2

In today’s opinion, the Board first provides background and procedural history on this

rulemaking. Next, the Board discusses the pre-first notice public comments filed in this

proceeding and describes how the Board ruled on the contested issues at first notice. The Board

then summarizes the public comments received during the first-notice public comment period.

Those summaries are followed by a description of the Board’s second-notice analysis and

disposition of those issues that remained in dispute after the Board’s first-notice decision. The

adopted rules themselves are set forth in the order following this opinion.

BACKGROUND

IEPA stated that the CAIR rule is intended to satisfy Illinois’ obligations under USEPA’s

“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

According to IEPA, the rule is also designed to address, in part, IEPA’s

obligation to meet certain federal Clean Air Act (CAA) requirements, including:

•

Adopting control strategies necessary to demonstrate attainment of the fine particulate

matter (PM

2.5

) and 8-hour ozone NAAQS in the greater Chicago and Metro East/St.

Louis nonattainment areas;

•

Adopting an implementation plan addressing visibility; and

•

Adopting an implementation plan addressing the interstate transport of air pollution.

Id

.

at 2.

In the federal CAIR, USEPA stated that 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). USEPA proposed the federal CAIR emission reductions for SO

2

and NO

x

that apply to upwind states based on that assessment.

Id

. USEPA gave three primary reasons for

addressing interstate pollution transport in a timely manner. First, 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, according to

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

cleanup costs 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 NAAQS in downwind areas to

revise their SIPs to include control measures on SO

2

and NO

x

. The federal CAIR also requires

1

“SIP” is the short form of state implementation plan.

2

IEPA’s “Statement of Reasons” included in the rulemaking proposal is cited as “Stat. at _.”

---

3

that 25 states must reduce: (1) annual SO

2

and NO

x

emissions for the purposes of the PM

2.5

NAAQS; and (2) seasonal NO

x

emissions for purposes of the 8-hour ozone NAAQS.

In the federal CAIR, 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 USEPA or adopting a federal “cap and trade” program

covering its electric generating units (EGUs). IEPA, in its proposal, chose the latter option, and

the Board adopted that approach at first and second notice and adopts it today as a final rule.

The CAA established 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).

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 8-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 the 8-hour ozone NAAQS for those two nonattainment

areas. Section 169(A) of the CAA requires the adoption of an implementation plan addressing

visibility. Section 110(a)(2)(D) of the CAA requires adoption of a SIP addressing the interstate

transport of air pollution. Stat. at 2.

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). USEPA believes that a major reason for this failure is that states are not able to address

the 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 emission 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 federal 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. Because 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 reductions will be implemented in two phases. Phase I for

NO

x

reductions will start in 2009 (covering 2009-2014). Phase I for SO

2

reductions will start in

2010 (covering 2010-2014). Phase II for both NO

x

and SO

2

reductions will start in 2015

---

4

(covering 2015 and thereafter).

In lieu of complying with USEPA’s 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.

For the CAIR NO

x

trading programs, a state is given a pool of allowances equal to its NO

x

budgets to distribute as it chooses. For 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.

This rule, which amends Subpart A and adds new Subparts C, D, E, and F of Part 225,

adopts the CAIR SO

2

, CAIR NO

x

annual, and CAIR NO

x

ozone season trading programs to

reduce the intrastate and interstate transport of SO

2

and NO

x

emissions. Stat. at 1. The rule is

intended to cover the entire State of Illinois and is expected to affect existing and new EGUs.

Id

.

at 24. Approximately 229 existing EGUs will be subject to the CAIR NO

x

annual, CAIR SO

2

,

and CAIR NO

x

ozone season trading programs.

Id

. 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.

Id

. 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.

Id

. 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 rule is 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

.

---

5

PROCEDURAL HISTORY

Rulemaking Proposal

IEPA filed its rulemaking proposal on May 30, 2006. On June 15, 2006, the Board

accepted the proposal for hearing. As required by Section 27(b) of the Environmental Protection

Act (Act) (415 ILCS 5/27(b) (2006)), the Board requested that the Department of Commerce and

Economic Opportunity (DCEO) conduct an economic impact study (EcIS) on this rulemaking.

The Board’s EcIS request, dated June 28, 2006, was placed in this rulemaking’s docket. DCEO

did not respond to the Board’s request. The Board has received no testimony or comment

regarding the DCEO’s lack of response.

On July 20, 2006, based on a federal deadline discussed below, the Board granted IEPA’s

motion for expedited review in part. To maximize opportunities for public participation,

however, the Board denied IEPA’s motion in part by declining to proceed immediately to first

notice without commenting on the merits of the IEPA proposal.

Hearings

The Board held five days of hearings. 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.

3

Over the course of the two hearings, Rachel Doctors and John Kim participated on behalf

of IEPA. Kathleen Bassi, Stephen Bonebrake, and Shelden Zabel participated on behalf of

Dynegy Midwest Generation (Dynegy) and Southern Illinois Power Cooperative (SIPC). David

Rieser participated on behalf of Ameren Energy Generating Company, Ameren Energy

Resources Generating Company, and Electric Energy, Inc. (collectively, Ameren). Steven J.

Murawski participated on behalf of Zion Energy, LLP (Zion). Faith E. Bugel participated on

behalf of the Environmental Law and Policy Center (ELPC). Bruce E. Nilles participated on

behalf of the Sierra Club. James Russell participated on behalf of the Christian County

Generation, LLC. Bill Forcade participated on behalf of Kincaid Generation, LLC (Kincaid).

Finally, Keith Harley participated on behalf of Environment Illinois.

At the first hearing, the hearing officer entered into the record and accepted as hearing

exhibits the pre-filed testimony of the following witnesses submitted on behalf of IEPA: 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.

At the second hearing, the hearing officer entered into the record and accepted as hearing

exhibits the pre-filed testimony of the following witnesses: Jason M. Goodwin on behalf of Zion

3

Hearing transcripts are cited as “Tr. at [page] ([hearing date]).”

---

6

(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 ELPC (Kubert Exh. 1). Robert B.

Asplund testified on behalf of Kincaid. A total of seven exhibits were offered and accepted at

the second hearing.

Motions to Dismiss and Amend

On November 30, 2006, Dynegy, Midwest Generation, LLC (Midwest Generation), and

SIPC moved to dismiss the rulemaking proposal. On January 5, 2007, SIPC and Midwest

Generation withdrew as parties to the motion to dismiss.

On March 13, 2007, IEPA 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 Motion at 1, 3. Dynegy also

requested that the Board stay action on the motion to dismiss. The Board received two

other motions to amend the rule: motions to amend were submitted by IEPA on

November 27, 2006, and by Midwest Generation and IEPA jointly on February 16, 2007.

In its April 19, 2007 first-notice opinion and order, the Board granted the three motions

to amend and incorporated the requested amendments. The Board also granted Dynegy’s request

to stay ruling on Dynegy’s motion to dismiss, based on Dynegy’s representation that it would

withdraw the motion if the rule changes proposed jointly by Dynegy and IEPA were accepted at

first notice. In its July 26, 2007 second-notice opinion, the Board, noting that Dynegy had not

filed the promised withdrawal, on its own motion struck Dynegy’s motion to dismiss. On

August 21, 2007, Dynegy filed a letter explaining why it did not withdraw its motion to dismiss.

According to Dynegy, the company was waiting to withdraw the motion because the rule

language jointly proposed by Dynegy and IEPA, as adopted at first notice by the Board,

contained a typographical error considered significant by Dynegy. Dynegy Letter at 1-2. The

typographical error, identified as such by IEPA (PC 15 at 27), was corrected by the Board at

second notice.

Pre-First-Notice Public Comments

Sixteen public comments were filed before first notice. IEPA filed post-hearing

comments to the first set of hearings on October 27, 2006 (PC 1). On December 15, 2006,

Kincaid filed a Dominion NO

x

Compliance Strategy and the resumé of Andy Yaros (PC 2). On

December 21, 2006, the Board received the post-hearing comments to the second set of hearings

from of Jason M. Goodwin for Zion (PC 3). On January 5, 2007, post-hearing comments were

received from Ameren (PC 4); IEPA (PC 5); Dynegy and SIPC (PC 6); ELPC, the American

Lung Association of Metropolitan Chicago, Environment Illinois, and the Sierra Club (PC 7);

Midwest Generation (PC 8); Midwest Generation and IEPA (PC 9); and Kincaid (PC 10). On

January 10, 2007, IEPA filed a motion for leave to file

instanter

a revised joint comment

(granted April 19, 2007), attaching the revised joint comment (PC 11) of IEPA and Midwest

---

7

Generation. Finally, on February 5, 2007, the Sierra Club submitted 85 clean air questionnaires

from Harold Washington College (PC 12).

First Notice

The Board adopted its first-notice opinion and order on April 19, 2007. First notice was

published in the

Illinois Register

on May 11, 2007 (31 Ill. Reg. 6769 (May 11, 2007)), which

began the 45-day first-notice public comment period, ending on June 25, 2007.

First-Notice Public Comments

The Board received five first-notice public comments: PC 13 from SIPC; PC 14 from

Midwest Generation; PC 15 from IEPA; PC 16 from Zion; and PC 17 from Kincaid and

Dominion.

Second Notice

The Board issued its second-notice opinion and order on July 26, 2007. The second-

notice period began the next day, on July 27, 2007, with the Board’s submittal of the written

notice to JCAR. The CAIR rule was considered by JCAR at its meeting on August 14, 2007. On

that same date JCAR issued a certification on no objection regarding the rule.

Motion for Additional Hearing

After the second-notice period had begun, Midwest Generation, on July 30, 2007, filed a

motion for an additional hearing. The Board denied the motion by order of August 9, 2007.

SUMMARY OF PRE-FIRST-NOTICE PUBLIC COMMENTS

Public Comment 2: Kincaid and Dominion

Kincaid and Dominion asserted that the most economical means to NO

x

compliance is to

install high capital cost selective catalytic reduction (SCR) equipment on their largest units with

the highest NO

x

rates. PC 2 at 1. Dominion has put SCRs on 12 of its largest coal units.

Id

.

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.

Public Comment 3: Zion

Zion preferred a fuel-neutral allocation mechanism, but was willing to consider a

compromise alternative fuel-weighting factor that closes the gap between the fuel-neutral option

and IEPA’s proposal. Zion suggested a compromise factor of 0.7 for both gas-fired and oil-fired

units. PC 3 at 2. 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,

according to Zion.

Id.

Zion added that a compromise factor also provides additional

consideration for reliability (through enhanced allocation treatment) for units operating in gas-

---

8

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.

Zion proposed a CASA set-aside in the 5-10% range, rather than 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. Zion also suggested 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

Ameren requested that the Board allow the use of CASA allowances to support advanced

over-fired air (OFA) NO

x

reduction strategies. PC 4 at 1. Ameren proposed language designed

to create a narrow and limited eligibility for OFA projects. PC 4 at 5. Ameren stated that such

projects can only be eligible if they achieve 30% reductions. 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: IEPA

IEPA maintained that fuel-weighting as proposed is appropriate. PC 5 at 4. IEPA

rejected a proposal on behalf of Christian County Generation to eliminate

pro rata

reduction of

CASA allocations for early adopters. IEPA maintained its support for the 25% CASA as

proposed.

Id

. at 7. IEPA disagreed with allowing OFA projects to receive allowances from the

CASA.

Id

. at 10.

IEPA agreed to allow the only remaining fluidized bed combustion (FBC) boiler in

Illinois to receive CASA allowances. The single existing FBC boiler is the SIPC 123 boiler in

Marion, Williamson County. IEPA, however, opposed allowing any future FBC boilers to

receive CASA allowances. PC 5 at 11.

IEPA agreed to revise the allocation method 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. The new subsections include a factor change from 1.0 to 1.4.

Id

. The factor change

would compensate for SIPC’s direct measurements and provide the same level of incentive IEPA

was attempting to achieve.

Id.

IEPA proposed several additional changes to the rule language suggested by USEPA. PC

5 at 21. IEPA contended that the three most significant suggested amendments were: (1)

deleting Subsection (d)(5)(C) in Sections 225.445 and 225.545 that required IEPA to reduce a

unit’s allocation from the new unit set-aside (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

---

9

indicate that IEPA can only allocate whole allowances and allowances that cannot be distributed

on that basis would be retained and distributed

pro rata

for the next control period.

Id

.

Public Comment 6: Dynegy and SIPC

Dynegy and SIPC stated they have consistently expressed their position that a set-aside of

25% for the CASA is not justifiable and would merely displace the location of the emissions. PC

6 at 3. Dynegy and SIPC stated that IEPA has not identified projects that justify the size of the

set-aside, and fear that a significant, and perhaps inequitable, portion of the CASA allowances

could go to Ameren.

Dynegy and SIPC also disputed IEPA’s economic analysis of the CASA as highly cost-

effective. Further, stated 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. PC 6 at 12. The companies took issue with the structure of the CASA and stated that

providing carve-out “incentives” for those who reduce early and subsidizing the costs of more

expensive pollution control equipment is inconsistent, and skews how CASA allowances are

allocated.

Id

. at 18. The companies argued that the CASA does not treat all EGUs equally and

offers examples as to how CASA subsidizes the construction of pollution control equipment by

some companies at the expense of others. The companies also opposed Ameren’s proposal to

add “advanced” OFA to the CASA.

The companies contended that the Governor’s energy plans are no bases to justify the

size of the energy efficiency and renewable energy (EE/RE) portion of the CASA and that IEPA

does not bear the responsibility for developing CAIR to accommodate the Governor’s energy

plan. PC 6 at 13.

The companies opposed IEPAs proposal that allowance allocations be based upon gross

electrical output rather than heat input. PC 6 at 24. The companies stated that the efficiency

assumed in IEPA’s heat input to gross electrical output formula is not representative of actual

efficiencies at the plants and disadvantages the vast majority of the regulated entities. Dynegy

and SIPC stated that industry wants an appropriate conversion formula to be applied.

Id

. at 25.

With respect to encouraging efficiency, the companies noted that high efficiency does not equate

to lower emissions and greater environmental benefit. The companies used SIPC’s circulating

fluidized bed (CFB) as an example.

Id

. at 25-26.

The companies supported IEPA’s proposal regarding weights assigned to fuel types and

opposed Zion’s request that the Board remove the fuel-weighting or, alternatively, assign a factor

of 1.0 for coal and 0.6 for all other fuels. PC 6 at 27.

Finally, Dynegy and SIPC had concerns about the two-year “look-back.” The companies

opposed IEPA’s approach to annual allowance allocations, and supported use of USEPA’s

approach of using a permanent baseline. PC 6 at 28-29. The companies favored 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 35 Ill. Adm. Code 217, Subpart W).

Id

. at 31.

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10

Public Comment 7: ELPC, American Lung Association of Metropolitan Chicago,

Environment Illinois, and Sierra Club

ELPC, by itself and on behalf of American Lung Association of Metropolitan Chicago,

Environment Illinois, and the Sierra Club urged the Board to amend IEPA’s proposed CAIR rule

in three principle ways. PC 7 at 1. First, the renewable energy and energy efficiency set-asides

should be increased from 12% to 15%, with an annual increase of 1% to a maximum of 20%, to

better meet the rule’s own renewable energy goals.

Id.

Second, the CASA proposed for FBC

boilers should be eliminated because FBC boilers are not a clean coal technology.

Id.

Third, the

fuel-weighting factors should be eliminated, because they discourage the use of cleaner fuels in

energy production.

Id.

According to these environmental groups, a fuel-neutral allocation

system that does not differentiate between coal and non-coal units is even-handed, treating all

units the same and allowing the trading program to do a more effective job of determining the

most cost-effective compliance combination.

Id

. at 10.

Public Comment 8: Midwest Generation

Midwest Generation supported a three-year averaging and five-year “look-back” period

to determine an EGU’s allowances, rather than the two-year period that IEPA proposed. PC 8 at

1. According to the company, this approach would help to make level the allowances for EGUs

in Illinois and avoid a skewed distribution of allowances or penalties associated with unexpected

or extended outages.

Id.

Midwest Generation was concerned that the two-year “look-back”

would encompass periods when the EGUs experience outages of various lengths of time and

EGUs would consequently receive a “short” allocation.

Id.

Finally, Midwest Generation

requested 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.

Public Comment 10: Kincaid

Kincaid did not support the 25% CASA. Kincaid stated that IEPA provided no

justification that the level of the proposed set-aside is necessary from an air quality perspective.

Kincaid further contended that these provisions would 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 adoption of the USEPA rule.

Kincaid also did not support the withholding of allowances from the Compliance

Supplement Pool (CSP). According to the company, the early reduction incentives that Illinois

included in its rules implementing the “NO

x

SIP Call” not only provide companies added

compliance flexibility, easing the burden once the requirements take effect, but also benefit the

environment by providing emission reductions sooner. PC 10 at 2-3.

---

11

Kincaid supported the five-year baseline 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 urged 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 asserted that a longer

baseline period would ensure that allocations would 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.

Public Comment 11: IEPA and Midwest Generation

IEPA and Midwest Generation 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 11 at 2. IEPA and Midwest Generation asked the Board to include a

new Subpart F entitled “Combined Pollutant Standards,” 35 Ill. Adm. Code Section 225.600 –

225.640, along with a new Appendix A to Part 225, in the proposed CAIR rulemaking that

reflects the parties’ agreement.

Id

. Under Subpart F, the agreement provides that Midwest

Generation will achieve reductions in mercury, NO

x

, Particulate Matter (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 installation of pollution control

equipment for NO

x

, PM, and SO

2

emissions that will also reduce mercury emissions.

Id

.

BOARD FIRST-NOTICE DISCUSSION

As the Board stated in its first-notice opinion of April 19, 2007, the majority of

participants in this rulemaking supported the majority of the IEPA-proposed rule, as amended

during this proceeding. The Board noted, however, that significant contested issues remained:

(1) whether 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 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 IEPA in its Technical Support Document (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 Subpart F, Combined Pollutant Standards (CPS), should be

included in the proposal. The Board at first notice addressed each of these contested issues in

turn, as described below.

Size of the Clean Air Set-Aside (CASA)

The Board noted that the CASA, and particularly the 25% set-aside, has been widely

addressed during this rulemaking. IEPA asserted that USEPA left the authority to the individual

states to distribute their allocations as necessary to meet each state’s individual goals. PC 5 at 7.

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12

IEPA contended that a financial analysis of the impact of the worst-case scenario (retiring the

30% set-aside (CASA plus NUSA) and relying solely on a 70% main pool) showed that 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

(Testimony of Saladino) at 13. Kincaid argued that the IEPA 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 contended that there appears to be little chance that these allowances will ever be

returned to the EGUs because 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 asserted that IEPA’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 suggested a CASA set-aside percentage

in the 5-10% range. Setting aside 25% of the allowance pool, in Zion’s opinion, unjustifiably

increases the compliance burden on facilities that already face significant emission reduction

obligations through an artificial reduction in allowances available for allocations.

Id

. at 4. Zion

also proposed that CASA applicants be restricted to electric generating sources and that non-

generating sources be eliminated from consideration in the proposed rule.

Id.

Ameren stated that CASA represents a useful balancing of technology, economic, energy,

and environmental considerations. Ameren requested the Board to adopt those portions of the

amended proposal that allow Ameren and other companies seeking to use the Multi-Pollutant

Strategy (MPS) to obtain CASA allowances. PC 4 at 3.

Dynegy and SIPC contended that a set-aside of 25% for the CASA is not justifiable. PC

6 at 2. They argued that setting aside 25% of Illinois’ cap is the equivalent of providing no

allowances to approximately a 4,250 megawatt (MW) EGU, and that this amounts to not

allocating allowances to the entirety of Dynegy’s system, plus City Water Light & Power and

SIPC, with 102 MW “still not accounted for.” PC 6 at 10-11.

Conversely, ELPC provided testimony recommending that the EE/RE set-asides be

increased to be consistent with the policy goals and policy targets set forth in the Governor

Blagojevich’s Sustainable Energy Plan. Tr.2 at 138. ELPC testified that increasing the EE/RE

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 found at first notice that the set-aside as proposed by IEPA is appropriate.

Kincaid’s assertion that it is penalized for previously installing technology is interesting but not

persuasive. IEPA 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 using

emission controls. As the Board noted, the intention appears to have been to provide as large an

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13

incentive as possible to attract new controls by subsidizing the large installation costs and not the

already existing, and smaller, operational costs. The Board at first notice agreed that providing

incentives for controls already installed would lessen the incentive for new controls.

Further, the record showed 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/selective non-catalytic NO

x

reduction (SNCR), one unit controlled by baghouse, and five

units controlled by flue gas desulfurization (FGD). Each of these units is ineligible for CASA as

proposed.

Kincaid acknowledged at hearing that installing the SCRs was a voluntary decision made

for business purposes.

See

Kincaid Exh. 1 (Testimony 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 Section 217.770 of the Subpart W rules. Thus, CASA aside, Kincaid has already

received credit to assist in recovering installation costs for its SCRs. Finally, the Board at first

notice agreed with IEPA that, while entities that have previously installed controls may not avail

themselves of CASA allocations for those installations, such entities may still earn allowances by

participating in a different CASA category.

At first notice, the Board found that ELPC’s position, that IEPA should increase the

EE/RE 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. IEPA has stated that it did not

intend to set its EE/RE allocations predicated on the policy goals of the Governor’s Sustainable

Energy Plan. Nonetheless, the Board noted that the possibility of under-subscription in CASA

categories other than EE/RE may result in allocations eligible for approved EE/RE projects,

thereby exceeding the 12% initial design value.

Over-Fired Air (OFA)

The Board observed at first notice that a question existed as to whether OFA projects

should be excluded from receiving allowances from the CASA. As proposed by IEPA, Sections

225.460(c)(1) and 225.560(c) specifically excluded OFA from the list of projects eligible for

CASA clean technology allowances. IEPA maintained that neither standard OFA nor advanced

OFA should be an eligible project for the CASA. IEPA argued 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. According to IEPA, 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 requested that the Board allow the use of CASA allowances to support advanced

OFA NO

x

reduction strategies. PC 4 at 1. Ameren proposed that projects providing advanced

OFA to achieve at least a 30% reduction of the baseline NO

x

or OFA projects that are included as

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14

part of a comprehensive NO

x

reduction strategy with other listed technologies be allowed to

receive CASA allowances.

Id

. at 3.

Dynegy and SIPC argued 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 SIPC contended 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.

Id

. at 17.

In reviewing the record, the Board noted that 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 showed that the costs of OFA and

advanced OFA are significantly less than the costs of other controls. IEPA’s primary stated

purpose in establishing the pollution control upgrade category of the CASA is to lower the

capitol costs of upgrading, thereby promoting more expensive controls than OFA and advanced

OFA. Further, IEPA contended that the more costly controls generally result in the greatest

reductions in emissions. PC 5 at 10.

At first notice, the Board agreed with IEPA in that no evidence exists that advanced OFA

would result in significantly higher costs than standard OFA. The Board found that IEPA’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.

, Ameren Exh. 1 at 5.

Further, any CASA allowances allocated to OFA or advanced OFA could possibly offset more

costly controls with 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

IEPA argued 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 IEPA. IEPA specifically determined 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 in support of eliminating

pro rata

reductions of CASA allocations for early adopters, primarily to reduce the uncertainty in

allocations introduced by a

pro rata

allotment. Christian County Exh. 1 (Testimony of Kunkel)

at 6. As an alternative, Christian County Generation suggested a “first-come first-served” basis.

Tr.2 at 156.

The Board at first notice found that a proportionate sharing of allowances among all

eligible applications is appropriate. The Board agreed with IEPA that a system using fixed

portions could lead to difficulties in execution because the CASA is based on the number of

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15

electricity hours generated or conserved, which will vary on a yearly basis. A

pro rata

allocation

system, the Board found, would open up the CASA to all eligible facilities, and would also be

workable from IEPA’s perspective.

Fluidized Bed Combustion (FBC) Boilers

In its in initial proposal, IEPA proposed that FBC boilers be allowed to receive CASA

allowances in the clean coal technology category. However, IEPA committed to review its

stance on this issue after the first hearing and proposed before first notice that Illinois’ single

existing FBC boiler be allowed to receive CASA allowances, but that allowances to any future

FBC boilers be denied. PC 5 at 11. The Board agreed with IEPA and at first notice adopted the

revisions proposed by IEPA to Sections 225.460 and 225.465 with some minor changes.

ELPC argued that allowances should not be available as proposed for FBC boilers. PC 7

at 2. ELPC argued 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 integrated gasification combined cycle (IGCC) plants do;

and (3) they emit more greenhouse gases than PC boilers.

Id

. at 4.

ELPC argued 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, according to ELPC.

Id

. Further, ELPC argued that

expected NO

x

emission levels for recently-proposed IGCC plants result in more than 45% lower

NO

x

emissions.

Id

. at 7.

The Board noted at first notice that Illinois has 59 coal-fired boilers that would be

affected by the proposal. Only one of these is an FBC boiler: the SIPC FBC boiler in Marion.

The other boilers are all pulverized coal combustion (PCC) boilers and cyclone-fired boilers

(which burn crushed coal). The SIPC FBC boiler was constructed in 2001 and began operating

in 2003. PC 5 at 11.

The SIPC 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 SIPC 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 SIPC’s FBC

boiler has reached as low as 0.06 lbs/mmBtu during the third 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 SIPC decide to more fully use the NO

x

controls currently in place or

install additional controls for NO

x

and SO

2

on the FBC boiler.

Id.

at 12.

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16

Regarding the existing SIPC FBC boiler, the Board at first notice agreed with IEPA that

it is appropriate to recognize SIPC’s prior initiative to invest in a cleaner technology and allow

SIPC 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 SIPC FBC boiler’s actual emissions between 2003 and 2005 averaged 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 IEPA, the FBC boiler emission rates could be lower should SIPC 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 SIPC FBC to receive CASA allowances provides an

incentive for SIPC to further reduce NO

x

emissions because the number of CASA allowances

received is proportional to the amount of NO

x

emitted.

The Board additionally found at first notice that it was proper to deny access to CASA

allowances for any new FBC boiler. At the time of construction, SIPC’s FBC boiler was

considered a more current technology for utility boilers. PC 5 at 11. Since the installation of

SIPC’s FBC boiler, however, IGCC facilities have become commercially viable and the number

of applications for IGCC permits has increased nationwide.

Id

. at 13. The Board found that the

record is clear, and IEPA acknowledges, that FBC boilers result in higher NO

x

emissions than

IGCC plants. IGCC have become commercially viable. The Board at first notice found that

CASA allowances for clean coal technology must be available only for the most promising

commercially available technology,

i.e

., IGCC.

The Board also found persuasive ELPC’s argument that it is inappropriate to allow

“other” technologies that achieve emission rates comparable to FBC boilers to receive CASA

allowance. PC 7 at 6. To further IEPA’s intent and implement ELPC’s suggestion, the Board

amended Section 225.460(e) to exclude FBC boilers from the list of comparable technologies.

The Board therefore amended Section 225.460(e) to limit the comparison only to projects similar

in effect as the projects listed in Sections 225.460(a), (b), (c)(1) and (c)(2)(A).

IEPA proposed revisions to the allocation method 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 SIPC directly measures its emission rate in pound per megawatt

(lb/MW) rather than converting from pound per million Btu (lb/mmBtu). PC 5 at 17-18. IEPA

asserted that the proposed revision would not result in a significant change for the CASA

allowance distribution.

Id

. The proposed revision would include new subsections in Sections

225.465(b)(5)(B) and 225.565(b)(5)(B). Subsection (b)(5)(B) would 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 would compensate for SIPC’s direct measurements and provide the same level of

incentive that IEPA was previously attempting to achieve.

Id

.

At first notice, the Board agreed that the SIPC FBC boiler represents a special

circumstance as compared to the other boilers in the State. The Board found that the solution

proposed by IEPA has merit in that it recognizes the difference between the SIPC FBC boiler

and existing boilers, while also recognizing that clean coal technology has improved since the

SIPC FBC boiler was constructed. As stated in the first-notice opinion, IEPA’s new proposal

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17

along with the changes made by the Board should also alleviate the concerns raised by ELPC in

that future FBC boilers will not have access to CASA clean coal technology allowances.

The Board explained that by focusing on the most promising technology, IGCC, IEPA’s

proposal accomplishes CASA intentions while not penalizing SIPC 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 only recently that have

IGCC facilities been recognized and accepted as commercially viable. Thus, the Board found

that IEPA’s amended proposal that Illinois’ existing FBC boiler be allowed to receive CASA

allowances, but that allowances to any future FBC boilers be denied, is appropriate.

Two-Year “Look-Back”

As the Board observed in its first-notice opinion, IEPA’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 SIPC were troubled by IEPA’s approach to annual allowance

allocations. The companies’ concern with the two-year look-back was that the look-back period

would, from time to time, encompass periods when the EGUs experience outages of various

lengths of time. PC 6 at 28. Dynegy and SIPC were concerned with the look-back being 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 argued that in light of IEPA’s past

failure to timely allocate allowances, it becomes critical that the updating occur annually and

timely. PC 6 at 29.

Dynegy and SIPC argued that 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 SIPC argued 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 also expressed concern about the impact of outages on what it

opined is a short, two-year, look-back period. PC 8 at 1. Midwest Generation asserted that

under the language of the rule, these situations cannot be avoided.

Id.

Further, Midwest

Generation noted that 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, argued 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 Generation supported revising the

rule to reflect a three-year averaging concept and five-year look-back period.

The Board found at first notice that, mindful of the issues concerning a two-year look-

back, the benefits of a relatively short look-back period outweigh any potential difficulties.

IEPA asserted that a two-year look-back period provides an incentive for efficient operations,

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18

which will result in fewer emissions per unit of power produced. Stat. at 35. The Board agreed

with this general principle.

In addition, the concerns raised by Midwest Generation, SIPC, and Dynegy were also

raised with IEPA prior to the proposal being filed with the Board. In response, IEPA 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. IEPA 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 found IEPA’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 the Board explained, 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 because 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 adopted the rule for first notice as proposed in this regard.

Heat Input vs. Gross Electrical Output

IEPA proposed 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 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% would

be used to convert the heat input of a unit to gross electrical output. Stat. at 35; TSD at 101.

Midwest Generation requested that the Board consider heat input as the basis for

allocations, which is what Midwest Generation has reported and certified for years. PC 8 at 5.

Midwest Generation argued 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 SIPC asserted that the two companies generally

prefer that allocations be based upon heat input rather than gross electrical output as proposed by

IEPA. PC 6 at 2. However, that same public comment provided 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 SIPC asserted that the efficiency

assumed in IEPA’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 SIPC stated that it is their understanding that IEPA 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 SIPC were concerned about language currently in the rule

suggesting that there must be an actual measurement device installed on the generator,

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19

effectively a wattmeter, when that is not required by USEPA under 40 C.F.R. § 60 or 75.

Dynegy and SIPC asked the Board to ensure that the language included in the rule reflects the

parties’ intent.

Id

.

Christian County Generation provided testimony that its IGCC project would be greatly

disadvantaged by an allocation methodology that relies upon heat input. Tr.2 at 126-29.

The Board found at first notice that IEPA’s proposal to use gross electrical output as a

basis for distributing allowances is reasonable. IEPA’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 in

the amendment to the proposal filed on November 27, 2006. As amended, the proposal clarified

that either gross electrical output or heat input may be used to calculate converted gross output

for the control periods 2009 through 2013.

The Board found at first notice that gross electrical output does encourage efficiency, and

that its application in this instance, as amended, is technical feasible and economically

reasonable.

Air Quality Modeling

Kincaid urged IEPA 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 asserted that recent air quality modeling by the Lake Michigan Air

Directors Consortium (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.

IEPA asserted that it presented the results of two modeling studies in the TSD that

address the issues raised by Kincaid, and has, therefore, already presented the type of modeling

suggested. PC 5 at 19.

In reviewing the record, the Board noted at first notice that in March 2005, USEPA

presented a document entitled: “Technical Support Document for the Final Clean Air Interstate

Rule – Air Quality Modeling.” TSD at 35. IEPA summarized 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 to reach the emission reduction targets needed

for both ozone and PM

2.5

attainment, local volatile organic compound (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.

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20

IEPA asserted 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. 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.

At first notice, the Board found that modeling submitted by IEPA in the TSD is

appropriate and supportive of the emissions standards in the proposal. The record indicates 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 found that the record

supports adopting the proposal, and that no additional modeling is needed at this time.

Fuel-Weighting

The various participants were split on this issue, but IEPA maintained that fuel-weighting

as proposed is appropriate. Zion preferred a fuel-neutral allocation mechanism, but was willing

to consider a compromise alternative fuel-weighting factor that closes the gap between the fuel-

neutral option and IEPA’s proposal. Zion suggested a compromise factor of 0.7 for both gas-

fired and oil-fired units. PC 3 at 2.

ELPC urged the elimination or modification of the fuel-weighting component of the

proposed Illinois rule, arguing that a fuel-neutral approach would achieve the deeper, faster

reductions IEPA seeks. PC 7 at 10.

Dynegy and SIPC supported IEPA’s proposal regarding weights assigned to fuel types,

noting that USEPA retained the fuel factors. Dynegy and SIPC encouraged the Board to retain

them as proposed by IEPA. PC 6 at 27-28.

The Board noted that 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 USEPA for not employing a fuel-neutral allocation

methodology in the CAIR model rule.

The Board agreed at first notice with IEPA 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. As the Board explained, the more feasible controlling these emissions is under

the proposed rule, the more likely they are to be controlled. Accordingly, the Board did not

modify IEPA’s approach to fuel-weighting as proposed.

Proposed Subpart F: Combined Pollutant Standards (CPS)

IEPA and Midwest Generation proposed that a new Subpart F, CPS, be added to the

proposal as a result of a December 10, 2006 MOU between the parties. The new subpart

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21

establishes an alternative means of compliance with emissions standards for mercury in Subpart

B, Section 225.230(a) and would 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, respectively. At first notice, the Board agreed that

the proposal for compliance set forth in Subpart F would achieve greater reductions in SO

2

, NO

x

,

and mercury than the proposed CAIR standards. The Board also found the proposed Subpart F

would further reduce ambient levels of ozone and PM

2.5

, leading to benefits to public health and

the environment. The parties to the MOU asserted 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 found at first notice that Subpart F is technically feasible and economically

reasonable, and included the subpart in the proposal the Board adopted.

Technical Feasibility and Economic Reasonableness

In its first-notice opinion, the Board found that IEPA demonstrated that technology is

available to meet CAIR requirements. The Board first discussed the CAIR SO

2

and NO

x

issues

before reaching a decision on technical feasibility and economic reasonableness.

SO

2

In the federal CAIR and supporting documents, 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.

As the Board discussed, 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

.

IEPA contended that costs of coal cleaning processes vary from $10.10 (at 35-70%

---

22

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 IEPA to

use the process at two boilers. TSD 5.1.

IEPA contended 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. IEPA asserted that it relied upon the cost analyses performed by USEPA

and believes that the cost-effectiveness of controls for Illinois EGUs will be similar. 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. IEPA

anticipated 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)

would 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. IEPA asserted that compliance with the CAIR NO

x

Ozone Season trading program during Phase I would not require additional control measures

because the NO

x

allocation budget for the years 2009 through 2014 is the same in Illinois, 30,701

tons for allocation.

Id

.

However, IEPA stated that for the annual program, sources that have not yet installed

---

23

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 USEPA. A listing of the technologies can be

found in table 5-2 of IEPA’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

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 IEPA, 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.

IEPA used an integrated planning model (IPM) to evaluate the economic impact of the

CASA and NUSA provisions included in this proposal. According to IEPA, the IPM modeling

shows that the reduction of allowances only minimally increases the costs discussed above. Stat.

at 44. IEPA stressed 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

. IEPA contended that IPM

modeling represents the worst-case scenario because it did not address the potential use of any

CASA allowances for the existing EGUs. IEPA noted, however, that future projects will more

likely be eligible for CASA use and thus further reduce cost. Stat. at 45.

Discussion

Section 27(a) of the Act directs the Board to take into account the “technical feasibility

and economic reasonableness of measuring or reducing the particular type of pollution” when

conducting a substantive rulemaking. 415 ILCS 5/27(a) (2006). After carefully reviewing the

entire record, the Board found at first notice that the proposal as amended is technically feasible

and economically reasonable. In making this determination, the Board considered the USEPA

findings on CAIR NO

x

and SO

2

control technology costs and applications, and NO

x

and SO

2

---

24

removal effectiveness. The Board was also persuaded by the IPM modeling provided by IEPA.

In addition to the IPM modeling discussed above, IEPA 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 agreed with IEPA that trading will provide EGUs a

cost-effective way to comply with CAIR that will minimize the costs passed on to consumers.

IEPA estimated that regional retail electricity prices will be 2-3% higher with CAIR. In Illinois,

IEPA predicted the retail electricity prices will increase 2.6% in 2010 and 4.3% in 2015 as a

result of implementing CAIR. However, by 2020, IEPA expected rates to decrease 2.6%,

leaving a net increase of 1.7%. TSD 6.4.

The Board noted that the SO

2

trading program IEPA proposed is substantially identical to

the measurement requirements for the federal CAIR Rule developed by USEPA. Further, the

issues concerning NO

x

are issues that relate to the underlying federal requirements. The Board

therefore found USEPA’s decision to adopt the requirements persuasive.

In addition, the Board noted that the interested parties in this rulemaking in large part did

not argue that the proposal is not technically feasible or economically reasonable. Kincaid

argued 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 disagreed. The Board considered whether each

rulemaking is technically feasible and economically reasonable, and decided affirmatively in

both rules.

SUMMARY OF FIRST-NOTICE PUBLIC COMMENTS

Public Comment 13: SIPC

SIPC stated that because of special circumstances at its facility during the proposed

“look-back” period of 2001 through 2005, SIPC is significantly disadvantaged in calculating

initial allowances. PC 13 at 2. SIPC asserted that due to the timing of construction of a CFB at

its generating station, it is unique relative to the initial allocations. The CFB began operating in

mid-2003 and “went through a shake-down period of a year to a year and a half.”

Id

. It was not

until 2005 that the CFB experienced “‛normal’ operation,” according to SIPC.

Id

.

For this reason, contended SIPC, averaging the converted gross electrical output of 2005

with the other years puts SIPC at a disadvantage for the distribution of initial allocations,

compared to the other EGU’s in the State. PC 13 at 2. SIPC requested that it be allowed to use

only 2005 data, or, alternatively, to average the converted gross electrical output from 2006 with

that from 2005 to determine SIPC’s initial allocation.

Id

. at 3. SIPC proposed amendments to

the first-notice versions of Sections 225.435 and 225.535 as follows:

---

25

Section 225.435/535 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 . . . :

1)

Gross electrical output. . . . 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. The gross electrical output data from the

2005 control period will be used for Unit 123 at SIPC. . . .

2)

Heat input (HI). . . . 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 heat input from the 2005 control

period will be used for Unit 123 at SIPC. . . .

Id

.

SIPC stated that IEPA did not agree with the above amendment because it would have to

adjust initial allocations that it has already calculated and submitted to USEPA to meet early

deadlines. SIPC did not believe this to be an adequate reason and noted that perhaps IEPA was

premature in submitting a rule to USEPA prior to second notice. PC 13 at 4.

SIPC also asked the Board to amend Sections 225.435(a) and 225.535(a), which provide

that the owners or operators of EGUs subject to CAIR may tell IEPA whether they want their

initial allocations determined on the basis of gross electrical output or heat input converted to

gross electrical output. As SIPC pointed out, however, the June 1, 2007 deadline for the owners

or operators to submit their choices had passed. PC 13 at 4-5. Accordingly, without amendment,

the rule “improperly contains a deadline that predates the final adoption and effectiveness of the

rule.”

Id

. at 5

SIPC preferred to have all allocations based upon heat input. SIPC stated that any

efficiencies from basing allocations on gross electrical output “are not available to SIPC and any

other type of unit that has pollution control as part of the boiler.” PC 13 at 5. Due to the “pre-

adoption deadline contained in the rule,” SIPC asked the Board to ensure that Sections

225.435(a) and 225.535(a) reflect that initial allocations will be based only on heat input, with no

conversions to gross electrical output. Later in its public comment, SIPC nevertheless requested

that the Board amend the date by which sources must notify IEPA of their “choice regarding use

of heat input or (converted) electrical output to a date after the rule is adopted.”

Id

. at 6-7.

SIPC also pointed out that IEPA’s proposed revision to the formulae at Sections

225.465(b)(5)(B) and 225.565(b)(5)(B), with which the Board concurred, did not appear in the

first-notice language through apparent inadvertent omission. PC 13 at 5-6. SIPC explained that

the IEPA-proposed revision accommodates SIPC’s CFB by changing the factor of 1.0 to 1.4 in

---

26

the equation used to determine the number of allowances that SIPC may receive from the CASA.

SIPC requested that the amendment be included at second notice.

Id

.

Public Comment 14: Midwest Generation

Midwest Generation sought to amend the method used in Subpart F, Combined Pollutant

Standards (CPS), for determining the flue gas flow rate. PC 14 at 1. According to Midwest

Generation, in Section 225.615(g)(4), the flue gas flow rate:

must be determined for the point of 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 100° F, or it may otherwise be

calculated from the stack flow rate, corrected for the difference in gas

temperatures.

Id

.

Midwest Generation proposed to amend Section 225.615(g)(4) to allow for correction of

the flue gas flow rate for the amount of “air in-leakage” between the injection location and the

stack, in addition to the difference in gas temperatures already allowed under the proposed rule.

PC 14 at 1. Midwest Generation maintained that allowing for this additional correction would

provide several benefits. For example, the correction would provide a more accurate

determination of the flue gas flow rate, resulting in a reduction of unnecessary sorbent use

“where the cost of such sorbent is significant and where the supply of sorbent is limited and may

be subject to shortfalls.”

Id

. According to Midwest Generation, the correction would neither

diminish neither the effectiveness of the applied sorbent nor the ability of an affected source to

otherwise comply with mercury emissions limits.

Midwest Generation proposed the following amendments to the first-notice version of

Section 225.615(g)(4):

(g)(4) For purposes of subsection (g)(3) of this Section, the flue gas flow rate

must be determined for the point of 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 and air leakage into the ductwork after the point of

injection as determined by measurement of O

2

or CO

2

. Unless the Agency

approves an alternative procedure, the following equations shall be used to

determine the flow rate at the point of injection corrected for air in-leakage into

the ductwork:

Corrected Flow Rate (acfm) = Stack Flow Rate (acfm) x (1-Air In-Leakage

Factor)

where:

Air In-Leakage Factor = (%O

2

, Stack, Wet - %O

2

, ESP Inlet, Wet)

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27

(20.9 - %O

2

, Stack, Wet)

or

Air In-Leakage Factor = (%CO

2

, ESP Inlet, Wet - %CO

2

, Stack, Wet)

(%CO

2

, Stack, Wet)

For purposes of this subsection, “acfm” shall mean actual cubic feet per minute.

PC 14 at 2.

Public Comment 15: IEPA

IEPA stressed the need for expedited adoption of the CAIR proposal. According to

IEPA, to avoid having USEPA’s Federal Implementation Plan (FIP) allocate NO

x

emission

allowances in Illinois for the 2009 control period:

Initial allocations based on a fully adopted state rule are required to be submitted

to USEPA no later than September 30, 2007. If Illinois fails to either fully adopt

its CAIR proposal by September 25, 2007, or submit final NOx allocations for the

Annual and Ozone trading programs by September 30, 2007, USEPA will use the

NO

x

allocations for Illinois sources as set forth in the FIP. PC 15 at 2-3, citing 71

Fed. Reg. 25328 (Apr. 28, 2006).

Later in its public comment, IEPA emphasized the “importance and urgency in the Board

continuing to handle this rulemaking in an expedited manner such that a final rule is effective

before September 2007 if at all possible.”

Id

. at 4.

IEPA also responded to the issues raised in the public comments of SIPC and Midwest

Generation. IEPA disagreed that the initial allocation methodology significantly disadvantages

SIPC. PC 15 at 4. Even if SIPC did not have three years of “normal” operations during the

initial look-back period, IEPA maintained that SIPC should not be treated differently from any

other regulated source:

In any regulation of general applicability, there will always be affected sources

that say the rule affects them differently than somebody else. However, adding a

special provision for SIPC raises the question of what other sources might have

issues whereby they did not have “normal” operations during the look-back

period – whatever “normal” might mean.

***

[G]ranting a special, essentially site-specific, change in the regulation for SIPC

opens the door to all other affected regulated entities to request special treatment

as well.

Id

. at 4-5.

IEPA also maintained that giving SIPC special treatment in the rule would be unfair and

harm other sources. Because Illinois has a fixed number of allowances, “[a]ny allowance that is

given to SIPC must be removed from the allocation for another source – a source that has

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28

demonstrated a need for that allowance using the proper allocation calculation.” PC at 5.

Additionally, IEPA asserted that SIPC’s unit does not need the extra allowances. Based

on SIPC’s description of 2005 being its first “normal” year, IEPA estimated the approximate

number of allowances SIPC would need for its unit. According to IEPA, the available

information indicates that if SIPC:

runs its control device throughout the year, it will easily have enough allowances,

based on the draft allocations sent to USEPA by the Illinois EPA and posted on its

website, to cover Unit 123. In addition, SIPC will almost certainly receive

additional

allowances from the CASA. This means SIPC should not only have

enough allowances to cover emissions from Unit 123, but also have enough

allowances to bank or sell. PC 15 at 4-5 (emphasis in original).

IEPA further disagreed with SIPC’s call for initial allocations to be based solely on heat

input. IEPA stated it is aware that the deadline for submitting gross electrical output data has

already passed and therefore needs to be modified in the rule. IEPA’s public comment proposed

language to remedy that problem. PC 15 at 5. SIPC’s concerns about efficiency, continued

IEPA, have been addressed at length in this record. Even though one of SIPC’s boilers may not

be as efficient as others in the State, IEPA explained, CFB boilers were considered in the

design of the regulation and:

Any perceived shortfall in allowances allocated to this unit due to differences in

efficiency should be exceeded by additional allowances allocated from the CASA.

It should also be noted that virtually all electrical generating utility (“EGU”)

boilers in Illinois operate pollution control equipment that reduce the overall

efficiency of a given unit. This is addressed by the allocation methodology being

based on gross electrical output rather than net electrical output.

Id

. at 5-6.

In addition, IEPA disputed SIPC’s suggestion that IEPA opposes SIPC’s heat input

position because IEPA would need to adjust allocations submitted to USEPA. According to

IEPA, SIPC has apparently misunderstood IEPA’s reasons for opposition, none of which “have

anything to do with previous submittal of allocations nor USEPA’s parallel processing. PC 15 at

6.

IEPA also disagreed with Midwest Generation’s suggestion to add a provision to the CPS

designed to correct the determination of the flue gas flow rate for air leaked in between the

mercury sorbent injection location and the stack. IEPA noted that the sorbent flow language in

the CPS matches equivalent language in the Multi-Pollutant Standard (MPS) at Section

225.233(c)(2)(D). According to IEPA, changing the CPS without likewise changing the MPS

would be “inappropriate and unfair to those sources planning to make use of the MPS.” PC 15 at

7. Moreover, continued IEPA, Midwest Generation “has only brought this issue to the Illinois

EPA’s attention one week prior to the end of first notice comment period.”

Id

. at 8. IEPA stated

therefore that it has not had an opportunity to properly review “the implications of such a

change.”

Id

. IEPA maintained that Midwest Generation’s proposal is a “last-minute

modification with unforeseeable consequences.”

Id

.

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29

Lastly, IEPA proposed a number of clarifications and corrections to the first-notice rule

language. According to IEPA, the proposed changes are of four types: (1) changed dates within

the CAIR rule to avoid retroactive application; (2) changes based on comments received from

USEPA; (3) previously proposed amendments that were inadvertently omitted from first notice;

and (4) “some typos that need correction and some clarifications that need to be made.” PC 15 at

7; see also PC 15 at 7-34, Attachments.

Public Comment 16: Zion

Zion focused on two elements of the rule as proposed at first notice: fuel-weighting, and

the CASA. Zion contended that “the Board has failed to adequately address or reasonably

incorporate comments about” these issues into the proposed rule. PC 16 at 1.

Fuel-Weighting

The first-notice proposed rule included the fuel-weighting factor recommended by IEPA:

1.0 for coal-fired units, 0.6 for oil fired units, and 0.4 for gas-fired units. This is identical to the

federal CAIR model rule.

While still maintaining that fuel neutrality is viable, Zion urged the Board to amend

Sections 225.435, 225.445, 225.535, and 225.545 by adopting Zion’s previously-recommended

compromise alternative fuel-weighting factor of 0.7 for both gas-fired and oil fired units. PC 16

at 2. Zion suggested that IEPA rejection of Zion’s positions has two bases, neither of which can

withstand scrutiny.

IEPA’s first basis, according to Zion, is that because coal-fired sources emit higher rates

of NO

x

and SO

2

, reductions at these sources will have higher benefits, so that these sources are

more likely to be controlled. PC 16 at 3, citing PC 5 at 4-5. Zion believed that this basis may

sound more logically accurate than is the case. Zion opined that the current allocation of

allotments operates as an “emission limit” that results in a less stringent “emission limit” for

coal-fired units at the expense of gas and oil-fired units. Zion calculated that as compared to a

fuel-neutral allotment approach, under the current proposal, there are approximately 10% more

allowances for coal-fired units, while gas-fired units would receive 56% fewer allowances and

oil-fired units 34% fewer allowances. PC 16 at 3-4.

Zion suggested that under a cap and trade program such as CAIR, unit owners compare

the cost of installing and operating controls versus purchasing allowances. Rather than

increasing controls of coal-fired units, Zion predicted that:

by reducing the gap between allocations and actual emissions for coal fired units, the

Proposed Rule will have just the opposite effect—it will create a disincentive to

install controls and reduce the financial incentive for units with existing controls to

increase their reduction capabilities and “over-control”(footnote omitted). PC 16 at 4-5.

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30

Zion pointed to IEPA’s experience with its own fuel-neutral NO

x

Budget Trading

Program as an example both of a “highly successful method of achieving reductions,” and of

how as:

control installations have allowed companies to over-control and generate excess

allowance, the cost of compliance via the ‘purchase’ [of allocations] route has

been significantly reduced, thus making it a more attractive option than installing

new or enhancing existing emission control. PC 16 at 5.

Zion concluded that adoption of the proposed rule would reduce the largest emitters’ incentive to

install controls on their most emitting units.

Id.

at 6.

IEPA’s second basis, Zion related, is that the State’s economic analysis found the NO

x

policy to be economically reasonable based upon fuel-weighting, and that deviation from it

would impact the economic analysis of the proposal. PC 16 at 6. In this context, IEPA noted

that the fuel-weighting factors proposed are identical to those in the federal CAIR model rule.

Id

. at 3. Zion believed this basis is faulty as well. According to Zion, IEPA’s economic analysis

“has been shown during the public hearing process to fail to stand up to scrutiny.”

Id.

at 6. Zion

also concluded that using the federal CAIR fuel-weighting factors does not support the proposal

because the factors’ “impact is substantially different on sources like Zion due to other elements

of the Proposed Rule that are not included in the federal CAIR model rule (

e.g.

CASA and its

size).”

Id.

Clean Air Set-Aside (CASA)

Zion maintained that the Board should reduce the size of the CASA found in Sections

225.445, 225.460, and 225.465 to more equitably address comments and the evidence in the

record. PC 16 at 6. Zion reiterated the position taken before first notice that the CASA should

be revised in two ways.

Id

.

First, Zion believed that a smaller portion of the total allowance budget should be made

available for non-emitting sources. PC 16 at 6-7. Rather than the proposed 25%, Zion suggested

a CASA set-aside of 5 to 10%, which it asserts is more in line with other states including

Minnesota.

Id.

at 7. Zion asserted that the 25% CASA “unjustifiably increases the compliance

burden on facilities that already face significant emission reduction obligations through an

artificial reduction in allowances available for allocations.”

Id

.

Second, Zion suggested that applicants for CASA be limited to electric generating units

and that non-generating sources (

e.g.

, energy efficiency projects and demand-side management

project) not be considered. PC 16 at 7. Zion maintained that allowing non-generating sources to

apply for CASA will give “unwarranted financial incentives to non-emitters that have no direct

compliance burden,” especially as economic incentives are already available.

Id

. Zion believed

that failing to restrict CASA applicants would provide even more stringent reduction obligations

for affected units.

Id

.

---

31

Zion maintained that the record is replete with commenters who support its position on

CASA. PC 16 at 7-8. However, Zion opined that despite the evidence in the record, IEPA

continues to reject a proposed reduction to the CASA size and the Board “seems to accept the

Agency’s positions regarding the need for the existing size of CASA.”

Id.

at 8. Zion

characterized IEPA’s position as consisting of four claims:

1.

Illinois 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

efficiencies/renewable energy (EE/RE) efforts for zero emission

generation, and a small pool to undertake these projects early on) whose

individual contribution will benefit the environment;

2.

each of the CASA project categories assists Illinois EPA in their duty to

attain the National Ambient Air Quality Standard (NAAQS);

3.

results of a financial analysis of the impact, under a worst-case scenario

where the entire 30% [set-aside] was retired, showed that the reliability of

the grid would be intact and that residential and commercial electric rates

would not be greatly impacted; and

4.

the positive impacts for Illinois outweigh the concomitant detriment posed

by Illinois EPA’s choice for a 30% set-aside.

Id.

, citing PC 5 at 7.

As to IEPA’s first claim, that CASA is necessary to promote other Illinois interests, Zion

believed the position is misplaced. PC 16 at 8. Zion opined that IEPA relied upon the

Governor’s Sustainable Energy Plan to justify the large size of the CASA; however, IEPA has

acknowledged that it is not responsible for implementing the renewable portfolio standard in

Governor’s Sustainable Energy Plan.

Id.

at 8-9.

Zion also believed IEPA second claim, that the size of CASA is necessary to achieve

NAAQS, is without merit. PC 16 at 9. Zion pointed to IEPA’s testimony indicating that CASA

will not reduce NO

x

emissions in Illinois even if the entire 30% is retired.

Id

. Zion also asserted

that IEPA “admitted during the hearing that the Chicago area has already attained the 8-hour

ozone standard without the Proposed Rule.”

Id

. Zion indicated that Illinois’ return to ozone

attainment has been confirmed by two recent redesignation proposals, which were possible

without this rule.

Id

. Zion further commented that CAIR is an interstate rule and as such “local

reductions will not necessarily be tied to improvements in Illinois’ air quality or attainment

goals.”

Id

. Zion argued that, in effect, the proposed CASA will place an increased burden on

Illinois, resulting in primarily benefits, if any, in other areas.

Id

. at 9-10.

Zion reiterated that the financial analysis IEPA is relying upon to support the size of

CASA did not withstand the scrutiny of the public comment period. PC 16 at 10. Further, Zion

maintains that IEPA did not bolster the economic analysis after the attacks upon the analysis and

IEPA admitted that the analysis performed was revised before submission to the Board.

Id

.

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32

Finally, Zion maintains that IEPA has no support in the record for its position that the

positive impacts of the 30% set-aside outweigh the concomitant detriments. PC 16 at 10. Zion

noted that IEPA has not clearly explained what the positive impacts are or whether the same

positive impacts would occur with a smaller CASA.

Id

. According to Zion, IEPA and the Board

have not fully evaluated the detriment posed by the 30% set-aside.

Id

. Zion further claimed that

the full evaluation of the detriments is lacking especially when comparing the full economic

impact on businesses in Illinois to similar businesses outside Illinois that have “far less reaching

or aggressive” CAIR standards.

Id.

PC 17: Kincaid and Dominion

Kincaid began its public comment by noting that Dominion owns and operates the 1,250

megawatt coal-fired Kincaid Generation, LLC power plant located in Kincaid, Illinois, and holds

a 50% interest in the 1,400 megawatt natural gas-fired Elwood Energy, LLC combustion turbine

plant located in Elwood, Illinois. PC 17 at 1.

According to Kincaid and Dominion, Subparts D (CAIR NO

x

Annual Trading Program)

and E (CAIR NO

x

Ozone Season Trading Program) of the first-notice rules “far exceed the

federal CAIR requirements and will competitively disadvantage Illinois businesses and

electricity ratepayers.” PC 17 at 1. Kincaid and Dominion did not support the 25% CASA of

NO

x

allowances under proposed Sections 225.455 and 225.555.

Id

. They felt that IEPA has

failed to justify that the level of the proposed set-aside is necessary from an air quality

perspective. They also believed these provisions “will significantly increase compliance costs

for Illinois sources and competitively disadvantage the state relative to surrounding states” by

denying Illinois the economic advantages of the USEPA trading program that many other

surrounding states will realize.

Id

. at 1-2.

Kincaid and Dominion further did not support the proposed withholding of allowances

from the Compliance Supplement Pool under Section 225.480 of the CAIR NO

x

Annual Trading

Program proposal. They argued that these allowances are provided in the USEPA rule to

“encourage early reductions during 2007 and 2008.” PC 17 at 2. Kincaid and Dominion noted

that Illinois included early reduction provisions in its NOx SIP Call rules:

These early reduction incentives not only provide companies added compliance

flexibility that ease the burden once the requirements take effect, but benefit the

environment as well by providing real emission reductions sooner.

Id

.

Kincaid and Dominion asserted that IEPA “should justify any ‘beyond CAIR’ NO

x

reductions with a thorough modeling demonstration.” PC 17 at 2. They felt that it is neither

reasonable nor environmentally justified to require all Illinois sources subject to CAIR to

implement “beyond CAIR” reductions “across-the-board” for the purpose of resolving “local

problems” of nonattainment.

Id

. Kincaid and Dominion urged IEPA to conduct a thorough

modeling demonstration to determine the “level of reductions that may be necessary to resolve

any residual nonattainment problems following implementation of the CAIR reductions.”

Id

.

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33

According to Kincaid and Dominion, the 25% NO

x

set-aside is “unreasonably

burdensome” to Illinois generators and their customers and “has not been demonstrated to be

necessary to achieve attainment with the ambient air quality standards.” PC17 at 2. Kincaid and

Dominion quoted USEPA in stating that the program is designed “to balance the burden for

achieving attainment between regional-scale and local-scale control programs.”

Id

., citing 70

Fed. Reg. 25166 (May 12, 2005). Kincaid and Dominion did not believe it is necessary for

Illinois to have “beyond CAIR” NO

x

reductions, and instead propose “full adoption of USEPA’s

federal ‘model rule’ on the same schedule established by the USEPA.”

Id

. at 3.

Kincaid and Dominion stated that recent air quality modeling by the LADCO suggests

additional NO

x

reductions from the EGU sector, beyond the reductions expected from federal

CAIR, “will not solve the residual ozone and PM

2.5

non-attainment problem in the Chicago

area.” PC 17 at 3. According to Kincaid and Dominion:

A comprehensive attainment plan should be thoroughly researched and fully

developed that clearly and conclusively demonstrates the level of emissions

reductions needed and the source categories for which the most efficient and

effective reductions can be achieved. Only when this plan has been fully

developed will IEPA have the justification to proceed with “beyond CAIR”

reductions.

Id

.

Kincaid and Dominion argued that further EGU reductions of SO

2

and NO

x

are “unlikely

to impact PM

2.5

concentrations sufficiently to achieve attainment in any residual PM

2.5

nonattainment areas in Illinois or in other states.” PC 17 at 3. They therefore asserted that

mandated “beyond CAIR” EGU reductions of SO

2

and NO

x

“may not be necessary, cost

effective or even have any beneficial effect” on reducing monitored PM

2.5

particle

concentrations.

Id

. Kincaid and Dominion felt 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 and Dominion also referenced recent modeling funded by the Midwest Ozone

Group, the Illinois Environmental Regulatory Group, the Illinois Energy Association, and others,

conducted by Alpine Geophysics. This modeling used “a finer, 4 kilometer grid and 2005 as a

base year.” PC 17 at 4. Kincaid and Dominion stated that the modeling results, which they have

reviewed with LADCO staff, indicate that:

all the monitors in the 5-state (Illinois, Indiana, Wisconsin, Ohio and Michigan)

region will attain both the ozone and the PM

2.5

ambient air quality standards by

2015, when Phase 2 of the federal CAIR rules becomes effective.

Id

.

According to Kincaid and Dominion, “[i]t does not appear that further regional

reductions by the utility sector will make a significant difference in the attainment status of the

Chicago MSA.” PC 17 at 4. Instead, based on an analysis presented at an October 18, 2005

meeting of the Indiana Department of Environmental Management Utility Rules Workgroup,

further utility emission reductions “actually cause ozone levels to increase in the Chicago MSA.”

Id

. Kincaid and Dominion also pointed out that data presented at the meeting indicate that

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34

Illinois EGU NO

x

emissions contribute approximately 4% of the ozone resulting in Chicago

nonattainment, behind ozone contributions from “Boundary Conditions” or sources outside the

5-state region (38% of the ozone from NO

x

and VOC), “Illinois On-road” or mobile sources

(26% of the ozone), and “Illinois Non-road,” “Illinois Non-EGU,” and “Indiana On-road”

sources.

Id

. Kincaid and Dominion therefore supported implementing CAIR as established by

USEPA, “and then work with sources in local nonattainment areas to determine the appropriate

mix of reductions needed to resolve remaining local nonattainment area issues.”

Id

.

BOARD SECOND-NOTICE DISCUSSION

The Board received five first-notice public comments, summarized above. In its second-

notice opinion of July 26, 2007, the Board addressed the remaining contested issues presented in

those comments. The Board then discussed amendments proposed to the rule language adopted

at first notice.

Contested Issues Analysis

The following contested issues were raised in public comment filed during the first-notice

period, though many of these issues were previously posed to the Board and addressed in the

Board’s first-notice decision: (1) determination of allocations for SIPC for 2009 – 2011; (2)

allocations based on gross electrical output instead of heat input; (3) proposal to correct for “air

in-leakage”; (4) fuel-weighting factors; (5) aspects of the CASA (size, availability, purpose,

economic impact); and (6) withholding allowances from the Compliance Supplement Pool

(CSP).

At second notice, the Board found that none of these disagreements warranted any

changes to the Board’s first-notice proposal. The Board addressed each of the issues separately.

Determination of Allocations for SIPC for 2009 - 2011

The first-notice rule for allowance trading included a “look-back” period that would be

updated on an annual basis to determine an EGU’s allowances. Although the proposal provided

for a two-year look-back period, the initial look-back period for the 2009 – 2011 control periods

uses data from the three highest control periods of 2001 through 2005. SIPC stated that during

the look-back period of 2001 – 2005, there were not three years of operation that SIPC considers

“normal” for the purposes of calculating a representative number of allocations. PC 13 at 1-2.

As the Board discussed in its first-notice opinion, the initial look-back period was

expanded from two years to five in response to concerns presented to IEPA before the proposal

was filed with the Board. Stat. at 48. When SIPC reiterated its concerns with the first-notice

proposal, IEPA responded that “the calculation methodology is fair and equal to all sources in

the program,” and that carving out a special provision for SIPC would “open the door” to all

other sources that might have similar issues. PC 15 at 4-5.

The Board recognized that each regulated entity might have factors that would affect

their number of allocations if more than just the gross electrical output or heat input data from

---

35

the look-back period were considered. Because Illinois has a fixed number of allowances, the

Board found that each source’s operating history should be treated as equally as possible. The

two-year look-back period, updated annually, also provides a means for IEPA to periodically

reevaluate the changes in operating patterns and the resulting allocations. As stated at first

notice, the short look-back period allows for the quick accounting of high and low usage years.

For these reasons, the Board declined at second notice to adopt SIPC’s recommendation.

Allocations Based on Gross Electrical Output vs. Heat Input

The first-notice proposal based allocations on converted gross electrical output. In its

latest public comment, SIPC maintained that it would prefer that allocations were based upon

heat input instead of gross electrical output because SIPC employs pollution control as part of

the boiler. PC 13 at 5. IEPA acknowledged that although operating pollution control equipment

reduces the overall efficiency of a unit, virtually all EGU boilers in Illinois are similarly affected.

PC 15 at 6.

As discussed in the Board’s second-notice opinion, IEPA’s Rory Davis testified that the

output-based allocation methodology “encourages greater efficiency from sources by allocating

based on output rather than use of fuel, adds a degree of flexibility in compliance strategies for

sources, as is true for most trading programs, and is consistent with the allocation methodology

used for the Clean Air Set-Aside.” Ag. Exh. 9 at 2. Davis explained:

Many of the categories of the CASA eligible for allowances for environmentally

beneficial practices do not include a measure of heat input, and measuring heat

input for other eligible categories would be inconsistent with the goals of the

CASA. These include zero emission electrical generation, energy efficiency

projects, clean coal technology projects, and pollution control technology

upgrades. Further, it would not promote the goals of the CASA to allocate a

greater number of CASA allowances for a greater measure of heat input. In

addition, employing an output-based allocation methodology creates a level

playing field where the production or conservation of electricity by the specified

means in the CASA is encouraged in the same manner that allowances are

allocated to affected CAIR sources.

Id

.

Although USEPA gave the states discretion in choosing their methods of allocation,

USEPA had this to say about its own methodology in a discussion referring to cogeneration

units:

The use of modified output, rather than actual heat input, as the basis of

determining allowance allocations will promote the development of cleaner more

efficient generation of both electricity and process steam . . . . This approach

neglects energy losses in the combustion turbine and generator. [US]EPA

believes that any efficiency gains made by reducing these losses will be rewarded

by [USEPA’s] approach, by resulting in greater electricity and/or steam output for

a given amount of heat input. 71 Fed. Reg. 25358 (Apr. 28, 2006).

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36

The Board noted its appreciation that different system configurations might detract from

allowances allocated to a unit, but stated its understanding from IEPA that this affects most all

boilers in Illinois similarly: “virtually all electrical generating utility (“EGU”) boilers in Illinois

operate pollution control equipment that reduce the overall efficiency of a given unit.” PC 15 at

5-6. The Board remained convinced that using gross electrical output to determine allocations

has the benefit of encouraging efficiency and providing a compatible way to determine

allowances for CASA projects that might have no definable heat input.

Correcting for “Air In-Leakage”

Midwest Generation proposed to add a provision to Section 225.615(g)(4) of the

Combined Pollutant Standards (CPS) that it claimed would correct the determination of the flue

gas flow rate for air leaked in between the mercury sorbent injection location and the stack. PC

14 at 1. By adjusting the flue gas flow rate for air leaked in, Midwest Generation stated that less

sorbent would be wasted without diminishing the effectiveness of the treatment. Midwest

Generation estimated the average “air in-leakage” at each unit accounts for 10 to 15% of the total

flue gas flow and “air in-leakage does not contain any emissions, let alone additional

concentrations of Mercury.”

Id

. at 1-2.

As the Board discussed in its second-notice opinion, the first-notice rule contained only a

provision to correct the flue gas flow rate for the difference in gas temperatures between the

point of injection and the stack. As noted by IEPA, this provision matches the language in the

Multi-Pollutant Standard (MPS) found at Section 225.233(c)(2)(D) of Subpart B on the control

of mercury emissions from coal-fired electric generating units. PC 15 at 6. IEPA expressed

concern about changing this provision in the CPS without a corresponding change in the MPS

and further analysis on the possible consequences. PC 15 at 6.

The Board noted that although Midwest Generation stated sorbent costs are significant

and supply may be limited, it did not include an economic analysis or cost figures to quantify the

sought-after benefit. Midwest Generation’s proposal also did not illustrate the derivation of the

equations or relate the adjustment to the correction for gas temperature. The Board found that at

that point in the rulemaking process, the justification for the equations proposed by Midwest

Generation had not been adequately developed and the Board accordingly declined to adopt the

change.

Fuel-Weighting Factors

The first-notice proposal contained fuel-weighting factors for calculating a unit’s

converted gross electrical output: 1.0 for coal-fired; 0.6 for oil-fired; and 0.4 for other fuels such

as natural gas. Zion again argued that the fuel-weighting factors should be revised either to a

fuel-neutral position or to reflect a factor of 0.7 for both natural gas-fired and oil-fired units. PC

16 at 2. Zion presented the 0.7 value as representing a compromise alternative fuel-weighting

factor to close the gap between the fuel-neutral and fuel-weighted options. According to Zion,

the alternative factor is intended to provide additional consideration for reliability when natural

gas is unavailable, power demand is high, or reliability is critical.

Id

.

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37

The Board quoted from USEPA’s discussion of fuel weighting:

[US]EPA proposed an allocation methodology based on the example allocation

methodology in the CAIR SIP model rules, which included adjustments to heat

input by fuel type, using fuel adjustment factors that are based on average historic

NO

x

emissions rates by 3 fuel types (coal, natural gas, and oil) for the years 1999-

2002. These adjustment factors are 1.0 for coal-fired units, 0.6 for oil-fired units,

and 0.4 for units fired with all other fuels (e.g., natural gas). The factors reflect

inherently different emissions rates of different fossil fuel-fired units.

***

[US]EPA believes that these adjustment factors appropriately consider the

inherently higher emissions rate of coal-fired units and the relatively greater

burden on these units to control emissions. 71 Fed. Reg. 25357 (Apr. 28, 2006).

As observed by the Board, the proposal contains fuel-weighting factors that are identical

to the federal CAIR model rule and reflect different burdens to control emissions. As stated by

USEPA, the factors are based on historic NO

x

emissions rates of which natural gas was one of

the three fuel types specifically assessed and assigned a factor of 0.4. USEPA used fuel types in

determining the state budgets. Stat. at 35. The Board found that Zion’s proposal to use a factor

of 0.7 did not appear to be based on historic emissions rates, but rather represented a mid-point

between the high 1.0 and low 0.4 factors. PC 3 at 2. Zion intended its alternative factor to

account for the burden of reliability problems with natural gas, but USEPA focused on the

burden of controlling emissions.

Coal-fired power plants represent the predominant sources of NO

x

and SO

2

in Illinois and

likewise have higher emission rates for both pollutants. As the Board observed at first and

second notice, reductions at these sources therefore will provide the greatest benefits, and the

more feasible controlling these emissions is under the rule, the more likely they are to be

controlled. Accordingly, at second notice, the Board did not modify the first-notice approach to

fuel-weighting.

Clean Air Set-Aside (CASA)

Size of the CASA.

For energy efficiency and conservation, renewable energy, and clean

technology projects, the proposal at first and second notice contained a CASA of 25% of the

federal allocations. The size of the proposed allocations reserved for the CASA continued to

concern Kincaid and Zion. Zion believed a smaller allowance budget should be made available,

suggesting 5-10% to be more comparable to other states. PC 16 at 7.

As the Board noted, IEPA’s Statement of Reasons provides that:

extensive modeling analysis has shown that Illinois will need to go significantly

beyond the CAIR NO

x

and SO

2

reductions to attain the PM

2.5

and 8-hour ozone

NAAQS.

See

, TSD 3.2. This set-aside, if unused, can be part of a larger plan to

reach attainment. Stat. at 50.

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38

IEPA acknowledged that the size of the CASA would not equate to an equal amount of emission

reduction, but maintained that “it will lead to an improvement in air quality as it will encourage

more efficient and cleaner operating technologies to enter the market place.”

Id

. As IEPA

expects the demand for energy to increase, ensuring commensurate air quality improvement

requires reduced demand for energy from fossil fuel-fired plants, and an increase in renewable

energy sources.

Id

. at 51.

USEPA left the decision on using set-asides up to the states, so they may craft their

allocation approaches to meet their state-specific policy goals. 70 Fed. Reg. 25279 (May 12,

2005). This flexibility under CAIR allows Illinois to use set-asides, like CASA, as a tool to

promote energy efficiency, clean technology, and renewable energy. Stat. at 51. USEPA

explained that such tools encourage innovate approaches to generating emission reductions:

In light of the increasing incremental cost associated with stationary source

emission reductions and the difficulty of identifying additional stationary sources

of emission reduction, [US]EPA believes that it needs to encourage innovative

approaches to generating emission reductions. Consequently, [US]EPA believes

that it is appropriate and consistent with the [Clean Air] Act to allow a percentage

of the total emission reductions needed to satisfy ROP [Rate of Progress], RFP

[Reasonable Further Progress], attainment, and maintenance requirements to

come from programs that may not fully meet the traditional requirements [of

Sections 110, 172, 182, and 175A of the CAA].

Incorporating Emerging and

Voluntary Measures in a State Implementation Plan

, USEPA (Sept. 2004) at 8.

USEPA also advised that “[i]t is . . . important to encourage and reward greater application of

energy efficiency and renewable energy measures and incorporate the emission reductions that

these measures will accrue into the air quality planning process.”

Guidance on SIP Credits for

Emission Reductions from Electric-Sector Energy Efficiency and Renewable Energy Measures

,

USEPA (Aug. 5, 2004) (USEPA, Aug. 2004 Guidance) at 1.

The proposal at first and second notice sets aside percentages for four categories making

up the CASA:

•

Energy Efficiency and Conservation Projects/Renewable Energy Generation: 12%

•

Pollution Control Upgrade: 5%

•

Clean Coal Technology: 6%

•

Early Adopters: 2%

IEPA explained that a portion of the set-asides comes about from Section 9.10 of the Act

(415 ILCS 5/9.10 (2006)), which prescribes a percentage of the State’s energy production that

should come from renewable energy: 5% by 2010 and 15% by 2020. Stat. at 51. The 12%

figure is a combined value representing the renewable energy initiative of Section 9.10 coupled

with energy efficiency and conservation. This value is consistent with the USEPA

recommendation that a set-aside for the combination of EE/RE range between 5% and 15%.

Id

.

at 33. USEPA guidance suggested other types of energy projects can also be encouraged through

set-asides. USEPA, Aug. 2004 Guidance at 3-4. IEPA proposed the additional categories above,

---

39

adding on another 13% of the budget to encourage new air pollution controls, cleaner

technology, and early adoption of such projects. Stat. at 51.

As stated in its first-notice and second-notice opinions, the Board found that the set-

asides proposed by IEPA are appropriate. The allocations under the CASA categories work

toward addressing the Section 9.10 initiative while “encouraging a more diverse universe of

energy producers.” Stat. at 49.

Availability of the CASA.

Zion renewed its suggestion that applicants for CASA

allowances be restricted to electric-generating sources, eliminating non-generating sources (

e.g.

,

energy efficiency projects and demand-side management projects) from applying for CASA

allowances. PC 16 at 7. The restriction, Zion continued, would make more allocations available

to affected units for compliance. Without the restrictions, Zion stated that IEPA would be

offering “unwarranted financial incentives to non-emitters that have no direct compliance

burden.”

Id

. In support of these restrictions, Zion added that such efficiency and demand-side

management projects already realize economic incentives through “reductions in direct energy

costs and tax breaks.”

Id

.

As discussed in the Board’s second-notice opinion, allowing non-generating sources to

apply for CASA allowances is consistent with the approach taken with the Emission Reduction

Market System (ERMS) for volatile organic material (VOM) trading. 35 Ill. Adm. Code 205. In

part like the rules proposed for second notice, ERMS was designed to:

Implement innovative and cost-effective strategies to attain the national ambient

air quality standard (NAAQS) for ozone and to meet the requirements of the

Clean Air Act. 35 Ill. Adm. Code 205.110(a).

ERMS provides for open trading, specifically allowing “Special Participants”:

c) Special Participants

Any person may purchase ATUs [Allotment Trading Units] to retire for air

quality benefit only. Such person shall be a special participant and shall register

with the Agency prior to its first ATU purchase. Special participants will not

have Transaction Accounts in the Transaction Account database. All ATUs

purchased by special participants will be retired effective on the date of purchase

and will be listed as retired in the appropriate database. 35 Ill. Adm. Code

205.610(c).

A “Special participant” in ERMS means “any person that registers with the Agency and may

purchase and retire ATUs but not sell ATUs, as specified in Section 205.610 of this Part.” 35 Ill.

Adm. Code 205.130.

The open trading policy is the approach the State took in ERMS, an earlier example of

pollution trading. Zion did not cite to the issue of restricting trade in the federal discussion. The

---

40

Board found the ability for non-generators to apply for CASA allowances is consistent with the

open trading policy of ERMS at the State level and promotes energy efficiency.

Purpose of the CASA.

In criticizing the 25% CASA as “unreasonably burdensome,”

Kincaid and Dominion maintained that IEPA should justify “beyond CAIR” reductions with a

modeling demonstration to determine the level of reductions needed to resolve residual

nonattainment problems after CAIR is implemented. PC 17 at 2. Kincaid and Dominion also

stated that “beyond CAIR” reductions may not have any beneficial effect on reducing PM

2.5

.

Id

.

at 3. Kincaid and Dominion claimed that modeling conducted by Alpine Geophysics, dated

March 20, 2007, indicates that Illinois, Indiana, Wisconsin, Ohio, and Michigan will attain both

the ozone and PM

2.5

ambient air quality standards by 2015, when Phase 2 of the CAIR rules

becomes effective.

Id

. at 3-4.

As clarified by the Board in its second-notice opinion, the 25% CASA set-aside does not

equate with emissions reductions. Rather, the CASA represents a portion of the NO

x

emissions

allowances to be used for particular purposes,

i.e.

, EE/RE, pollution control upgrades, clean coal

technology, and early adopters. Accordingly, the CASA itself is not a “beyond CAIR”

reduction. That said, in IEPA’s Statement of Reasons, IEPA responded to a suggestion that set-

asides be retired only if modeling showed an air quality benefit would result. According to

IEPA, a “modeling demonstration would not be particularly instructive in this instance. The

effect of emissions reductions are incremental and no measure alone will assure attainment.”

Stat. at 52. IEPA continued by listing several other control measures that it intends to pursue

before seeking additional reductions in SO

2

or NO

x

from EGUs.

Id

.

Zion reiterated IEPA’s testimony at hearing that the proposed CASA and NUSA would

not reduce NO

x

emissions in Illinois even if the entire 30% were retired, and that the Chicago

area has already attained the 8-hour ozone standard without implementation of the proposed rule.

PC 16 at 9. Zion observed that local reductions would not necessarily result in improvements in

Illinois because CAIR is regional program, and Illinois would experience a burden from CASA

that will have primary benefits in other areas.

Id

.

Again, the Board emphasized that the allowances in the CASA are not simply being

retired. This contrasts with the Compliance Supplement Pool, discussed below. At hearing,

James R. Ross, Manager of the Division of Air Pollution Control in IEPA’s Bureau of Air,

testified in response to the question of whether the “primary purpose behind the proposal of the

CASA in its form [is] to result in reduced emissions, or was there a different purpose that was

driving the Agency’s proposal?” (Tr. at 91 (Oct. 10, 2006, a.m.):

The primary purpose was to encourage energy efficiency, renewable energy, clean

technology and early adopters, and as I stated, to the extent that those result in

additional NO

x

reductions, we would expect corresponding improvements to

public health and air quality (

id

.).

The Board further noted that neither of Illinois’ ozone nonattainment areas has been redesignated

as having attained the 8-hour ozone NAAQS. Moreover, in its Statement of Reasons, IEPA

stated that it:

---

41

presented modeling indicating that neither the greater Chicago nor Metro-East

nonattainment areas will attain the PM

2.5

NAAQS by the attainment dates nor will

the greater Chicago area attain the 8-hour ozone NAAQS by the attainment date.

Moreover these areas will not reach attainment in 2018, 3 ½ years after the

implementation of Phase II of the CAIR SO

2

and NO

x

trading programs.

See,

TSD 3.2. Illinois will need between 30 and 35 percent reductions of NO

x

beyond

the CAIR to achieve the current PM

2.5

NAAQS. Stat. at 51-52.

Finally, the Board found it useful to keep in mind the regional nature of CAIR, as

described by USEPA:

The [US]EPA conducted extensive air modeling to determine the extent to which

emissions from certain upwind States were impacting downwind nonattainment

areas. All States found to contribute significantly to downwind PM

2.5

[and 8-hour

ozone] nonattainment and maintenance problems are included in the CAIR region

. . . . 71 Fed. Reg. 25304 (Apr. 28. 2006).

In addition, the CAIR will improve PM

2.5

and 8-hour ozone air quality in the areas that

would remain in nonattainment for those two NAAQS after implementation of the CAIR.

Because of CAIR, the States with those remaining nonattainment areas will find it less

burdensome and less expensive to reach attainment by adopting additional local controls.

71 Fed. Reg. 25333 (Apr. 28, 2006).

Economic Impact of the CASA.

Zion expressed reservations over the reliance on the

“Analysis of Illinois NOx Budget Reductions by ICF Resource Incorporated using the Integrated

Planning Model [IPM].” PC 16 at 10. Zion associated the size of the CASA with a detrimental

economic impact to Illinois businesses when compared to businesses in other states that will be

subject to less aggressive CAIR standards.

Id

. Kincaid and Dominion followed this idea, stating

that the proposed CASA provisions will competitively disadvantage Illinois businesses and

electricity ratepayers relative to surrounding states. PC 17 at 1.

Although Zion, Kincaid, and Dominion expressed concern regarding the economic

implications of the rule, the companies did not provide for the rulemaking record a comparative

economic analysis of the predicted retail electricity rates in surrounding states to demonstrate or

quantify a competitive disadvantage for Illinois businesses or electricity ratepayers.

USEPA gave a regional perspective on the economics of the rule, stating that:

incentives provided by cap-and-trade encourage economically efficient

compliance over the entire region . . . . The economically efficient outcome will

not depend on the relative levels of individual unit allowance allocations. 71 Fed.

Reg. 25357 (Apr. 28, 2006).

As to the potential benefits to the economy from the approaches like CASA, USEPA stated:

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42

[Energy efficiency and renewable energy] measures can save money, have other

economic benefits, reduce dependence on foreign sources of fuel, increase the

reliability of the electricity grid, enhance energy security, and, most importantly

for air quality purposes, reduce air emissions from electric generating power

plants. USEPA, Aug. 2004 Guidance at 1.

As stated at first and second notice, the Board considered the USEPA findings on CAIR NO

x

and

SO

2

control technology costs, the IPM modeling provided by IEPA, and IEPA modeling used to

determine the cost impact of CASA on Illinois electricity rates. The modeling projects that retail

electricity rates would not change, and there was a slight change in average production costs.

TSD Table 7.6. The Board found that no new information has been presented in this rulemaking

record to warrant the Board altering its first-notice finding that the proposal is economically

reasonable.

Compliance Supplement Pool (CSP)

As the Board discussed in its second-notice opinion, USEPA created a Compliance

Supplement Pool (CSP) for the first year of the CAIR program that states may elect to distribute

through early reduction credits or through direct distribution for a demonstrated hardship or

disruption in the electricity supplied to the grid. Illinois received 11,299 CAIR NO

x

allowances

in the CSP for the 2009 control period. Stat. at 31. IEPA proposed retiring the allowances in the

CSP in the interest of “working toward a timely attainment of [the 8-hour ozone and PM

2.5

]

NAAQS.” Stat. at 36;

see

proposed 35 Ill. Adm. Code 225.480.

Kincaid, Dominion, Dynegy, and SIPC did not support IEPA’s plan to withhold the

allowances from the CSP. PC 6 at 35; PC 17 at 2. Kincaid and Dominion stated that the CSP

allowances used as early reduction incentives provide compliance flexibility and “real emission

reductions sooner.” PC 17 at 2. IEPA viewed the CSP as counter-productive:

Given the difficulty that the State will face in attaining the PM

2.5

and 8-hour

ozone NAAQS, to have an additional 11,299 tons (for the annual NOx program)

emitted during the critical years that are being used to determine attainment is

counter productive. Further, the State may take SIP credit for retirement of these

allowances. Stat. at 36.

Although different than having a CSP for early reduction incentives, the Board noted that

for early adopters, the 2% CASA would provide 1,525 and 614 allowances for Phase I (2009 –

2014) NO

x

annual and ozone season trading, respectively. At second notice, the Board agreed

with IEPA that distributing the one-time allowances in the CSP for the 2009 control period

would be counter-productive to Illinois’ attainment efforts.

Rule Language Changes from First to Second Notice

In its first-notice public comment, IEPA proposed a number of “clarifications and

corrections” to the rules proposed at first notice. PC 15 at 7. IEPA further described its

proposed revisions:

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43

a number of dates in the proposal, if left unchanged, would require retroactive

compliance. The Illinois EPA has also received a second set of comments from

USEPA and has noticed that a number of the amendments that it recommended in

its January 5, 2007, comments to the Board on the initial proposal were not

included in the first notice. In addition, there are some typos that need correction

and that some clarifications that need to be made.

Id

.

IEPA’s public comment, like the other four first-notice public comments, was filed on the

last day of the public comment period, June 25, 2007. The Board nevertheless did not receive

any motion for leave to file

instanter

a public comment in response to the IEPA-proposed

amendments. Accordingly, while contested issues have remained in this rulemaking as discussed

above, there was no opposition in the record to the specific word changes IEPA sought to make.

The Board also agreed with IEPA that these proposed changes in PC 15 were in the

nature of clarifications and corrections to the first-notice rules. The vast majority of the changes

were based on USEPA input received by IEPA. PC 15 at 7-26. Before first notice, in December

2006, USEPA provided IEPA with most of USEPA’s recommended “conforming amendments.”

PC 5 at 21; PC 15 at 7-19. On January 5, 2007, IEPA filed with the Board, as part of PC 5, these

USEPA-suggested edits, the highlights of which were discussed in the Board’s first-notice

opinion. 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, slip op. at

15 (Apr. 19, 2007) (CAIR First Notice). The changes, however, were inadvertently left out of

the first-notice rule text.

As SIPC pointed out, some other changes proposed by IEPA were found meritorious by

the Board in the first-notice opinion but also unintentionally omitted from the first-notice order.

PC 13 at 5-6; PC 15 at 27-28; CAIR First Notice at 14, 37;

see

Sections 225.465(b)(5)(B) and

225.565(b)(5)(B). IEPA also proposed changes to avoid any retroactive application of the rule.

For example, under the CAIR NO

x

annual trading program, for control periods 2009, 2010, and

2011, the deadline for the EGU owner or operator to submit to IEPA 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 was revised from June 1, 2007, to September 15, 2007.

See

Section 225.435(a).

The Board found all of the changes proposed by IEPA in PC 15 appropriate and adopted

them for second notice. At the request of JCAR, the Board also made several minor language

changes to its first-notice order.

CONCLUSION

To reduce the interstate transport of SO

2

and NO

x

emissions and take steps necessary to

attain the PM

2.5

and 8-hour ozone NAAQS in the greater Chicago and Metro East/St. Louis

nonattainment areas, the Board adopts the CAIR SO

2

, CAIR NO

x

annual, and CAIR NO

x

ozone

season trading programs. The rule amends Subpart A and adds new Subparts C, D, E, and F and

Appendix A of Part 225. No substantive changes are made to the rule as proposed for second

notice. Based on this record, the Board finds that the amendments adopted today are technically

---

44

feasible and economically reasonable and will not have an adverse economic impact on the

People of Illinois.

See

415 ILCS 5/27(a), (b) (2006).

The rule will become effective on August 31, 2007. Accordingly, the State of Illinois

will be able to meet the USEPA deadline and avoid losing control of NO

x

allocations for the

2009 period. Important policy objectives underlying this rulemaking are therefore preserved,

including the CASA incentives to invest in renewable energy projects, which work toward

addressing the renewable energy initiative of Section 9.10 of the Act (415 ILCS 5/9.10 (2006)).

The Board adopts CAIR as a final rule.

ORDER

The Board adopts the following amendments to 35 Ill. Adm. Code 225 and directs the

Clerk to submit the amendments to the Secretary of State for publication in the

Illinois Register

as a final rule.

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

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45

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

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

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46

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)

225.550

Monitoring, Recordkeeping and Reporting Requirements for Gross Electrical

Output and Useful Thermal Energy

225.555

Clean Air Set-Aside (CASA)

225.560

Energy Efficiency and Conservation, Renewable Energy, and Clean Technology

Projects

225.565

Clean Air Set-Aside (CASA) Allowances

225.570

Clean Air Set-Aside (CASA) Applications

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 August 31, 2007.

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47

SUBPART A: GENERAL PROVISIONS

Section 225.120

Abbreviations and Acronyms

Unless otherwise specified within this Part, the abbreviations used in this Part must be the same

as those found in 35 Ill. Adm. Code 211. The following abbreviations and acronyms are used in

this Part:

Act

Environmental Protection Act [415 ILCS 5]

ACI

activated carbon injection

Agency

Illinois Environmental Protection Agency

Btu

British thermal unit

CAA

Clean Air Act [42 USC 7401 et seq.]

CAAPP

Clean Air Act Permit Program

CAIR

Clean Air Interstate Rule

CASA

Clean Air Set-Aside

CEMS

continuous emission monitoring system

CO

2

carbon dioxide

CPS

Combined Pollutant Standard

CGO

converted gross electrical output

CUTE

converted useful thermal energy

EGU

electric generating unit

ESP

electrostatic precipitator

FGD

flue gas desulfurization

GO

gross electrical output

GWh

gigawatt hour

HI

heat input

hr

hour

kg

kilogram

lb

pound

MPS

Multi-Pollutant Standard

MW

megawatt

MWe

megawatt electrical

MWh

megawatt hour

NAAQS

National Ambient Air Quality Standards

NO

x

nitrogen oxides

NUSA

New Unit Set-Aside

ORIS

Office of Regulatory Information Systems

O

2

oxygen

PM

2.5

particles less than 2.5 micrometers in diameter

RATA

relative accuracy test audit

SO

2

sulfur dioxide

SNCR

selective noncatalytic reduction

TTBS

Temporary Technology Based Standard

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48

TCGO

total converted useful thermal energy

UTE

useful thermal energy

USEPA

United States Environmental Protection Agency

yr

year

(Source: Amended at 31 Ill. Reg. ____________, effective _______________)

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.

“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

compliance account, or a CAIR NO

x

Ozone Season compliance

account, the CAIR designated representative of the source.

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49

“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 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, CAIR SO

2

Trading Program, 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.

“Coal” means any solid fuel classified as anthracite, bituminous, subbituminous, or

lignite by the American Society for Testing and Materials (ASTM) Standard

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 and F, or for purposes of allocating allowances under

Sections 225.435, 225.445, 225.535, and 225.545, combusting any amount of coal

or coal-derived fuel, alone or in combination with any amount of any other fuel,

during a specified year;

Except as provided above, 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

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50

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:

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 described in

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 Subparts B and F 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:

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51

“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:

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

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52

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; or

For the purposes of Subpart C, a “compliance account” means a CAIR SO

2

compliance account, established by the USEPA for a CAIR SO

2

source pursuant to

40 CFR 96, subpart FFF, in which any SO

2

units at the source are initially

recorded and in which are held any SO

2

allowances available for use for a control

period in order to meet the source’s CAIR SO

2

emissions limitations in

accordance with Section 225.310 and 40 CFR 96.254, as incorporated by

reference in Section 225.140.

“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.

“Designated representative” means, for the purposes of Subpart B of this Part, the natural

person same as defined in 40 CFR 60.4102, and is the same natural person as the person

who is the designated representative for the CAIR trading and Acid Rain programs.

“Electric generating unit” or “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 of any amount of fossil fuel, alone or in

combination with any other fuel in any calendar year.

“Generator” means a device that produces electricity.

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53

“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” or “HHV” means the total heat liberated per mass of fuel burned

(Btu/lb), 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” or “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

seasonal or other deratings) as of such installation as specified by the manufacturer of the

generator or, starting from the completion of any subsequent physical change in the

generator resulting in an increase in the maximum electrical generating output (in MWe)

that the generator is capable of producing on a steady-state basis and during continuous

operation (when not restricted by seasonal or other deratings), such increased maximum

amount as of completion 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.

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54

“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.

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

---

55

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 Subparts B and F 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

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 (2006 2005).

c)

40 CFR 78 (2006).

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56

d)

40 CFR 96, CAIR SO

2

Trading Program, subparts AAA (excluding 40 CFR

96.204 and 96.206), BBB, FFF, GGG, and HHH (2006).

e)

40 CFR 96, CAIR NO

x

Annual Trading Program, subparts AA (excluding 40

CFR 96.104, 96.105(b)(2), and 96.106), BB, FF, GG, and HH (2006).

f)

40 CFR 96, CAIR NO

x

Ozone Season Trading Program, subparts AAAA

(excluding 40 CFR 96.304, 96.305(b)(2), and 96.306), BBBB, FFFF, GGGG, and

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).

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 Guidelines: 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 _______________)

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57

Section 225.150

Commence Commercial Operation

Commence commercial operation means, for the purposes of Subparts C, D and E, with regard to

a unit:

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 Sections 225.305, 225.405, and

225.505, 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 Sections 225.305, 225.405, and

225.505, 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 replacement 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.

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 225.505, 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 a CAIR

SO

2

unit, CAIR NO

x

unit, or CAIR NO

x

Ozone Season unit pursuant to

Section 225.305, 225.405, or 225.505, 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

---

58

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 replacement 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:

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 of the unit’s combustion chamber, a

generator with nameplate capacity of more than 25 MWe producing

electricity for sale.

2)

If a stationary boiler or stationary combustion turbine that, 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.

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59

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 would otherwise be classified as 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 continues

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 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 would otherwise be classified as a CAIR SO

2

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)

Has 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 would otherwise be classified as 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

---

60

B)

Has 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 20

percent or more.

(Source: Added at 31 Ill. Reg. ________________, effective ______________)

Section 225.310

Compliance Requirements

a)

The designated representative 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:

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, reporting and

recordkeeping requirements of 40 CFR 96, subpart HHH. The CAIR

---

61

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, midnight of March 1, 2011, and by

midnight of March 1 of each subsequent year if March 1 is a business day,

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

compliance account. If March 1 is

not a business day, the allowance transfer deadline means by midnight of

the first business day thereafter. The number of allowances held on the

allowance transfer deadline may not be less than the total tonnage

equivalent of the 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 excess emissions of SO

2

emitted by a CAIR SO

2

source for

each day of a control period, starting in 2010 will constitute a separate

violation of this Subpart C, the Clean Air Act, and the Act.

3)

Each CAIR SO

2

unit will be subject to the requirements of subsection

(d)(1) of this Section for the control period starting on the later of January

1, 2010 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

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62

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 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 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 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

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.

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63

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 a 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.

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

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64

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, 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.

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 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 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 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

---

65

must specify that they are applying for CAIR permits and must address the

CAIR permit application requirements of this Section.

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;

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, 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 specified in 225.130 and 40 CFR 96.202, as incorporated by

reference in Section 225.140 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 ______________)

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66

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.

202, 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, 0.50 ton of SO

2

, except as provided for in the compliance

deductions pursuant to 40 CFR 96.254(b); and

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

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67

November 15, 1990 or the start-up of the unit’s combustion chamber, a

generator with nameplate capacity of more than 25 MWe producing

electricity for sale.

2)

If a stationary boiler or stationary combustion turbine that, 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 would otherwise be classified as 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 continues

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 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 would otherwise be classified as 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

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68

B)

Has 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 would otherwise be classified as 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)

Has 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

1990 for which the unit has an average annual fuel consumption of 20

percent or more.

(Source: Added at 31 Ill. Reg. ________________, effective ______________)

Section 225.410

Compliance Requirements

a)

The designated representative 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 designated representative 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

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69

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, reporting, and

recordkeeping 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:

1)

By the allowance transfer deadline, midnight of March 1, 2010, and by

midnight March 1 of each subsequent year if March 1 is a business day,

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. If March 1 is not a business day, the allowance

transfer deadline means by midnight of the first business day thereafter.

The number of allowances held on the allowance transfer deadline 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 excess emissions of a CAIR NO

x

source for each day in a

control period, starting in 2009, 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 requirements of subsection

(d)(1) of this Section for the control period 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.

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70

4)

CAIR NO

x

allowances must be held in, deducted from, or transferred into

or 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 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 does not constitute a property right.

8)

Upon recordation by USEPA pursuant to 40 CFR 96, subpart FF or

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.

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71

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

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).

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72

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

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, 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 Sections 39 and 39.5 of the

Act, must contain federally enforceable conditions addressing all

applicable CAIR NO

x

Annual Trading Program requirements, and will be

a complete and segregable portion of the source’s entire permit pursuant to

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73

subsection (a)(1) of this Section.

3)

No CAIR permit may be issued 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 December 31,

2007, the owner or operator of the unit must submit a CAIR permit

application meeting the requirements of this Section on or before

December 31, 2007.

5)

For all CAIR NO

x

units that commence operation on or after December

31, 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.

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

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74

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, 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 specified in Section 225.130 and 40 CFR 96.102, as

incorporated by reference in Section 225.140 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

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

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75

a)

On or before September 25, 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. For example, on

October 31, 2008, the Agency will submit to USEPA the allocations for the 2012

control period.

c)

For CAIR NO

x

units that commence commercial operation on or after January 1,

2006, that have not been allocated allowances under Section 225.440 for the

applicable or any preceding control period, the Agency will allocate allowances

from the NUSA in accordance with Section 255.445. 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,

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 (CGO) 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 September 15, 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

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76

those control periods for which data is available. 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 (in MWh)

×

1.0;

B)

If the unit is oil-fired:

CGO (in MWh) = GO (in MWh)

×

0.6; or

C)

If the unit is neither coal-fired nor oil-fired:

CGO (in MWh) = GO (in 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 inputs from the 2001, 2002, 2003,

2004 or 2005 control period will be used. If the unit has three or fewer

control periods of heat input data, the heat input will be the average of

those control periods for which data is available. 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 will 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. If a unit commences

commercial operation in the 2007 control period and does not have gross

electrical output for the 2006 control period, then the gross electrical

output from 2007 will be used. 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:

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77

A)

If the unit is coal-fired:

CGO (in MWh) = GO (in MWh)

×

1.0;

B)

If the unit is oil-fired:

CGO (in MWh) = GO (in MWh)

×

0.6;

C)

If the unit is neither coal-fired nor oil-fired:

CGO (in MWh) = GO (in MWh)

×

0.4.

2)

Heat input: The average of the unit’s two most recent years of control

period heat inputs, e.g., for the 2012 control period, the average of the

unit’s heat input from the 2006 and 2007 control periods. 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. If a unit commences commercial operation in the most recent control

period and does not have gross electrical output for two control periods, the gross

electrical output from the most recent period, e.g., if the unit commences

commercial operation in 2009 and does not have gross electrical output from

2008, gross electrical output from 2009 will be used. 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 (in MWh)

×

1.0;

2)

If the unit is oil-fired:

CGO (in MWh) = GO (in MWh)

×0.6;

or

3)

If the unit is neither coal-fired nor oil-fired:

CGO (in MWh) = GO (in MWh)

×

0.4.

d)

For a unit that is a combustion turbine or boiler and has equipment used to

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78

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

(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. In the first year for which a unit is considered to be an

existing unit rather than a new unit, 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

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 to all CAIR NO

x

units in Illinois for which the Agency has calculated the

converted gross electrical output pursuant to Section 225.435(a), (b), or (c) or

total converted gross electrical output pursuant to Section 225.435(d), as

applicable, 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 as adjusted to add allowances not allocated

pursuant to subsection (b) of this Section in the previous year’s allocation.

b)

The Agency will allocate CAIR NO

x

allowances to each CAIR NO

x

unit on a pro-

rata basis using the unit’s converted gross electrical output pursuant to Section

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79

225.435(a), (b), or (c) or total converted gross electrical output calculated

pursuant to Section 225.435(d), as applicable, to the extent whole allowances may

be allocated. The Agency will retain any additional allowances beyond this

allocation of whole allowances for allocation pursuant to subsection (a) of this

Section in the next control period.

(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 or any

preceding 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 five 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

period in which the new unit commences commercial operation and until the fifth

control period after the control period in which the unit commenced commercial

operation. 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

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:

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80

A)

If the unit is coal-fired:

CGO (in MWh) = GO (in MWh)

×

1.0;

B)

If the unit is oil-fired:

CGO (in MWh) = GO (in MWh)

×

0.6; or

C)

If the unit is neither coal-fired nor oil-fired:

CGO (in MWh) = GO (in MWh)

×

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 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:

lbs ton

NCGO

lbs MWh

UA

y

y

2000

/

*(1.0

/

)

=

Where:

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81

UA

y

=

unprorated allocation to a new

CAIR NO

x

unit.

NCGO

y

=

converted gross electrical output or total

converted gross electrical output, as

applicable, 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, to the extent that

whole allowances may be allocated. For any additional allowances

beyond this allocation of whole allowances, the Agency will retain

the additional allowances in the NUSA for allocation pursuant to

this Section in later control periods.

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, to the extent that whole allowances may be allocated.

For any additional allowances beyond this allocation of whole

allowances, the Agency will retain the additional allowances in the

NUSA for allocation pursuant to this Section in later control

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.

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.

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82

h)

After a new CAIR NO

x

unit has operated in one control period, it becomes an

existing unit for the purposes of calculating future allocations in Section 225.440

only, and the Agency will allocate CAIR NO

x

allowances for that unit, for the

control period commencing five control periods after the control period in which

the unit commences commercial operation, 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 ______________)

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 accurately measuring gross electrical output that is consistent with the

requirements of either 40 CFR 60 or 75; must measure gross electrical output in

MWh using such a system; and must record the output of the measurement system

at all times. 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 of 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 the 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,

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83

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 to USEPA as follows:

1)

By September 15, 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 of 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 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

or 75, as applicable, including the appropriate 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

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84

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 five

years from the date the record is created or the data is collected under subsections

(a) and (b) of this Section, and the reports are 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)

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 the 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 after 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 the 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.

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85

(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:

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 USC 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 following applicable

thresholds and criteria:

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.

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86

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, a 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 commenced operation on or after January 1, 2006, and that

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 waste,

institutional lunchroom waste, 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. For this purpose, a unit will be considered

“existing” after it has been in commercial operation for at least eight

years. 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 an activated carbon injection or other sorbent injection system

for control of mercury.

2)

Clean coal technologies projects include:

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87

A)

Integrated gasification combined cycle (IGCC) plants.

B)

Fluidized bed coal combustion that commenced operation prior to

December 31, 2006.

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 or Subpart F.

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 fit 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

subsections (a) through (c)(2)(B) of this Section.

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88

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

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 Section

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 project pursuant to Section

225.460(b)(1), the number of allowances must be calculated using the

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89

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.

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

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90

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:

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 that 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 that does not

assign a Q factor then Q shall equal:

Q= 0.25 – (P x ER

q

)

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91

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 rate of 10 mmBtu/1 MW.

5)

For highly efficient power generation and clean coal technology projects:

A)

For projects other than fluidized coal combustion pursuant to

Section 225.460(a)(4)(B), (a)(4)(C), and (c)(2), the number of

allowances must be calculated using the number of MWh 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.

B)

For fluidized bed coal combustion projects pursuant to Section

225.460 (c)(2), the number of allowances shall be calculated using

the number of gross MWh of electricity the project generates

during a control period and the following formula:

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92

A

=

(MWh

g

) x (1.4 lb/MWh – ER lb/MWh) / 2000 lb

Where:

A

=

The number of allowances for a particular

project.

MWh

g

=

The number of gross MWh of electricity

generated during a control period by a

project.

ER

=

Annual NO

x

emission rate for the control

period based on CEMS data in lb/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 in this subsection. 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;

2)

Fluidized bed coal combustion projects, highly efficient power generation

operations projects, or renewable energy emission units, that commenced

construction on or after January 1, 2001; and

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93

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 names 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;

ii)

Occupancy type;

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94

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, and

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 subsection (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.”

d)

A project sponsor may request allowances from the CASA for each project for a

total number of control periods not to exceed the number of control periods listed

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95

in this subsection. After a project has been allocated allowances from the 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.

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

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96

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:

1)

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 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 (b)(1) 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 subsections (b)(1) through (b)(3) 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

allowed allocation of an additional 11,299 CAIR NO

x

allowances in Illinois as a compliance

supplement pool to Illinois for the control period in 2009. However, for the purposes of public

health and air quality improvements, none of these allowances will be allocated.

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97

(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 of the unit’s combustion

chamber, a generator with nameplate capacity of more than 25 MWe

producing electricity for sale.

2)

If a stationary boiler or stationary combustion turbine that, 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

Ozone Season 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 would otherwise be classified as a CAIR NO

x

Ozone Season

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 continues

to qualify as a cogeneration unit; and

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98

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 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 would otherwise be classified as 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)

Has 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 would otherwise be classified as 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)

Has 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

Ozone Season unit

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99

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 20 percent or more.

(Source: Added at 31 Ill. Reg. ________________, effective ______________)

Section 225.510

Compliance Requirements

a)

The designated representative 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 designated representative 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, reporting and recordkeeping 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 96,

subpart HHHH, applicable to a CAIR designated representative.

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

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100

reported in accordance with 40 CFR 96, subpart HHHH.

d)

Emission requirements:

1)

By the allowance transfer deadline, midnight of November 30, 2009, and

by midnight of November 30 of each subsequent year if November 30 is a

business day, 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.

If November 30 is not a business day, the allowance transfer deadline

means by 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 excess emissions of a CAIR NO

x

Ozone Season source for

each day in a control period, starting in 2009 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 requirements of

subsection (d)(1) of this Section for the control period 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 or 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 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 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 does not constitute a property

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101

right.

8)

Upon recordation by USEPA pursuant to 40 CFR 96, subpart FFFF or

GGGG, every allocation, transfer, or deduction of a CAIR NO

x

Ozone

Season 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 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.

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 NO

x

Ozone Season

Trading Program.

E)

Copies of all records and logs for gross electrical output and useful

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102

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).

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

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103

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, 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 Sections 39 and 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 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

December 31, 2007, the owner or operator of the unit must submit a CAIR

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104

permit application meeting the requirements of this Section on or before

December 31, 2007.

5)

For all units that commence operation on or after December 31, 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

same procedural requirements. When the Agency issues a CAIR permit

pursuant to the requirements of this Section, 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 specified in Section 225.130 and 40 CFR 96.302, as

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105

incorporated by reference in Section 225.140, 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

and the 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)

On or before September 25, 2007, 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 2009, 2010, and 2011 control periods.

b)

By July, 2008 and July 31 of each year thereafter, the Agency will submit to

USEPA the CAIR NO

x

Ozone Season allowance allocations in accordance with

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106

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. For example, on

July 31, 2008, the Agency will submit to USEPA the allocation for the 2012

control period.

c)

For CAIR NO

x

Ozone Season units that commence commercial operation on or

after May 1, 2006, that have not been allocated allowances under Section 225.440

for the applicable or any preceding control period, the Agency will allocate

allowances from the NUSA in accordance with Section 225.545. 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 (CGO), 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 September 15, 2007, a statement that either

gross electrical output data or heat input data is to be used to calculate 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 outputs, the gross electrical output will be the average of those

control periods for which data is available. If a generator is served by two

or more units, then the gross electrical output of the generator will be

attributed to each unit in proportion to the unit’s share of 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:

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107

A)

If the unit is coal-fired:

CGO (in MWh) = GO (in MWh)

×

1.0;

B)

If the unit is oil-fired:

CGO (in MWh) = GO (in MWh)

×

0.6; or

C)

If the unit is neither coal-fired nor oil-fired:

CGO (in MWh) = GO (in 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 control period heat inputs from 2001,

2002, 2003, 2004, or 2005 will be used. If the unit has three or fewer

control periods of heat input data, the heat input will be the average of

those control periods for which data is available. 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 is to 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. If a unit commences

commercial operation in the 2007 control period and does not have gross

electrical output for the 2006 control period, the gross electrical output

from the 2007 control period will be used. 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 (in MWh)

×

1.0;

B)

If the unit is oil-fired:

CGO (in MWh) = GO (in MWh)

×

0.6;

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108

C)

If the unit is neither coal-fired nor oil-fired:

CGO (in MWh) = GO (in MWh)

×

0.4.

2)

Heat input: The average of the unit’s two most recent years of control

period heat inputs, e.g., for the 2012 control period, the average of the

unit’s heat input from the 2006 and 2007 control periods. 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. If a unit commences commercial operation in the most recent control

period and does not have gross electrical output from the most recent control

period, e.g., if the unit commences commercial operation in the 2009 control

period and does not have gross electrical output from the 2008 control period,

gross electrical output from the 2009 control period will be used. 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 (in MWh)

×

1.0;

2)

If the unit is oil-fired:

CGO (in MWh) = GO (in MWh)

×

0.6; or

3)

If the unit is neither coal-fired nor oil-fired:

CGO (in MWh) = GO (in MWh)

×

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 subsection

(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

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109

of the unit’s control period useful thermal energy for the prior two control

periods, if available. In the first control period for which the unit is considered to

be an existing unit rather than a new unit, 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, to all CAIR NO

x

Ozone Season units in Illinois for which the Agency

has calculated the converted gross electrical output pursuant to Section

225.535(a), (b), or (c), or total converted gross electrical output pursuant to

Section 225.535(d), as applicable, 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, as

adjusted to add allowances not allocated pursuant to subsection (b) of this Section

in the previous year’s allocation.

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 converted gross

electrical output pursuant to Section 225.535(a), (b), or (c), or total converted

gross electrical output calculated pursuant to Section 225.535(d), as applicable, to

the extent whole allowances may be allocated. The Agency will retain any

additional allowances beyond this allocation of whole allowances for allocation

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110

pursuant to subsection (a) of this Section in the next control period.

(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 or any preceding 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 NUSA will

be allocated CAIR NO

x

Ozone Season allowances equal to five 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 fifth control period after the control period in

which the unit commenced commercial operation. 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:

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111

CGO (in MWh) = GO (in MWh)

×

1.0;

B)

If the unit is oil-fired:

CGO (in MWh) = GO (in MWh)

×

0.6; or

C)

If the unit is neither coal-fired nor oil-fired:

CGO (in MWh) = GO (in MWh)

×

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 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 .

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:

lbs ton

NCGO

lbs MWh

UA

y

y

2000

/

×(1

.0

/

)

=

Where:

UA

y

=

unprorated allocation to a new CAIR NO

x

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112

Ozone Season unit.

NCGO

y

=

converted gross electrical output or total

converted gross electrical output, as

applicable, 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, to the extent that

whole allowances may be allocated. For any additional allowances

beyond this allocation of whole allowances, the Agency will retain

the additional allowances in the NUSA for allocation pursuant to

this Section in later control periods.

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, to the extent that whole allowances may be allocated. For

any additional allowances beyond this allocation of whole

allowances, the Agency will retain the additional allowances in the

NUSA for allocation pursuant to this Section in later control

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.

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.

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.

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113

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 calculating future allocations in

Section 225.540 only, and the Agency will allocate CAIR NO

x

Ozone Season

allowances for that unit, for the control period commencing five control periods

after the control period in which the unit commenced commercial operation,

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

Ozone Season unit

must operate a system for accurately measuring gross electrical output that is

consistent with the requirements of either 40 CFR 60 or 75; must measure gross

electrical output in MWh using such a system; and must record the output of the

measurement system at all times. 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 of 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,

2008, 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 the 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 transfer medium other than

steam, e.g., hot water or glycol, must install, calibrate, maintain, and operate the

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114

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

Ozone Season 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 September 15, 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 of 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 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 or 75, as applicable, including the appropriate

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 225.550(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,

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115

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 five years from the date the record is created or the data is collected under

subsections (a) and (b) of this Section, and the reports are 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

Ozone Season allowances from the 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

Ozone Season allowances that it received pursuant to its CASA

request or an equivalent number of CAIR NO

x

Ozone Season allowances to the

CASA within six months after receipt of an Agency notice that NO

x

Ozone

Season allowances must be restored. These allowances will be assigned to the

fund from which they were distributed.

c)

CAIR NO

x

Ozone Season allowances from the 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

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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 projects 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