. Reg. ________________, effective ______________)
SUBPART D: CAIR NO
x
ANNUAL TRADING PROGRAM
Section 225.400
Purpose
The purpose of this Subpart D is to control the annual emissions of nitrogen oxides (NO
x
) from
EGUs by determining allocations and implementing the CAIR NO
x
Annual Trading Program.
(Source: Added at 31 Ill. Reg. ________________, effective ______________)
Section 225.405
Applicability
a)
Except as provided in subsections (b)(1), (b)(3), and (b)(4) of this Section:
1)
The following units are CAIR NO
x
units, and any source that includes one
or more such units is a CAIR NO
x
source subject to the requirements of
this Subpart D: any stationary, fossil-fuel-fired boiler or stationary, fossil-
fuel-fired combustion turbine serving at any time, since the later of
November 15, 1990 or the start-up the unit’s combustion chamber, a
generator with nameplate capacity of more than 25 MWe producing
electricity for sale.
2)
If a stationary boiler or stationary combustion turbine that, pursuant to
subsection (a)(1) of this Section, is not a CAIR NO
x
unit begins to
combust fossil fuel or to serve a generator with nameplate capacity of
more than 25 MWe producing electricity for sale, the unit will become a
CAIR NO
x
unit as provided in subsection (a)(1) of this Section on the first
date on which it both combusts fossil fuel and serves such generator.
b)
The units that meet the requirements set forth in subsections (b)(1), (b)(3), and
(b)(4) of this Section will not be CAIR NO
x
units and units that meet the
requirements of subsections (b)(2) and (b)(5) of this Section are CAIR NO
x
units:
1)
Any unit that is a CAIR NO
x
unit pursuant to subsection (a)(1) or (a)(2) of
this Section and:
A)
Qualifies as a cogeneration unit during the 12-month period
starting on the date the unit first produces electricity and
continuing to qualify as a cogeneration unit; and
68
B)
Does not serve at any time, since the later of November 15, 1990
or the start-up of the unit’s combustion chamber, a generator with
nameplate capacity of more than 25 MWe supplying any calendar
year more than one-third of the of the unit’s potential electric
output capacity or 219,000 MWh, whichever is greater, to any
utility power distribution for sale.
2)
If a unit qualifies as a cogeneration unit during the 12-month period
starting on the date the unit first produces electricity and meets the
requirements of subsection (b)(1) of this Section for at least one calendar
year, but subsequently no longer meets all such requirements, the unit
shall become a CAIR NO
x
unit starting on the earlier of January 1 after the
first calendar year during which the unit no longer qualifies as a
cogeneration unit or January 1 after the first calendar year during which
the unit no longer meets the requirements of subsection (b)(1)(B) of this
Section.
3)
Any unit that is a CAIR NO
x
unit pursuant to subsection (a)(1) or (a)(2) of
this Section commencing operation before January 1, 1985 and:
A)
Qualifies as a solid waste incineration unit; and
B)
With an average annual fuel consumption of non-fossil fuel for
1985-1987 exceeding 80 percent (on a Btu basis) and an average
annual fuel consumption of non-fossil fuel for any three
consecutive calendar years after 1990 exceeding 80 percent (on a
Btu basis).
4)
Any unit that is a CAIR NO
x
unit under subsection (a)(1) or (a)(2) of this
Section commencing operation on or after January 1, 1985: and
A)
Qualifies as a solid waste incineration unit; and
B)
With an average annual fuel consumption of non-fossil fuel the
first three years of operation exceeding 80 percent (on a Btu basis)
and an average annual fuel consumption of non-fossil fuel for any
three consecutive calendar years after 1990 exceeding 80 percent
(on a Btu basis).
5)
If a unit qualifies as a solid waste incineration unit and meets the
requirements of subsection (b)(3) or (b)(4) of this Section for at least three
consecutive years, but subsequently no longer meets all such
requirements, the unit shall become a CAIR NO
x
unit starting on the
earlier of January 1 after the first three consecutive calendar years after
69
1990 for which the unit has an average annual fuel consumption of fuel of
20 percent or more.
(Source: Added at 31 Ill. Reg. ________________, effective ______________)
Section 225.410
Compliance Requirements
a)
The owner or operator of a CAIR NO
x
unit must comply with the requirements of
the CAIR NO
x
Annual Trading Program for Illinois as set forth in this Subpart D
and 40 CFR 96, subpart AA (NO
x
Annual Trading Program General Provisions,
excluding 40 CFR 96.104, 96.105(b)(2), and 96.106); 40 CFR 96, subpart BB
(CAIR Designated Representative for CAIR NO
x
Sources); 40 CFR 96, subpart
FF (CAIR NO
x
Allowance Tracking System); 40 CFR 96, subpart GG (CAIR
NO
x
Allowance Transfers); and 40 CFR 96, subpart HH (Monitoring and
Reporting); as incorporated by reference in Section 225.140.
b)
Permit requirements:
1)
The owner or operator of each source with one or more CAIR NO
x
units at
the source must apply for a permit issued by the Agency with federally
enforceable conditions covering the CAIR NO
x
Annual Trading Program
(“CAIR permit”) that complies with the requirements of Section 225.420
(Permit Requirements).
2)
The owner or operator of each CAIR NO
x
source and each CAIR NO
x
unit
at the source must operate the CAIR NO
x
unit in compliance with its
CAIR permit.
c)
Monitoring requirements:
1)
The owner or operator of each CAIR NO
x
source and each CAIR NO
x
unit
at the source must comply with the monitoring requirements of 40 CFR
96, subpart HH and Section 225.450. The CAIR designated representative
of each CAIR NO
x
source and each CAIR NO
x
unit at the CAIR NO
x
source must comply with those sections of the monitoring, reporting and
recordkeeping requirements of 40 CFR 96, subpart HH, applicable to a
CAIR designated representative.
2)
The compliance of each CAIR NO
x
source with the NO
x
emissions
limitation pursuant to subsection (d) of this Section will be determined by
the emissions measurements recorded and reported in accordance with 40
CFR 96, subpart HH.
d)
Emission requirements:
70
1)
By the allowance transfer deadline, March 1, 2010, and by March 1 of
each subsequent year, the allowance transfer deadline, the owner or
operator of each CAIR NO
x
source and each CAIR NO
x
unit at the source
must hold CAIR NO
x
allowances available for compliance deductions
pursuant to 40 CFR 96.154(a) in the CAIR NO
x
source’s CAIR NO
x
compliance account. The allowance transfer deadline means by midnight
of March 1 (if it is a business day) or midnight of the first business day
thereafter. The number of allowances held may not be less than the tons
of NO
x
emissions for the control period from all CAIR NO
x
units at the
source, as determined in accordance with 40 CFR 96, subpart HH.
2)
Each ton of NO
x
emitted in excess of the number of CAIR NO
x
allowances held by the owner or operator for each CAIR NO
x
unit in its
CAIR NO
x
compliance account for each day of the applicable control
period will constitute a separate violation of this Subpart D, the Act, and
the CAA.
3)
Each CAIR NO
x
unit will be subject to the monitoring requirements of
subsection (c)(1) of this Section starting on the later of January 1, 2009, or
the deadline for meeting the unit’s monitoring certification requirements
pursuant to 40 CFR 96.170(b)(1) or (b)(2) and for each control period
thereafter.
4)
CAIR NO
x
allowances must be held in, deducted from, or transferred
among allowance accounts in accordance with this Subpart and 40 CFR
96, subparts FF and GG.
5)
In order to comply with the requirements of subsection (d)(1) of this
Section, a CAIR NO
x
allowance may not be deducted for compliance
according to subsection (d)(1) of this Section, for a control period in a year
before the calendar year for which the allowance is allocated.
6)
A CAIR NO
x
allowance allocated by the Agency or USEPA pursuant to
the CAIR NO
x
Annual Trading Program is a limited authorization to emit
one ton of NO
x
in accordance with the CAIR NO
x
Trading Program. No
provision of the CAIR NO
x
Trading Program, the CAIR NO
x
permit
application, the CAIR permit, or a retired unit exemption pursuant to 40
CFR 96.105, and no provision of law, will be construed to limit the
authority of the United States or the State to terminate or limit this
authorization.
7)
A CAIR NO
x
allowance allocated by the Agency or USEPA pursuant to
the CAIR NO
x
Annual Trading Program does not constitute a property
right.
8)
Upon recordation by USEPA pursuant to 40 CFR 96, subpart FF or 40
71
CFR 96, subpart GG, every allocation, transfer, or deduction of a CAIR
NO
x
allowance to or from a CAIR NO
x
source compliance account is
deemed to amend automatically, and become a part of, any CAIR NO
x
permit of the CAIR NO
x
source. This automatic amendment of the CAIR
permit will be deemed an operation of law and will not require any further
review.
e)
Recordkeeping and reporting requirements:
1)
Unless otherwise provided, the owner or operator of the CAIR NO
x
source
and each CAIR NO
x
unit at the source must keep on site at the source each
of the documents listed in subsections (e)(1)(A) through (e)(1)(E) of this
Section for a period of five years from the date the document is created.
This period may be extended for cause, at any time prior to the end of five
years, in writing by the Agency or USEPA.
A)
The certificate of representation for the CAIR designated
representative for the source and each CAIR NO
x
unit at the
source, all documents that demonstrate the truth of the statements
in the certificate of representation, provided that the certificate and
documents must be retained on site at the source beyond such five-
year period until the documents are superseded because of the
submission of a new certificate of representation pursuant to 40
CFR 96.113, changing the CAIR designated representative.
B)
All emissions monitoring information, in accordance with 40 CFR
96, subpart HH.
C)
Copies of all reports, compliance certifications, and other
submissions and all records made or required pursuant to the CAIR
NO
x
Annual Trading Program or documents necessary to
demonstrate compliance with the requirements of the CAIR NO
x
Annual Trading Program or with the requirements of this Subpart
D.
D)
Copies of all documents used to complete a CAIR NO
x
permit
application and any other submission or documents used to
demonstrate compliance pursuant to the CAIR NO
x
Annual
Trading Program.
E)
Copies of all records and logs for gross electrical output and useful
thermal energy required by Section 225.450.
2)
The CAIR designated representative of a CAIR NO
x
source and each
CAIR NO
x
unit at the source must submit to the Agency and USEPA the
reports and compliance certifications required pursuant to the CAIR NO
x
72
Annual Trading Program, including those pursuant to 40 CFR 96, subpart
HH.
f)
Liability:
1)
No revision of a permit for a CAIR NO
x
unit may excuse any violation of
the requirements of this Subpart D or the requirements of the CAIR NO
x
Annual Trading Program.
2)
Each CAIR NO
x
source and each CAIR NO
x
unit must meet the
requirements of the CAIR NO
x
Annual Trading Program.
3)
Any provision of the CAIR NO
x
Annual Trading Program that applies to a
CAIR NO
x
source (including any provision applicable to the CAIR
designated representative of a CAIR NO
x
source) will also apply to the
owner and operator of the CAIR NO
x
source and to the owner and
operator of each CAIR NO
x
unit at the source.
4)
Any provision of the CAIR NO
x
Annual Trading Program that applies to a
CAIR NO
x
unit (including any provision applicable to the CAIR
designated representative of a CAIR NO
x
unit) will also apply to the
owner and operator of the CAIR NO
x
unit.
5)
The CAIR designated representative of a CAIR NO
x
unit that has excess
emissions in any control period must surrender the allowances as required
for deduction pursuant to 40 CFR 96.154(d)(1).
6)
The owner or operator of a CAIR NO
x
unit that has excess NO
x
emissions
in any control period must pay any fine, penalty, or assessment or comply
with any other remedy imposed pursuant to the Act and 40 CFR
96.154(d)(2).
g)
Effect on other authorities. No provision of the CAIR NO
x
Annual Trading
Program, a CAIR permit application, a CAIR permit, or a retired unit exemption
pursuant to 40 CFR 96.105 will be construed as exempting or excluding the
owner and operator and, to the extent applicable, the CAIR designated
representative of a CAIR NO
x
source or a CAIR NO
x
unit, from compliance with
any other regulation promulgated pursuant to the CAA, the Act, any State
regulation or permit, or a federally enforceable permit.
(Source: Added at 31 Ill. Reg. ________________, effective ______________)
Section 225.415
Appeal Procedures
The appeal procedures for decisions of USEPA pursuant to the CAIR NO
x
Annual Trading
73
Program are set forth in 40 CFR 78, as incorporated by reference in Section 225.140.
(Source: Added at 31 Ill. Reg. ________________, effective ______________)
Section 225.420
Permit Requirements
a)
Permit requirements:
1)
The owner or operator of each source with a CAIR NO
x
unit is required to
submit:
A)
A complete permit application addressing all applicable CAIR NO
x
Annual Trading Program requirements for a permit meeting the
requirements of this Section 225.420, applicable to each CAIR
NO
x
unit at the source. Each CAIR permit must contain elements
required for a complete CAIR permit application pursuant to
subsection (b)(2) of this Section.
B)
Any supplemental information that the Agency determines
necessary in order to review a CAIR permit application and issue
any CAIR permit.
2)
Each CAIR permit will be issued pursuant to Section 39 and 39.5 of the
Act, must contain federally enforceable conditions addressing all
applicable CAIR NO
x
Annual Trading Program requirements and must be
a complete and segregable portion of the source’s entire permit pursuant to
subsection (a)(1) of this Section.
3)
No CAIR permit may be issued, and no CAIR NO
x
compliance account
may be established for a CAIR NO
x
source, until the Agency and USEPA
have received a complete certificate of representation for a CAIR
designated representative pursuant to 40 CFR 96, subpart BB, for the
CAIR NO
x
source and the CAIR NO
x
unit at the source.
4)
For all CAIR NO
x
units that commenced operation before July 1, 2007,
the owner or operator of the unit must submit a CAIR permit application
meeting the requirements of this Section 225.420 on or before July 1,
2007.
5)
For all CAIR NO
x
units that commence operation on or after July 1, 2007,
the owner or operator of these units must submit applications for
construction and operating permits pursuant to the requirements of
Sections 39 and 39.5 of the Act, as applicable, and 35 Ill. Adm. Code 201
and the applications must specify that they are applying for CAIR permits,
and must address the CAIR permit application requirements of this
74
Section 225.420.
b)
Permit applications:
1)
Duty to apply. The owner or operator of any source with one or more
CAIR NO
x
units must submit to the Agency a CAIR permit application for
the source covering each CAIR NO
x
unit pursuant to subsection (b)(2) of
this Section by the applicable deadline in subsection (a)(4) or (a)(5) of this
Section. The owner or operator of any source with one or more CAIR
NO
x
units must reapply for a CAIR permit for the source as required by
this Subpart, 35 Ill. Adm. Code 201, and, as applicable, Sections 39 and
39.5 of the Act.
2)
Information requirements for CAIR permit applications. A complete
CAIR permit application must include the following elements concerning
the source for which the application is submitted:
A)
Identification of the source, including plant name. The ORIS
(Office of Regulatory Information Systems) or facility code
assigned to the source by the Energy Information Administration
must also be included, if applicable;
B)
Identification of each CAIR NO
x
unit at the source; and
C)
The compliance requirements applicable to each CAIR NO
x
unit as
set forth in Section 225.410.
3)
An application for a CAIR permit will be treated as a modification of the
CAIR NO
x
source’s existing federally enforceable permit, if such a permit
has been issued for that source, and will be subject to the same procedural
requirements. When the Agency issues a CAIR permit pursuant to the
requirements of this Section 225.420, it will be incorporated into and
become part of that source’s existing federally enforceable permit.
c)
Permit content. Each CAIR permit is deemed to incorporate automatically the
definitions and terms pursuant to Section 225.120 and, upon recordation of
USEPA under 40 CFR 96, Subparts FF and GG as incorporated by reference in
Section 225.140, every allocation, transfer, or deduction of a CAIR NO
x
allowance to or from the compliance account of the CAIR NO
x
source covered by
the permit.
(Source: Added at 31 Ill. Reg. ________________, effective ______________)
Section 225.425
Annual Trading Budget
75
The CAIR NO
x
Annual Trading budget available for allowance allocations for each control
period will be determined as follows:
a)
The total base CAIR NO
x
Annual Trading budget is 76,230 tons per control
period for the years 2009 through 2014, subject to a reduction for two set-asides,
the New Unit Set-Aside (NUSA) and the Clean Air Set-Aside (CASA). Five
percent of the budget will be allocated to the NUSA and 25 percent will be
allocated to the CASA, resulting in a CAIR NO
x
Annual Trading budget of
53,361 tons available for allocation per control period pursuant to Section
225.440. The requirements of the NUSA are set forth in Section 225.445, and the
requirements of the CASA are set forth in Sections 225.455 through 225.470.
b)
The total base CAIR NO
x
Annual Trading budget is 63,525 tons per control
period for the year 2015 and thereafter, subject to a reduction for two set-asides,
the NUSA and the CASA. Five percent of the budget will be allocated to the
NUSA and 25 percent will be allocated to the CASA, resulting in a CAIR NO
x
Annual Trading budget of 44,468 tons available for allocation per control period
pursuant to Section 225.440.
c)
If USEPA adjusts the total base CAIR NO
x
Annual Trading budget for any
reason, the Agency will adjust the base CAIR NO
x
Annual Trading budget and
the CAIR NO
x
Annual Trading budget available for allocation, accordingly.
(Source: Added at 31 Ill. Reg. ________________, effective ______________)
Section 225.430
Timing for Annual Allocations
a)
No later than July 31, 2007, the Agency will submit to USEPA the CAIR NO
x
allowance allocations, in accordance with Sections 225.435 and 225.440, for the
2009, 2010, and 2011 control periods.
b)
By October 31, 2008, and October 31 of each year thereafter, the Agency will
submit to USEPA the CAIR NO
x
allowance allocations in accordance with
Sections 225.435 and 225.440, for the control period four years after the year of
the applicable deadline for submission pursuant to this Section 225.430. For
example, on October 31, 2008, the Agency will submit to USEPA the allocations
for the 2012 control period.
c)
The Agency will allocate allowances from the NUSA to CAIR NO
x
units that
commence commercial operation on or after January 1, 2006. The Agency will
report these allocations to USEPA by October 31 of the applicable control period.
For example, on October 31, 2009, the Agency will submit to USEPA the
allocations from the NUSA for the 2009 control period.
d)
The Agency will allocate allowances from the CASA to energy efficiency,
76
renewable energy, and clean technology projects pursuant to the criteria in
Sections 225.455 through 225.470. The Agency will report these allocations to
USEPA by October 1 of each year. For example, on October 1, 2009, the Agency
will submit to USEPA the allocations from the CASA for the 2009 control period,
based on reductions made in the 2008 control period.
(Source: Added at 31 Ill. Reg. ________________, effective ______________)
Section 225.435
Methodology for Calculating Annual Allocations
The Agency will calculate converted gross electrical output, in MWh, for each CAIR NO
x
unit
that has operated during at least one calendar year prior to the calendar year in which the Agency
reports the allocations to USEPA as follows:
a)
For control periods 2009, 2010, and 2011, the owner or operator of the unit must
submit in writing to the Agency by June 1, 2007, a statement that either gross
electrical output data or heat input data is to be used to calculate the unit’s
converted gross electrical output. The data shall be used to calculate converted
gross electrical output pursuant to either subsection (a)(1) or (a)(2) of this Section:
1)
Gross electrical output. If the unit has four or five control periods of data,
then the gross electrical output (GO) will be the average of the unit’s three
highest gross electrical outputs from the 2001, 2002, 2003, 2004, or 2005
control periods. If the unit has three or fewer control periods of gross
electrical output data, the gross electrical output will be the average of
those control periods. If the unit does not have gross electrical output for
the 2004 and 2005 control periods, the gross electrical output will be the
gross electrical output data from the 2005 control period. If a generator is
served by two or more units, the gross electrical output of the generator
will be attributed to each unit in proportion to the unit’s share of the total
control period heat input of these units for the control period. The unit’s
converted gross electrical output will be calculated as follows:
A)
If the unit is coal-fired:
CGO (in MWh) = GO
×
MWh
×
1.0;
B)
If the unit is oil-fired:
CGO (in MWh) = GO
×
MWh
×
0.6; or
C)
If the unit is neither coal-fired nor oil-fired:
CGO (in MWh) = GO
×
MWh
×
0.4
2)
Heat input (HI). If the unit has four or five control periods of data, the
average of the unit’s three highest heat input from the 2001, 2002, 2003,
2004 or 2005 control period, will be used. If the unit has heat inputs from
77
the 2003, 2004, or 2005 control period, the heat input will be the average
of those years. If the unit does not have heat input from the 2004 and
2005 control periods, the heat input from the 2005 control period will be
used. The unit’s converted gross electrical output will be calculated as
follows:
A)
If the unit is coal-fired:
CGO (in MWh) = HI (in mmBtu)
×
0.0967;
B)
If the unit is oil-fired:
CGO (in MWh) = HI (in mmBtu)
×
0.0580; or
C)
If the unit is neither coal-fired nor oil-fired:
CGO (in MWh) = HI (in mmBtu)
×
0.0387.
b)
For control periods 2012 and 2013, the owner or operator of the unit must submit
in writing to the Agency by June 1, 2008, a statement that either gross electrical
output data or heat input data be used to calculate the unit’s converted gross
electrical output. The unit’s converted gross electrical output shall be calculated
pursuant to either subsection (b)(1) or (b)(2) of this Section:
1)
Gross electrical output. The average of the unit’s two most recent years of
control period gross electrical output, if available; otherwise it will be the
unit’s most recent control period’s gross electrical output. If a generator is
served by two or more units, the gross electrical output of the generator
shall be attributed to each unit in proportion to the unit’s share of the total
control period heat input of such units for the control period. The unit’s
converted gross electrical output shall be calculated as follows:
A)
If the unit is coal-fired:
CGO (in MWh) = GO
×
MWh
×
1.0;
B)
If the unit is oil-fired:
CGO (in MWh) = GO
×
MWh
×
0.6;
C)
If the unit is neither coal-fired nor oil-fired:
CGO (in MWh) = GO
×
MWh
×
0.4.
2)
Heat input. The average of the unit’s two most recent years of control
period heat input; otherwise the unit’s most recent control period’s heat
input, e.g. for the 2012 control period the average of the unit’s heat input
from the 2006 and 2007 control periods. If the unit does not have heat
input from the 2006 and 2007 control periods, the heat input from the
2007 control period shall be used. The unit’s converted gross electrical
output shall be calculated as follows:
78
A)
If the unit is coal-fired:
CGO (in MWh) = HI (in mmBtu)
×
0.0967;
B)
If the unit is oil-fired:
CGO (in MWh) = HI (in mmBtu)
×
0.0580; or
C)
If the unit is neither coal-fired nor oil-fired:
CGO (in MWh) = HI (in mmBtu)
×
0.0387.
c)
For control period 2014 and thereafter, the unit’s gross electrical output will be
the average of the unit’s two most recent years of control period gross electrical
output, if available; otherwise it will be the unit’s most recent control period’s
gross electrical output. If a generator is served by two or more units, the gross
electrical output of the generator will be attributed to each unit in proportion to
the unit’s share of the total control period heat input of these units for the control
period. The unit’s converted gross electrical output will be calculated as follows:
1)
If the unit is coal-fired:
CGO (in MWh) = GO
×
1.0;
2)
If the unit is oil-fired:
CGO (in MWh) = GO
×0.6;
or
3)
If the unit is neither coal-fired nor oil-fired:
CGO (in MWh) = GO
×
0.4.
d)
For a unit that is a combustion turbine or boiler and has equipment used to
produce electricity and useful thermal energy for industrial, commercial, heating,
or cooling purposes through the sequential use of energy, the Agency will add the
converted gross electrical output calculated for electricity pursuant to subsections
(a), (b), or (c) of this Section to the converted useful thermal energy (CUTE) to
determine the total converted gross electrical output for the unit (TCGO). The
Agency will determine the converted useful thermal energy by using the average
of the unit’s control period useful thermal energy for the prior two control
periods, if available, otherwise the unit’s control period useful thermal output for
the prior year will be used. The converted useful thermal energy will be
determined using the following equations:
1)
If the unit is coal-fired:
CUTE (in MWh) = UTE (in mmBtu)
×
0.2930;
2)
If the unit is oil-fired:
CUTE (in MWh) = UTE (in mmBtu)
×
0.1758; or
3)
If the unit is neither coal-fired nor oil-fired:
CUTE (in MWh) = UTE (in mmBtu)
×
0.1172.
79
e)
The CAIR NO
x
unit’s converted gross electrical output and converted useful
thermal energy in subsections (a)(1), (b)(1), (c) and (d) of this Section for each
control period will be based on the best available data reported or available to the
Agency for the CAIR NO
x
unit pursuant to the provisions of Section 225.450.
f)
The CAIR NO
x
unit’s heat input in subsections (a)(2) and (b)(2) of this Section
for each control period will be determined in accordance with 40 CFR 75, as
incorporated by reference in Section 225.140.
(Source: Added at 31 Ill. Reg. ________________, effective ______________)
Section 225.440
Annual Allocations
a)
For the 2009 control period, and each control period thereafter, the Agency will
allocate CAIR NO
x
allowances to all CAIR NO
x
units in Illinois for which the
Agency has calculated the total converted gross electrical output pursuant to
Section 225.435, a total amount of CAIR NO
x
allowances equal to tons of NO
x
emissions in the CAIR NO
x
Annual Trading budget available for allocation as
determined in Section 225.425 and allocated pursuant to this Section 225.440.
b)
The Agency will allocate CAIR NO
x
allowances to each CAIR NO
x
unit on a pro-
rata basis using the unit’s total converted gross electrical output calculated
pursuant to Section 225.435. If there are insufficient allowances to allocate whole
allowances pro rata, these unallocated allowances will be retained by the Agency
and will be available for allocation in later control periods.
(Source: Added at 31 Ill. Reg. ________________, effective ______________)
Section 225.445
New Unit Set-Aside (NUSA)
For the 2009 control period and each control period thereafter, the Agency will allocate CAIR
NO
x
allowances from the NUSA to CAIR NO
x
units that commenced commercial operation on
or after January 1, 2006, and do not yet have an allocation for the particular control period
pursuant to Section 225.440, in accordance with the following procedures:
a)
Beginning with the 2009 control period and each control period thereafter, the
Agency will establish a separate NUSA for each control period. Each NUSA will
be allocated CAIR NO
x
allowances equal to 5 percent of the amount of tons of
NO
x
emissions in the base CAIR NO
x
Annual Trading budget in Section 225.425.
b)
The CAIR designated representative of a new CAIR NO
x
unit may submit to the
Agency a request, in a format specified by the Agency, to be allocated CAIR NO
x
allowances from the NUSA starting with the first control period after the control
80
period in which the new unit commences commercial operation and until the first
control period for which the unit may use CAIR NO
x
allowances allocated to the
unit pursuant to Section 225.440. The NUSA allowance allocation request may
only be submitted after a new unit has operated during one control period, and no
later than March 1 of the control period for which allowances from the NUSA are
being requested.
c)
In a NUSA allowance allocation request pursuant to subsection (b) of this
Section, the CAIR designated representative must provide in its request
information for gross electrical output and useful thermal energy, if any, for the
new CAIR NO
x
unit for that control period.
d)
The Agency will allocate allowances from the NUSA to a new CAIR NO
x
unit
using the following procedures:
1)
For each new CAIR NO
x
, the unit’s gross electrical output for the most
recent control period will be used to calculate the unit’s gross electrical
output. If a generator is served by two or more units, the gross electrical
output of the generator will be attributed to each unit in proportion to the
unit’s share of the total control period heat input of these units for the
control period. The new unit’s converted gross electrical output will be
calculated as follows:
A)
If the unit is coal-fired:
CGO (in MWh) = GO
×
1.0;
B)
If the unit is oil-fired:
CGO (in MWh) = GO
×
0.6; or
C)
If the unit is neither coal-fired nor oil-fired:
CGO (in MWh) = GO
×
0.4.
2)
If the unit is a combustion turbine or boiler and has equipment used to
produce electricity and useful thermal energy for industrial, commercial,
heating, or cooling purposes through the sequential use of energy, the
Agency will add the converted gross electrical output calculated for
electricity pursuant to subsection (d)(1) of this Section to the converted
useful thermal energy to determine the total converted gross electrical
output for the unit. The Agency will determine the converted useful
thermal energy using the unit’s useful thermal energy for the most recent
control period. The converted useful thermal energy will be determined
using the following equations:
A)
If the unit is coal-fired:
CUTE (in MWh) = UTE (in mmBtu)
×
0.2930;
81
B)
If the unit is oil-fired:
CUTE (in MWh) = UTE (in mmBtu)
×
0.1758; or
C)
If the unit is neither coal-fired nor oil-fired:
CUTE (in MWh) = UTE (in mmBtu)
×
0.1172.
3)
The gross electrical output and useful thermal energy in subsections (d)(1)
and (d)(2) of this Section for each control period will be based on the best
available data reported or available to the Agency for the CAIR NO
x
unit
pursuant to the provisions of Section 225.450.
4)
The Agency will determine a unit’s unprorated allocation (
UA
y
) using the
unit’s converted gross electrical output plus the unit’s converted useful
thermal energy, if any, calculated in subsections (d)(1) and (d)(2) of this
Section, converted to approximate NO
x
tons (the unit’s unprorated
allocation), as follows:
2000lbs / ton
TCGO * (1.0lbs / MWh)
UA
y
y
=
Where:
UA
y
=
unprorated allocation to a new
CAIR NO
x
unit.
TCGO
y
=
total converted gross electrical output for a
new CAIR NO
x
unit.
5)
The Agency will allocate CAIR NO
x
allowances from the NUSA to new
CAIR NO
x
units as follows:
A)
If the NUSA for the control period for which CAIR NO
x
allowances are requested has a number of allowances greater than
or equal to the total unprorated allocations for all new units
requesting allowances, the Agency will allocate the number of
allowances using the unprorated allocation determined for that unit
pursuant to subsection (d)(4) of this Section.
B)
If the NUSA for the control period for which the allowances are
requested has a number of CAIR NO
x
allowances less than the
total unprorated allocation to all new CAIR NO
x
units requesting
allocations, the Agency will allocate the available allowances for
new CAIR NO
x
units on a pro-rata basis, using the unprorated
allocation determined for that unit pursuant to subsection (d)(4) of
this Section. If there are insufficient allowances to allocate whole
82
allowances, the unallocated allowances will be retained by the
Agency and will be available for allocation in a later control
period.
C)
If the gross electrical output or useful thermal energy reported to
the Agency in subsection (d) of this Section is later determined to
be greater than the unit’s actual gross electrical output or useful
thermal energy for the applicable control period, the Agency will
reduce the unit’s allocation from the NUSA for the current control
period to account for the excess allowances allocated in the prior
control period or periods.
e)
The Agency will review each NUSA allowance allocation request pursuant to
subsection (b) of this Section. The Agency will accept a NUSA allowance
allocation request only if the request meets, or is adjusted by the Agency as
necessary to meet, the requirements of this Section 225.445.
f)
By June 1 of the applicable control period, the Agency will notify each CAIR
designated representative that submitted a NUSA allowance request of the amount
of CAIR NO
x
allowances from the NUSA, if any, allocated for the control period
to the new unit covered by the request.
g)
The Agency will allocate CAIR NO
x
allowances to new units from the NUSA no
later than October 31 of the applicable control period.
h)
After a new CAIR NO
x
unit has operated in one control period, it becomes an
existing unit for the purposes of Section 225.440 only, and the Agency will
allocate CAIR NO
x
allowances for that unit, for the control period commencing
four years in the future pursuant to Section 225.440. For example, if a unit
commences commercial operation in 2009, in 2010, the Agency will allocate to
that unit allowances pursuant to Section 225.440 for the 2014 control period. The
new CAIR NO
x
unit will continue to receive CAIR NO
x
allowances from the
NUSA according to this Section until the unit is eligible to use the CAIR NO
x
allowances allocated to the unit pursuant to Section 225.440.
i)
If, after the completion of the procedures in subsection (c) of this Section for a
control period, any unallocated CAIR NO
x
allowances remain in the NUSA for
the control period, the Agency will, at a minimum, accrue those CAIR NO
x
allowances for future control period allocations to new CAIR NO
x
units. The
Agency may from time to time elect to retire CAIR NO
x
allowances in the NUSA
that are in excess of 15,881 for the purposes of continued progress toward
attainment and maintenance of National Ambient Air Quality Standards pursuant
to the CAA.
(Source: Added at 31 Ill. Reg. ________________, effective ______________)
83
Section 225.450
Monitoring, Recordkeeping and Reporting Requirements for Gross
Electrical Output and Useful Thermal Energy
a)
By January 1, 2008, or by the date of commencing commercial operation,
whichever is later, the owner or operator of the CAIR NO
x
unit must operate a
system for measuring gross electrical output that is consistent with the
requirements of either 40 CFR 60 or 75; must measure gross electrical output in
MW-hrs using such a system; and must record the output of the measurement
system. If a generator is served by two or more units, the information to
determine each unit’s heat input for that control period must also be recorded, so
as to allow each unit’s share of the gross electrical output to be determined. If
heat input data is used, the owner or operator must comply with the applicable
provisions 40 CFR 75, as incorporated by reference in Section 225.140.
b)
For a CAIR NO
x
unit that is a cogeneration unit by January 1, 2008, or by the date
the CAIR NO
x
unit commences to produce useful thermal energy, whichever is
later, the owner or operator of a CAIR NO
x
unit with cogeneration capabilities
must install, calibrate, maintain, and operate meters for steam flow in lbs/hr,
temperature in degrees Fahrenheit, and pressure in PSI, to measure and record the
useful thermal energy that is produced, in mmBtu/hr, on a continuous basis.
Owners and operators of a CAIR NO
x
unit that produces useful thermal energy
but uses an energy transfer medium other than steam, e.g., hot water or glycol,
must install, calibrate, maintain, and operate the necessary meters to measure and
record the necessary data to express the useful thermal energy produced, in
mmBtu/hr, on a continuous basis. If the CAIR NO
x
unit ceases to produce useful
thermal energy, the owner or operator may cease operation of the meters,
provided that operation of these meters must be resumed if the CAIR NO
x
unit
resumes production of useful thermal energy.
c)
The owner or operator of a CAIR NO
x
unit must either report gross electrical
output data to the Agency or comply with the applicable provisions for providing
heat input data as follows:
1)
By June 1, 2007, the gross electrical output for control periods 2001, 2002,
2003, 2004 and 2005, if available, and, the unit’s useful thermal energy
data, if applicable. If a generator is served by two or more units, the
documentation needed to determine each unit’s share of the heat input of
such units for that control period must also be submitted. If heat input
data is used, the owner or operator must comply with the applicable
provisions 40 CFR 75, as incorporated by reference in Section 225.140.
2)
By June 1, 2008, the gross electrical output for control periods 2006 and
2007, if available, and the unit’s useful thermal energy data, if applicable.
If a generator is served by two or more units, the documentation needed to
determine each unit’s share of the heat input of such units for that control
84
period must also be submitted. If heat input data is used, the owner or
operator must comply with the applicable provisions of 40 CFR 75, as
incorporated by reference in Section 225.140.
d)
Beginning with year 2008, the CAIR designated representative of the CAIR NO
x
unit must submit to the Agency quarterly, by no later than April 30, July 31,
October 31, and January 31 of each year, information for the CAIR NO
x
unit’s
gross electrical output, on a monthly basis for the prior quarter, and, if applicable,
the unit’s useful thermal energy for each month.
e)
The owner or operator of a CAIR NO
x
unit must maintain on-site the monitoring
plan detailing the monitoring system, maintenance of the monitoring system,
including quality assurance activities pursuant to the requirements of 40 CFR 60
and 75, including the applicable provisions for the measurement of gross
electrical output for the CAIR NO
x
trading program and, if applicable, for new
units. The monitoring plan must include, but is not limited to:
1)
A description of the system to be used for the measurement of gross
electrical output pursuant to Section 225.450(a), including a list of any
data logging devices, solid-state kW meters, rotating kW meters,
electromechanical kW meters, current transformers, transducers, potential
transformers, pressure taps, flow venturi, orifice plates, flow nozzles,
vortex meters, turbine meters, pressure transmitters, differential pressure
transmitters, temperature transmitters, thermocouples, resistance
temperature detectors, and any equipment or methods used to accurately
measure gross electrical output.
2)
A certification statement by the CAIR designated representative that all
components of the gross electrical output system have been tested to be
accurate within three percent and that the gross electrical output system is
accurate to within ten percent.
f)
The owner or operator of a CAIR NO
x
unit must retain records for at least 5 years
from the date the record is created or the data collected in subsections (a) and (b)
of this Section, and the reports submitted to the Agency and USEPA in
accordance with subsections (c) and (d) of this Section. The owner or operator of
a CAIR NO
x
unit must retain the monitoring plan required in subsection (e) of this
Section for at least five years from the date that it is replaced by a new or revised
monitoring plan.
(Source: Added at 31 Ill. Reg. ________________, effective ______________)
Section 225.455
Clean Air Set-Aside (CASA)
85
a)
A project sponsor may apply for allowances from the CASA for sponsoring an
energy efficiency and conservation, renewable energy, or clean technology
project as set forth in Section 225.460 by submitting the application required by
Section 225.470.
b)
Notwithstanding subsection (a) of this Section, a project sponsor with a CAIR
NO
x
source that is out of compliance with this Subpart for a given control period
may not apply for allowances from the CASA for that control period. If a source
receives CAIR NO
x
allowances from CASA and then is subsequently found to
have been out of compliance with this Subpart for the applicable control period or
periods, the project sponsor must restore the CAIR NO
x
allowances that it
received pursuant to its CASA request or an equivalent number of CAIR NO
x
allowances to the CASA within six months of receipt of an Agency notice that
NO
x
allowances must be restored. These allowances will be assigned to the fund
from which they were distributed.
c)
CAIR NO
x
allowances from CASA will be allocated in accordance with the
procedures in Section 225.475.
d)
The project sponsor may submit an application that aggregates two or more
projects under a CASA project category that would individually result in less than
one allowance, but that equal at a minimum one whole allowance when
aggregated.
(Source: Added at 31 Ill. Reg. ________________, effective ______________)
Section 225.460
Energy Efficiency and Conservation, Renewable Energy, and Clean
Technology Projects
a)
Energy efficiency and conservation project means any of the following projects
implemented and located in Illinois:
1)
Demand side management projects that reduce overall power demand by
using less energy, include:
A)
Smart building management software that more efficiently
regulates power flows.
B)
The use of or replacement to high efficiency motors, pumps,
compressors, or steam systems.
C)
Lighting retrofits.
2)
Energy efficient new building construction projects include:
86
A)
ENERGY STAR-qualified new home projects.
B)
Measures to reduce or conserve energy consumption beyond the
requirements of the Illinois Energy Conservation Code for
Commercial Buildings (20 ILCS 687/6-3).
C)
New residential construction projects that qualify for Energy
Efficient Tax Incentives pursuant to the Energy Policy Act of
2005, 42 U.S.C. 15801 (2005).
3)
Supply-side energy efficiency projects include projects implemented to
improve the efficiency in electricity generation by coal-fired power plants,
and the efficiency of electrical transmission and distribution systems.
4)
Highly efficient power generation projects, such as, but not limited to,
combined cycle projects, combined heat and power, and microturbines.
To be considered a highly efficient power generation project pursuant to
this subsection (a)(4), a project must meet the applicable thresholds and
criteria listed below:
A)
For combined heat and power projects generating both electricity
and useful thermal energy for space, water, or industrial process
heat, a rated-energy efficiency of at least 60 percent and is not a
CAIR NO
x
unit.
B)
For combined cycle projects rated at greater than 0.50 MW, a
rated-energy efficiency of at least 50 percent.
C)
For microturbine projects rated at or below 0.50 MW and all other
projects, rated-energy efficiency of at least 40 percent.
b)
Renewable energy project means any of the following projects implemented and
located in Illinois:
1)
Zero-emission electric generating projects, including wind, solar (thermal
or photovoltaic), and hydropower projects. Eligible hydropower plants are
restricted to new generators, that are not replacements of existing
generators, that commence operation on or after January 1, 2006, and do
not involve the significant expansion of an existing dam or the
construction of a new dam.
2)
Renewable energy units are those units that generate electricity using more
than 50 percent of the heat input, on an annual basis, from dedicated crops
grown for energy production or the capture systems for methane gas from
landfills, water treatment plants or sewage treatment plants, and organic
waste biomass, and other similar sources of non-fossil fuel energy.
87
Renewable energy projects do not include energy from incineration by
burning or heating of waste wood, tires, garbage, general household,
institutional lunchroom or office waste, landscape waste, or construction
or demolition debris.
c)
Clean technology project for reducing emissions from producing electricity and
useful thermal energy means any of the following projects implemented and
located in Illinois:
1)
Air pollution control equipment upgrades at existing coal-fired EGUs, as
follows: installation of flue gas desulfurization (FGD) for control of SO
2
emissions; installation of a baghouse for control of particulate matter
emissions; and installation of selective catalytic reduction (SCR), selective
non-catalytic reduction (SNCR), or other add-on control devices for
control of NO
x
emissions. Air pollution control upgrade projects do not
include the addition of low NO
x
burners, overfired air techniques or gas
reburning techniques for control of NO
x
emissions; projects involving flue
gas conditioning techniques or upgrades, or replacement of electrostatic
precipitators; or addition of activated carbon injection or other sorbent
injection system for control of mercury. For this purpose, a unit will be
considered “existing” after it has been in commercial operation for at least
eight years.
2)
Clean coal technologies projects include:
A)
Integrated gasification combined cycle (IGCC) plants.
B)
Fluidized bed coal combustion.
d)
In addition to those projects excluded in subsections (a) through (c) of this
Section, the following projects are also not energy efficiency and conservation,
renewable energy, or clean technology projects:
1)
Nuclear power projects.
2)
Projects required to meet emission standards or technology requirements
under State or federal law or regulation, except that allowances may be
allocated for:
A)
The installation of a baghouse.
B)
Projects undertaken pursuant to Section 225.233.
3)
Projects used to meet the requirements of a court order or consent decree,
except that allowances may be allocated for:
88
A)
Emission rates or limits achieved that are lower than what is
required to meet the emission rates or limits for SO
2
or NO
x,
or for
installing a baghouse as provided for in a court order or consent
decree entered into before May 30, 2006.
B)
Projects used to meet the requirements of a court order or consent
decree entered into on or after May 30, 2006, if the court order or
consent decree does not specifically preclude such allocations.
4)
A Supplemental Environmental Project (SEP).
e)
Applications for projects implemented and located in Illinois that are not
specifically listed in subsections (a) through (c) of this Section, and that are not
specifically excluded by definition in subsections (a) through (c) of this Section or
by specific exclusion in subsection (d) of this Section, may be submitted to the
Agency. The application must designate which category or categories from those
listed in subsections (a)(1) through (c)(2)(A) of this Section best fits the proposed
project and the applicable formula pursuant to Section 225.465(b) to calculate the
number of allowances that it is requesting. The Agency will determine whether
the application is approvable based on a sufficient demonstration by the project
sponsor that the project is a new type of energy efficiency, renewable energy, or
clean technology project, similar in its effects as the projects specifically listed in
subsection (a) through (c)(2)(A) of this Section.
f)
Early adopter projects include projects that meet the criteria for any energy
efficiency and conservation, renewable energy, or clean technology projects listed
in subsections (a), (b), (c), and (e) of this Section and commence construction
between July 1, 2006, and December 31, 2012.
(Source: Added at 31 Ill. Reg. ________________, effective ______________)
Section 225.465
Clean Air Set-Aside (CASA) Allowances
a)
The CAIR NO
x
allowances for the CASA for each control period will be assigned
to the following categories of projects:
Phase I
Phase II
(2009-2014) (2015 and thereafter)
1)
Energy Efficiency and Conservation/ 9149
7625
Renewable Energy
2)
Air Pollution Control Equipment
3811
3175
Upgrades
89
3)
Clean Coal Technology
4573
3810
4)
Early Adopters
1525
1271
b)
The following formulas must be used to determine the number of CASA
allowances that may be allocated to a project per control period:
1)
For an energy efficiency and conservation project pursuant to Sections
225.460(a)(1) through (a)(4)(A), the number of allowances must be
calculated using the number of megawatt hours of electricity that was not
consumed during a control period and the following formula:
A
=
(MWh
c
)
×
(1.5 lb/MWh) / 2000 lb
Where:
A
=
The number of allowances for a particular project.
MWh
c
=
The number of megawatt hours of electricity
conserved or generated during a control period by a
project.
2)
For a zero emission electric generating projects pursuant to Section
225.460(b)(1), the number of allowances must be calculated using the
number of megawatt hours of electricity generated during a control period
and the following formula:
A
=
(MWh
g
)
×
(2.0 lb/MWh) / 2000 lb
Where:
A
=
The number of allowances for a particular project
MWh
g
=
The number of megawatt hours of electricity
generated during a control period by a project.
3)
For a renewable energy emission unit pursuant to Section 225.460(b)(2),
the number of allowances must be calculated using the number of MWhs
of electricity generated during a control period and the following formula:
A
=
(MWh
g
)
×
(0.5 lb/MWh) / 2000 lb
Where:
A
=
The number of allowances for a particular project.
MWh
g
=
The number of MW hours of electricity generated
during a control period by a project.
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4)
For an air pollution control equipment upgrade project pursuant to Section
225.460(c)(1), the number of allowances will be calculated as follows:
A)
For NO
x
or SO
2
control projects, by determining the difference in
emitted NO
x
or SO
2
per control period using the emission rate
before and after replacement or improvement, and the following
formula:
A=
(MWh
g
)
×
K
×
(ER
B
lb/MWh - ER
A
lb/MWh) / 2000 lb
Where:
A
=
The number of allowances for a particular
project.
MWh
g
=
The number of megawatt hours of electricity
generated during a control period by a
project.
K
=
The pollutant factor: for NO
x
, K= 0.1; and
for SO
2
, K = 0.05.
ER
B
=
Average NO
x
or SO
2
emission rate based on
CEMS data from the most recent two
control periods prior to the replacement or
improvement of the control equipment in
lb/MWh, unless subject to a court order
or consent decree. For units subject to a
court order or consent decree entered into
before May 30, 2006, ER
B
is limited to
emission rates that are lower than the
emission rate required in the consent decree
or court order. For a court order or consent
decree entered into after May 30, 2006, ER
B
is limited to the lesser of the emission rate
specified in the court order or consent
decree or the actual average emission rate
during the control period. If such limit is
not expressed in lb/MWh, the limit must be
converted into lb/MWh using a heat rate of
10 mmBtu/1 MW.
ER
A
=
Annual NO
x
or SO
2
average emission rate
for the applicable control period data based
on CEMS data in lb/MWh.
B)
For a baghouse project:
A =
(MWh
g
)
×
(Q lb/MWh) / 2000 lb
Where:
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A =
The number of allowances for a
particular project.
MWh
g
=
The number of MWh of
electricity generated during a control period
or the portion of a control period that the
units were controlled by the baghouse.
Q
=
1)
If a baghouse was not installed pursuant to a
consent decree or court order, Q shall equal
0.2.
2)
If a baghouse was installed pursuant to a
consent decree or court order which assigns
a Q factor, then Q equals the factor
established in the consent decree or court
order but must not exceed a factor of 0.2.
3)
If a baghouse was installed pursuant to a
consent decree or court order which does not
assign a Q factor then Q shall equal:
Q= 0.25 – (P x ER
q
)
Where:
P = If the most recent control period’s
average PM emission rate was based on PM
CEMS data, P equals 1.0; otherwise P = 1.1.
ER
q
= The magnitude of most recent control
period’s average PM emission rate in
lb/MWh exiting the baghouse, subject to the
following limits:
If P = 1.0, then 1/10
≤
ER
q
≤
2/10
If P = 1.1, then 1/11
≤
ER
q
≤
2/11
If the ER
q
is less than the lower limit, the
lower limit shall be used. If ER
q
is greater
than the upper limit, the upper limit shall be
used. If ER
q
is not expressed in lb/MWh, the
number must be converted to lb/MWh using
a heat ratio of 10 mmBtu/1 MW.
5)
For highly efficient power generation and clean technology projects
pursuant to Sections 225.460(a)(4)(B), (a)(4)(C), and (c)(2), the number of
92
allowances must be calculated using the number of megawatt hours of
electricity the project generates during a control period and the following
formula:
A
=
(MWh
g
)
×
(1.0 lb/MWh – ER lb/MWh) / 2000 lb
Where:
A
=
The number of allowances for a particular project.
MWh
g
=
The number of megawatt hours of electricity
generated during a control period by a project.
ER
=
Annual average NO
x
emission rate based on CEMS
data in 1b/MWh.
6)
For a CASA project that commences construction before December 31,
2012, in addition to the allowances allocated pursuant to subsections
(b)(1) through (b)(5) of this Section, a project sponsor may also request
additional allowances pursuant to the early adopter project category
pursuant to Section 225.460(e) based on the following formula:
A
=
1.0 + 0.10
×
Σ
A
i
Where:
A
=
The number of allowances for a particular project as
determined in subsections (b)(1) through (b)(5) of
this Section.
A
i
=
The number of allowances as determined in
subsection (b)(1), (b)(2), (b)(3), (b)(4) or (b)(5) of
this Section for a given project.
(Source: Added at 31 Ill. Reg. ________________, effective ______________)
Section 225.470
Clean Air Set-Aside (CASA) Applications
a)
A project sponsor may request allowances if the project commenced construction
on or after the dates listed below. The project sponsor may request and be
allocated allowances from more than one CASA category for a project, if
applicable.
1)
Demand side management, energy efficient new construction, and supply
side energy efficiency and conservation projects that commenced
construction on or after January 1, 2003;
93
2)
Fluidized bed coal combustion projects, highly efficient power generation
operations projects, or renewable energy emission units, which
commenced construction on or after January 1, 2001; and
3)
All other projects on or after July 1, 2006.
b)
Beginning with the 2009 control period and each control period thereafter, a
project sponsor may request allowances from the CASA. The application must be
submitted to the Agency by May 1 of the control period for which the allowances
are being requested.
c)
The allocation will be based on the electricity conserved or generated in the
control period preceding the calendar year in which the application is submitted.
To apply for a CAIR NO
x
allocation from the CASA, project sponsors must
provide the Agency with the following information:
1)
Identification of the project sponsor, including name, address, type of
organization, certification that the project sponsor has met the definition of
“project sponsor” as set forth in Section 225.130,and name(s) of the
principals or corporate officials.
2)
The number of the CAIR NO
x
general or compliance account for the
project and the name of the associated CAIR account representative.
3)
A description of the project or projects, location, the role of the project
sponsor in the projects, and a general explanation of how the amount of
energy conserved or generated was measured, verified, and calculated, and
the number of allowances requested with the supporting calculations.
The number of allowances requested will be calculated using the
applicable formula from Section 225.470(b).
4)
Detailed information to support the request for allowances, including the
following types of documentation for the measurement and verification of
the NO
x
emissions reductions, electricity generated, or electricity
conserved using established measurement verification procedures, as
applicable. The measurement and verification required will depend on the
type of project proposed.
A)
As applicable, documentation of the project’s base and control
period conditions and resultant base and control period energy
data, using the procedures and methods included in
M&V
Guidelines: Measurement and Verification for Federal Energy
Projects,
incorporated by reference in Section 225.140, or other
method approved by the Agency. Examples include:
i)
Energy consumption and demand profiles;
94
ii)
Occupancy type;
iii)
Density and periods;
iv)
Space conditions or plant throughput for each operating
period and season. (For example, in a building this would
include the light level and color, space temperature,
humidity and ventilation);
v)
Equipment inventory, nameplate data, location, condition;
and
vi)
Equipment operating practices (schedules and set points,
actual temperatures/pressures).
B)
Emissions data, including, if applicable, CEMS data;
C)
Information for rated–energy efficiency including supporting
documentation and calculations; and
D)
Electricity, in MWh generated or conserved for the applicable
control period.
5)
Notwithstanding the requirements of subsections (c)(4) of this Section,
applications for fewer than five allowances may propose other reliable and
applicable methods of quantification acceptable to the Agency.
6)
Any additional information requested by the Agency to determine the
correctness of the requested number of allowances, including site
information, project specifications, supporting calculations, operating
procedures, and maintenance procedures.
7)
The following certification by the responsible official for the project
sponsor and the applicable CAIR account representative for the project:
“I am authorized to make this submission on behalf of the project sponsor
and the holder of the CAIR NO
x
general account or compliance account
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 application 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.”
95
d)
A project sponsor may request allowances from the CASA for each project a total
number of control periods not to exceed the number of control periods listed
below. After a project has been allocated allowances from CASA, subsequent
requests for the project from the project sponsor must include the information
required by subsections (c)(1), (c)(2), (c)(3) and (c)(7) of this Section, a
description of any changes, or further improvements made to the project, and
information specified in subsections (c)(5) and (c)(6) as specifically requested by
the Agency.
1)
For energy efficiency and conservation projects (except for efficient
operation and renewable energy projects), for a total of eight control
periods.
2)
For early adopter projects, for a total of ten control periods.
3)
For air pollution control equipment upgrades for a total of 15 control
periods.
4)
For renewable energy projects, clean coal technology, and highly efficient
power generation projects, for each year that the project is in operation.
e)
A project sponsor must keep copies of all CASA applications and the
documentation used to support the application for at least five years.
(Source: Added at 31 Ill. Reg. ________________, effective ______________)
Section 225.475
Agency Action on Clean Air Set-Aside (CASA) Applications
a)
By September 1, 2009, and each September 1 thereafter, the Agency will
determine the total number of allowances that are approvable for allocation to
project sponsors based upon the applications submitted pursuant to Section
225.470.
1)
The Agency will determine the number of CAIR NO
x
allowances that are
approvable based on the formulas and the criteria for these projects. The
Agency will notify a project sponsor within 90 days after receipt of an
application if the project is not approvable, the number of allowances
requested is not approvable, or additional information is needed by the
Agency to complete its review of the application.
2)
If the total number of CAIR NO
x
allowances requested for approved
projects is less than or equal to the number of CAIR NO
x
allowances in
the CASA project category, the number of allowances that are approved
will be allocated to each CAIR NO
x
compliance or general account.
96
3)
If more CAIR NO
x
allowances are requested than the number of CAIR
NO
x
allowances in a given CASA project category, allowances will be
allocated on a pro-rata basis based on the number of allowances available,
subject to further adjustment as provided for by subsection (b) of this
Section. CAIR NO
x
allowances will be allocated, transferred, or used as
whole allowances. The number of whole allowances will be determined
by rounding down for decimals less than 0.5 and rounding up for decimals
of 0.5 or greater.
b)
For control periods 2011 and thereafter, if there are, after the completion of the
procedures in subsection (a) of this Section for a control period, any CAIR NO
x
allowances not allocated to a CASA project for the control period:
1)
The remaining allowances will accrue in each CASA project category up
to twice the number of allowances that are assigned to the project category
each control period as set forth in Section 225.465.
2)
If any allowances remain after allocations pursuant to subsection (a) of
this Section, the Agency will allocate these allowances pro rata to projects
that received fewer allowances than requested, based on the number of
allowances not allocated but approved by the Agency for the project under
CASA. No project may be allocated more allowances than approved by
the Agency for the applicable control period.
3)
If any allowances remain after the allocation of allowances pursuant to
subsection (b)(2) of this Section, the Agency will then distribute pro rata
the remaining allowances to project categories that have fewer than twice
the number of allowances assigned to that project category. The pro rata
distribution will be based on the difference between two times the project
category and the number of allowances that remain in the project category.
4)
If allowances still remain undistributed after the allocations and
distributions in the above subsections are completed, the Agency may
elect to retire the CAIR NO
x
allowances that have not been distributed to
any CASA category to continue progress toward attainment or
maintenance of the National Ambient Air Quality Standards pursuant to
the CAA.
(Source: Added at 31 Ill. Reg. ________________, effective ______________)
Section 225.480
Compliance Supplement Pool
In addition to the CAIR NO
x
allowances allocated pursuant to Section 225.425, the USEPA has
provided an additional 11,299 CAIR NO
x
allowances from the federal compliance supplement
97
pool to Illinois for the control period in 2009. On January 1, 2009, the Agency will retire all
11,299 NO
x
allowances for public health and air quality improvements.
(Source: Added at 31 Ill. Reg. ________________, effective ______________)
SUBPART E: CAIR NO
x
OZONE SEASON TRADING PROGRAM
Section 225.500
Purpose
The purpose of this Subpart E is to control the seasonal emissions of nitrogen oxides (NO
x
) from
EGUs by determining allocations and implementing the CAIR NO
x
Ozone Season Trading
Program.
(Source: Added at 31 Ill. Reg. ________________, effective ______________)
Section 225.505
Applicability
a)
Except as provided in subsections (b)(1), (b)(3), and (b)(4) of this Section:
1)
The following units are CAIR NO
x
Ozone Season units, and any source
that includes one or more such units is a CAIR NO
x
source subject to the
requirements of this Subpart E: any stationary, fossil-fuel-fired boiler or
stationary, fossil-fuel-fired combustion turbine serving at any time, since
the later of November 15, 1990 or the start-up the unit’s combustion
chamber, a generator with nameplate capacity of more than 25 MWe
producing electricity for sale.
2)
If a stationary boiler or stationary combustion turbine that, pursuant to
subsection (a)(1) of this Section, is not a CAIR NO
x
Ozone Season unit
begins to combust fossil fuel or to serve a generator with nameplate
capacity of more than 25 MWe producing electricity for sale, the unit will
become a CAIR NO
x
Ozone Season unit as provided in subsection (a)(1)
of this Section on the first date on which it both combusts fossil fuel and
serves such generator.
b)
The units that meet the requirements set forth in subsections (b)(1), (b)(3), and
(b)(4) of this Section will not be CAIR NO
x
units and units that meet the
requirements of subsections (b)(2) and (b)(5) of this Section are CAIR NO
x
Ozone Season units:
1)
Any unit that is a CAIR NO
x
Ozone Season unit pursuant to subsection
(a)(1) or (a)(2) of this Section and:
98
A)
Qualifies as a cogeneration unit during the 12-month period
starting on the date the unit first produces electricity and
continuing to qualify as a cogeneration unit; and
B)
Does not serve at any time, since the later of November 15, 1990
or the start-up of the unit’s combustion chamber, a generator with
nameplate capacity of more than 25 MWe supplying any calendar
year more than one-third of the of the unit’s potential electric
output capacity or 219,000 MWh, whichever is greater, to any
utility power distribution for sale.
2)
If a unit qualifies as a cogeneration unit during the 12-month period
starting on the date the unit first produces electricity and meets the
requirements of subsection (b)(1) of this Section for at least one calendar
year, but subsequently no longer meets all such requirements, the unit
shall become a CAIR NO
x
Ozone Season unit starting on the earlier of
January 1 after the first calendar year during which the unit no longer
qualifies as a cogeneration unit or January 1 after the first calendar year
during which the unit no longer meets the requirements of subsection
(b)(1)(B) of this Section.
3)
Any unit that is a CAIR NO
x
Ozone Season unit pursuant to subsection
(a)(1) or (a)(2) of this Section commencing operation before January 1,
1985 and:
A)
Qualifies as a solid waste incineration unit; and
B)
With an average annual fuel consumption of non-fossil fuel for
1985-1987 exceeding 80 percent (on a Btu basis) and an average
annual fuel consumption of non-fossil fuel for any three
consecutive calendar years after 1990 exceeding 80 percent (on a
Btu basis).
4)
Any unit that is a CAIR NO
x
Ozone Season unit under subsection (a)(1) or
(a)(2) of this Section commencing operation on or after January 1, 1985:
and
A)
Qualifies as a solid waste incineration unit; and
B)
With an average annual fuel consumption of non-fossil fuel the
first three years of operation exceeding 80 percent (on a Btu basis)
and an average annual fuel consumption of non-fossil fuel for any
three consecutive calendar years after 1990 exceeding 80 percent
(on a Btu basis).
99
5)
If a unit qualifies as a solid waste incineration unit and meets the
requirements of subsection (b)(3) or (b)(4) of this Section for at least three
consecutive years, but subsequently no longer meets all such
requirements, the unit shall become a CAIR NO
x
Ozone Season unit
starting on the earlier of January 1 after the first three consecutive calendar
years after 1990 for which the unit has an average annual fuel
consumption of fuel of 20 percent or more.
(Source: Added at 31 Ill. Reg. ________________, effective ______________)
Section 225.510
Compliance Requirements
a)
The owner or operator of a CAIR NO
x
Ozone Season unit must comply with the
requirements of the CAIR NO
x
Ozone Season Trading Program for Illinois as set
forth in this Subpart E and 40 CFR 96, subpart AAAA (CAIR NO
x
Ozone Season
Trading Program General Provisions) (excluding 40 CFR 96.304, 96.305(b)(2),
and 96.306); 40 CFR 96, subpart BBBB (CAIR Designated Representative for
CAIR NO
x
Ozone Season Sources); 40 CFR 96, subpart FFFF (CAIR NO
x
Ozone
Season Allowance Tracking System); 40 CFR 96, subpart GGGG (CAIR NO
x
Ozone Season Allowance Transfers); and 40 CFR 96, subpart HHHH
(Monitoring and Reporting); as incorporated by reference in Section 225.140.
b)
Permit requirements:
1)
The owner or operator of each source with one or more CAIR NO
x
Ozone
Season units at the source must apply for a permit issued by the Agency
with federally enforceable conditions covering the CAIR NO
x
Ozone
Season Trading Program (“CAIR permit”) that complies with the
requirements of Section 225.520 (Permit Requirements).
2)
The owner or operator of each CAIR NO
x
Ozone Season source and each
CAIR NO
x
Ozone Season unit at the source must operate the CAIR NO
x
Ozone Season unit in compliance with its CAIR permit.
c)
Monitoring requirements:
1)
The owner or operator of each CAIR NO
x
Ozone Season source and each
CAIR NO
x
Ozone Season unit at the source must comply with the
monitoring requirements of 40 CFR 96, subpart HHHH; 40 CFR 75; and
Section 225.550. The CAIR designated representative of each CAIR NO
x
Ozone Season source and each CAIR NO
x
Ozone Season unit at the
source must comply with those sections of the monitoring, reporting and
recordkeeping requirements of 40 CFR 6, subpart HHHH, applicable to a
CAIR designated representative.
100
2)
The compliance of each CAIR NO
x
Ozone Season source with the CAIR
NO
x
Ozone Season emissions limitation pursuant to subsection (d) of this
Section will be determined by the emissions measurements recorded and
reported in accordance with 40 CFR 96, subpart HHHH.
d)
Emission requirements:
1)
By the allowance transfer deadline, November 30, 2009, and by
November 30, of each subsequent year, the owner or operator of each
CAIR NO
x
Ozone Season source and each CAIR NO
x
Ozone Season unit
at the source must hold allowances available for compliance deductions
pursuant to 40 CFR 96.354(a) in the CAIR NO
x
Ozone Season source’s
compliance account. The allowance transfer deadline means by midnight
of November 30 (if it is business day) or midnight of the first business day
thereafter. The number of allowances held may not be less than the tons
of NO
x
emissions for the control period from all CAIR NO
x
Ozone Season
units at the CAIR NO
x
Ozone Season source, as determined in accordance
with 40 CFR 96, subpart HHHH.
2)
Each ton of NO
x
emitted in excess of the number of CAIR NO
x
Ozone
Season allowances held by the owner or operator for each CAIR NO
x
Ozone Season unit in its CAIR NO
x
Ozone Season compliance account for
each day of the applicable control period will constitute a separate
violation of this Subpart E, the Act, and the CAA.
3)
Each CAIR NO
x
Ozone Season unit will be subject to the monitoring
requirements of subsection (c)(1) of this Section starting on the later of
May 1, 2009, or the deadline for meeting the unit’s monitoring
certification requirements pursuant to 40 CFR 96.370(b)(1), (b)(2) or
(b)(3) and for each control period thereafter.
4)
CAIR NO
x
Ozone Season allowances must be held in, deducted from, or
transferred into among allowance accounts in accordance with this
Subpart and 40 CFR 96, subparts FFFF and GGGG.
5)
In order to comply with the requirements of subsection (d)(1) of this
Section, a CAIR NO
x
Ozone Season allowance may not be deducted for
compliance according to subsection (d)(1) of this Section, for a control
period in a calendar year before the year for which the CAIR NO
x
Ozone
Season allowance is allocated.
6)
A CAIR NO
x
Ozone Season allowance allocated by the Agency or
USEPA pursuant to the CAIR NO
x
Ozone Season Trading Program is a
limited authorization to emit one ton of NO
x
in accordance with the CAIR
NO
x
Ozone Season Trading Program. No provision of the CAIR NO
x
Ozone Season Trading Program, the CAIR permit application, the CAIR
101
permit, or a retired unit exemption pursuant to 40 CFR 96.305, and no
provision of law, will be construed to limit the authority of the United
States or the State to terminate or limit this authorization.
7)
A CAIR NO
x
Ozone Season allowance allocated by the Agency or
USEPA pursuant to the CAIR NO
x
Ozone Season Trading Program does
not constitute a property right.
8)
Upon recordation by USEPA pursuant to 40 CFR 96, subpart FFFF or
subpart GGGG, every allocation, transfer, or deduction of an allowance to
or from a CAIR NO
x
Ozone Season source compliance account is deemed
to amend automatically, and become a part of, any CAIR NO
x
Ozone
Season permit of the CAIR NO
x
Ozone Season source. This automatic
amendment of the CAIR permit will be deemed an operation of law and
will not require any further review.
e)
Recordkeeping and reporting requirements:
1)
Unless otherwise provided, the owner or operator of the CAIR NO
x
Ozone
Season source and each CAIR NO
x
Ozone Season unit at the source must
keep on site at the source each of the documents listed in subsections
(e)(1)(A) through (e)(1)(E) of this Section for a period of five years from
the date the document is created. This period may be extended for cause,
at any time prior to the end of five years, in writing by the Agency or
USEPA.
A)
The certificate of representation for the CAIR designated
representative for the source and each CAIR NO
x
Ozone Season
unit at the source, all documents that demonstrate the truth of the
statements in the certificate of representation, provided that the
certificate and documents must be retained on site at the source
beyond such five-year period until the documents are superseded
because of the submission of a new certificate of representation
pursuant to 40 CFR 96.313, changing the CAIR designated
representative.
B)
All emissions monitoring information, in accordance with 40 CFR
96, subpart HHHH.
C)
Copies of all reports, compliance certifications, and other
submissions and all records made or required pursuant to the CAIR
NO
x
Ozone Season Trading Program or documents necessary to
demonstrate compliance with the requirements of the CAIR NO
x
Ozone Season Trading Program or with the requirements of this
Subpart E.
102
D)
Copies of all documents used to complete a CAIR NO
x
Ozone
Season permit application and any other submission or documents
used to demonstrate compliance pursuant to the CAIR NO
x
Ozone
Season Trading Program.
E)
Copies of all records and logs for gross electrical output and useful
thermal energy required by Section 225.550.
2)
The CAIR designated representative of a CAIR NO
x
Ozone Season source
and each CAIR NO
x
Ozone Season unit at the source must submit to the
Agency and USEPA the reports and compliance certifications required
pursuant to the CAIR NO
x
Ozone Season Trading Program, including
those pursuant to 40 CFR 96, subpart HHHH and Section 225.550.
f)
Liability:
1)
No revision of a permit for a CAIR NO
x
Ozone Season unit may excuse
any violation of the requirements of this Subpart E or the requirements of
the CAIR NO
x
Ozone Season Trading Program.
2)
Each CAIR NO
x
Ozone Season source and each CAIR NO
x
Ozone Season
unit must meet the requirements of the CAIR NO
x
Ozone Season Trading
Program.
3)
Any provision of the CAIR NO
x
Ozone Season Trading Program that
applies to a CAIR NO
x
Ozone Season source (including any provision
applicable to the CAIR designated representative of a CAIR NO
x
Ozone
Season source) will also apply to the owner and operator of the CAIR NO
x
Ozone Season source and to the owner and operator of each CAIR NO
x
Ozone Season unit at the source.
4)
Any provision of the CAIR NO
x
Ozone Season Trading Program that
applies to a CAIR NO
x
Ozone Season unit (including any provision
applicable to the CAIR designated representative of a CAIR NO
x
Ozone
Season unit) will also apply to the owner and operator of the CAIR NO
x
Ozone Season unit.
5)
The CAIR designated representative of a CAIR NO
x
Ozone Season unit
that has excess emissions in any control period must surrender the
allowances as required for deduction pursuant to 40 CFR 96.354(d)(1).
6)
The owner or operator of a CAIR NO
x
Ozone Season unit that has excess
NO
x
emissions in any control period must pay any fine, penalty, or
assessment or comply with any other remedy imposed pursuant to the Act
and 40 CFR 96.354(d)(2).
103
g)
Effect on other authorities. No provision of the CAIR NO
x
Ozone Season
Trading Program, a CAIR permit application, a CAIR permit, or a retired unit
exemption pursuant to 40 CFR 96.305 will be construed as exempting or
excluding the owner and operator and, to the extent applicable, the CAIR
designated representative of a CAIR NO
x
Ozone Season source or a CAIR NO
x
Ozone Season unit, from compliance with any other regulation promulgated
pursuant to the CAA, the Act, any State regulation or permit, or a federally
enforceable permit.
(Source: Added at 31 Ill. Reg. ________________, effective ______________)
Section 225.515
Appeal Procedures
The appeal procedures for decisions of USEPA pursuant to the CAIR NO
x
Ozone Season
Trading Program are set forth in 40 CFR 78, as incorporated by reference in Section 225.140.
(Source: Added at 31 Ill. Reg. ________________, effective ______________)
Section 225.520
Permit Requirements
a)
Permit requirements:
1)
The owner or operator of each source with a CAIR NO
x
Ozone Season
unit is required to submit:
A)
A complete permit application addressing all applicable CAIR NO
x
Ozone Season Trading Program requirements for a permit meeting
the requirements of this Section 225.520, applicable to each CAIR
NO
x
Ozone Season unit at the source. Each CAIR permit must
contain elements required for a complete CAIR permit application
pursuant to subsection (b)(2) of this Section.
B)
Any supplemental information that the Agency determines
necessary in order to review a CAIR permit application and issue
any CAIR permit.
2)
Each CAIR permit will be issued pursuant to Section 39 of 39.5 of the Act
and will contain federally enforceable conditions addressing all applicable
CAIR NO
x
Ozone Season Trading Program requirements and will be a
complete and segregable portion of the source’s entire permit pursuant to
subsection (a)(1) of this Section.
3)
No CAIR permit may be issued, and no CAIR NO
x
Ozone Season
compliance account may be established for a CAIR NO
x
Ozone Season,
104
until the Agency and USEPA have received a complete certificate of
representation for a CAIR designated representative pursuant to 40 CFR
96, subpart BBBB, for the CAIR NO
x
Ozone Season source and the CAIR
NO
x
Ozone Season unit at the source.
4)
For all CAIR NO
x
Ozone Season units that commenced operation before
July 1, 2007, the owner or operator of the unit must submit a CAIR permit
application meeting the requirements of this Section 225.520 on or before
July 1, 2007.
5)
For all units that commence operation on or after July 1, 2007, the owner
or operator of these units must submit applications for construction and
operating permits pursuant to the requirements of Sections 39 and 39.5 of
the Act, as applicable, and 35 Ill. Adm. Code 201, and the applications
must specify that they are applying for CAIR permits, and must address
the CAIR permit application requirements of this Section 225.520.
b)
Permit applications:
1)
Duty to apply. The owner or operator of any source with one or more
CAIR NO
x
Ozone Season units must submit to the Agency a CAIR permit
application for the source covering each CAIR NO
x
Ozone Season unit
pursuant to subsection (b)(2) of this Section by the applicable deadline in
subsection (a)(4) or (a)(5) of this Section. The owner or operator of any
source with one or more CAIR NO
x
Ozone Season units must reapply for
a CAIR permit for the source as required by this Subpart, 35 Ill. Adm.
Code 201, and, as applicable, Sections 39 and 39.5 of the Act.
2)
Information requirements for CAIR permit applications. A complete
CAIR permit application must include the following elements concerning
the source for which the application is submitted:
A)
Identification of the source, including plant name. The ORIS
(Office of Regulatory Information Systems) or facility code
assigned to the source by the Energy Information Administration
must also be included, if applicable;
B)
Identification of each CAIR NO
x
Ozone Season unit at the source;
and
C)
The compliance requirements applicable to each CAIR NO
x
Ozone
Season unit as set forth in Section 225.510.
3)
An application for a CAIR permit will be treated as a modification of the
CAIR NO
x
Ozone Season source’s existing federally enforceable permit,
if such a permit has been issued for that source, and will be subject to the
105
same procedural requirements. When the Agency issues a CAIR permit
pursuant to the requirements of this Section 225.520, it will be
incorporated into and become part of that source’s existing federally
enforceable permit.
c)
Permit content. Each CAIR permit is deemed to incorporate automatically the
definitions and terms pursuant to Section 225.120 and, upon recordation of
USEPA under 40 CFR 96, Subparts FFFF and GGGG as incorporated by
reference in Section 225.140, every allocation, transfer, or deduction of a CAIR
NO
x
Ozone Season allowance to or from the compliance account of the CAIR
NO
x
Ozone Season source covered by the permit.
(Source: Added at 31 Ill. Reg. ________________, effective ______________)
Section 225.525
Ozone Season Trading Budget
The CAIR NO
x
Ozone Season Trading budget available for allowance allocations for each
control period will be determined as follows:
a)
The total base CAIR NO
x
Ozone Season Trading budget is 30,701 tons per
control period for the years 2009 through 2014, subject to a reduction for two set-
asides, the NUSA and the CASA. Five percent of the budget will be allocated to
the NUSA and 25 percent will be allocated to the CASA, resulting in a CAIR NO
x
Ozone Season Trading budget available for allocation of 21,491 tons per control
period pursuant to Section 225.540. The requirements of the NUSA are set forth
in Section 225.545, and the requirements of the CASA are set forth in Sections
225.555 through 225.570.
b)
The total base CAIR NO
x
Ozone Season Trading budget is 28,981 tons per
control period for the year 2015 and thereafter, subject to a reduction for two set-
asides, the NUSA and the CASA. Five percent of the budget will be allocated to
the NUSA and 25 percent will be allocated to the CASA, resulting, in a CAIR
NO
x
Ozone Season Trading budget available for allocation of 20,287 tons per
control period pursuant to Section 225.540.
c)
If USEPA adjusts the total base CAIR NO
x
Ozone Season Trading budget for any
reason, the Agency will adjust the base CAIR NO
x
Ozone Season Trading budget
CAIR NO
x
Ozone Season Trading budget available for allocation, accordingly.
(Source: Added at 31 Ill. Reg. ________________, effective ______________)
Section 225.530
Timing for Ozone Season Allocations
a)
No later than July 31, 2007, the Agency will submit to USEPA the CAIR NO
x
106
Ozone Season allowance allocations, in accordance with Sections 225.535 and
225.540 for the 2009, 2010, and 2011 control periods.
b)
By October, 2008, and October 31 of each year thereafter, the Agency will submit
to USEPA the CAIR NO
x
Ozone Season allowance allocations in accordance with
Sections 225.535 and 225.540, for the control period four years after the year of
the applicable deadline for submission pursuant to this Section 225.530. For
example, on July 31, 2008, the Agency will submit to USEPA the allocation for
the 2012 control period.
c)
The Agency will allocate allowances from the NUSA to CAIR NO
x
Ozone
Season units that commence commercial operation on or after May 1, 2006. The
Agency will report these allocations to USEPA by July 31 of the applicable
control period. For example, on July 31, 2009, the Agency will submit to USEPA
the allocations from the NUSA for the 2009 control period.
d)
The Agency will allocate allowances from the CASA to energy efficiency,
renewable energy, and clean technology projects pursuant to the criteria in
Sections 225.555 through 225.570. The Agency will report these allocations to
USEPA by October 1 of each year. For example, on October 1, 2009, the Agency
will submit to USEPA the allocations from the CASA for the 2009 control period,
based on reductions made in the 2008 control period.
(Source: Added at 31 Ill. Reg. ________________, effective ______________)
Section 225.535
Methodology for Calculating Ozone Season Allocations
The Agency will calculate converted gross electrical output, in MWh, for each CAIR NO
x
Ozone
Season unit that has operated during at least one control period prior to the calendar year in
which the Agency reports the allocations to USEPA as follows:
a)
For control periods 2009, 2010, and 2011, the owner or operator of the unit must
submit in writing to the Agency by June 1, 2007, a statement that either gross
electrical output data or heat input is to be used to calculate converted gross
electrical output. The data shall be used calculate converted gross electrical
output pursuant to either subsection (a)(1) or (a)(2) of this Section:
1)
Gross electrical output. If the unit has four or five control periods of data,
then the gross electrical output (GO) will be the average of the unit’s three
highest gross electrical outputs from the 2001, 2002, 2003, 2004, or 2005
control periods. If the unit has three or fewer control periods of gross
electrical outputs, the gross electrical output will be the average of those
control periods. If the unit does not have gross electrical output for the
2004 and 2005 control periods, the gross electrical output will be the gross
electrical output from the 2005 control period. If a generator is served by
107
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 the total control
period heat input of these units for the control period. The unit’s
converted gross electrical output will be calculated as follows:
A)
If the unit is coal-fired:
CGO (in MWh) = GO
×
MWh
×
1.0;
B)
If the unit is oil-fired:
CGO (in MWh) = GO
×
MWh
×
0.6; or
C)
If the unit is neither coal-fired nor oil-fired:
CGO (in MWh) = GO
×
MWh
×
0.4.
2)
If heat input. If the unit has four or five control periods of data, the
average of the unit’s three highest control period heat inputs from 2001,
2002, 2003, 2004 or 2005 will be used. If the unit has heat input from the
2003, 2004, or 2005 control periods, the heat input shall be the average of
those control periods. If the unit does not have heat input from the 2004
and 2005 control periods, the heat input from the 2005 control period will
be used. The unit’s converted gross electrical output will be calculated as
follows:
A)
If the unit is coal-fired:
CGO (in MWh) = HI (in mmBtu)
×
0.0967;
B)
If the unit is oil-fired:
CGO (in MWh) = HI (in mmBtu)
×
0.0580; or
C)
If the unit is neither coal-fired nor oil-fired:
CGO (in MWh) = HI (in mmBtu)
×
0.0387.
b)
For control periods 2012 and 2013, the owner or operator of the unit must submit
in writing to the Agency by June 1, 2008, a statement that either gross electrical
output data or heat input data be used to calculate the unit’s converted gross
electrical output. The unit’s converted gross electrical output shall be calculated
pursuant to either subsection (b)(1) or (b)(2) of this Section:
1)
Gross electrical output. The average of the unit’s two most recent years of
control period gross electrical output, if available; otherwise it will be the
unit’s most recent control period’s gross electrical output. If a generator is
served by two or more units, the gross electrical output of the generator
shall be attributed to each unit in proportion to the unit’s share of the total
control period heat input of such units for the control period. The unit’s
converted gross electrical output shall be calculated as follows:
108
A)
If the unit is coal-fired:
CGO (in MWh) = GO
×
MWh
×
1.0;
B)
If the unit is oil-fired:
CGO (in MWh) = GO
×
MWh
×
0.6;
C)
If the unit is neither coal-fired nor oil-fired:
CGO (in MWh) = GO
×
MWh
×
0.4.
2)
Heat input. The average of the unit’s two most recent years of control
period heat input; otherwise the unit’s most recent control period’s heat
input, e.g. for the 2012 control period the average of the unit’s heat input
from the 2006 and 2007 control periods. If the unit does not have heat
input from the 2006 and 2007 control periods, the heat input from the
2007 control period shall be used. The unit’s converted gross electrical
output shall be calculated as follows:
A)
If the unit is coal-fired:
CGO (in MWh) = HI (in mmBtu)
×
0.0967;
B)
If the unit is oil-fired:
CGO (in MWh) = HI (in mmBtu)
×
0.0580; or
C)
If the unit is neither coal-fired nor oil-fired:
CGO (in MWh) = HI (in mmBtu)
×
0.0387.
c)
For control period 2014 and thereafter, the unit’s gross electrical output will be
the average of the unit’s two most recent control period’s gross electrical output,
if available, otherwise it will be the unit’s most recent control period gross
electrical output. If a generator is served by two or more units, the gross electrical
output of the generator will be attributed to each unit in proportion to the unit’s
share of the total control period heat input of these units for the control period.
The unit’s converted gross electrical output will be calculated as follows:
1)
If the unit is coal-fired:
CGO (in MWh) = GO
×
1.0;
2)
If the unit is oil-fired:
CGO (in MWh) = GO
×
0.6; or
3)
If the unit is neither coal-fired nor oil-fired:
CGO (in MWh) = GO
×
0.4.
d)
For a unit that is a combustion turbine or boiler and has equipment used to
produce electricity and useful thermal energy for industrial, commercial, heating,
or cooling purposes through the sequential use of energy, the Agency will add the
109
converted gross electrical output calculated for electricity pursuant to subsections
(a), (b), or (c) of this Section to the converted useful thermal energy (CUTE) to
determine the total converted gross electrical output for the unit (TCGO). The
Agency will determine the converted useful thermal energy by using the average
of the unit’s control period useful thermal energy for the prior two control
periods, if available, otherwise the unit’s control period useful thermal output for
the prior year will be used. The converted useful thermal energy will be
determined using the following equations:
1)
If the unit is coal-fired:
CUTE (in MWh) = UTE (in mmBtu)
×
0.2930;
2)
If the unit is oil-fired:
CUTE (in MWh) = UTE (in mmBtu)
×
0.1758; or
3)
If the unit is neither coal-fired nor oil-fired:
CUTE (in MWh) = UTE (in mmBtu)
×
0.1172.
e)
The CAIR NO
x
Ozone Season unit’s converted gross electrical output and
converted useful thermal energy in subsections (a)(1), (b)(1), (c), and (d) of this
Section for each control period will be based on the best available data reported or
available to the Agency for the CAIR NO
x
Ozone Season unit pursuant to the
provisions of Section 225.550.
f)
The CAIR NO
x
Ozone Season unit’s heat input in subsections (a)(2) and (b)(2) of
this Section for each control period will be determined in accordance with 40
CFR 75, as incorporated by reference in Section 225.140.
(Source: Added at 31 Ill. Reg. ________________, effective ______________)
Section 225.540
Ozone Season Allocations
a)
For the 2009 control period, and each control period thereafter, the Agency will
allocate CAIR NO
x
Ozone Season allowances to all CAIR NO
x
Ozone Season
units in Illinois for which the Agency has calculated the total converted gross
electrical output pursuant to Section 225.535, a total amount of CAIR NO
x
Ozone
Season allowances equal to tons of NO
x
emissions in the CAIR NO
x
Ozone
Season Trading budget available for allocation as determined in Section 225.525
and allocated pursuant to this Section 225.540.
b)
The Agency will allocate CAIR NO
x
Ozone Season allowances to each CAIR
NO
x
Ozone Season unit on a pro-rata basis using the unit’s total converted gross
electrical output calculated pursuant to Section 225.535. If there are insufficient
allowances to allocate whole allowances pro rata, these unallocated allowances
will be retained by the Agency and will be available for allocation in later control
110
periods.
(Source: Added at 31 Ill. Reg. ________________, effective ______________)
Section 225.545
New Unit Set-Aside (NUSA)
For the 2009 control period and each control period thereafter, the Agency will allocate CAIR
NO
x
Ozone Season allowances from the NUSA to CAIR NO
x
Ozone Season units that
commenced commercial operation on or after May 1, 2006, and do not yet have an allocation for
the particular control period pursuant to Section 225.540, in accordance with the following
procedures:
a)
Beginning with the 2009 control period and each control period thereafter, the
Agency will establish a separate NUSA for each control period. Each new unit
set-aside will be allocated CAIR NO
x
Ozone Season allowances equal to 5
percent of the amount of tons of NO
x
emissions in the base CAIR NO
x
Ozone
Season Trading budget in Section 225.525.
b)
The CAIR designated representative of a new CAIR NO
x
Ozone Season unit may
submit to the Agency a request, in a format specified by the Agency, to be
allocated CAIR NO
x
Ozone Season allowances from the NUSA starting with the
first control period after the control period in which the new unit commences
commercial operation and until the first control period for which the unit may use
CAIR NO
x
Ozone Season allowances allocated to the unit pursuant to Section
225.540. The NUSA allowance allocation request may only be submitted after a
new unit has operated during one control period, and no later than March 1 of the
control period for which allowances from the NUSA are being requested.
c)
In a NUSA allowance allocation request pursuant to subsection (b) of this
Section, the CAIR designated representative must provide in its request
information for gross electrical output and useful thermal energy, if any, for the
new CAIR NO
x
Ozone Season unit for that control period.
d)
The Agency will allocate allowances from the NUSA to a new CAIR NO
x
Ozone
Season unit using the following procedures:
1)
For each new CAIR NO
x
Ozone Season unit, the unit’s gross electrical
output for the most recent control period, will be used to calculate the
unit’s gross electrical output. If a generator is served by two or more
units, the gross electrical output of the generator will be attributed to each
unit in proportion to the unit’s share of the total control period heat input
of these units for the control period. The new unit’s converted gross
electrical output will be calculated as follows:
A)
If the unit is coal-fired:
111
CGO (in MWh) = GO
×
1.0;
B)
If the unit is oil-fired:
CGO (in MWh) = GO
×
0.6; or
C)
If the unit is neither coal-fired nor oil-fired:
CGO (in MWh) = GO
×
0.4.
2)
If the unit is a combustion turbine or boiler and has equipment used to
produce electricity and useful thermal energy for industrial, commercial,
heating, or cooling purposes through the sequential use of energy, the
Agency will add the converted gross electrical output calculated for
electricity pursuant to subsection (d)(1) of this Section to the converted
useful thermal energy to determine the total converted gross electrical
output for the unit. The Agency will determine the converted useful
thermal energy using the unit’s useful thermal energy for the most recent
control period. The converted useful thermal energy will be determined
using the following equations:
A)
If the unit is coal-fired:
CUTE (in MWh) = UTE (in mmBtu)
×
0.2930;
B)
If the unit is oil-fired:
CUTE (in MWh) = UTE (in mmBtu)
×
0.1758; or
C)
If the unit is neither coal-fired nor oil-fired:
CUTE (in MWh) = UTE (in mmBtu)
×
0.1172.
3)
The gross electrical output and useful thermal energy in subsections (d)(1)
and (d)(2) of this Section for the control period in each year will be based
on the best available data reported or available to the Agency for the
CAIR NO
x
Ozone Season unit pursuant to the provisions of Section
225.550 .
4)
The Agency will determine a unit’s unprorated allocation (
UA
y
) using the
unit’s converted gross electrical output plus the unit’s converted useful
thermal energy, if any, calculated in subsections (d)(1) and (d)(2) of this
Section, converted to approximate NO
x
tons (the unit’s unprorated
allocation), as follows:
2000lbs / ton
TCGO
(1.0lbs / MWh)
UA
y
y
×
=
Where:
112
UA
y
=
unprorated allocation to a new CAIR NO
x
Ozone Season unit.
TCGO
y
=
total converted gross electrical output for a
new CAIR NO
x
Ozone Season unit.
5)
The Agency will allocate CAIR NO
x
Ozone Season allowances from the
NUSA to new CAIR NO
x
Ozone Season units as follows:
A)
If the NUSA for the control period for which CAIR NO
x
Ozone
Season allowances are requested has a number of allowances
greater than or equal to the total unprorated allocations for all new
units requesting allowances, the Agency will allocate the number
of allowances using the unprorated allocation determined for that
unit pursuant to subsection (d)(4) of this Section.
B)
If the NUSA for the control period for which the allowances are
requested has a number of CAIR NO
x
Ozone Season allowances
less than the total unprorated allocation to all new CAIR NO
x
Ozone Season units requesting allocations, the Agency will
allocate the available allowances for new CAIR NO
x
Ozone
Season units on a pro-rata basis, using the unprorated allocation
determined for that unit pursuant to subsection (d)(4) of this
Section. If there are insufficient allowances to allocate whole
allowances, the unallocated allowances will be retained by the
Agency and will be available for allocation in a later control
period.
C)
If the gross electrical output or useful thermal energy reported to
the Agency pursuant to subsection (d) of this Section is later
determined to be greater than the unit’s actual gross electrical
output or useful thermal energy for the applicable control period,
the Agency will reduce the unit’s allocation from the NUSA for
the current control period to account for the excess allowances
allocated in the prior control period or periods.
e)
The Agency will review each NUSA allowance allocation request pursuant to
subsection (b) of this Section. The Agency will accept a NUSA allowance
allocation request only if the request meets, or is adjusted by the Agency as
necessary to meet, the requirements of this Section 225.545.
f)
By June 1 of the applicable control period, the Agency will notify each CAIR
designated representative that submitted a NUSA allowance request of the amount
of CAIR NO
x
Ozone Season allowances from the NUSA, if any, allocated for the
control period to the new unit covered by the request.
113
g)
The Agency will allocate CAIR NO
x
Ozone Season allowances to new units from
the NUSA no later than July 31 of the applicable control period.
h)
After a new CAIR NO
x
Ozone Season unit has operated in one control period, it
becomes an existing unit for the purposes of Section 225.540 only, and the
Agency will allocate CAIR NO
x
Ozone Season allowances for that unit, for the
control period commencing four years in the future pursuant to Section 225.540 .
The new CAIR NO
x
Ozone Season unit will continue to receive CAIR NO
x
Ozone Season allowances from the NUSA according to this Section until the unit
is eligible to use the CAIR NO
x
Ozone Season allowances allocated to the unit
pursuant to Section 225.540 .
i)
If, after the completion of the procedures in subsection (c) of this Section for a
control period any unallocated CAIR NO
x
Ozone Season allowances remain in
the NUSA for the control period, the Agency will, at a minimum, accrue those
CAIR NO
x
Ozone Season allowances for future control period allocations to new
CAIR NO
x
Ozone Season units. The Agency may from time to time elect to retire
CAIR NO
x
Ozone Season allowances in the NUSA that are in excess of 7,245 for
the purposes of continued progress toward attainment and maintenance of
National Ambient Air Quality Standards pursuant to the CAA.
(Source: Added at 31 Ill. Reg. ________________, effective ______________)
Section 225.550
Monitoring, Recordkeeping and Reporting Requirements for Gross
Electrical Output and Useful Thermal Energy
a)
By January 1, 2008, or by the date of commencing commercial operation,
whichever is later, the owner or operator of the CAIR NO
x
unit must operate a
system for measuring gross electrical output that is consistent with the
requirements of either 40 CFR 60 or 75; must measure gross electrical output in
MW-hrs using such a system; and must record the output of the measurement
system. If a generator is served by two or more units, the information to
determine each unit’s heat input for that control period must also be recorded, so
as to allow each unit’s share of the gross electrical output to be determined. If
heat input data is used, the owner or operator must comply with the applicable
provisions 40 CFR 75, as incorporated by reference in Section 225.140.
b)
For a CAIR NO
x
Ozone Season unit that is a cogeneration unit by January 1,
2007, or by the date the CAIR NO
x
Ozone Season unit commences to produce
useful thermal energy, whichever is later, the owner or operator of a CAIR NO
x
Ozone Season unit with cogeneration capabilities must install, calibrate, maintain,
and operate meters for steam flow in lbs/hr, temperature in degrees Fahrenheit,
and pressure in PSI, to measure and record the useful thermal energy that is
produced, in mmBtu/hr, on a continuous basis. Owners and operators of aCAIR
NO
x
Ozone Season unit that produces useful thermal energy but uses an energy
114
transfer medium other than steam, e.g., hot water or glycol, must install, calibrate,
maintain, and operate the necessary meters to measure and record the necessary
data to express the useful thermal energy produced, in mmBtu/hr, on a continuous
basis. If the CAIR NO
x
Ozone Season unit ceases to produce useful thermal
energy, the owner or operator may cease operation of these meters, provided that
operation of such meters must be resumed if the CAIR NO
x
Ozone Season unit
resumes production of useful thermal energy.
c)
The owner or operator of a CAIR NO
x
unit must either report gross electrical
output data to the Agency or comply with the applicable provisions for providing
heat input data to USEPA as follows:
1)
By June 1, 2007, the gross electrical output for control periods 2001, 2002,
2003, 2004 and 2005, if available, and, the unit’s useful thermal energy
data, if applicable. If a generator is served by two or more units, the
documentation needed to determine each unit’s share of the heat input of
such units for that control period must also be submitted. If heat input
data is used, the owner or operator must comply with the applicable
provisions 40 CFR 75, as incorporated by reference in Section 225.140.
2)
By June 1, 2008, the gross electrical output for control periods 2006 and
2007, if available, and the unit’s useful thermal energy data, if applicable.
If a generator is served by two or more units, the documentation needed to
determine each unit’s share of the heat input of such units for that control
period must also be submitted. If heat input data is used, the owner or
operator must comply with the applicable provisions of 40 CFR 75, as
incorporated by reference in Section 225.140.
d)
Beginning with calendar year 2008, the CAIR designated representative of the
CAIR NO
x
Ozone Season unit must submit to the Agency quarterly, by no later
than April 30, July 31, October 31, and January 31 of each year, information for
the CAIR NO
x
Ozone Season unit’s gross electrical output, on a monthly basis for
the prior quarter, and, if applicable, the unit’s useful thermal energy for each
month.
e)
The owner or operator of a CAIR NO
x
Ozone Season unit must maintain on-site
the monitoring plan detailing the monitoring system, maintenance of the
monitoring system, including quality assurance activities pursuant to the
requirements of 40 CFR 60 and 75, including the applicable provisions for the
measurement of gross electrical output for the CAIR NO
x
Ozone Season trading
program and, if applicable, for new units. The monitoring plan must include, but
is not limited to:
1)
A description of the system to be used for the measurement of gross
electrical output pursuant to Section 225.450(a), including a list of any
data logging devices, solid-state kW meters, rotating kW meters,
115
electromechanical kW meters, current transformers, transducers, potential
transformers, pressure taps, flow venturi, orifice plates, flow nozzles,
vortex meters, turbine meters, pressure transmitters, differential pressure
transmitters, temperature transmitters, thermocouples, resistance
temperature detectors, and any equipment or methods used to accurately
measure gross electrical output.
2)
A certification statement by the CAIR designated representative that all
components of the gross electrical output system have been tested to be
accurate within three percent and that the gross electrical output system is
accurate to within ten percent.
f)
The owner or operator of a CAIR NO
x
Ozone Season unit must retain records for
at least 5 years from the date the record is created or the data collected in
subsections (a) and (b) of this Section, and the reports submitted to the Agency
and USEPA in accordance with subsections (c) and (d) of this Section. The
owner or operator of a CAIR NO
x
Ozone Season unit must retain the monitoring
plan required in subsection (e) of this Section for at least five years from the date
that it is replaced by a new or revised monitoring plan.
(Source: Added at 31 Ill. Reg. ________________, effective ______________)
Section 225.555
Clean Air Set-Aside (CASA)
a)
A project sponsor may apply for allowances from the CASA for sponsoring an
energy efficiency and conservation, renewable energy, or clean technology
project as set forth in Section 225.560 by submitting the application required by
Section 225.570.
b)
Notwithstanding subsection (a) of this Section, a project sponsor with a CAIR
NO
x
Ozone Season source that is out of compliance with this Subpart for a given
control period may not apply for allowances from the CASA for that control
period. If a source receives CAIR NO
x
allowances from CASA and then is
subsequently found to have been out of compliance with this Subpart for the
applicable control period or periods, the project sponsor must restore the CAIR
NO
x
allowances that it received pursuant to its CASA request or an equivalent
number of CAIR NO
x
allowances to the CASA within six months of receipt of an
Agency notice that NO
x
allowances must be restored. These allowances will be
assigned to the fund from which they were distributed.
c)
CAIR NO
x
allowances from CASA will be allocated in accordance with the
procedures in Section 225.575.
d)
The project sponsor may submit an application that aggregates two or more
projects under a CASA project category that would individually result in less than
116
one allowance, but that equal at a minimum one whole allowance when
aggregated.
(Source: Added at 31 Ill. Reg. ________________, effective ______________)
Section 225.560
Energy Efficiency and Conservation, Renewable Energy, and Clean
Technology Projects
a)
Energy efficiency and conservation project means any of the following projects
implemented and located in Illinois:
1)
Demand side management projects that reduce the overall power demand
by using less energy include:
A)
Smart building management software that more efficiently
regulates power flows.
B)
The use of or replacement to high efficiency motors, pumps,
compressors, or steam systems.
C)
Lighting retrofits.
2)
Energy efficient new building construction projects include:
A)
ENERGY STAR-qualified new home projects.
B)
Measures to reduce or conserve energy consumption beyond the
requirements of the Illinois Energy Conservation Code for
Commercial Buildings (20 ILCS 687/6-3).
C)
New residential construction projects that qualify for Energy
Efficient Tax Incentives pursuant to the Energy Policy Act of
2005, 42 U.S.C. 15801 (2005).
3)
Supply-side energy efficiency projects include projects implemented to
improve the efficiency in electricity generation by coal-fired power plants,
and the efficiency of electrical transmission and distribution systems.
4)
Highly efficient power generation project, such as, but not limited to,
combined cycle projects, combined heat and power, and microturbines.
To be considered a highly efficient power generation project pursuant to
this subsection (a)(4), a project must meet the thresholds and criteria listed
below:
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A)
For combined heat and power projects generating both electricity
and useful thermal energy for space, water, or industrial process
heat, a rated-energy efficiency of at least 60 percent and is not a
CAIR NO
x
Ozone Season unit.
B)
For combined cycle projects rated at greater than 0.50 MW, a
rated-energy efficiency of at least 50 percent.
C)
For microturbine projects rated at or below 0.50 MW and all other
projects rated-energy efficiency of at least 40 percent.
b)
Renewable energy unit means any of the following projects implemented and
located in Illinois:
1)
Zero-emission electric generating units, including wind, solar (thermal or
photovoltaic), and hydropower projects. Eligible hydropower plants are
restricted to new generators, that are not replacements of existing
generators, that commence operation on or after January 1, 2006, and do
not involve the significant expansion of an existing dam or the
construction of a new dam.
2)
Renewable energy units are those units that generate electricity using more
than 50 percent of the heat input, on an annual basis, from dedicated crops
grown for energy production or the capture systems for methane gas from
landfills, water treatment plants or sewage treatment plants, and organic
waste biomass, and other similar sources of non-fossil fuel energy.
Renewable energy projects do not include energy from incineration by
burning or heating of waste wood, tires, garbage, general household,
institutional lunchroom or office waste, landscape waste, or construction
or demolition debris.
c)
Clean technology project for reducing emissions from producing electricity and
useful thermal energy means any of the following projects implemented and
located in Illinois:
1)
Air pollution control equipment upgrades for control of NO
x
emissions at
existing coal-fired EGUs, as follows: installation of a selective catalytic
reduction (SCR) or selective non-catalytic reduction (SNCR) system, or
other emission control technologies. Air pollution control upgrades do not
include the addition of low NO
x
burners, overfired air techniques, gas
reburning techniques, flue gas conditioning techniques for the control of
NO
x
emissions, projects involving upgrades or replacement of electrostatic
precipitators, or addition of activated carbon injection, or other sorbent
injection for control of mercury. For this purpose, a unit will be
considered “existing” after it has been in commercial operation for at least
eight years.
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2)
Clean coal technologies projects include:
A)
Integrated gasification combined cycle (IGCC) plants.
B)
Fluidized bed coal combustion.
d)
In addition to those projects excluded in subsections (a) through (c) of this
Section, the following projects are also not energy efficiency and conservation,
renewable energy, or clean technology projects:
1)
Nuclear power projects.
2)
Projects required to meet emission standards or technology requirements
under State or federal law or regulation, except that allowances may be
allocated for projects undertaken pursuant to Section 225.233.
3)
Projects used to meet the requirements of a court order or consent decree,
except that allowances may be allocated for:
A)
Emission rates or limits achieved that are lower than what is
required to meet the emission rates or limits for SO
2
or NO
x,
or for
installing a baghouse as provided for in a court order or consent
decree entered into before May 30, 2006.
B)
Projects used to meet the requirements of a court order or consent
decree entered into on or after May 30, 2006, if the court order or
consent decree does not specifically preclude such allocations.
4)
A Supplemental Environmental Project (SEP).
e)
Applications for projects implemented and located in Illinois that are not
specifically listed in subsections (a) through (c) of this Section, and that are not
specifically excluded by definition in subsections (a) through (c) of this Section or
by specific exclusion in subsection (d) of this Section, may be submitted to the
Agency. The application must designate which category or categories from those
listed in subsections (a)(1) through (c)(2)(B) of this Section best fits the proposed
project and the applicable formula pursuant to Section 225.565(b) to calculate the
number of allowances that it is requesting. The Agency will determine whether
the application is approvable based on a sufficient demonstration by the project
sponsor that the project is a new type of energy efficiency, renewable energy, or
clean technology project, similar in its effects as the projects specifically listed in
subsection (a) through (c) of this Section.
f)
Early adopter projects include projects that meet the criteria for any energy
efficiency and conservation, renewable energy, or clean technology projects listed
119
in subsections (a) , (b), (c), and (e) of this Section and commence construction
between July 1, 2006, and December 31, 2012.
(Source: Added at 31 Ill. Reg. ________________, effective ______________)
Section 225.565
Clean Air Set-Aside (CASA) Allowances
a)
The CAIR NO
x
allowances for the CASA for each control period will be assigned
to the following categories of projects:
Phase I
Phase II
(2009-2014)
(2015 and
thereafter)
1)
Energy Efficiency and Conservation/
3684
3479
Renewable Energy
2)
Air Pollution Control Equipment
1535
1448
Upgrades
3)
Clean Coal Technology Projects
1842
1738
4)
Early Adopters
614
580
b)
The following formulas must be used to determine the number of CASA
allowances that may be allocated to a project per control period:
1)
For an energy efficiency and conservation project pursuant to Sections
225.560(a)(1) through (a)(4)(A), the number of allowances must be
calculated using the number of megawatt hours of electricity that was not
consumed during a control period and the following formula:
A
=
(MWh
c
)
×
(1.5 lb/MWh) / 2000 lb
Where:
A
=
The number of allowances for a particular project.
MWh
c
=
The number of megawatt hours of electricity
conserved or generated during a control period by a
project.
2)
For a zero emission electric generating projects pursuant to Section
225.560(b)(1), the number of allowances must be calculated using the
number of megawatt hours of electricity generated during a control period
and the following formula:
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A
=
(MWh
g
)
×
(2.0 lb/MWh) / 2000 lb
Where:
A
=
The number of allowances for a particular project
MWh
g
=
The number of megawatt hours of electricity
generated during a control period by a project.
3)
For a renewable energy emission unit pursuant to Section 225.560(b)(2),
the number of allowances must be calculated using the number of
megawatt hours of electricity generated during a control period and the
following formula:
A
=
(MWh
g
)
×
(0.5 lb/MWh) / 2000 lb
Where:
A
=
The number of allowances for a particular project.
MWh
g
=
The number of MW hours of electricity generated
during a control period by a project.
4)
For an air pollution control equipment upgrade project pursuant to Section
225.560(c)(1), the number of allowances must be calculated using the
emission rate before and after replacement or improvement, and the
following formula:
A
=
(MWh
g
)
×
0.10
×
(ER
B
lb/MWh - ER
A
lb/MWh) / 2000 lb
Where:
A
=
The number of allowances for a particular project.
MWh
g
=
The number of MWhs of electricity
generated during a control period by a project.
ER
B
=
Average NO
x
emission rate based on CEMS data
from the most recent two control periods prior to
the replacement or improvement of the control
equipment in lb/MWh, unless subject to a consent
decree or court order. For units subject to a consent
decree or court order, entered into before May 30,
2006, ER
B
is limited to emission rates or limits that
are lower than the emission rate or limit required in
the consent decree or court order. On or after May
30, 2006, ER
B
is limited to emission rates or limits
specified in the consent decree or court order. If
such limit is not expressed in lb/MWh, the limit
121
shall be converted into lb/MWh using a heat rate of
10 mmBtu/1 MW.
ER
A
=
Average NO
x
emission rate for the applicable
control period data based on CEMS data in
lb/MWh.
5)
For highly efficient power generation and clean technology projects
pursuant to Sections 225.560(a)(4)(B), (a)(4)(C) and (c)(2), the number of
allowances must be calculated using the number of megawatt hours of
electricity the project generates during a control period and the following
formula:
A
=
(MWh
g
)
×
(1.0 lb/MWh – ER lb/MWh) / 2000 lb
Where:
A
=
The number of allowances for a particular project.
MWh
g
=
The number of megawatt hours of electricity
generated during a control period by a project.
ER
=
Average NO
x
emission rate for the control period
based on CEMS data in 1b/MWh.
6)
For a CASA project that commences construction before December 31,
2012, in addition to the allowances allocated pursuant to subsections
(b)(1) through (b)(5) of this Section, a project sponsor may also request
additional allowances under the early adopter project category pursuant to
Section 225.460(e) based on the following formula:
A
=
1.0 + 0.10
×
Σ
A
i
Where:
A
=
The number of allowances for a particular project as
determined in subsections (b)(1) through (b)(5) of
this Section.
A
i
=
The number of allowances as determined in
subsection (b)(1), (b)(2), (b)(3), (b)(4) or (b)(5) of
this Section for a given project.
(Source: Added at 31 Ill. Reg. ________________, effective ______________)
Section 225.570
Clean Air Set-Aside (CASA) Applications
a)
A project sponsor may request allowances if the project commenced construction
on or after the dates listed below. The project sponsor may request and be
122
allocated allowances from more than one CASA category for a project, if
applicable.
1)
Demand side management, energy efficient new construction, and supply
side energy efficiency and conservation projects that commenced
construction on or after January 1, 2003;
2)
Fluidized bed coal combustion projects, highly efficient power generation
operations projects, or renewable energy emission units, which
commenced construction on or after January 1, 2001; and
3)
All other projects on or after July 1, 2006.
b)
Beginning with the 2009 control period and each control period thereafter, a
project sponsor may request allowances from the CASA. The application must be
submitted to the Agency by May 1 of the control period for which the allowances
are being requested.
c)
The allocation will be based on the electricity conserved or generated in the
control period preceding the calendar year in which the application is submitted.
To apply for a CAIR NO
x
allocation from the CASA, project sponsors must
provide the Agency with the following information:
1)
Identification of the project sponsor, including name, address, type of
organization, certification that the project sponsor has met the definition of
“project sponsor” as set forth in Section 225.130, and name(s) of the
principals or corporate officials.
2)
The number of the CAIR NO
x
general or compliance account for the
project and the name of the associated CAIR account representative.
3)
A description of the project or projects, location, the role of the project
sponsor in the projects, and a general explanation of how the amount of
energy conserved or generated was measured, verified, and calculated, and
the number of allowances requested with the supporting calculations. The
number of allowances requested will be calculated using the applicable
formula from Section 225.570(b).
4)
Detailed information to support the request for allowances, including the
following types of documentation for the measurement and verification of
the NO
x
emissions reductions, electricity generated, or electricity
conserved using established measurement verification procedures, as
applicable. The measurement and verification required will depend on the
type of project proposed.
A)
As applicable, documentation of the project’s base and control
123
period conditions and resultant base and control period energy
data, using the procedures and methods included in
M&V
Guidelines: Measurement and Verification for Federal Energy
Projects,
incorporated by reference in Section 225.140 , or other
method approved by the Agency. Examples include:
i)
Energy consumption and demand profiles;
ii)
Occupancy type;
iii)
Density and periods;
iv)
Space conditions or plant throughput for each operating
period and season. (For example, in a building this would
include the light level and color, space temperature,
humidity and ventilation);
v)
Equipment inventory, nameplate data, location, condition;
and
vi)
Equipment operating practices (schedules and set points,
actual temperatures/pressures).
B)
Emissions data, including, if applicable, CEMS data;
C)
Information for rated–energy efficiency including supporting
documentation and calculations; and
D)
Electricity, in MWh, generated or conserved for the applicable
control period.
5)
Notwithstanding the requirements of subsections (c)(4) of this Section,
applications for fewer than five allowances may propose other reliable and
applicable methods of quantification acceptable to the Agency.
6)
Any additional information requested by the Agency to determine the
correctness of the requested number of allowances, including site
information, project specifications, supporting calculations, operating
procedures, and maintenance procedures.
7)
The following certification by the responsible official for the project
sponsor and the applicable CAIR account representative for the project:
“I am authorized to make this submission on behalf of the project sponsor
and the holder of the CAIR NO
x
general account or compliance account
for which the submission is made. I certify under penalty of law that I
124
have personally examined, and am familiar with the statements and
information submitted in this application 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.”
d)
A project sponsor may request allowances from the CASA for each project a total
number of control periods not to exceed the number of control periods listed
below. After a project has been allocated allowances from CASA, subsequent
requests for the project from the project sponsor must include the information
required by subsections (c)(1), (c)(2), (c)(3) and (c)(7) of this Section, a
description of any changes, or further improvements made to the project, and
information specified in subsections (c)(5) and (c)(6) as specifically requested by
the Agency.
1)
For energy efficiency and conservation projects (except for efficient
operation and renewable energy projects), for a total of eight control
periods.
2)
For early adopter projects, for a total of ten control periods.
3)
For air pollution control equipment upgrades for a total of 15 control
periods.
4)
For renewable energy projects, clean coal technology, and highly efficient
power generation projects, for each year that the project is in operation.
e)
A project sponsor must keep copies of all CASA applications and the
documentation used to support the application for at least five years.
(Source: Added at 31 Ill. Reg. ________________, effective ______________)
Section 225.575
Agency Action on Clean Air Set-Aside (CASA) Applications
a)
By September 1, 2009, and each September 1 thereafter, the Agency will
determine the total number of allowances that are approvable for allocation to
project sponsors based upon the applications submitted pursuant to Section
225.570.
1)
The Agency will determine the number of CAIR NO
x
allowances that are
approvable based on the formulas and the criteria for such projects. The
Agency will notify a project sponsor within 90 days after receipt of an
application if the project is not approvable, the number of allowances
125
requested is not approvable, or additional information is needed by the
Agency to complete its review of the application.
2)
If the total number of CAIR NO
x
allowances requested for approved
projects is less than or equal to the number of CAIR NO
x
allowances in
the CASA project category, the number of allowances that are approved
shall be allocated to each CAIR NO
x
compliance or general account.
3)
If more CAIR NO
x
allowances are requested than the number of CAIR
NO
x
allowances in a given CASA project category, allowances will be
allocated on a pro-rata basis based on the number of allowances available,
subject to further adjustment as provided for by subsection (b) of this
Section. CAIR NO
x
allowances will be allocated, transferred, or used as
whole allowances. The number of whole allowances will be determined
by rounding down for decimals less than 0.5 and rounding up for decimals
of 0.5 or greater.
b)
For control periods 2011 and thereafter, if there are, after the completion of the
procedures in subsection (a) of this Section for a control period, any CAIR NO
x
allowances not allocated to a CASA project for the control period:
1)
The remaining allowances will accrue in each CASA project category up
to twice the number of allowances that are assigned to the project category
each control period as set forth in Section 225.565 .
2)
If any allowances remain after allocations pursuant to subsection (a) of
this Section, the Agency will allocate these allowances pro-rata to projects
that received fewer allowances than requested, based on the number of
allowances not allocated but approved by the Agency for the project under
CASA. No project may be allocated more allowances than approved by
the Agency for the applicable control period.
3)
If any allowances remain after the allocation of allowances pursuant to
subsection (b)(2) of this Section the Agency will then distribute pro rata
the remaining allowances to project categories that have fewer than twice
the number of allowances assigned to the project category. The pro-rata
distribution will be based on the difference between two times the project
category and the number of allowances that remain in the project category.
4)
If allowances still remain undistributed after the allocations and
distributions in the above subsections are completed, the Agency may
elect to retire any CAIR NO
x
allowances that have not been distributed to
any CASA category, to continue progress toward attainment or
maintenance of the National Ambient Air Quality Standards pursuant to
the CAA.
126
(Source: Added at 31 Ill. Reg. ________________, effective ______________)
SUBPART F: COMBINED POLLUTANT STANDARDS
Section 225.600
Purpose
The purpose of this Subpart F is to allow an alternate means of compliance with the emissions
standards for mercury in Section 225.230(a) for Specified EGUs through permanent shut-down,
installation of ACI, and the application of pollution control technology for NO
x
, PM, and SO
2
emissions that also reduce mercury emissions as a co-benefit and to establish permanent
emissions standards for those Specified EGUs. Unless otherwise provided for in this Subpart F,
owners and operators of those Specified EGUs are not excused from compliance with other
applicable requirements of Subparts B, C, D, and E.
(Source: Added at 31 Ill. Reg. ____________, effective _____________)
Section 225.605
Applicability
a)
As an alternative to compliance with the emissions standards of Section
225.230(a), the owner or operator of specified EGUs in this Subpart F located at
Fisk, Crawford, Joliet, Powerton, Waukegan, and Will County power plants may
elect for all of those EGUs as a group to demonstrate compliance pursuant to this
Subpart F, which establishes control requirements and emissions standards for
NO
x
, PM, SO
2
, and mercury. For this purpose, ownership of a Specified EGU is
determined based on direct ownership, by holding a majority interest in a
company that owns the EGU or EGUs, or by the common ownership of the
company that owns the EGU, whether through a parent-subsidiary relationship, as
a sister corporation, or as an affiliated corporation with the same parent
corporation, provided that the owner or operator has the right or authority to
submit a CAAPP application on behalf of the EGU.
b)
A Specified EGU is a coal-fired EGU listed in Appendix A, irrespective of any
subsequent changes in ownership of the EGU or power plant, changes in the
operator, unit designation, or name of unit.
c)
The owner or operator of each of the Specified EGUs electing to demonstrate
compliance with Section 225.230(a) pursuant to this Subpart must submit an
application for a CAAPP permit modification to the Agency, as provided for in
Section 225.220, that includes the information specified in Section 225.610 that
clearly states the owner’s or operator’s election to demonstrate compliance with
Section 225.230(a) pursuant to this Subpart F.
127
d)
If an owner or operator of one or more Specified EGUs elects to demonstrate
compliance with Section 225.230(a) pursuant to this Subpart F, then all Specified
EGUs owned or operated in Illinois by the owner or operator as of December 31,
2006, as defined in subsection (a) of this Section, are thereafter subject to the
standards and control requirements of this Subpart F. Such EGUs are referred to
as a Combined Pollutant Standard (CPS) group.
e)
If an EGU is subject to the requirements of this Section, then the requirements
apply to all owners and operators of the EGU, and to the CAIR designated
representative for the EGU.
(Source: Added at 31 Ill. Reg. ____________, effective _____________)
Section 225.610
Notice of Intent
The owner or operator of one or more Specified EGUs that intends to comply with Section
225.230(a) by means of this Subpart F must notify the Agency of its intention on or before
December 31, 2007. The following information must accompany the notification:
a)
The identification of each EGU that will be complying with Section 225.230(a)
pursuant to this Subpart F, with evidence that the owner or operator has identified
all Specified EGUs that it owned or operated in Illinois as of December 31, 2006,
and which commenced commercial operation on or before December 31, 2004;
b)
If an EGU identified in subsection (a) of this Section is also owned or operated by
a person different than the owner or operator submitting the notice of intent, a
demonstration that the submitter has the right to commit the EGU or authorization
from the responsible official for the EGU submitting the application; and
c)
A summary of the current control devices installed and operating on each EGU
and identification of the additional control devices that will likely be needed for
each EGU to comply with emission control requirements of this Subpart F.
(Source: Added at 31 Ill. Reg. ____________, effective _____________)
Section 225.615
Control Technology Requirements and Emissions Standards for Mercury
a)
Control Technology Requirements for Mercury.
1)
For each EGU in a CPS group other than an EGU that is addressed by
subsection (b) of this Section, the owner or operator of the EGU must
install, if not already installed, and properly operate and maintain, by the
dates set forth in subsection (a)(2) of this Section, ACI equipment
128
complying with subsections (g), (h), (i), (j), and (k) of this Section, as
applicable.
2)
By the following dates, for the EGUs listed below, which include hot and
cold side ESPs, the owner or operator must install, if not already installed,
begin operating ACI equipment or the Agency must be given written
notice that the EGU will be shutdown on or before the dates below:
A)
Fisk 19, Crawford 7, Crawford 8, Waukegan 7, and Waukegan 8
on or before July 1, 2008; and
B)
Powerton 5, Powerton 6, Will County 3, Will County 4, Joliet 6,
Joliet 7, and Joliet 8 on or before July 1, 2009.
b)
Notwithstanding subsection (a) of this Section, the following EGUs are not
required to install ACI equipment because they will be permanently shut-down, as
addressed by Section 225.630, by the date specified:
1)
EGUs that are required to permanently shut-down:
A)
On or before December 31, 2007, Waukegan 6; and
B)
On or before December 31, 2010, Will County 1 and Will County
2.
2)
Any other Specified EGU that is permanently shut down by December 31,
2010.
c)
Beginning on January 1, 2015, and continuing thereafter, and measured on a
rolling 12-month basis (the initial period is January 1, 2015, through December
31, 2015, and, then, for every 12-month period thereafter), each Specified EGU,
except Will County 3, shall achieve one of the following emissions standards:
1)
An emissions standard of 0.0080 lbs mercury/GWh gross electrical output;
or
2)
A minimum 90 percent reduction of input mercury.
d)
Beginning on January 1, 2016, and continuing thereafter, Will County 3 shall
achieve the mercury emissions standards of subsection (c) of this Section
measured on a rolling 12-month basis (the initial period is January 1, 2016,
through December 31, 2016, and, then, for every 12-month period thereafter).
e)
At any time prior to the dates required for compliance in subsections (c) and (d)
of this Section, the owner or operator of a Specified EGU, upon notice to the
Agency, may elect to comply with the emissions standards of subsection (c) of
129
this Section measured on a rolling 12-month basis for one or more EGUs. Once
an EGU is subject to the mercury emissions standards of subsection (c) of this
Section, it shall not be subject to the requirements of subsections (g), (h), (i), (j)
and (k) of this Section.
f)
Compliance with the mercury emissions standards or reduction requirement of
this Section must be calculated in accordance with Section 225.230(a) or (b).
g)
For each EGU for which injection of halogenated activated carbon is required by
subsection (a)(1) of this Section, the owner or operator of the EGU must inject
halogenated activated carbon in an optimum manner, which, except as provided in
subsection (h) of this Section, is defined as all of the following:
1)
The use of an injection system for effective absorption of mercury,
considering the configuration of the EGU and its ductwork;
2)
The injection of halogenated activated carbon manufactured by Alstom,
Norit, or Sorbent Technologies, or the injection of any other halogenated
activated carbon or sorbent that the owner or operator of the EGU has
demonstrated to have similar or better effectiveness for control of mercury
emissions; and
3)
The injection of sorbent at the following minimum rates, as applicable:
A)
For an EGU firing subbituminous coal, 5.0 lbs per million actual
cubic feet or, for any cyclone-fired EGU that will install a scrubber
and baghouse by December 31, 2012, and which already meets an
emission rate of 0.020 lb mercury/GWh gross electrical output or
at least 75 percent reduction of input mercury, 2.5 lbs million
actual cubic feet;
B)
For an EGU firing bituminous coal, 10.0 lbs per million actual
cubic feet or, for any cyclone-fired EGU that will install a scrubber
and baghouse by December 31, 2012, and which already meets an
emission rate of 0.020 lb mercury/GWh gross electrical output or
at least 75 percent reduction of input mercury, 5.0 lbs million
actual cubic feet;
C)
For an EGU firing a blend of subbituminous and bituminous coal,
a rate that is the weighted average of the above rates, based on the
blend of coal being fired; or
D)
A rate or rates set lower by the Agency, in writing, than the rate
specified in any of subsections (g)(3)(A), (g)(3)(B), or (g)(3)(C) of
this Section on a unit-specific basis, provided that the owner or
operator of the EGU has demonstrated that such rate or rates are
130
needed so that carbon injection will not increase particulate matter
emissions or opacity so as to threaten noncompliance with
applicable requirements for particulate matter or opacity.
2)
For purposes of subsection (g)(3) of this Section, the flue gas flow rate
must be determined for the point sorbent injection; provided that this flow
rate may be assumed to be identical to the stack flow rate if the gas
temperatures at the point of injection and the stack are normally within
100º F, or the flue gas flow rate may otherwise be calculated from the
stack flow rate, corrected for the difference in gas temperatures.
h)
The owner or operator of an EGU that seeks to operate an EGU with an activated
carbon injection rate or rates that are set on a unit-specific basis pursuant to
subsection (g)(3)(D) of this Section must submit an application to the Agency
proposing such rate or rates, and must meet the requirements of subsections (h)(1)
and (h)(2) of this Section, subject to the limitations of subsections (h)(3) and
(h)(4) of this Section:
1)
The application must be submitted as an application for a new or revised
federally enforceable operation permit for the EGU, and it must include a
summary of relevant mercury emissions data for the EGU, the unit-
specific injection rate or rates that are proposed, and detailed information
to support the proposed injection rate or rates; and
2)
This application must be submitted no later than the date that activated
carbon must first be injected. For example, the owner or operator of an
EGU that must inject activated carbon pursuant to subsection (a)(1) of this
Section must apply for unit-specific injection rate or rates by July 1, 2008.
Thereafter, the owner or operator may supplement its application; and
3)
Any decision of the Agency denying a permit or granting a permit with
conditions that set a lower inject rate or rates may be appealed to the
Board pursuant to Section 39 of the Act.
4)
The owner or operator of an EGU may operate at the injection rate or rates
proposed in its application until a final decision is made on the application
including a final decision on any appeal to the Board.
i)
During any evaluation of the effectiveness of a listed sorbent, alternative sorbent,
or other technique to control mercury emissions, the owner or operator of an EGU
need not comply with the requirements of subsection (g) of this Section for any
system needed to carry out the evaluation, as further provided as follows:
1)
The owner or operator of the EGU must conduct the evaluation in
accordance with a formal evaluation program submitted to the Agency at
least 30 days prior to commencement of the evaluation;
131
2)
The duration and scope of the evaluation may not exceed the duration and
scope reasonably needed to complete the desired evaluation of the
alternative control techniques, as initially addressed by the owner or
operator in a support document submitted with the evaluation program;
and
3)
The owner or operator of the EGU must submit a report to the Agency no
later 30 days after the conclusion of the evaluation that describes the
evaluation conducted and which provides the results of the evaluation; and
4)
If the evaluation of the alternative control techniques shows less effective
control of mercury emissions from the EGU than was achieved with the
principal control techniques, the owner or operator of the EGU must
resume use of the principal control techniques. If the evaluation of the
alternative control technique shows comparable effectiveness to the
principal control technique, the owner or operator of the EGU may either
continue to use the alternative control technique in a manner that is at least
as effective as the principal control technique or it may resume use of the
principal control techniques. If the evaluation of the control techniques
shows more effective control of mercury emissions than the control
technique, the owner or operator of the EGU must continue to use the
alternative control technique in a manner that is more effective than the
principal control technique, so long as it continues to be subject to this
Section 225.615.
j)
In addition to complying with the applicable recordkeeping and monitoring
requirements in Sections 225.240 through 225.290, the owner or operator of an
EGU that elects to comply with Section 225.230(a) by means of this Subpart F
must also comply with the following additional requirements:
1)
For the first 36 months that injection of sorbent is required, it must
maintain records of the usage of sorbent, the exhaust gas flow rate from
the EGU, and the sorbent feed rate, in pounds per million actual cubic feet
of exhaust gas at the injection point, on a weekly average;
2)
After the first 36 months that injection of sorbent is required, it must
monitor activated sorbent feed rate to the EGU, flue gas temperature at the
point sorbent injection, and exhaust gas flow rate from the EGU,
automatically recording this data and the sorbent carbon feed rate, in
pounds per million actual cubic feet of exhaust gas at the injection point,
on an hourly average; and
3)
If a blend of bituminous and subbituminous coal is fired in the EGU, it
must keep records of the amount of each type of coal burned and the
required injection rate for injection of activated carbon, on a weekly basis.
132
k)
In addition to complying with the applicable reporting requirements in Sections
225.240 through 225.290, the owner or operator of an EGU that elects to comply
with Section 225.230(a) by means of this Subpart F must also submit quarterly
reports for the recordkeeping and monitoring conducted pursuant to subsection (j)
of this Section.
(Source: Added at 31 Ill. Reg. ____________, effective _____________)
Section 225.620
Emissions Standards for NO
x
and SO
2
a)
Emissions Standards for NO
x
and Reporting Requirements.
1)
Beginning with calendar year 2012 and continuing in each calendar year
thereafter, the CPS group, which includes all Specified EGUs that have
not been permanently shut-down by December 31 before the applicable
calendar year, must comply with a CPS group average annual NO
x
emissions rate of no more than 0.11 lbs/mmBtu.
2)
Beginning with ozone season control period 2012 and continuing in each
ozone season control period (May 1 through September 30) thereafter, the
CPS group, which includes all Specified EGUs that have not been
permanently shut-down by December 31 before the applicable ozone
season, must comply with a CPS group average ozone season NO
x
emissions rate of no more than 0.11 lbs/mmBtu.
3)
The owner or operator of the Specified EGUs in the CPS group must file
not later than one year after startup of any selective SNCR on such EGU, a
report with the Agency describing the NO
x
emissions reductions that the
SNCR has been able to achieve.
b)
Emissions Standards for SO
2
. Beginning in calendar year 2013 and continuing in
each calendar year thereafter, the CPS group must comply with the applicable
CPS group average annual SO
2
emissions rate listed below:
year
lbs/mmBtu
2013
0.44
2014
0.41
2015
0.28
2016
0.195
2017
0.15
2018
0.13
2019
0.11
133
c)
Compliance with the NO
x
and SO
2
emissions standards must be demonstrated in
accordance with Sections 225.310, 225.410, and 225.510. The owner or operator
of the Specified EGUs must complete the demonstration of compliance pursuant
to Section 225.635(c) before March 1 of the following year for annual standards
and before November 30 of the particular year for ozone season control periods
(May 1 through September 30) standards, by which date a compliance report must
be submitted to the Agency.
d)
The CPS group average annual SO
2
emission rate, annual NO
x
emission rate and
ozone season NO
x
emission rates shall be determined as follows:
n
n
ER
avg
=
Σ
(SO
2i
or NO
xi
tons)
∕
Σ
(HI
i
)
i=1
i=1
Where:
ER
avg
=
average annual or ozone season emission
rate in lbs/mmBbtu of all EGUs in the CPS
group.
HI
i
=
heat input for the annual or ozone control
period of each EGU, in mmBtu.
SO
2i
=
actual annual SO
2
tons of each EGU in the
CPS group.
NO
xi
=
actual annual or ozone season NO
x
tons of
each EGU in the CPS group.
n
=
number of EGUs that are in the CPS group
i
=
each EGU in the CPS group.
(Source: Added at 31 Ill. Reg. ____________, effective _____________)
Section 225.625
Control Technology Requirements for NO
x
, SO
2
, and PM Emissions
a)
Control Technology Requirements for NO
x
and SO
2
.
1)
On or before December 31, 2013, the owner or operator must either
permanently shutdown or install and have operational FGD equipment on
Waukegan 7:
2)
On or before December 31, 2014, the owner or operator must either
permanently shutdown or install and have operational FGD equipment on
Waukegan 8;
3)
On or before December 31, 2015, the owner or operator must either
permanently shutdown or install and have operational FGD equipment on
Fisk 19:
134
4)
If Crawford 7 will be operated after December 31, 2018, and not
permanently shutdown by this date, the owner or operator must
A)
On or before December 31, 2015, install and have operational
SNCR or equipment capable of delivering essentially equivalent
NO
x
reductions on Crawford 7; and
B)
On or before December 31, 2018, install and have operational FGD
equipment on Crawford 7;
5)
If Crawford 8 will be operated after December 31, 2017 and not
permanently shutdown by this date, the owner or operator must:
A)
On or before December 31, 2015, install and have operational
SNCR or equipment capable of delivering essentially equivalent
NO
x
emissions reductions on Crawford 8; and
B)
On or before December 31, 2017, install and have operational FGD
equipment on Crawford 8.
b)
Other Control Technology Requirements for SO
2
. Owners or operators of
Specified EGUs must either permanently shutdown or install FGD equipment on
each Specified EGU (except Joliet 5), on or before December 31, 2018, unless an
earlier date is specified in subsection (a) of this Section.
c)
Control technology requirements for PM. The owner or operator of the two
Specified EGUs listed below that are equipped with a hot-side ESP must either
replace the hot-side ESPs with a cold-side ESP, install an appropriately designed
fabric filter, or permanently shut-down the EGU by the dates specified below.
Hot-side ESP means an ESP on a coal-fired boiler that is installed before the
boiler's air-preheater where the operating temperature is typically at least 550º F,
as distinguished from a cold-side ESP that is installed after the air pre-heater
where the operating temperature is typically no more than 350º F.
1)
Waukegan 7 on or before December 31, 2013; and
2)
Will County 3 on or before December 31, 2015.
d)
Beginning on December 31, 2008, and annually thereafter up to and including
December 31, 2015, the owner or operator of the Fisk power plant must submit in
writing to the Agency a report on any technology or equipment designed to affect
air quality that has been considered or explored for the Fisk power plant in the
preceding 12 months. This report will not obligate the owner or operator to install
any equipment described in the report.
135
e)
Notwithstanding 35 Ill. Adm. Code 201.146(hhh), until an EGU has complied
with the applicable requirements of Sections 225.625(a), (b), and (c), the owner or
operator of the EGU must obtain a construction permit for any new or modified
air pollution control equipment that it proposes to construct for control of
emissions of mercury, NO
x
, PM, or SO
2
.
(Source: Added at 31 Ill. Reg. ____________, effective _____________)
Section 225.630
Permanent Shut-Downs
a)
The owner or operator of the following EGUs must permanently shut-down the
EGU by the dates specified:
1)
Waukegan 6 on or before December 31, 2007; and
2)
Will County 1 and Will County 2 on or before December 31, 2010.
b)
No later than 8 months before the date that a Specified EGU will be permanently
shut-down, the owner or operator must submit a report to the Agency that
includes a description of the actions that have already been taken to allow the
shut-down of the EGU and a description of the future actions that must be
accomplished to complete the shut-down of the EGU, with the anticipated
schedule for those actions and the anticipated date of permanent shut-down of the
unit.
c)
No later than six months before a Specified EGU will be permanently shut-down,
the owner or operator shall apply for revisions to the operating permits for the
EGU to include provisions that terminate the authorization to operate the unit on
that date.
d)
If after applying for or obtaining a construction permit to install required control
equipment, the owner or operator decides to permanently shut-down a Specified
EGU rather than install the required control technology, the owner or operator
must immediately notify the Agency in writing and thereafter submit the
information required by subsections (b) and (c) of this Section.
e)
Failure to permanently shut-down a Specified EGU by the required date shall be
considered separate violations of the applicable emissions standards and control
technology requirements of this Subpart F for NO
x
, PM, SO
2
, and mercury.
(Source: Added at 31 Ill. Reg. ____________, effective _____________)
136
Section 225.635
Requirements for CAIR SO
2
, CAIR NO
x
, and CAIR NO
x
Ozone Season
Allowances
a)
The following requirements apply to the owner, the operator and the designated
representative with respect to CAIR SO
2
, CAIR NO
x
, and CAIR NO
x
Ozone
Season allowances:
1)
The owner, operator, and CAIR designated representative of Specified
EGUs in a CPS group is permitted to sell, trade, or transfer SO
2
and NO
x
emissions allowances of any vintage owned, allocated to, or earned by the
Specified EGUs (the "CPS Allowances") to its affiliated Homer City,
Pennsylvania generating station (“Homer City Station”) for as long as the
Homer City Station needs the CPS Allowances for compliance.
2)
When and if the Homer City Station no longer requires all of the CPS
Allowances, the owner, operator, or CAIR designated representative of
Specified EGUs in CPS group may sell any and all remaining CPS
Allowances, without restriction, to any person or entity located anywhere,
except that the owner or operator may not directly sell, trade, or transfer
CPS Allowances to a CAIR NO
x
or CAIR SO
2
unit located in Ohio,
Indiana, Illinois, Wisconsin, Michigan, Kentucky, Missouri, Iowa,
Minnesota, or Texas.
3)
In no event shall this subsection (a) require or be interpreted to require any
restriction whatsoever on the sale, trade, or exchange of the CPS
Allowances by persons or entities who have acquired the CPS Allowances
from the owner, operator, or CAIR designated representative of Specified
EGUs in a CPS group.
b)
The owner, operator, and CAIR designated representative of EGUs in a CPS
group comprised of is prohibited from purchasing or using CAIR SO
2
, CAIR
NO
x
, and CAIR NO
x
Ozone Season allowances for the purposes of meeting the
SO
2
and NO
x
emissions standards set forth in Section 225.620.
c)
Before March 1, 2010, and continuing each year thereafter, the CAIR designated
representative of the EGUs in a CPS group must submit a report to the Agency
that demonstrates compliance with the requirements of this Section 225.635 for
the previous calendar year and ozone season control period (May 1 through
September 30), and includes identification of any CAIR allowances that have
been used for compliance with the CAIR trading programs as set forth in Subparts
C, D, and E, and any CAIR allowances that were sold, gifted, used, exchanged, or
traded. A final report must be submitted to the Agency by August 31 of each
year, providing either verification that the actions described in the initial report
have taken place, or, if such actions have not taken place, an explanation of the
changes that have occurred and the reasons for such changes.
137
(Source: Added at 31 Ill. Reg. ____________, effective _____________)
Section 225.640
Clean Air Act Requirements
The SO
2
emissions rates set forth in this Subpart F shall be deemed to be best available retrofit
technology (“BART”) under the Visibility Protection provisions of the CAA, 42 U.S.C. 7491,
reasonably available control technology (“RACT”) and reasonably available control measures
(“RACM”) for achieving fine particulate matter (“PM
2.5
”) requirements under NAAQS in effect
on the effective date of this Subpart F, as required by the CAA, 42 U.S.C. 7502. The Agency
may use the SO
2
and NO
x
emissions reductions required under this Subpart F in developing
attainment demonstrations and demonstrating reasonable further progress for PM
2.5
and 8 hour
ozone standards, as required under the CAA. Furthermore, in developing rules, regulations, or
state implementation plans designed to comply with PM
2.5
and 8 hour ozone NAAQS, the
Agency, taking into account all emission reduction efforts and other appropriate factors, will use
best efforts to seek SO
2
and NO
x
emissions rates from other EGUs that are equal to or less than
the rates applicable to the CPS Group and will seek SO
2
and NO
x
reductions from other sources
before seeking additional emissions reductions from any EGU in the CPS Group.
(Source: Added at 31 Ill. Reg. ____________, effective _____________)
138
225.Appendix A
Specified EGUs for Purposes of Subpart F (Midwest Generation’s Coal-
Fired Boilers as of July 1, 2006)
Plant
Permit
Boiler
Permit designation
Subpart F
Number
Designation
Crawford
031600AIN
7
Unit 7 Boiler BLR1
Crawford 7
8
Unit 8 Boiler BLR2
Crawford 8
Fisk
031600AMI
19
Unit 19 Boiler BLR19
Fisk 19
Joliet
197809AAO
71
Unit 7 Boiler BLR71
Joliet 7
72
Unit 7 Boiler BLR72
Joliet 7
81
Unit 8 Boiler BLR81
Joliet 8
82
Unit 8 Boiler BLR82
Joliet 8
5
Unit 6 Boiler BLR5
Joliet 6
Powerton
179801AAA
51
Unit 5 Boiler BLR 51
Powerton 5
52
Unit 5 Boiler BLR 52
Powerton 5
61
Unit 6 Boiler BLR 61
Powerton 6
62
Unit 6 Boiler BLR 62
Powerton 6
Waukegan
097190AAC
17
Unit 6 Boiler BLR17
Waukegan 6
7
Unit 7 Boiler BLR7
Waukegan 7
8
Unit 8 Boiler BLR8
Waukegan 8
Will County 197810AAK
1
Unit 1 Boiler BLR1
Will County 1
2
Unit 2 Boiler BLR2
Will County 2
3
Unit 3 Boiler BLR3
Will County 3
4
Unit 4 Boiler BLR4
Will County 4
(Source: Added at 31 Ill. Reg. ____________, effective _____________)
IT IS SO ORDERED.
I, Dorothy M. Gunn, Clerk of the Illinois Pollution Control Board, certify that the Board
adopted the above opinion and order on April 19, 2007, by a vote of 3-0.
Dorothy M. Gunn, Clerk
Illinois Pollution Control Board
